10-K

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2021

OR

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For transition period from         to

Commission File Number 001-41132

Crescent Energy Company

(Exact name of registrant as specified in its charter)

Delaware	87-1133610
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification Number)

600 Travis Street, Suite 7200

Houston, Texas 77002

(713) 337-4600

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol	Name of each exchange on which registered
Class A Common Stock, par value $0.0001	CRGY	New York Stock Exchange

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act Yes ☐ No ☒

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the Registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit such files). Yes ☒ No ☐

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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☐	Accelerated filer	☒
Non-accelerated filer	☐	Smaller reporting company	☐
		Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 7(a)(2)(B) of the Securities Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act): Yes ☐ No ☒

The aggregate market value of Class A common stock outstanding held by non-affiliates of the registrant on February 28, 2022, based on the closing price of $15.15 for shares of the registrant’s Class A common stock as reported by the New York Stock Exchange, was approximately $488.3 million. The registrant has elected to use February 28, 2022 as the calculation date because the registrant was a privately held company on June 30, 2021 (the last business day of the registrant’s most recently completed second fiscal quarter). The aggregate market value of the common stock of Contango Oil & Gas Company, the registrant’s predecessor pursuant to Rule 12g-3 under the Exchange Act, held by non-affiliates thereof as of June 30, 2021, based on the closing price of $4.32 for shares of its common stock as reported on the NYSE American, was approximately $571.9 million.

As of February 28, 2022, there were approximately 41,954,385 and 127,536,463 shares of the registrant's Class A and Class B common stock outstanding, respectively.

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Table of Contents

Where you can find more information	4
Cautionary Statement Regarding Forward-Looking Statements	4
Risk Factors Summary	5
Glossary of Terms	7
Part I
Items 1 and 2. Business and Properties	11
Item 1A. Risk Factors	37
Item 1B. Unresolved Staff Comments	66
Item 3. Legal Proceedings	66
Item 4. Mine Safety Disclosures	67
Part II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	67
Item 6. Reserved	67
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations	67
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	84
Item 8. Financial Statements and Supplementary Data	86
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosures	136
Item 9A. Controls and Procedures	136
Item 9B. Other Information	136
Item 9C. Disclosure Regarding Foreign Jurisdiction that Prevent Inspections	137
Part III
Item 10. Directors, Executive Officers and Corporate Governance	137
Item 11. Executive Compensation	141
Item 12. Security Ownership of Certain Beneficial Owner and Management and Related Stockholder Matters	145
Item 13. Certain Relationships and Related Transactions, and Director Independence	148
Item 14. Principal Accounting Fees and Services	150
Part IV
Item 15. Exhibits and Financial Statement Schedules	151
Item 16. Form 10-K Summary	153
Signatures	154

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Where You Can Find More Information

Crescent Energy Company ("we," "us," or the "Company") files annual, quarterly and current reports with the U.S. Securities and Exchange Commission ("SEC"). The SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC, including the Company.

Investors can also access financial and other information via our website at www.crescentenergyco.com. The Company makes available, free of charge through the website, copies of Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to such reports, our ESG report and all reports filed by executive officers and directors under Section 16 of the Securities Exchange Act of 1934 (the "Exchange Act") reporting transactions in the Company's securities. Access to these reports is provided as soon as reasonably practical after such reports are electronically filed with the SEC. Information contained on or connected to our website which is not directly incorporated by reference into this Annual Report on Form 10-K (this "Annual Report") should not be considered part of this report or any other filing made with the SEC.

Crescent Energy Company's website also can be used to access copies of charters for various board committees, including the Audit Committee and governance documents, including our Corporate Governance Guidelines and our Code of Conduct free of charge. Additionally, we intend to make future Annual Reports, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports as soon as reasonably practical after the filing of such reports available on our website. Our website is maintained at www.crescentenergyco.com. While the Company recommends that you view Crescent Energy Company's website, the information available on our website is not part of this report and is not incorporated herein by reference.

You may request a copy of filings other than an exhibit to a filing unless that exhibit is specifically incorporated by reference into that filing, at no cost by writing or calling Crescent Energy Company, 600 Travis Street, Suite 7200, Houston, TX 77002 (telephone number: 713-337-4600).

Cautionary Statement Regarding Forward-Looking Statements

The information in this Annual Report contains or incorporates by reference information that includes or is based upon "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Exchange Act. All statements, other than statements of historical facts, included herein concerning, among other things, planned capital expenditures, increases in oil, natural gas and natural gas liquids (“NGL”) production, the number of anticipated wells to be drilled or completed after the date hereof, future cash flows and borrowings, pursuit of potential acquisition opportunities, our financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. These forward-looking statements are identified by their use of terms and phrases such as “may,” “expect,” “estimate,” “project,” “plan,” “believe,” “intend,” “achievable,” “anticipate,” “will,” “continue,” “potential,” “should,” “could,” and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Our results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including, among others:

•commodity price volatility;

•our business strategy;

•the length, scope, and severity of the ongoing coronavirus disease 2019 (“COVID-19”) pandemic, including the effects of related public health concerns and the impact of continued actions taken by governmental authorities and other third parties in response to the pandemic and its impact on commodity prices, supply and demand considerations, and storage capacity;

•our ability to identify and select possible acquisition and disposition opportunities;

•capital requirements and uncertainty of obtaining additional funding on terms acceptable to us;

•risks and restrictions related to our debt agreements and the level of our indebtedness;

•our reliance on KKR Energy Assets Manager LLC as our external manager;

•our hedging strategy and results;

•realized oil, natural gas and natural gas liquids ("NGL") prices;

•political and economic conditions and events in foreign oil, natural gas and NGL producing countries, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, the armed conflict in Ukraine and associated economic sanctions on Russia, conditions in South America, Central America and China and acts of terrorism or sabotage;

•timing and amount of our future production of oil, natural gas and NGLs;

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•a decline in oil, natural gas and NGL production, and the impact of general economic conditions on the demand for oil, natural gas and NGLs and the availability of capital;

•unsuccessful drilling and completion (“D&C”) activities and the possibility of resulting write downs;

•our ability to meet our proposed drilling schedule and to successfully drill wells that produce oil, natural gas and NGLs in commercially viable quantities;

•shortages of equipment, supplies, services and qualified personnel and increased costs for such equipment, supplies, services and personnel;

•adverse variations from estimates of reserves, production, prices and expenditure requirements, and our inability to replace our reserves through exploration and development activities;

•incorrect estimates associated with properties we acquire relating to estimated proved reserves, the presence or recoverability of estimated oil, natural gas and NGL reserves and the actual future production rates and associated costs of such acquired properties;

•hazardous, risky drilling operations, including those associated with the employment of horizontal drilling techniques, and adverse weather and environmental conditions;

•limited control over non-operated properties;

•title defects to our properties and inability to retain our leases;

•our ability to successfully develop our large inventory of undeveloped acreage;

•our ability to retain key members of our senior management and key technical employees;

•risks relating to managing our growth, particularly in connection with the integration of significant acquisitions;

•impact of environmental, occupational health and safety, and other governmental regulations, and of current or pending legislation, including as a result of the recent change in presidential administrations;

•federal and state regulations and laws;

•our ability to predict and manage the effects of actions of the Organization of the Petroleum Exporting Countries (“OPEC”) and agreements to set and maintain production levels;

•changes in tax laws;

•effects of competition; and

•seasonal weather conditions.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties incident to the development, production, gathering and sale of oil, natural gas and NGLs, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability and cost of drilling and production equipment and services, project construction delays, environmental risks, drilling and other operating risks, lack of availability or capacity of midstream gathering and transportation infrastructure, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures and the other risks described under “Risk Factors.”

Reserve engineering is a process of estimating underground accumulations of hydrocarbons that cannot be measured in an exact way. The accuracy of any reserve estimates depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development program. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.

Should one or more of the risks or uncertainties described in this Annual Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this Annual Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Annual Report.

Risk Factors Summary

The following is a summary of the principal risks that could adversely affect our business, operations and financial results. Please refer to Item 1A Risk Factors of this Annual Report below for additional discussion of the risks summarized in this Risk Factors Summary.

Risks related to the oil and natural gas industry and our operations

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•Events beyond our control, including the recent COVID-19 pandemic or any other future global or domestic health crisis, may result in unexpected adverse operating and financial results.

•Oil, natural gas and NGL prices are volatile. A sustained decline in prices could adversely affect our business, financial condition and results of operations, liquidity and our ability to meet our financial commitments or cause us to delay planned capital expenditures.

•Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

•Due to the recent increase in commodity prices following extreme volatility during 2020, the unavailability or high cost of equipment, supplies, personnel and oilfield services could adversely affect our ability to execute development and exploitation plans on a timely basis and within budget, and consequently could materially and adversely affect our anticipated cash flow.

•We are not the operator on all of our acreage or drilling locations, and, therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated assets and could be liable for certain financial obligations of the operators or any of its contractors to the extent such operator or contractor is unable to satisfy such obligations.

•We have consolidated our business over time through acquisitions, including the recent Merger Transactions and the contemplated Uinta Transaction, and there are risks associated with integration of all of these assets, operations and our ability to manage those risks. In addition, we may be unable to make attractive acquisitions or successfully integrate acquired businesses, assets or properties, and any inability to do so may disrupt its business and hinder its ability to grow.

•Through the Management Agreement, we depend on the Manager and its personnel to manage and operate our business, the loss of any of whom would materially and adversely affect future operations. Additionally, operational risks affecting the Manager, and our ability to work collaboratively with the Manager, including with respect to the allocation of corporate opportunities and other conflicts of interest, may impact our business and have a material effect on our business, financial results and prospects.

•Future commodity price declines may result in write-downs of our asset carrying values.

Risks related to regulatory matters

•Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have a material and adverse effect on its financial condition, results of operations and cash flows.

•Our ability to pursue our business strategies may be adversely affected if we incur costs and liabilities due to a failure to comply with environmental laws or regulations or a release of hazardous substances or other wastes into the environment.

•Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which may adversely affect our future cash flows.

•Our operations are subject to a series of risks arising from climate change.

•Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.

Risks related to our indebtedness

•We are partially dependent on our Revolving Credit Facility and continued access to capital markets to successfully execute our operating strategies.

•The reduction in the borrowing base under our Credit Agreement, and any further reductions as a result of periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

Risks related to our common stock

•An active, liquid and orderly trading market for our Class A Common Stock may not develop or be maintained.

•Future sales of our Class A Common Stock in the public market, or the perception that such sales may occur, could reduce the price of our Class A Common Stock, and any additional capital raised by the Company through the sale of equity or convertible securities may dilute your ownership in Crescent.

Risks related to our financial condition

•Our hedging activities could result in financial losses or could reduce our net income.

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•Certain employees of our operating subsidiaries have profits interests that may require substantial payouts and result in substantial accounting charges.

•Our only principal asset is our interest in OpCo; accordingly, we will depend on distributions from OpCo to pay taxes, make payments under the Management Agreement and cover our corporate and other overhead expenses.

Risks related to our governance structure

•Our Preferred Stockholder’s significant voting power limits the ability of holders of our common stock to influence our business.

•The Preferred Stockholder’s controlling ownership position may have the effect of delaying or preventing changes in control or changes in management and may adversely affect the trading price of our Class A Common Stock to the extent investors perceive a disadvantage in owning stock of a company with a controlling shareholder.

•Our Certificate of Incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or its directors, officers, employees or agents.

•Our Certificate of Incorporation provides that the Preferred Stockholder is, to the fullest extent permitted by law, under no obligation to consider the separate interests of the other stockholders and will contain provisions limiting the liability of the Preferred Stockholder.

Tax risks

•If OpCo were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, we and OpCo might be subject to potentially significant tax inefficiencies.

•Changes to applicable tax laws and regulations may adversely affect our business, results of operations, financial condition and cash flow.

General risks

•Our business could be negatively affected by security threats, including cyber security threats and other disruptions and is subject to complex and evolving laws and regulations regarding privacy and data protection.

•We may be unable to protect our intellectual property rights or be subject to litigation if another party claims that we have infringed upon its intellectual property rights.

•From time to time, we may be involved in legal proceedings that could result in substantial liabilities.

•We may be unable to dispose of non-strategic assets on attractive terms and may be required to retain liabilities for certain matters.

Glossary of Terms

"Adjusted Cash G&A" means General and administrative expense excluding noncash equity-based compensation, and including certain non-controlling interest distributions made by OpCo related to the management fee.

"April 2021 Exchange” means the redemption by certain of Independence’s consolidated subsidiaries of the noncontrolling equity interests held in such subsidiaries by certain third-party investors in exchange for membership interests in Independence in April 2021.

“ARO” means an asset retirement obligation.

“Bbl” means 42 U.S. gallons liquid volume per stock tank barrel.

“BLM” means the federal Bureau of Land Management.

“Boe” means barrels of oil equivalent.

“Btu” means British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water one degree Fahrenheit.

“CAA” means the federal Clean Air Act, as amended, and the rules and regulations promulgated thereunder.

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“CARB” means the California Air Resources Board.

“CERCLA” means the federal Comprehensive Environmental Response, Compensation, and Liability Act, as amended, and the rules and regulations promulgated thereunder.

“CFTC” means the Commodity Futures Trading Commission.

“Class A Common Stock” means the shares of Class A common stock, par value $0.0001 per share, of the Company..

“Class B Common Stock” means the shares of Class B common stock, par value $0.0001 per share, of the Company.

“Code” means the Internal Revenue Code of 1986, as amended.

“Company Group” means the Company and each of its subsidiaries (other than OpCo and its subsidiaries).

"Contango" means Contango Oil & Gas Company, a Texas corporation.

"Contango Incentive Plan" means the Contango Oil & Gas Company Third Amended and Restated 2009 Incentive Compensation Plan.

“Contango Merger” means the merger of IE C Merger Sub Inc., a Delaware corporation, with and into Contango, with Contango surviving the merger as a direct wholly owned corporate subsidiary of the Company.

"Contango PSU Award" means each award of performance stock units (whether vested or unvested) granted under the Contango Incentive Plan that were outstanding immediately prior to the effective time of the Contango Merger.

“CWA” means the Federal Water Pollution Control Act, as amended, and the rules and regulations promulgated thereunder.

“Decontrol Act” means the Natural Gas Wellhead Decontrol Act, effective January 1, 1993.

“DJ” means Denver Julesburg.

“Dodd-Frank” means the Dodd-Frank Wall Street Reform and Consumer Protection Act.

“DOI” means the U.S. Department of the Interior.

“DOT” means the U.S. Department of Transportation.

“EHS” means Environment, Health and Safety.

“EIGF II” means Energy Income and Growth Fund II, formed in 2018 as a KKR energy investment fund.

“EPA” means the U.S. Environmental Protection Agency.

“Equity Incentive Plan” means the Crescent Energy Company 2021 Equity Incentive Plan.

“ESA” means the federal Endangered Species Act, as amended, and the rules and regulations promulgated thereunder.

“ESG” means Environmental, Social and Governance.

“Exchange Act” means the Securities Exchange Act of 1934, as amended, and the rules and regulations promulgated thereunder.

“Exchanges” means, collectively, the December 2020 Exchange and the April 2021 Exchange.

“FERC” means the Federal Energy Regulatory Commission.

“FRA” means the Federal Railroad Administration.

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“FTC” means the Federal Trade Commission.

“FWS” means the U.S. Fish and Wildlife Service.

“GAAP” means U.S. generally accepted accounting principles.

“GHGs” means greenhouse gases.

“Independence” means Independence Energy LLC, a Delaware limited liability company.

“IRS” means the United States Internal Revenue Service.

“IT” means Information Technology.

“KKR” means the Manager and its affiliates, which includes the Preferred Stockholder and EIGF II.

“KKR Funds” means EIGF II and/or other KKR funds.

“KKR Group” means KKR & Co. Inc and its subsidiaries.

“LCFS” means low carbon fuel standard.

“LIBOR” means the London Interbank Offer Rate.

“M" means in thousands.

"MM" means in millions.

“Management Agreement” means the management agreement, dated as of December 7, 2021, by and between the Company and the Manager, whereby the Manager manages the business and operations of the Company and its subsidiaries and provides the executive management team for the benefit of the Company and its subsidiaries.

“Manager” means KKR Energy Assets Manager LLC, a Delaware limited liability company.

"Manager Incentive Plan” means the Crescent Energy Company 2021 Manager Incentive Plan.

“MBTA” means the Migratory Bird Treaty Act, as amended, and the rules and regulations promulgated thereunder.

“MBbls” means thousand barrels of oil or NGL.

“MBoe” means thousand Boe.

“Mcf” means thousand cubic feet of natural gas.

“MMBoe” means million Boe.

“MMBtu” means million British thermal units.

“MMcf” means million cubic feet of natural gas.

“NAAQS” means National Ambient Air Quality Standard.

“NEPA” means the National Environmental Policy Act, as amended, and the rules and regulations promulgated thereunder.

"Non-Economic Series I Preferred Stock” means the 1,000 shares of the Company's Preferred Stock that are designated as “Series I Preferred Stock,” which will have no economic rights.

“NGA” means the Natural Gas Act of 1938 and the rules and regulations promulgated thereunder.

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“NGFS” means the Network for Greening the Financial System.

“NGPA” means the Natural Gas Policy Act of 1978, as amended, and the rules and regulations promulgated thereunder.

“NWPR” means the Navigable Waters Protection Rule, as amended.

“NYMEX” means the New York Mercantile Exchange.

“NYMEX Henry Hub” or “Henry Hub Index” means the major exchange for pricing natural gas futures on the New York Mercantile Exchange.

“NYSE” means the New York Stock Exchange.

“oil equivalent” means natural gas is converted to a crude oil equivalent at the ratio of six Mcf of natural gas to one Boe.

“OPA” means the federal Oil Pollution Act of 1990, as amended, and the rules and regulations promulgated thereunder.

“OpCo” means IE OpCo LLC, a Delaware limited liability company.

“OpCo LLC Agreement” means the Amended and Restated Limited Liability Company Agreement of OpCo.

“OpCo Units” means the units representing economic limited liability company interests in OpCo.

“OPEC” means the Organization of Petroleum Exporting Countries.

“OSHA” means the federal Occupational Safety and Health Act, as amended, and the rules and regulations promulgated thereunder.

“PDP” means proved developed producing.

“PHMSA” means the Pipeline and Hazardous Materials Safety Administration.

“Preferred Stockholder” means Independence Energy Aggregator LP, the initial holder of the Non-Economic Series I Preferred Stock, and, as applicable, any successor thereto.

“PT Independence” means PT Independence Energy Holdings, LLC, a Delaware limited liability company.

“PUD” means proved undeveloped reserve.

“PV-0 value” means the present value of estimated future oil and gas revenues, net of estimated direct expenses, discounted at an annual discount rate of 0% used to estimate the present value of proved oil and natural gas reserves.

“PV-10 value” means the present value of estimated future oil and gas revenues, net of estimated direct expenses, discounted at an annual discount rate of 10% used to estimate the present value of proved oil and natural gas reserves.

“RCRA” means the federal Resource Conservation and Recovery Act, as amended, and the rules and regulations promulgated thereunder.

“Redemption Right” means the right of a holder of OpCo Units (other than a member of the Company Group) pursuant to the OpCo LLC Agreement to cause OpCo to redeem all or a portion of its OpCo Units for, at the election of OpCo, (a) shares of Class A Common Stock at a redemption ratio of one share of Class A Common Stock for each OpCo Unit redeemed, or (b) an approximately equivalent amount of cash as determined pursuant to the terms of the OpCo LLC Agreement. In connection with such redemption, a corresponding number of shares of Class B Common Stock will be cancelled.

“Revolving Credit Facility” means the credit agreement, by and between Independence Energy Finance LLC (n/k/a Crescent Energy Finance LLC), Wells Fargo Bank, N.A., as administrative agent, and the lender parties thereto.

“SDWA” means the federal Safe Drinking Water Act, as amended, and the rules and regulations promulgated thereunder.

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“SEC” means the United States Securities and Exchange Commission.

“SEC pricing” means the unweighted average first-day-of-the-month commodity price for crude oil or natural gas for the period beginning January 1, 2021 and ending December 1, 2021, adjusted by lease for market differentials (quality, transportation, fees, energy content, and regional price differentials). The SEC provides a complete definition of prices in “Modernization of Oil and Gas Reporting” (Final Rule, Release Nos. 33-8995; 34-59192).

“Securities Act” means the Securities Act of 1933, as amended, and the rules and regulations promulgated thereunder.

"Senior Notes" means the 7.250% senior notes due 2026 issued by Independence Energy Finance LLC (n/k/a Crescent Energy Finance LLC) on May 6, 2021.

“Titan” means Titan Energy Holdings, LLC (f/k/a Liberty Energy LLC).

“Titan Acquisition” means the acquisition by Independence (n/k/a Crescent) of Titan.

“Transaction Agreement” means that certain Transaction Agreement, dated as of June 7, 2021, by and among Contango, Independence, the Company, OpCo, IE C Merger Sub Inc., a Delaware corporation, and IE L Merger Sub LLC, a Delaware limited liability company.

“Merger Transactions” means the transactions contemplated by the Transaction Agreement, which include the merger of Independence with and into OpCo, the Contango Merger, the subsequent merger of Contango with and into IE L Merger Sub LLC, with L Merger Sub surviving the merger as a wholly owned subsidiary of the Company, which we describe as the “Merger”, and the subsequent contribution of such surviving subsidiary by the Company to OpCo.

“TRC” means the Texas Railroad Commission.

“UIC” means the Underground Injection Control program administered by the SDWA.

“WTI” or “West Texas Intermediate” means a light crude oil produced in the United States with an American Petroleum Institute gravity of approximately 38 to 40 and the sulfur content is approximately 0.3%.

Part I

Except as noted in this Annual Report, we refer to Crescent Energy Company as "Crescent", "we", "us", "our", or "the Company." This Annual Report includes certain terms commonly used in the oil and natural gas industry, which are defined above in the "Glossary of Terms."

Items 1 and 2. Business and Properties

Business Overview

We are a well-capitalized U.S. independent energy company with a portfolio of assets in key proven basins across the lower 48 states and substantial cash flow supported by a predictable base of production. Our core leadership team is a group of experienced investment, financial and industry professionals who continue to execute on the strategy we have employed since 2011. Our mission is to invest in energy assets and deliver better returns, operations and stewardship. We seek to deliver attractive risk-adjusted investment returns and predictable cash flows across cycles by employing our differentiated approach to investing in the oil and gas industry. Our approach includes a cash flow-based investment mandate with a focus on operated working interests, and is complemented by non-operated working interests, mineral and royalty interests, and midstream infrastructure, as well as an active risk management strategy. Our Class A Common Stock trades on the New York Stock Exchange (“NYSE”) under the symbol “CRGY.”

We pursue our strategy through the production, development and acquisition of oil, natural gas and NGL reserves. Our free cash flow-focused portfolio includes a balanced set of oil and natural gas assets in proven onshore U.S. basins with substantial existing production, a low decline rate and an acreage position that is 98% held by production. As a result of this low decline profile, which averages 11% over the first 5 years and is expected to be 17% in 2022 based on forecasts used in our reserve reports, we require relatively minimal capital expenditures to maintain our production and cash flows. We have a robust

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inventory of attractive operated undeveloped locations, providing for optimal flexibility to maintain or grow our production base. Our portfolio is enhanced and complemented by our additional interests in mineral acreage and midstream infrastructure, which provide operational benefits and enhance our cash flow margins.

We have built a substantial portfolio of reserves, production, cash flow and reinvestment opportunities. Our portfolio of assets:

•at December 31, 2021 consisted of 531.6 net MMBoe of proved reserves, of which approximately 54% were liquids, reflecting $5.0 billion in net proved Standardized Measure and $5.2 billion and $4.3 billion in net proved and net proved developed ("PD") present value discounted at a 10% discount rate;

•during the year ended December 31, 2021 produced 94 net MBoe/d, including 116 net MBoe/d for the month ended December 31, 2021;

•during the year ended December 31, 2021, generated a $432.2 million net loss, $520.1 million of Adjusted EBITDAX and $276.7 million of levered free cash flow; and

•at December 31, 2021 had 1,528 gross (685 net) undrilled locations, including 567 gross (450 net) operated drilling locations. Of our total 685 net locations, 159 net locations are identified as PUD drilling locations. In total, our drilling locations represent an aggregate of over $3.5 billion of reinvestment potential, of which $0.9 billion is attributable to PUD drilling locations.

The results above include only 25 days of impact for the assets acquired in the Merger Transactions.

See “Non-GAAP financial measures” and "Results of Operations" in Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations for definitions of Adjusted EBITDAX and levered free cash flow and reconciliations to the nearest comparable GAAP metric.

The following diagram displays our simplified ownership structure:

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Merger Transactions

On December 7, 2021, we completed the Merger Transactions, pursuant to which Contango’s business combined with Independence's business under a new publicly traded holding company named "Crescent Energy Company." Beginning on December 8, 2021, our Class A Common Stock has been listed on the NYSE and trades under the symbol “CRGY.” Our company is structured as an “Up-C.” Former Contango shareholders now own shares of our Class A Common Stock, which has both voting and economic rights with respect to our company. The former owners of Independence now own economic, non-voting limited liability company interests in OpCo (“OpCo Units”) and corresponding shares of Class B common stock (“Class B Common Stock” and, together with Class A Common Stock, “Common Stock”) of our company, which have voting (but no economic) rights with respect to us. We are a holding company, our sole material asset consists of OpCo Units. We are the sole managing member of OpCo and indirect sole managing member of Crescent Energy Finance LLC, a Delaware limited liability company ("Crescent Finance"). We are therefore responsible for all operational, management and administrative decisions relating to Crescent Finance's business and consolidate the financial results of Crescent Finance and its subsidiaries.

Free cash flow-focused portfolio

Our asset base, which includes oil and natural gas assets in key proven onshore U.S. basins such as the Eagle Ford, Rockies, Barnett, Permian, and Mid-Con, is composed of producing properties with substantial production and hedged cash flow that are complemented by an extensive inventory of reinvestment opportunities across our undeveloped acreage. While many of our peers have historically outspent their cash flows in pursuit of production growth and left themselves particularly vulnerable to declines in commodity prices, we have averaged a reinvestment rate of 45% of Adjusted EBITDAX since 2018.

Low-decline production base

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Our PDP reserves as of December 31, 2021 have estimated average five-year and ten-year annual decline rates of approximately 11% and 10%, respectively, and an estimated 2022 PDP decline rate of 17%, based on forecasts used in our reserve reports. As a result of this low decline profile, we require relatively minimal capital expenditures to maintain our production and cash flows. Our properties located in the Eagle Ford, Rockies, and Barnett represent approximately 78% of our PD reserves as of December 31, 2021, and provide us with diversification from both a regional location and commodity price perspective, which provides us certain downside protection as it relates to commodity-specific pressures, isolated infrastructure constraints or severe weather events. Our net proved standardized measure totaled $5.0 billion as of December 31, 2021. The table below illustrates the aggregate leasehold acreage positions, reserve volumes and weighted average decline profiles associated with our proved assets as of December 31, 2021.

	Net Acreage	Net Proved Reserves (1)	% Oil & Liquids (1)		Net PD Reserves (1)	Weighted Average Annual PDP Decline (2)				2021 Total Net Production (6)	Net Proved PV-10 (1)(3)		Net PD PV-10 (1)(3)
Operating Area						Five Year		Ten Year
	(M)	(MMBoe)			(MMBoe)					(MBoe)	(MM)		(MM)
Eagle Ford	143	136	79	%	84	13	%	11	%	9,404	$	1,954	$	1,307
Rockies (4)	243	147	52	%	143	10	%	10	%	10,982	1,319		1,250
Barnett	133	130	16	%	129	6	%	6	%	8,165	605		605
Permian	107	54	69	%	37	15	%	12	%	2,756	594		458
Mid-Con	365	40	67	%	40	11	%	10	%	313	413		411
Other (5)	37	25	71	%	26	17	%	12	%	2,625	274		274
Total	1,028	532	54	%	459	11	%	10	%	34,245	$	5,159	$	4,305

(1)Our reserves and present value (discounted at ten percent, or PV-10) were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For oil and NGL volumes, the average WTI posted price of $66.56 per barrel as of December 31, 2021, was adjusted for items such as gravity, quality, local conditions, gathering, transportation fees and distance from market. For natural gas volumes, the average Henry Hub Index spot price of $3.60 per MMBtu as of December 31, 2021, was similarly adjusted for items such as quality, local conditions, gathering, transportation fees and distance from market. All prices are held constant throughout the lives of the properties. The average adjusted product prices over the remaining lives of the properties are $64.84 per barrel of oil, $3.46 per Mcf of natural gas and $27.21 per barrel of NGLs.

(2)Reflects the estimated average annual decline rates of our PDP reserves as of December 31, 2021 for the five-year period ending January 31, 2027 and the ten-year period ending January 31, 2032, in each case based on the forecasts used in estimating our proved reserves.

(3)Reflects the net Proved and PD present values reflected in our proved reserve estimates as of December 31, 2021. PV-10 is not a financial measure prepared in accordance with GAAP. See “Oil, natural gas and NGL reserve data” for additional discussion.

(4)We have a contractual right to participate in 29 thousand net acres in the DJ Basin through an agreement with a large operator and will be entitled to receive our proportionate share of acreage in the future based on our participation in proposed wells.

(5)Includes working interest properties located in California as well as diversified minerals.

(6)Includes only 25 days of production for assets acquired in the Merger Transactions.

Attractive development opportunities

As of December 31, 2021, we have identified 1,528 gross (685 net) undrilled locations, including 567 gross (450 net) operated drilling locations. Of our total 685 net locations, 159 net locations are identified as PUD drilling locations as of December 31, 2021. The majority of these locations are on acreage that is held by production.

Eagle Ford. We have operated and non-operated Eagle Ford development opportunities with attractive return profiles in Dimmit, Frio, Atascosa, Zavala and Webb Counties, Texas. As of December 31, 2021, we have identified 890 gross (393 net) undrilled locations in the Eagle Ford, including 270 gross (259 net) operated drilling locations. Of our total 393 net locations, 123 net locations are reflected as PUDs.

Permian. We have operated and non-operated Permian development opportunities with attractive return profiles in Reeves, Ector and Pecos Counties, Texas targeting the Wolfcamp, Bone Spring and Spraberry formations. As of December 31, 2021,

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we have identified 326 gross (123 net) undrilled locations in the Permian, including 153 gross (88 net) operated drilling locations. Of our total 123 net locations, 18 net locations are reflected as PUDs.

Total identified drilling locations. The following table describes our net identified drilling locations and total reinvestment opportunity calculated based on the estimated net D&C expenditures by area, in each case, as of December 31, 2021.

	Total Net Identified Drilling Locations (1)	Operated Net Identified Drilling Locations (1)	Total Estimated Net D&C Expenditures
			(in millions)
Eagle Ford	393	259	$	2,166
Permian	123	88	842
Other (2)	169	103	587
Total	685	450	$	3,595

(1)Includes 123, 18 and 19 net PUD locations in the Eagle Ford, Permian and our other operating areas, respectively, with associated estimated net D&C expenditures of $766 million, $136 million and $21 million, respectively. Does not include minerals. For information regarding the assumptions underlying our identified reinvestment opportunities, see “—Drilling locations.”

(2)Includes drilling locations in the Rockies, Barnett and other areas.

In addition to our identified drilling locations listed in the table above, we have additional undeveloped locations under our mineral and royalty interests that, when developed by the oil and natural gas companies designated as the operators on such acreage, will provide cash flows unburdened by capital costs.

Our Relationship with the KKR Group

On December 7, 2021, in connection with the closing of the Merger Transactions, we entered into the Management Agreement with the Manager, that engages the Manager to provide certain management and investment advisory services to us and our subsidiaries. Our management team provides services to us pursuant to the Management Agreement.

The Manager is an indirect subsidiary of KKR & Co. Inc. (together with its subsidiaries, the “KKR Group”). The KKR Group is a leading global investment firm that offers alternative asset management as well as capital markets and insurance solutions.

Pursuant to the Management Agreement, the Manager has agreed to provide us with management services, including our full executive and corporate management teams, and other assistance, including with respect to strategic planning, risk management, identifying and screening potential acquisitions, identifying and analyzing ESG issues and providing such other assistance as we may require.

Through our integration with the KKR Group’s global platform, we believe that we benefit from: the power of the “KKR Brand;” KKR Capstone, which creates value by assisting with due diligence and identifying and delivering sustainable operational performance improvements within the KKR Group’s portfolio companies; KKR Global Macro and Asset Allocation, which assists with assessing the impact of macroeconomic factors on potential investments and helps identify market opportunities; KKR Capital Markets, which assists with optimizing the capital structure of investments and underwrites and arranges debt, equity and other forms of financing for both KKR portfolio companies and independent clients, and KKR Public Affairs, which, together with the KKR Global Institute, provides insight into public policy, government and regulatory affairs, including experience working with key stakeholders, such as labor unions, industry and trade associations and non-governmental organizations, and ESG issues and opportunities.

For additional information regarding our Management Agreement and our relationship with the KKR Group, see Part I, Item 1A. Risk Factors, "Risks related to our business and the oil and natural gas industry,"Through our Management Agreement, we depend on the KKR Group personnel to manage and operate our business, the loss of any of whom would materially and adversely affect future operations. Additionally, operational risks affecting the KKR Group, and our ability to work collaboratively with the KKR Group, including with respect to the allocation of corporate opportunities, may impact our business and have a material effect on our results of operations.

Management Agreement

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In connection with the Merger Transactions, we entered into a Management Agreement to engage the Manager to manage the strategy, assets and day-to-day business and affairs of us and our subsidiaries, subject at all times to applicable law, the further terms and conditions set forth in the Management Agreement and to the supervision of our Board of Directors. Pursuant to the Management Agreement, the Manager will provide us with our executive management team and will manage our day-to-day operations. Additionally, pursuant to the Management Agreement:

•Investment opportunities in upstream oil and gas assets will be presented to us with the total amount of the available investment allocated between us and EIGF II in good faith by the Manager on a pro rata basis subject to and taking into account available capital, applicable concentration limits, investment restrictions and other similar considerations. After all available investment capital within EIGF II has been fully deployed, the Manager shall ensure that at least 70% of any such investment amounts are allocated to us.

•From time to time, investment opportunities outside of upstream oil and gas assets may arise that are suitable for investment by us, on the one hand, and by and EIGF II (and any successor fund) or other KKR Funds, on the other that are (A) engaged in an investment strategy that is materially different from us (such as distressed debt or special situations investment vehicles) and (B) have pre-existing defined allocation rights pursuant to KKR’s allocation policies or contractual undertakings agreed with the investors in such other KKR Funds. In such cases, we may elect to co-invest alongside EIGF II and/or such other KKR Funds in such investments, in which case KKR will allocate such investment opportunities among us, on the one hand, and EIGF II and/or such other KKR Funds, on the other hand, in a manner consistent with the priority investment rights of such KKR Funds, taking into account such factors as KKR deems appropriate. We shall have no obligation to make any such co-investment.

•As consideration for the services rendered pursuant to the Management Agreement and the Manager’s overhead, including compensation of the executive management team, as of the closing date of the Merger Transactions, the Manager is entitled to receive:

(i) compensation from us equal to $13.5 million per annum (calculated based on our pro rata portion of $53.3 million (the “Management Compensation”) based on our relative ownership of OpCo), which is included in General and administrative expenses on our combined and consolidated statements of operations. As our business and assets expand, the Management Compensation will increase by an amount equal to 1.5% per annum of the net proceeds from all future issuances of primary equity securities by us (including in connection with acquisitions) and, in certain instances, OpCo; however, incremental management fees will not apply to secondary share offerings or the issuance of shares of our Class A Common Stock upon the redemption or exchange of OpCo Units.

We expect our ownership percentage of OpCo will increase over time through the exchange of OpCo Units into shares of our Class A Common Stock or the issuance of additional shares of Class A Common Stock. As this occurs, the portion of the Management Compensation borne by us will increase from $13.5 million up to, in the situation in which we own all of the interests in OpCo, the total Management Compensation. While only the portion borne by us impacts our combined and consolidated statements of operations, we include the full Management Compensation in the calculation of Adjusted EBITDAX and Levered Free Cash Flow (the delta between the Management Compensation and the amount borne by us is represented by “Certain-redeemable noncontrolling interest distributions made by OpCo related to the management fee”). We believe our Adjusted Cash General and Administrative Expense, which excludes noncash equity-based compensation and includes the Management Compensation, is in line with our peers on a per Boe basis.

(ii) a performance-based incentive grant pursuant to which the Manager is targeted to receive up to 10% of outstanding Class A Common Stock based on the achievement of certain performance-based measures (the "Incentive Compensation."). The Incentive Compensation consists of five tranches that may become earned during successive performance periods and will be settled over a five year period beginning after the end of the first performance period in 2024, and each tranche relates to a target number of shares of Class A Common Stock equal to 2% of the outstanding Class A Common Stock as of the time such tranche is settled. Performance goals are evaluated on absolute stock price performance and relative stock price performance versus a set of our peers and there is no vesting based solely on time. Based on the level of achievement with respect to the performance goals applicable to such tranche, the Manager is entitled to settlement of such tranche with respect to a number of shares of Class A Common Stock ranging from 0% to 4.8% of the outstanding Class A Common Stock at the time each tranche is settled so long as the Manager continuously provides services to us until the end of the performance period applicable to a tranche.

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(iii) reimbursement for the Manager's pro rata share (based on percentage of public ownership of us) of any documented costs or expenses incurred by the Manager on behalf of us (other than normal overhead expenses relating to the business or operations of the Manager). These costs and expenses include, among other things, costs of outside counsel, accountants and auditors, taxes, fees related to regulatory compliance, costs related to information technology services and other costs related to identifying, evaluating and structuring investments.

•The Management Agreement has an initial three-year term, with automatic three-year renewals thereafter.

•Upon the written notice to the Manager at least 180 days prior to the expiration of the initial term or any automatic renewal term, we may, without cause, decline to renew the Management Agreement upon the affirmative determination by at least two-thirds of our independent directors reasonably and in good faith that (1) there has been unsatisfactory long-term performance by the Manager that is materially detrimental to us and our subsidiaries taken as a whole or (2) the fees payable to the Manager, in the aggregate, are materially unfair and excessive compared to those that would be charged by a comparable asset manager managing assets comparable to our assets, subject to the Manager’s right to renegotiate the fees. In the event of such a termination, we shall pay the Manager a termination fee equal to three (3) times the sum of (i) the average annual Management Compensation and (ii) the average of the Incentive Compensation (but only with respect to the fully vested portion thereof as of the termination date), in each case earned by the Manager during the 24-month period immediately preceding the most recently completed calendar quarter prior to the termination.

Properties

Summary of our assets

Leasehold acreage

Our portfolio includes a variety of oil and natural gas assets throughout proven onshore U.S. basins, including in the Eagle Ford, Rockies, Barnett, Permian, and Mid-Con. In addition to this geographic diversity, we believe that our portfolio of leasehold acreage is enhanced and complemented by our additional interests in mineral acreage and midstream infrastructure. We had leasehold interests in an aggregate 1,029 thousand net acres as of December 31, 2021, 898 thousand on which we were designated as operator. We are responsible for our pro rata share of capital expenditures and lease operating expenses for the operated and non-operated working interests within our leasehold acreage based on our percentage working interest and we are entitled to revenues derived from such interest based on our net revenue interest, which generally equals our working interest in such property less any royalties and production payments and any overriding royalty and net profits interests burdening the property.

Mineral and royalty interests

In addition to our leasehold acreage, we own mineral and royalty interests. As of December 31, 2021, we owned mineral and royalty interests in 174 thousand gross acres and an overriding royalty interest in 117 thousand gross acres, both operated by large, well-capitalized oil and natural gas companies primarily in the Eagle Ford, Marcellus, Utica and Rockies. On our mineral acreage, all of which we have leased to other operators, we have typically retained a royalty interest, which is a cost-free percentage of production revenue that expires upon termination of the lease, at which time the entire mineral interest reverts to us. These interests entitle us to receive an average 5.4% royalty and 0.7% overriding royalty interest on all production from such acreage with no additional future capital or operating costs required.

Midstream infrastructure

Further, we own a 12.0% interest in the Springfield Gathering System in the Eagle Ford Shale in Dimmit, La Salle and Webb Counties of southeast Texas. The Springfield Gathering System is operated by Western Midstream Partners, LP (NYSE: WES) and includes both oil and gas gathering systems. We also own and operate the Howell Pipeline, a 125-mile, 16-inch carbon dioxide pipeline that stretches across central Wyoming. The Howell Pipeline provides CO2 supply to support enhanced oil recovery operations on our acreage located in the Salt Creek and Monell Fields, in addition to serving third-party customers in the area. Additionally, we own a 50% interest in a centralized production facility, referred to as the Hub, which is located just east of Erie, Colorado, and provides a single site for processing equipment for portions of our DJ asset. We have a 65.0% equity method investment in the Lost Creek Gathering System, a 158-mile, 20-inch natural gas pipeline in Wyoming. We also own interests in and operate three gas processing plants and several pipelines in Wyoming. Finally, we own a 66.7% interest and operate the Cherokee Water Gathering System, an approximately 200-mile produced water pipeline in Oklahoma. Our midstream assets provide services to our upstream assets and other customers.

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Our operating areas

Our operating areas include the Eagle Ford, Rockies, Barnett, Permian and Mid-Con. The below table describes the net acreage, net PDP wells, production and proved reserve amounts for each of our geographic areas for the year ended and as of December 31, 2021:

Geographic Area	Net Acreage	Net PDP Wells	2021 Production (3)	Proved Reserves
	(M)		(MBoe)	(MBoe)
Eagle Ford	143	666	9,404	136,175
Rockies (1)	243	1,239	10,982	146,584
Barnett	133	899	8,165	129,354
Permian	107	1,112	2,756	54,056
Mid-Con	365	1,372	313	40,146
Other Basins (2)	37	609	2,625	25,330

(1)We have a contractual right to participate in 29 thousand net acres in the DJ basin through an agreement with a large operator and will be entitled to receive our proportionate share of acreage in the future based on our participation in proposed wells.

(2)Includes working interest properties located in California as well as our minerals and royalty interests.

(3)Includes only 25 days of production for assets previously held by Contango acquired in the Merger Transactions.

Oil, natural gas and NGL reserve data

The following table summarizes our estimated net proved reserves as of December 31, 2021 based on an evaluation prepared in accordance with SEC Pricing, including the provisions of the SEC rule regarding reserve estimation regarding a historical twelve month pricing average applied prospectively.

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	As of December 31,
	2021 (1)		2020 (1)
Net Proved Reserves:
Oil (MBbls)	210,160		167,190
Natural gas (MMcf)	1,469,953		822,864
NGLs (MBbls)	76,493		55,324
Total Proved Reserves (MBoe)	531,645		359,658
Standardized Measure (millions) (2)	4,958		1,328
PV-0 (millions) (2)	$	9,391	$	2,598
PV-10 (millions) (2)	$	5,159	$	1,344
Net Proved Developed Reserves:
Oil (MBbls)	158,091		92,024
Natural gas (MMcf)	1,404,570		748,496
NGLs (MBbls)	66,402		44,307
Total Proved Developed Reserves (MBoe)	458,588		261,079
PV-0 (millions) (2)	$	7,495	$	1,658
PV-10 (millions) (2)	$	4,305	$	1,055
Net Proved Undeveloped Reserves:
Oil (MBbls)	52,069		75,166
Natural gas (MMcf)	65,383		74,368
NGLs (MBbls)	10,091		11,017
Total Proved Undeveloped Reserves (MBoe)	73,057		98,579
PV-0 (millions) (2)	$	1,896	$	941
PV-10 (millions) (2)	$	854	$	289

(1)Our reserves and present value (discounted at ten percent, or PV-10) were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For oil and NGL volumes, the average WTI posted price of $66.56 per barrel and $39.56 per barrel as of December 31, 2021 and 2020, was adjusted for items such as gravity, quality, local conditions, gathering, transportation fees and distance from market. For natural gas volumes, the average Henry Hub Index spot price of $3.60 per MMBtu and $1.99 per MMBtu as of December 31, 2021 and 2020, was similarly adjusted for items such as quality, local conditions, gathering, transportation fees and distance from market. All prices are held constant throughout the lives of the properties. The average adjusted product prices over the remaining lives of the properties are $64.84 per barrel of oil, $3.46 per Mcf of natural gas and $27.21 per barrel of NGLs as of December 31, 2021. The average adjusted product prices over the remaining lives of the properties were $37.67 per barrel of oil, $1.62 per Mcf of natural gas and $10.66 per barrel of NGLs as of December 31, 2020.

(2)Present value (discounted at PV-0 and PV-10) is not a financial measure calculated in accordance with GAAP because it does not include the effects of income taxes on future net revenues. None of PV-0, PV-10 and standardized measure represent an estimate of the fair market value of our oil and natural gas properties. Our PV-0 measurement does not provide a discount rate to estimated future cash flows. PV-0 therefore does not reflect the risk associated with future cash flow projections like PV-10 does. PV-0 should therefore only be evaluated in connection with an evaluation of our PV-10 and standardized measure of discounted future net cash flows. We believe that the presentation of PV-0 and PV-10 is relevant and useful to its investors as supplemental disclosure to the standardized measure of future net cash flows, or after tax amount, because it presents the discounted future net cash flows attributable to its reserves prior to taking into account future income taxes and its current tax structure. The PV-0 and PV-10 income tax amounts included in the net proved standardized measure but not included in PV-0 and PV-10 were $352.1 million and $200.5 million, respectively. We and others in our industry use PV-0 and PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. Investors should be cautioned that none of PV-0, PV-10 and standardized measure represent an estimate of the fair market value of our proved reserves.

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Preparation of reserve estimates

Our reserve estimates as of December 31, 2021 and 2020 are based on a combination of evaluations prepared or audited, as applicable, by the independent petroleum engineering firms of (a) Haas Petroleum Engineering Services, Inc., with respect to 34% of our total net proved reserves, (b) William M. Cobb and Associates, with respect to 24% of our total net proved reserves (c) Cawley, Gillespie & Associates, Inc. with respect to 23% of our total net proved reserves, and (d) Netherland, Sewell & Associates, Inc. with respect to 19% of our total net proved reserves, (collectively, the “Independent Reserve Engineers”), in each case in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC. Our Independent Reserve Engineers were selected for their historical experience and geographic expertise in engineering similar resources. Our reserve estimation process is a collaborative effort coordinated by the lead reservoir engineers at each of our operating subsidiaries, who are petroleum engineers with an average of 15 years of reservoir and operations experience per person. This process is overseen by our Director of Corporate Reserves, who has over 24 years of experience in the estimation and evaluation of petroleum reserves. Our technical staff uses historical information for our properties such as ownership interest, oil and natural gas production, well test data, commodity prices and operating and development costs to formulate our reserves estimates. The preparation of our proved reserve estimates is completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

•review and verification of historical production, cost and capital expenditures data;

•verification of property ownership by our land department;

•preparation of reserves estimates by our lead reservoir engineers;

•review by our management, including our Chief Executive Officer and Chief Financial Officer, of all significant reserve changes and all new proved undeveloped reserves additions; and

•no employee’s compensation is tied to the amount of reserves booked.

The technical persons responsible for preparing our reserves estimates at (a) Haas Petroleum Engineering & Associates, Inc. has over 20 years of industry experience; (b) William M. Cobb and Associates has over 40 years of experience in the estimation and evaluation of reserves; (c) Cawley, Gillespie & Associates, Inc. has over 29 years of experience in the estimation and evaluation of petroleum reserves; and (d) Netherland, Sewell & Associates, Inc. has over 20 years of experience in the estimation and evaluation of petroleum reserves.

Proved reserves are reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, we and the independent reserve engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps and available downhole and production data and well-test data.

Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of natural gas that are ultimately recovered. Estimates of economically recoverable natural gas and of future net cash flows are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. See "Part I, Item 1A. Risk Factors" appearing elsewhere in this Annual Report.

With respect to the Independent Reserve Engineers that performed an audit of our reserves, we provided to such Independent Reserve Engineers our public and internal engineering and geoscience technical data and analyses. Such Independent Reserve Engineers accepted without independently verifying the accuracy and completeness of the historical information and data furnished by us with respect to ownership interest, oil and natural gas production, well test data, commodity prices, operating and development costs and any agreements relating to current and future operations of the properties and sales of production. However, if in the course of its evaluations something came to their attention that brought into question the validity or

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sufficiency of any such information or data, the Independent Reserve Engineers did not rely on such information or data until it had satisfactorily resolved their questions relating thereto or had independently verified such information or data. In the course of their evaluations, the Independent Reserve Engineers prepared, for all of the audited properties, their own estimates of our reserves. The Independent Reserve Engineers reviewed their audit differences with us, and, as necessary, held meetings with us to review additional reserves work performed by our technical teams and any updated performance data related to the reserve differences. Such data was incorporated, as appropriate, by both parties into the reserve estimates. The Independent Reserve Engineers’ estimates, including any adjustments resulting from additional data, of those reserves and did not differ from our estimates by more than 10% in the aggregate. When such differences did not exceed 10% in the aggregate and the Independent Reserve Engineers was satisfied that the reserves were reasonable and that its audit objectives had been met, the Independent Reserve Engineers issued an unqualified audit opinion.

Proved undeveloped reserves (PUDs)

Our PUDs will be converted from undeveloped to developed as the applicable wells have been drilled or completed and have minimal capital remaining to bring the well onto production. The changes to our PUDs that occurred during the year are summarized in the table below:

	2021
	(MBoe)
Balance at December 31, 2020	98,579
Purchases of reserves in place	1,427
Extensions and discoveries	8,588
Revisions of previous estimates	(21,115)
Sales of reserves in place	(3,190)
Transfers to proved developed	(11,232)
Balance at December 31, 2021	73,057

Purchases of reserves in place of 1.4 MMBoe during the year ended December 31, 2021 primarily relate to PUD locations added as part of the Contango Acquisition. Revisions of previous estimates during the year ended December 31, 2021 were due to the removal of certain locations that are no longer part of our five-year consolidated development plan following the Merger Transactions. Additionally, during the year ended December 31, 2021, we spent $86 million to convert 11.2 MMBoe to proved developed reserves.

All of such reserves are scheduled to be developed within five years from the date such locations were initially disclosed as PUD reserves. Our PUD reserves represent only reserves that are scheduled, based on such plan, to be developed within five years from the date such locations were initially disclosed as PUDs; however, our five-year development plan may not contemplate a uniform (i.e., 20% per year) conversion of PUD reserves. At December 31, 2021, we estimate that our future development costs relating to the development of PUD reserves are $311 million in 2022, $299 million in 2023 and $176 million in 2024, $74 million in 2025 and $60 million in 2026. We believe cash flow from operations and availability under the Revolving Credit Facility will be sufficient to cover these estimated future development costs.

Drilling locations

The following table provides a summary of gross and net operated and non-operated drilling locations by area as of December 31, 2021:

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	Operated (1)		Non-Operated (1)		Total WI (1)		Minerals (2)
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Total Locations by Area
Eagle Ford (3)	270	259	620	135	890	393	1,249	9
Rockies (4)	99	73	167	66	266	139	498	6
Barnett (5)	40	24	—	—	40	24	—	—
Permian (6)	152	88	174	35	326	123	—	—
Mid-Con (7)	1	1	—	—	1	1	—	—
Other (8)	5	5	—	—	5	5	2,550	21
Total	567	450	961	236	1,528	685	4,297	36

(1)We estimate that the significant majority of our identified drilling locations are economic at oil and natural gas prices of $60/Bbl oil and $3.00/MMBtu gas.

(2)Net mineral locations defined as NRI locations.

(3)Includes 219 gross (123 net) total PUD locations and assumes average well spacing of 720 feet.

(4)Includes 22 gross (18 net) total PUD locations and assumes average well spacing of 848 feet.

(5)Includes zero PUD locations and assumes well spacing of 500 feet.

(6)Includes 88 gross (18 net) total PUD locations and assumes average well spacing of 887 feet.

(7)Includes 1 gross and net total PUD locations.

(8)Includes working interest properties located in California as well as diversified mineral and royalty interests.

We have estimated our drilling locations based on well spacing assumptions and upon the evaluation of our drilling results and those of other operators in our area, combined with our interpretation of available geologic and engineering data. The drilling locations that we actually drill will depend on the availability of capital, regulatory approvals, commodity prices, costs, actual drilling results and other factors. Any drilling activities we are able to conduct on these identified locations may not be successful and may not result in additional proved reserves. Further, to the extent the drilling locations are associated with acreage that expires, we would lose our right to develop the related locations.

Oil, natural gas and NGL production prices and operating costs

Production and price history

The following table sets forth production, price and cost data for the years ended December 31, 2021, 2020, and 2019.

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	Year Ended December 31,
	2021		2020		2019
Net Production:
Eagle Ford:
Oil (MBbls)	5,107		6,964		8,001
Natural gas (MMcf)	14,871		15,556		14,998
NGLs (MBbls)	1,818		2,309		2,796
Total (MBoe)	9,404		11,866		13,297
Average daily production (MBoe/d)	26		32		36
Rockies:
Oil (MBbls)	6,088		4,959		4,504
Natural gas (MMcf)	17,560		7,513		61
NGLs (MBbls)	1,968		764		41
Total (MBoe)	10,982		6,975		4,555
Average daily production (MBoe/d)	30		19		12
Barnett:
Oil (MBbls)	11		16		19
Natural gas (MMcf)	40,823		47,032		53,463
NGLs (MBbls)	1,350		1,565		1,983
Total (MBoe)	8,165		9,419		10,913
Average daily production (MBoe/d)	22		26		30
Total:
Oil (MBbls)	13,237		13,132		13,752
Natural gas (MMcf)	89,455		78,541		73,747
NGLs (MBbls)	6,099		5,078		5,188
Total (MBoe)	34,245		31,300		31,232
Average daily production (MBoe/d)	94		86		86
Average Realized Prices (before effects of derivatives):
Eagle Ford:
Oil (per Bbl)	$	65.93	$	35.92	$	57.60
Natural gas (per Mcf)	$	5.35	$	2.11	$	2.73
NGLs (per Bbl)	$	32.01	$	15.15	$	19.29
Rockies:
Oil (per Bbl)	$	66.91	$	39.12	$	55.81
Natural gas (per Mcf)	$	4.44	$	3.11	$	1.06
NGLs (per Bbl)	$	33.20	$	17.03	$	21.47
Barnett:
Oil (per Bbl)	$	61.86	$	33.99	$	53.41
Natural gas (per Mcf)	$	3.47	$	1.70	$	2.29
NGLs (per Bbl)	$	24.00	$	9.79	$	13.13
Total:
Oil (per Bbl)	$	66.71	$	37.45	$	57.14
Natural gas (per Mcf)	$	3.96	$	1.90	$	2.35
NGLs (per Bbl)	$	30.42	$	13.77	$	16.67
Average Operating Costs per Boe:
Eagle Ford	$	18.79	$	16.55	$	16.77
Rockies	23.98		23.99		39.62
Barnett	10.17		8.46		8.82
Total	$	17.41	$	15.39	$	17.17

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Wells

The following table sets forth information regarding our proved developed producing wells as of December 31, 2021:

	Working Interest Assets				Mineral and Royalty Interests
	Gross	Net	Average Working Interest		Gross	Net	Average Net Revenue Interest
Natural gas	3,700	1,645	44	%	1,384	34	2	%
Oil	8,213	4,252	52	%	2,207	35	2	%
Total	11,913	5,897	50	%	3,591	69	2	%

Leasehold acreage

The following table sets forth certain information regarding the total developed and undeveloped acreage in which we owned an interest as of December 31, 2021.

	Gross	Net
Developed Acres	1,969,914	930,154
Undeveloped Acres	223,358	98,586
Total Acres (1)	2,193,272	1,028,740
Royalty Acres (2)	173,593	55,471

(1)We have a contractual right to participate in 28,768 net acres in the DJ Basin through an agreement with a large operator and will be entitled to receive our proportionate share of acreage in the future based on our participation in proposed wells.

(2)Royalty acres excludes our overriding royalty interest in 117,000 gross acres.

Undeveloped acreage expirations

The following table sets forth the number of total net undeveloped acres as of December 31, 2021 that will expire in 2022, 2023, 2024 and 2025 unless production is established within the spacing units covering the acreage prior to the expiration dates or unless such leasehold rights are extended or renewed.

	2022	2023	2024	2025
Net undeveloped acres	6,960	1	229	320

The leases comprising the acreage that is subject to expiration as set forth in the table above will generally expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which case the lease will remain in effect until the cessation of production. Upon expiration of the primary term, we will lose our interests in the associated acreage unless fully held by production, maintained through our delivery of a lease extension payment or, in the case of many of our leases, we utilize the “continuous development clause” that permits us to continue to hold such acreage if we initiate additional development activities within 120-180 days after the completion of the last well drilled on such lease. Thereafter, the lease remains held under the continuous development clause so long as we undertake additional development activities every 120 to 180 days or until the entire lease is held by production. There can be no assurances as to our ability to maintain such acreage. For more information, see "Part I, Item 1A. Risk Factors" appearing elsewhere in this Annual Report.

Drilling and other exploration and development activities

The table below sets forth the results of our operated drilling activities for the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce, or

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are capable of producing, commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return. Dry wells are those that prove to be incapable of producing hydrocarbons in sufficient quantities to justify completion.

	Year Ended December 31,
	2021		2020		2019
	Gross	Net	Gross	Net	Gross	Net
Operated Development Wells:
Productive	2	1.9	23	15.3	32	32.0
Dry holes	—	—	—	—	—	—
Total Development	2	1.9	23	15.3	32	32.0
Operated Exploratory Wells:
Productive	—	—	—	—	—	—
Dry holes	—	—	—	—	—	—
Total Exploratory	—	—	—	—	—	—
Total Operated Wells:
Productive	2	1.9	23	15.3	32	32.0
Dry holes	—	—	—	—	—	—
Total	2	1.9	23	15.3	32	32.0

As of December 31, 2021, we were not a party to any long-term drilling rig contracts. The following table provides our wells in progress, as well as the various stages of such progress, at December 31, 2021.

	Gross	Net
Well Status:
Drilling	6	5.7
Waiting on completion	4	3.8
Being completed, not producing	9	6.7

Delivery commitments

We are party to various long-term agreements that require us to physically deliver crude oil and natural gas. These delivery commitments require us to deliver 15.9 MMBoe in 2022 and 37.1 MMBoe thereafter. These commitments are contracted gathering arrangements that require delivery of a fixed and determinable quantity of crude oil, natural gas, or NGLs in the future. We believe that our current production and reserves are sufficient to satisfy the majority of these commitments and alternatively we could purchase sufficient volumes of oil, natural gas and NGL in the market at prevailing index-related prices to satisfy the commitments. We incurred shortfalls related to some of our gathering and transportation commitments and as a result paid $5.8 million, $14.5 million (including the termination of a midstream contract) and $1.9 million for the years ended December 31, 2021, 2020 and 2019, respectively.

Marketing and customers

Production from our oil and natural gas properties is marketed using methods that are consistent with industry practices. Sales prices for oil and natural gas production, including natural gas with recoverable NGLs, are negotiated based on factors normally considered in the industry, such as an index or spot price, price regulations, distance from the well to the pipeline, commodity quality and prevailing supply and demand conditions. In areas where there is no practical or commercial access to pipelines, oil is transported to storage facilities by truck. Our marketing of oil and natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted.

During the years ended December 31, 2021, 2020 and 2019, we sold oil and natural gas production representing 10% or more of total revenues to the following purchasers:

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	Year Ended December 31,
	2021	2020	2019
SN EF Maverick, LLC	*	15.5%	20.0%
Eighty Eight Oil	*	11.7%	*
Shell Trading US Company	18.3%	10.4%	*
Cokinos Energy Corporation	*	*	18.1%
BP Products North America	*	*	13.1%

*Purchaser did not account for greater than 10% of revenue for the year.

While the loss of a significant purchaser could result in a temporary interruption in sales of, or a lower price for, our production, we believe that the loss of any such purchasers would not have a material adverse effect on our operations because there are other purchasers in our producing regions.

We have entered into certain oil and natural gas transportation and gathering agreements with various pipeline carriers. Under these agreements, we are obligated to ship minimum daily quantities or pay for any deficiencies at a specified rate. We are also obligated under certain of these arrangements to pay a demand charge for firm capacity rights on pipeline systems regardless of the amount of pipeline capacity that we utilize. If we do not utilize the capacity, we can release it to others, thus reducing our potential liability.

Competition

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil or natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in evaluating and bidding for oil and natural gas properties.

There is also competition between oil and natural gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments of the United States and the jurisdictions in which we operate. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of developing oil or natural gas and may prevent or delay the commencement or continuation of a given operation. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position.

Seasonality of business

Generally, demand for oil, natural gas and NGL decreases during the spring and fall months and increases during the summer and winter months. However, certain natural gas and NGL markets utilize storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. In addition, seasonal anomalies such as mild winters or mild summers can have a significant impact on prices. These seasonal anomalies can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages, increased costs or delay operations.

Title to properties

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties in connection with acquisition of leasehold acreage. At such time as we determine to conduct drilling operations on those

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properties, we conduct a thorough title examination and perform curative work with respect to significant defects prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry.

Prior to completing an acquisition of producing leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion, obtain an updated title review or opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.

We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this Annual Report.

Human Capital Measures

Employees

We manage our operations through (i) management and corporate-level services provided by the Manager and (ii) asset-level services and operations provided by our approximately 700 employees that dedicate all or substantially all of their time to our business. We hire independent contractors on an as-needed basis. We have no collective bargaining agreements with our employees. We believe that our employee relationships are satisfactory.

Safety

EHS managers at our operations are responsible for safety program management and strive to reinforce safety culture at each operating location. Workplace safety procedures and programs include confined space entry, emergency response, fall protection, hearing conservation, hot work, hydrogen sulfide, incident reporting and investigation, personal protective equipment and spill prevention. Safety performance is tracked on a monthly basis across operations and incident reporting and corrective actions guide safety program improvements.

Recruitment, development and training

We foster an entrepreneurial culture where open communication is encouraged, the views of our employees are heard and the results of their efforts are recognized. We implement an inclusive and dynamic recruiting process that utilizes online recruiting platforms, referrals and professional recruiters. We foster the growth and professional development of our employees through the use of a robust performance review process, which includes the creation of performance development goals and plans to achieve those goals in order to help our employees reach their full potential.

Health and welfare benefits

We retain employees by offering competitive wages and generous benefits that are designed to meet the varied and evolving needs of a diverse workforce. We provide employees with the ability to participate in health and welfare plans, including medical, dental, life and short-term and long-term disability insurance plans. In response to the COVID–19 pandemic, we increased safety measures and protocols for those employees choosing to report to the office.

Community & social engagement

We are committed to supporting and giving back to the communities in which we operate and live. We recognize the link between local communities, the success of our employees and ultimately the success of our business.

Legislative and regulatory environment

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Our oil, natural gas and NGL exploration, development, production and related operations and activities are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with such rules and regulations can result in administrative, civil or criminal penalties, compulsory remediation and imposition of natural resource damages or other liabilities. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such requirements. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, we believe these obligations generally do not impact us differently or to any greater or lesser extent than they affect other operators in the oil and natural gas industry with similar operations and types, quantities and locations of production.

Regulation of production

In many states oil and natural gas companies are generally required to obtain permits for drilling operations, provide drilling bonds, file reports concerning operations and meet other requirements related to the exploration, development and production of oil, natural gas and NGL. Such states also have statutes and regulations addressing conservation matters, including provisions for unitization or pooling of oil and natural gas interests, rights and properties, the surface use and restoration of properties upon which wells are drilled and disposal of water produced or used in the D&C process. These regulations include the establishment of maximum rates of production from oil and natural gas wells, rules as to the spacing, plugging and abandoning of such wells, restrictions on venting or flaring oil and natural gas and requirements regarding the ratability of production, as well as rules governing the surface use and restoration of properties upon which wells are drilled.

These laws and regulations may limit the amount of oil, natural gas and NGL that can be produced from wells in which we own an interest and may limit the number of wells, the locations in which wells can be drilled or the method of drilling wells. Additionally, the procedures that must be followed under these laws and regulations may result in delays in obtaining permits and approvals necessary for our operations and therefore our expected timing of drilling, completion and production may be negatively impacted. These regulations apply to us directly as the operator of our leasehold. The failure to comply with these rules and regulations can result in substantial penalties.

Regulation of sales and transportation of liquids

Sales of condensate and NGLs are not currently regulated and are made at negotiated prices. Nevertheless, the U.S. Congress could reenact price controls in the future.

Our sales of NGLs are affected by the availability, terms and cost of transportation. The transportation of NGLs in common carrier pipelines is also subject to rate and access regulation. FERC regulates interstate oil, NGL and other liquid pipeline transportation rates under the Interstate Commerce Act. In general, interstate liquids pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances.

Intrastate liquids pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate liquids pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate liquids pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates and regulations regarding access are equally applicable to all comparable shippers, we believe that the regulation of liquids transportation will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

Regulation of transportation and sales of oil and natural gas

Historically, the transportation and sale for resale of oil and natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, the U.S. Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA, and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed controls affecting wellhead sales of natural gas effective January 1, 1993. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the NGA, and by regulations and orders promulgated under the NGA by FERC. In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by the U.S. Congress and by FERC regulations.

The EP Act of 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, the EP Act of 2005 amends the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to

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engage in prohibited behavior to be prescribed by FERC. The EP Act of 2005 also provided FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and increased FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000 per violation per day. In January 2022, the maximum penalty increased to $1,388,496 per violation per day to account for inflation. The civil penalty provisions are applicable to entities that engage in the sale and transportation of natural gas for resale in interstate commerce.

On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-market manipulation provision of the EP Act of 2005, and subsequently denied rehearing. The rules make it unlawful: (i) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (ii) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (iii) to engage in any act or practice that operates as a fraud or deceit upon any person. The anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704, described below. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.

On December 26, 2007, FERC issued Order 704, a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing. Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year, including natural gas producers, gatherers and marketers, are now required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.

Gathering service, which occurs upstream of jurisdictional transportation services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transportation function, FERC’s determinations as to the classification of facilities are done on a case-by-case basis. To the extent that FERC issues an order that reclassifies certain jurisdictional transportation facilities as non-jurisdictional gathering facilities, and depending on the scope of that decision, our costs of getting gas to point of sale locations may increase. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transportation services and federally unregulated gathering services could be the subject of ongoing litigation, so the classification and regulation of our gathering facilities could be subject to change based on future determinations by FERC, the courts or the U.S. Congress. State regulation of natural gas gathering facilities generally includes various occupational safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical and financial sales of these energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by FERC under the EP Act of 2005 and under the Commodity Exchange Act (“CEA”), and regulations promulgated thereunder enforced by the CFTC. The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity as well as certain disruptive trading practices. The CFTC also has statutory authority to seek civil penalties of up to the greater of approximately $1,227,202 (adjusted annually for inflation) or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the CEA. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

Further, the Federal Trade Commission (“FTC”) has the authority under the Federal Trade Commission Act (“FTCA”) and the Energy Independence and Security Act of 2007 (“EISA”) to regulate wholesale petroleum markets. The FTC has adopted anti-market manipulation rules, including prohibiting fraud and deceit in connection with the purchase or sale of certain petroleum products, and prohibiting omissions of material information which distort or are likely to distort market conditions for such

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products. In addition to other enforcement powers it has under the FTCA, the FTC can sue violators under EISA and request that a court impose fines of approximately $1,323,791 (adjusted annually for inflation) per violation per day.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. As such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Changes in law and to FERC or state policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate and intrastate pipelines, and we cannot predict what future action FERC or state regulatory bodies will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers and marketers with which we compete.

Regulation of environmental and occupational safety and health matters general

Our operations are subject to numerous stringent federal, regional, state and local statutes and regulations governing environmental protection, occupational safety and health, and the release, discharge or disposal of materials into the environment, some of which carry substantial administrative, civil and criminal penalties for failure to comply. Applicable U.S. federal environmental laws include, but are not limited to, RCRA, CERCLA, OPA, the CWA, the CAA, the SDWA, the ESA, and the MBTA. In addition, state and local laws and regulations set forth specific standards for drilling wells, the maintenance of bonding requirements in order to drill or operate wells, the spacing and location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, the prevention and cleanup of pollutants, and other matters. These laws and regulations may, among other things, require the acquisition of permits to conduct exploration, drilling, and production operations; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines; govern the sourcing and disposal of water used in the D&C process; limit or prohibit construction or drilling activities in sensitive areas such as wilderness, wetlands, critical habitat of protected species, frontier and other protected areas; require investigatory or remedial actions to prevent or mitigate pollution conditions caused by our operations; impose obligations to reclaim and abandon well sites and pits; establish specific safety and health criteria addressing worker protection; and impose substantial liabilities for pollution resulting from operations or failure to comply with regulatory filings. Additionally, the U.S. Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in delay or more stringent and costly permitting, waste handling, disposal and clean-up requirements for the oil and gas industry could have a significant impact on our operating costs. Although environmental obligations have not historically had a material adverse impact on the results of our operations or financial condition, there can be no assurance that future developments, such as increasingly stringent environmental laws or enforcement thereof, will not cause us to incur material environmental liabilities or costs.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties, loss of permits or leases, the imposition of investigatory or remedial obligations and the issuance of orders enjoining some or all of our operations in affected areas. These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. It is possible that, over time, environmental regulation could evolve to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or reinterpretation of enforcement policies that result in more stringent and costly well drilling, construction, completion or water management activities or waste handling, storage, transport, disposal, or remediation requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our results of operations and financial position. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot be sure that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. Although we believe that we are in substantial compliance with applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on our business, there can be no assurance that this will continue in the future.

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The following is a summary of the more significant existing environmental and occupational health and safety laws and regulations, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on its capital expenditures, results of operations or financial position.

Hazardous substances and wastes

CERCLA, also known as the “Superfund” law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct, on certain classes of persons with respect to the release of a “hazardous substance” into the environment. These classes of persons, or, as termed in CERCLA, potentially responsible parties, include the current and past owners or operators of a disposal site or site where the release occurred and anyone who disposed or arranged for the disposal of the hazardous substances found at such sites. Under CERCLA, such persons may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. We are able to control directly the operation of only those wells with respect to which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us. We generate materials in the course of our operations that may be regulated as hazardous substances under CERCLA and other environmental laws but we are unaware of any liabilities for which we may be held responsible that would materially and adversely affect our business operations. While petroleum and crude oil fractions are generally not considered hazardous substances under CERCLA and its analogues because of the so-called “petroleum exclusion,” adulterated petroleum products containing other hazardous substances have been treated as hazardous substances in the past.

We also generate solid and hazardous wastes that may be subject to the requirements of the RCRA, and analogous state laws. RCRA regulates the generation, handling, storage, treatment, transport and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes “drilling fluids, produced waters and other wastes associated with the development or production of oil, natural gas or geothermal energy” from regulation as hazardous wastes. With the approval of the EPA, individual states can administer some or all of the provisions of RCRA and some states have adopted their own, more stringent requirements. However, legislation has been proposed from time to time and various environmental groups have filed lawsuits that, if successful, could result in the reclassification of certain oil and natural gas exploration and production wastes as “hazardous wastes,” which would make such wastes subject to much more stringent handling, disposal and clean-up requirements. Any future loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and financial position. In addition, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils that may be regulated as hazardous wastes if such wastes are determined to have hazardous characteristics. Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.

We currently own, lease or operate numerous properties that may have been used by prior owners or operators for oil and natural gas development and production activities for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations where such substances have been taken for recycling or disposal. In addition, some of our properties may have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and/or analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination.

Water discharges

The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including spills and leaks of oil and other natural gas wastes, into or near waters of the United States or state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The discharge of dredge and fill material into regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (the “Corps”). The scope of these regulated waters has been subject to controversy in recent years. In September 2015, the EPA and the Corps issued new rules revising the definition of “waters of the United States” (the “Clean Water Rule”), but in April 2020, the EPA and the Corps replaced the

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Clean Water Rule with the Navigable Waters Protection Rule (“NWPR”), which narrows the definition of “waters of the United States” to four categories of jurisdictional waters and includes 12 categories of exclusions, including groundwater. However, district courts for the U.S. Districts of Arizona and New Mexico have vacated the NWPR, and the Biden Administration has announced its intention to develop its own definition for “waters of the United States. In December 2021, the EPA and Corps published the first of two proposed rulemakings, including a definition largely in keeping with a broader pre-2015 definition and related regulatory guidance and case law. A second proposed rulemaking expanding on this definition is expected later in 2022. Additionally, the Supreme Court of the United States has agreed to hear a case regarding the scope of “waters of the United States.” To the extent any judicial ruling or administrative rulemaking expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits, including for dredge and fill activities in wetland areas.

The process for obtaining permits also has the potential to delay our operations. Additionally, spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” are required by federal law in connection with on-site storage of significant quantities of oil. Compliance may require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture or leak.

Safe Drinking Water Act

The SDWA grants the EPA broad authority to take action to protect public health when an underground source of drinking water is threatened with pollution that presents an imminent and substantial endangerment to humans. The SDWA also regulates saltwater disposal wells under the UIC program. The EP Act of 2005 amended the UIC provisions of the SDWA to expressly exclude certain hydraulic fracturing from the definition of “underground injection,” but disposal of hydraulic fracturing fluids and produced water or their injection for enhanced oil recovery is not excluded. In 2014, the EPA issued permitting guidance governing hydraulic fracturing with diesel fuels. While we do not currently use diesel fuels in our hydraulic fracturing fluids, we may become subject to federal permitting under SDWA if our fracturing formula changes. Additionally, we may incur significant costs to comply with disposal requirements for hydraulic fracturing fluids and produced water. For more information, see Part I, Item 1A. Risk Factors.

Air emissions

The CAA and comparable state laws restrict the emission of air pollutants from many sources, including compressor stations, through the issuance of permits and other requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion and completed attainment/non-attainment designations in 2018. In December 2020, the EPA announced its intention to leave the ozone NAAQS unchanged at 70 parts per billion; however, this decision has been subject to legal challenges, and the Biden Administration has formally announced that it would reconsider the 2020 decision. To the extent more stringent standards are implemented, we could be required to incur further costs for pollution control equipment or other compliance measures. Further, in June 2016, the EPA also finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. These rules could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements.

State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. In addition, the EPA has adopted new rules under the CAA that require the reduction of volatile organic compound (“VOC”) and methane emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. In addition, the regulations place new requirements to detect and repair volatile organic compound and methane at certain well sites and compressor stations. However, in September 2020, the EPA finalized a rule removing transmission and storage activities from the purview of the rules, thereby rescinding the VOC and methane emissions limits applicable to such activities and rescinding the methane specific limits for other activities but maintaining emissions limits for VOCs. However, subsequently, the U.S. Congress approved, and President Biden signed into law, a resolution under the Congressional Review Act to repeal the September 2020 rulemaking, effectively reinstating the prior standards. Additionally, in November 2021, the EPA issued a proposed rule that, if finalized, would establish OOOOb as new source and OOOOc as first-time existing source standards of performance for methane and VOC emissions for the crude

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oil and natural gas source category. Owners or operators of affected emission units or processes would have to comply with specific standards of performance that may include leak detecting using optical gas imaging and subsequent repair requirements, reduction of regulated emissions through capture and control systems, zero-emission requirements for certain equipment or processes, operations and maintenance requirements and requirements for “green well” completions. The EPA plans to issue a supplemental proposal enhancing the proposed rulemaking in 2022 that will contain proposed rule text, which was not included in the November 2021 proposed rule, and anticipates issuing a final rule by the end of 2022. Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of natural gas projects and increase our costs of development, which costs could be significant.

Climate change

Climate change continues to attract considerable public and scientific attention. As a result, our operations as well as the operations of our operators are subject to a series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of GHG. At the federal level, no comprehensive climate change law or regulation has been implemented to date. The EPA has, however, adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, and together with DOT, implement GHG emissions limits on vehicles manufactured for operation in the United States. The federal regulation of methane emissions from oil and gas facilities has been subject to controversy in recent years. For more information, see “Part I, Items 1 and 2. Business and Properties—Legislative and regulatory environment—Air emissions.”

Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of GHG emissions. For example, California, through CARB has implemented a cap and trade program for GHG emissions that sets a statewide maximum limit on covered GHG emissions, and this cap declines annually to reach 40% below 1990 levels by 2030. Covered entities must either reduce their GHG emissions or purchase allowances to account for such emissions. Separately, California has implemented LCFS and associated tradable credits that require a progressively lower carbon intensity of the state’s fuel supply than baseline gasoline and diesel fuels. CARB has also promulgated regulations regarding monitoring, leak detection, repair and reporting of methane emissions from both existing and new oil and gas production facilities. Similar regulations applicable to oil and gas facilities have been promulgated in Colorado.

Internationally, the United Nations-sponsored “Paris Agreement” requires member states to individually determine and submit non-binding emission reduction targets every five years after 2020. Although the United States had withdrawn from the agreement, President Biden has signed executive orders recommitting the United States to the agreement and, in April 2021, announced a target of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. In November 2021, the international community gathered again in Glasgow at the 26th Conference to the Parties on the UN Framework Convention on Climate Change (“COP26”), during which multiple announcements were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-CO2 GHGs. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. The impacts of these orders, pledges, agreements and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, COP26, or other international conventions cannot be predicted at this time.

Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change related pledges made by the recently elected administration. These have included promises to limit emissions and curtail the production of oil and gas on federal lands, such as through the cessation of leasing public land for hydrocarbon development. For example, President Biden has issued several executive orders focused on addressing climate change, including items that may impact our costs to produce, or demand for, oil and gas. Additionally, in November 2021, the Biden Administration released “The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” which establishes a roadmap to net zero emissions in the United States by 2050 through, among other things, improving energy efficiency; decarbonizing energy sources via electricity, hydrogen, and sustainable biofuels; and reducing non-CO2 GHG emissions, such as methane and nitrous oxide. The Biden Administration is also considering revisions to the leasing and permitting programs for oil and gas development on federal lands. Other actions that could be pursued by the Biden Administration may include the imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities, as well as more restrictive GHG emission limitations for oil and gas facilities. Litigation risks are also increasing, as a number of parties have sought to bring suit against oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed climate change or alleging that companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts.

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There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies may elect in the future to shift some or all of their investments into non-fossil fuel related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. For example, at COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. President Biden signed an executive order calling for the development of a “climate finance plan” and, separately, the Federal Reserve announced that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. More recently, in November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities. Additionally, the SEC has announced its intention to promulgate rules requiring climate disclosures. Although the form and substance of these requirements is not yet known, this may result in additional costs to comply with any such disclosure requirements.

The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from oil and natural gas producers, such as ourselves or our operators, or otherwise restrict the areas in which we may produce oil and natural gas or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for or erode value for, the oil and natural gas that we produce. Additionally, political, litigation, and financial risks may result in our restricting or canceling oil and natural gas production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing our ability to continue to operate in an economic manner. Moreover, climate change may also result in various physical risks, such as the increased frequency or intensity of extreme weather events (including storms, wildfires, and other natural disasters) or changes in meteorological and hydrological patterns, that could adversely impact our operations, as well as those of our operators and their supply chains. Such physical risks may result in damage to our facilities or otherwise adversely impact our operations, such as if we become subject to water use curtailments in response to drought, or demand for our products, such as to the extent warmer winters reduce the demand for energy for heating purposes. Such physical risks may also impact our supply chain or infrastructure on which we rely to produce or transport our products. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.

Hydraulic fracturing

Hydraulic fracturing is a common practice that is used to stimulate production of oil and/or natural gas from low permeability subsurface rock formations and is important to our business. The hydraulic fracturing process involves the injection of water, proppants and chemicals under pressure into targeted subsurface formations to fracture the hydrocarbon-bearing rock formation and stimulate production of hydrocarbons. We regularly use hydraulic fracturing as part of our operations. Presently, hydraulic fracturing is primarily regulated at the state level, typically by state oil and natural gas commissions, but the practice has become increasingly controversial in certain parts of the country, resulting in increased scrutiny and regulation. For example, the EPA finalized rules under the CWA in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.

In addition, there have been heightened concerns by the public about hydraulic fracturing causing damage to aquifers and there is potential for future regulation to address those concerns. In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that certain activities associated with hydraulic fracturing may impact drinking water resources under certain limited circumstances. Additionally, BLM finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. While this rule was subsequently rescinded in December 2017, which rescission was upheld by the District Court of Northern California, litigation is ongoing. Additionally, the Biden Administration may seek to revisit these regulations.

Separately, the Biden Administration may also pursue further restriction of hydraulic fracturing and other oil and gas development on federal lands. For example, on January 27, 2021, President Biden issued an executive order that suspended the issuance of new leases for oil and gas development on public lands, but not on existing operations under valid leases or on tribal lands that the federal government merely holds in trust, pending completion of a comprehensive review and reconsideration of the federal oil and natural gas permitting and leasing practices. In response to this, in November 2021, the DOI released a report on the federal oil and gas leasing program that included several recommendations for how to reform the program, many of

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which would require Congressional action. These recommended reforms included, among other items, raising royalty rates and current minimum levels for bids, royalties, and bonds; revising bidding practices to avoid leasing of low potential lands; and performing more meaningful public and tribal consultations regarding the leasing and permitting processes. Provisions of these reforms have been subject to litigation, and on February 19, 2022, the DOI announced that decisions on permits to drill for oil and gas on federal lands will be delayed in response to a court ruling preventing agencies from using the social cost of carbon in their decision-making. A portion of our net acreage and total proved reserves are on federal land. Although the order does not apply to existing operations under valid leases, and the current delay on permit applications is similarly not expected to affect existing operations, we cannot guarantee that further action will not be taken to curtail oil and gas development on federal lands. To the extent we are unable to obtain the leases, permits, or other authorizations required for our operations or business strategy, our business performance and results of operations may be adversely affected.

Separately, in March 2016, the U.S. Occupational Safety and Health Administration issued a final rule to impose stricter standards for worker exposure to silica, which went into effect on June 23, 2021 for hydraulic fracturing employers. We may be required to incur additional costs associated with compliance with these standards.

At the state level, several states, including Texas, have adopted or are considering legal requirements that require oil and natural gas operators to disclose chemical ingredients and water volumes used to hydraulically fracture wells, in addition to more stringent well construction and monitoring requirements. For example, Colorado has adopted, and California is considering adopting, more stringent setbacks for oil and gas development. Local governments may also adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and attendant permitting delays and potential increases in costs. Such changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential legislation or regulation governing hydraulic fracturing, and any of the above risks could impair our ability to manage our business and have a material adverse effect on our operations, cash flows and financial position.

Oil Pollution Act

The OPA establishes strict liability for owners and operators of facilities that are the source of a release of oil into waters of the U.S. The OPA and its associated regulations impose a variety of requirements on responsible parties, including owners and operators of certain facilities from which oil is released, related to the prevention of oil spills and liability for damages resulting from such spills. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct, resulted from violation of a federal safety, construction or operating regulation, or if the party fails to report a spill or to cooperate fully in the cleanup. Few defenses exist to the liability imposed by the OPA. The OPA imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill.

National Environmental Policy Act

Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies to evaluate major agency actions having the potential to significantly impact the environment. The process involves the preparation of an environmental assessment and, if necessary, an environmental impact statement depending on whether the specific circumstances surrounding the proposed federal action have the potential to significantly impact the environment. The NEPA process involves public input through comments which can alter the nature of a proposed project either by limiting the scope of the project or requiring resource-specific mitigation. NEPA decisions can be appealed through the court system by process participants. This process may result in delaying the permitting and development of projects, may increase the costs of permitting and developing some facilities and could result in certain instances in the cancellation of existing leases. In July 2020, the White House Council on Environmental Quality ("CEQ") finalized changes to NEPA regulations that, among other things, narrows the definition of “effects” to exclude the terms “direct,” “indirect,” and

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“cumulative” and redefines the term to be “reasonably foreseeable” and having “a reasonably close causal relationship to the proposed action or alternatives.” However, these regulations are subject to ongoing legal challenges, and the Biden Administration has expressed its intentions to revisit these regulations, particularly to address climate change and environmental justice considerations. The Biden Administration has issued the first of several proposed rulemakings aimed at revising the NEPA process, including the reversal of several of the changes from the 2020 rulemaking.

Endangered Species Act and Migratory Bird Treaty Act

The ESA restricts activities that may affect endangered or threatened species or their habitat. Similar protections are offered to migratory birds under the MBTA. We may conduct operations on natural gas leases in areas where certain species that are or could be listed as threatened or endangered are known to exist. For example, a 12-month review is currently pending to determine whether the dunes sagebrush lizard should be listed and, on June 1, 2021, the FWS proposed to list two distinct population segments of the lesser prairie-chicken under the ESA. In August 2020, the FWS and the National Marine Fisheries Service issued three rules amending the implementation of the ESA regulations, among other things revising the process for listing species and designating critical habitat. However, in October 2021, FWS and NMFS proposed to rescind two rules related to the definition of “critical habitat,” and the Biden administration has stated that it is reviewing several other Trump-era ESA rules.

The DOI also issued an opinion in December 2017 that would narrow certain protections afforded to migratory birds pursuant to the MBTA. In August 2020, the U.S. District Court for the Southern District of New York vacated this opinion as contrary to law. While the FWS subsequently finalized a rule incorporating the DOI opinion, rule was revoked on October 4, 2021, and FWS returned to pre-2017 implementation of the MBTA, including the ability to enforce the MBTA against accidental harm or death to birds (known as “incidental take”). FWS is currently soliciting public comments on an Advanced Notice of Proposed Rulemaking under the MBTA as it considers how to develop regulations to authorize some incidental take of migratory birds, which may include a permitting program. The identification or designation of previously unprotected species, such as the dunes sagebrush lizard, lesser prairie chicken, and greater sage grouse, as threatened or endangered, or the redesignation of a species from threatened to endangered, in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our development activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.

Related permits and authorizations

Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation or other oil and natural gas activities, and to maintain these permits and compliance with their requirements for on-going operations. These permits are generally subject to protest, appeal or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines and other operations.

Worker health and safety

We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state statutes, whose purpose is to protect the health and safety of workers. For example, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes and any implementing regulations require that we maintain, organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens. Other OSHA standards regulate specific worker safety aspects of our operations. Failure to comply with OSHA requirements can lead to the imposition of penalties.

Related insurance

We maintain insurance against some contamination risks associated with our development activities. However, this insurance is limited to activities at the well site and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a material and adverse effect on our financial condition and operations. Further, we have no coverage for gradual, long-term pollution events.

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Item 1A. Risk Factors

Described below are certain risks that we believe are applicable to our business and the oil and gas industry in which we operate. Investors should read carefully the following factors as well as the cautionary statements referred to in "Cautionary Statement Regarding Forward-Looking Statements" herein. If any of the risks and uncertainties described below or elsewhere in this Annual Report actually occur, the Company's business, financial condition or results of operations could be materially adversely affected.

Risks related to the oil and natural gas industry and our operations

Events beyond our control, including the COVID-19 pandemic or any other future global or domestic health crisis, may result in unexpected adverse operating and financial results.

The outbreak of the COVID-19 pandemic or future outbreaks of disease may materially and adversely affect our business, operating and financial results and liquidity. The severity, magnitude and duration of the current COVID-19 pandemic is uncertain, rapidly changing and hard to predict. While the full impact of this virus and the long-term worldwide reaction to it and impact from it remains unknown at this time, government reaction to the COVID-19 pandemic, including restrictions and limitations on travel and economic activity, continued widespread growth in infections, or site closures as a result of the virus could, among other things, impact the ability of our employees and contractors to perform their duties, cause increased technology and security risk due to extended and company-wide telecommuting, lead to disruptions in our supply chain (including necessary contractors), lead to a disruption in our acquisition or permitting activities and cause disruption in our relationship with our customers and suppliers. Additionally, the COVID-19 pandemic has significantly impacted economic activity and markets around the world, and COVID-19 or another pandemic could materially and adversely affect our business in numerous ways, including, but not limited to, the following:

•our revenue may be reduced if the pandemic results in an economic downturn or recession, to the extent it leads to a prolonged decrease in the demand for oil, natural gas and NGLs;

•our operations may be disrupted or impaired, thus lowering our production levels, if a significant portion of our employees, contractors or D&C crews are unable to work due to illness or if our field operations are suspended or temporarily shut-down or restricted due to control measures designed to contain the outbreak; and

•the operations of our midstream service providers, on whom we rely for the transmission, gathering and processing of a significant portion of our produced oil and natural gas, may be disrupted or suspended in response to or as a result of the COVID-19 pandemic and result in the shut-in of producing wells or the delay or discontinuance of development plans for our properties.

Oil, natural gas and NGL prices are volatile. A sustained decline in prices could adversely affect our business, financial condition and results of operations, liquidity and our ability to meet our financial commitments or cause us to delay our planned capital expenditures.

Our revenues, operating results, profitability, liquidity and ability to grow depend primarily upon the prices we receive for the oil, natural gas and NGL we sell. We require substantial expenditures to replace our oil, natural gas and NGL reserves, sustain production and fund our business plans, including our development plan. Low oil, natural gas and NGL prices resulting from reduced demand caused by COVID-19 pandemic and other factors materially affected our revenues, particularly before the effects of commodity derivatives, operating results and cash flows in 2020. In March 2020, crude oil demand experienced significant declines due to the COVID-19 pandemic and resulting government-led shut-downs in economic activity. While oil, natural gas and NGL prices began to stabilize in the second half of 2020 and have continued to do so, the overall drop in prices and lack of forward visibility in demand may combine to negatively affect the amount of cash available for capital expenditures and debt repayment, our ability to borrow money or raise additional capital and, as a result, could have a material adverse effect on our business, prospects, financial condition, results of operations and cash flows. In addition, low prices may reduce the quantities of oil, natural gas and NGL reserves that may be economically produced and result in an impairment of our oil and natural gas properties.

Historically, the markets for oil, natural gas and NGL have been volatile, and they are likely to continue to be volatile. For

example, the recent conflict between Russia and Ukraine has contributed to significant increases and volatility in the price for oil and natural gas. Wide fluctuations in oil, natural gas and NGL prices may result from relatively minor changes in the supply of or demand for oil, natural gas and NGL market uncertainty and other factors that are beyond our control, including:

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•worldwide and regional economic conditions impacting the supply and demand for oil, natural gas and NGLs, including uncertainty regarding the timing, pace and extent of an economic recovery in the United States;

•the extraordinary market environment and effects of the COVID-19 pandemic, including a significant decline in demand for oil, natural gas and NGLs;

•changes in seasonal temperatures, including the number of heating degree days during winter months and cooling degree days during summer months;

•the level of oil, natural gas and NGL exploration, development and production;

•the level of oil, natural gas and NGL inventories;

•the level of U.S. LNG exports;

•prevailing prices on local price indexes in the areas in which we operate;

•the proximity, capacity, cost and availability of gathering and transportation facilities;

•localized and global supply and demand fundamentals and transportation availability;

•the cost of exploring for, developing, producing and transporting reserves;

•the spot price of LNG on world markets;

•weather conditions and natural disasters;

•technological advances affecting energy consumption;

•the price and availability of alternative fuels;

•speculative trading in oil and natural gas derivative contracts;

•increased end-user conservation;

•political and economic conditions in or affecting other producing regions or countries, including the Middle East, Africa, South America and Russia;

•political and economic conditions in or affecting major LNG consumption regions or countries, particularly Asia and Europe;

•actions of OPEC, including the ability and willingness of the members of OPEC and other exporting nations to agree to and maintain oil price and production controls, including the anticipated increases in supply from Russia and OPEC, particularly Saudi Arabia;

•U.S. trade policies and their effect on U.S. oil and natural gas exports;

•expectations about future commodity prices;

•the possibility of terrorist or cyberattacks and the consequences of any such attacks; and

•U.S. federal, state and local and non-U.S. governmental regulation and taxes.

We have been negatively affected and may continue to be negatively affected by a drop in commodity prices.

Lower commodity prices may reduce our operating margins, cash flow and borrowing ability. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to develop future reserves or make acquisitions could be adversely affected. Also, using lower prices in estimating proved reserves may result in a reduction in proved reserve volumes due to economic limits. In addition, sustained periods with oil and natural gas prices at levels lower than pre-COVID-19 levels may

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adversely affect our drilling economics, cash flow and our ability to raise capital, which may require us to re-evaluate and postpone or substantially restrict our development program, and result in the reduction of some of our PUD reserves and related PV-10. As a result, a substantial or extended decline in commodity prices, such as what occurred in early 2020, may materially and adversely affect our future business, financial condition, results of operations, liquidity and ability to meet our financial commitments or cause us to delay our planned capital expenditures.

We have consolidated our business over time through acquisitions, including the recent Merger Transactions and the contemplated Uinta Transaction, and there are risks associated with integration of all of these assets, operations and our ability to manage those risks. In addition, we may be unable to make attractive acquisitions or successfully integrate acquired businesses, assets or properties, and any inability to do so may disrupt our business and hinder our ability to grow.

We intend to pursue a strategy focused on both reinvestment and future acquisitions, which is designed to obtain the optimal risk adjusted returns through commodity cycles. Accordingly, in the future we may make acquisitions of businesses, assets or properties that we expect to complement or expand our current assets. For example, in February 2022, we entered into a definitive agreement to acquire certain exploration and production assets in the State of Utah pursuant to the Uinta Transaction (as defined herein). However, we may not be able to identify attractive acquisition opportunities in the future. Even if we do identify attractive acquisition opportunities, such as the Uinta Transaction, we may not be able to complete the acquisition or do so on commercially acceptable terms. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets.

The success of any completed acquisition, including the recently completed Merger Transactions, will depend on our ability to integrate effectively the acquired business, asset or property into our existing operations. The process of integrating acquired businesses, assets and properties may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. Our failure to achieve consolidation savings, to incorporate the acquired businesses, assets and properties into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material and adverse effect on our financial condition and results of operations.

We may fail to realize the anticipated benefits of the Merger Transactions and may assume unanticipated liabilities.

The success of the Merger Transactions will depend on, among other things, our ability to combine the Contango and Independence businesses in a manner that realizes the various benefits, growth opportunities and synergies identified by the companies. Achieving the anticipated benefits is subject to a number of risks and uncertainties. OpCo would assume all of the liabilities associated with the acquired properties and environmental, title and other problems could reduce the value of the properties to OpCo. There can also be no assurance that attractive investment opportunities in upstream oil and gas assets will materialize for KKR to present to us, and there can be no guarantee that any such investment would be successful. Also, it is uncertain whether Contango’s and Independence’s existing operations and the acquired properties and assets can be integrated in an efficient and effective manner.

In addition, the integration of operations following will require the attention of our management and other personnel, which may distract their attention from our day-to-day business and operations and prevent us from realizing benefits from other opportunities. While the Manager’s personnel and other resources expect to dedicate the majority of their time to our assets and operations, the Manager’s personnel and other resources may be utilized for other projects unrelated to us, and the allocation of such resources is generally within the discretion of the Manager. We are obligated to pay the Manager annual Management Compensation under the terms of the Management Agreement. There can be no assurance we will realize the anticipated benefits from the Management Agreement. Those fees may be greater than the costs that would otherwise be incurred by us in managing our business and compensating our executive team. Completing the integration process may be more expensive than anticipated, and we cannot assure you that it will be able to affect the integration of these operations smoothly or efficiently or that the anticipated benefits of the transaction will be achieved.

Combining the businesses of Contango and Independence may be more difficult, costly and time-consuming than expected, which may adversely affect our results and negatively affect the value of our Class A Common Stock following the Merger Transactions.

Contango and Independence entered into the Transaction Agreement because each believed that combining the businesses of Contango and Independence will produce benefits and cost savings. However, Contango and Independence had historically operated as independent companies. Since the completion of the Merger Transactions, our management has been actively engaged in the integration of Contango’s and Independence’s respective businesses. The combination of two independent businesses is a complex, costly and time-consuming process, and our management may face significant challenges in

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implementing such integration, many of which may be beyond the control of management. Some of these factors will be outside of the control of Contango and Independence, and any one of them could result in increased costs and diversion of management’s time and energy, as well as decreases in the amount of expected revenue that could materially impact our business, financial conditions and results of operations. The integration process and other disruptions resulting from the Merger Transactions may also adversely affect our relationships with employees, suppliers, customers, distributors, licensors and others with whom Contango and Independence have business or other dealings, and difficulties in integrating the businesses of Contango and Independence could harm our reputation.

If we are not able to successfully integrate the businesses of Contango and Independence in an efficient, cost-effective and timely manner, the anticipated benefits and cost savings of the Merger Transactions may not be realized fully, or at all, or may take longer to realize than expected, and the value of our Class A Common Stock, the revenues, levels of expenses and results of operations may be affected adversely. If we are not able to adequately address integration challenges, we may be unable to successfully integrate Contango’s and Independence’s operations or realize the anticipated benefits of the Merger Transactions.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Numerous uncertainties are inherent in estimating quantities of oil and natural gas reserves. Our estimates of our SEC reserves are based upon average commodity prices over the prior 12 months, which may not reflect actual prices received for our production. The process of estimating oil and natural gas reserves is complex and requires significant decisions and assumptions in the evaluation of available geological, engineering and economic data for each reservoir. The reports rely upon various assumptions, including assumptions regarding future oil and natural gas prices, our drilling program, production levels, and operating and development costs. In addition, the reserves that we present herein are aggregated from several reports, which were prepared by several engineering firms and therefore may be based on slightly different assumptions and preparation and review procedures. Our ability to develop any identified drilling location is subject to various limitations and any drilling activities we are able to conduct may not be successful. As a result, our actual drilling activities may materially differ from those presently identified and could result in downward revisions of estimated proved reserves. In addition, loss of production and leasehold rights due to mechanical failure or depletion of wells and our inability to re-establish their production may occur in certain cases. Production from wellbores may be affected by nearby fracturing activities by offset operators or us, resulting in reserve revisions.

As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling and production. Any significant variance in our assumptions and actual results could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. Specifically, future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. Sustained lower prices will cause the 12-month weighted average price to decrease over time as the lower prices are reflected in the average price, which may result in the estimated quantities and present values of our reserves being reduced.

Any material inaccuracies in our reserves estimates could also materially affect our borrowing base and liquidity under the Revolving Credit Facility. If the borrowing base under the Revolving Credit Facility decreases as a result of any reductions in our reserve estimates, we may have limited ability to obtain the capital necessary to sustain our operations at current and anticipated future levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all.

The present value of future net revenues from our proved reserves, as reflected in our standardized measure and PV-10 value, will not necessarily be the same as the current market value of our estimated proved oil and natural gas reserves.

You should not assume that the present value of future net revenues from our proved reserves, as reflected in our standardized measure and PV-10 value, is the current market value of our estimated oil and natural gas reserves. We currently base the estimated discounted future net revenues from our proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the preceding 12 months. Actual future net revenues from our oil and natural gas properties will be affected by factors such as:

•actual prices we receive for crude oil, natural gas and NGLs;

•actual cost of development and production expenditures;

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•the amount and timing of actual production;

•transportation and processing; and

•changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of, and investment in, our oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues at PV-10 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Actual future prices and costs may differ materially from those used in the present value estimates.

Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which may adversely affect our future cash flows and results of operations.

In general, the volume of production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on each reservoir’s characteristics. Except to the extent that we conduct successful exploration, exploitation, development or reinvestment activities or acquire properties containing proved reserves, our proved reserves will decline as reserves are produced. Our future oil and natural gas production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves as well as the pace of D&C of new wells. Additionally, the business of exploring for, exploiting, developing or acquiring reserves is capital intensive. Recovery of our reserves, particularly undeveloped reserves, will require significant additional capital expenditures and successful drilling operations. To the extent cash flow from operations is reduced and external sources of capital become limited, unavailable or on terms deemed unacceptable by us, our ability to make the necessary capital investment to maintain or expand our asset base of oil and natural gas reserves or to return capital to our investors would be impaired.

As part of our exploration and development operations, we have expanded, and expect to further expand, the application of horizontal drilling and multi-stage hydraulic fracture stimulation techniques as well as enhanced recovery operations. The utilization of these techniques requires substantially greater capital expenditures as compared to the completion cost of a vertical well or a horizontal well utilizing less advanced techniques and therefore may result in fewer wells being completed or recompleted in any given year. The incremental capital expenditures are generally the result of greater measured depths, additional hydraulic fracture stages in horizontal wellbores and increased volumes of water, CO2 and proppant.

Due to the recent increase in commodity prices following extreme volatility during 2020, the unavailability or high cost of equipment, supplies, personnel and oilfield services could adversely affect our ability to execute development and exploitation plans on a timely basis and within budget, and consequently could materially and adversely affect our anticipated cash flow.

We utilize third-party services to maximize the efficiency of our operation. The cost of oilfield services typically fluctuates based on demand for those services, and the recent increase in commodity prices following extreme volatility during 2020 has increased the cost of oilfield services. While we currently have excellent relationships with oilfield service companies, there is no assurance that we will be able to contract for such services on a timely basis or that the cost of such services will remain at a satisfactory or affordable level. Shortages or the high cost of equipment, supplies or personnel could delay or adversely affect our development and exploitation operations, which could have a material and adverse effect on our business, financial condition or results of operations.

Our development projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms or at all, which could lead to a decline in our reserves and cash flows.

The oil and natural gas industry is capital intensive. We have made and expect to continue to make substantial capital expenditures in our business for the development of, and reinvestment in, oil and natural gas reserves. We have historically funded development and operating activities primarily through the sale of our oil, natural gas and NGL production. If necessary, we may also access capital through proceeds from asset dispositions, borrowings under the Revolving Credit Facility and capital markets offerings from time to time. Our cash flow from operations and access to capital are subject to a number of variables, including:

•the amount of oil and natural gas we produce from existing wells;

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•the prices at which we sell our production;

•take-away capacity;

•the estimated quantities of our oil and natural gas reserves; and

•our ability to acquire, locate and produce new reserves.

If our revenues or the borrowing base under the Revolving Credit Facility decrease as a result of lower commodity prices, operating difficulties, production cost increases, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to conduct our operations at expected levels. The Revolving Credit Facility and the documents governing our other indebtedness may restrict our ability to obtain new debt financing. If additional capital is required, we may not be able to obtain debt and/or equity financing on terms favorable to us, or at all, which could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a decline in our reserves, production and cash flows, and could adversely affect our business, results of operation, financial conditions and ability to make payments on our outstanding indebtedness.

The development of our estimated PUD reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated PUD reserves may not be ultimately developed or produced.

Recovery of PUDs requires significant capital expenditures and successful drilling operations. At December 31, 2021 approximately 73.1 MMBoe of our total estimated proved reserves were undeveloped. The reserve data included in our reserve reports assumes that substantial capital expenditures will be made to develop non-producing reserves. The calculation of our estimated net proved reserves as of December 31, 2021 assumes that we will spend $0.9 billion to develop our estimated PUDs. Although cost and reserve estimates attributable to our oil and natural gas reserves have been prepared in accordance with industry standards, we cannot be sure that the estimated costs are accurate. We may need to raise additional capital in order to develop our estimated PUDs, and we cannot be certain that additional financing will be available to us on acceptable terms, if at all. Additionally, extended declines in commodity prices will reduce the future net revenues of our estimated PUDs and may result in some projects becoming uneconomical. Further, our drilling efforts may be delayed or unsuccessful and actual reserves may prove to be less than current reserve estimates, which could have a material and adverse effect on our financial condition, results of operations and future cash flows.

Our identified development opportunities are scheduled to be developed over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of such development. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such locations.

As of December 31, 2021, we have identified 1,528 gross (685 net) undrilled locations, including 567 gross (450 net) operated drilling locations. Of our total 685 net locations, 159 net locations are identified as PUD drilling locations as of December 31, 2021. These identified drilling locations represent a meaningful part of our future development strategy. Our ability to drill and develop these identified drilling locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system, marketing and transportation constraints, regulatory approvals, labor, takeaway capacity and other factors. Because of these uncertain factors, we do not know if the identified drilling locations will ever be developed or if we will be able to produce oil or natural gas from these drilling locations at anticipated levels or at all. In addition, unless production is established within the spacing units covering the undeveloped acreage on which some of the identified locations are located, the leases for such acreage will expire. Therefore, our actual development activities may materially differ from those presently identified.

Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Drilling oil and natural gas wells, including development wells, involves numerous risks, including the risk that we may not encounter commercially productive oil and natural gas reserves (including “dry holes”). We must incur significant expenditures to drill and complete wells, the costs of which are often uncertain. It is possible that we will make substantial expenditures on drilling and not discover reserves in commercially viable quantities.

Specifically, we often are uncertain as to the future cost or timing of drilling, completing and operating wells, and our drilling operations and those of our third-party operators may be curtailed, delayed or canceled. The cost of our drilling, completion and

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well operations may increase and/or our results of operations and cash flows from such operations may be impacted, as a result of a variety of factors, including:

•unexpected drilling conditions;

•title problems;

•pressure or irregularities in formations;

•equipment failures or accidents;

•adverse weather conditions, such as winter storms, fires, flooding and hurricanes, and changes in weather patterns;

•compliance with, or changes in, environmental laws and regulations relating to air emissions, hydraulic fracturing and disposal of produced water, drilling fluids and other wastes, laws and regulations imposing conditions and restrictions on D&C operations and other laws and regulations, such as tax laws and regulations;

•the availability and timely issuance of required governmental permits and licenses; and

•the availability of, costs associated with and terms of contractual arrangements for properties, including mineral licenses and leases, pipelines, rail cars, crude oil hauling trucks and qualified drivers and related facilities and equipment to gather, process, compress, transport and market oil, natural gas, NGLs and related commodities.

Our failure to recover our investment in wells, increases in the costs of our drilling operations or those of our third-party operators, and/or curtailments, delays or cancellations of our drilling operations or those of our third-party operators in each case due to any of the above factors or other factors, may materially and adversely affect our business, financial condition and results of operations.

We may experience difficulty in achieving and managing future growth.

Future growth may place strains on our resources and cause us to rely more on project partners and independent contractors, possibly negatively affecting our financial condition and results of operations. Our ability to grow will depend on a number of factors, including:

•the results of our drilling program;

•hydrocarbon prices;

•our ability to develop existing prospects;

•our ability to continue to retain and attract skilled personnel;

•our ability to maintain or enter into new relationships with project partners and independent contracts; and

•our access to capital.

We may also be unable to make attractive acquisitions or asset exchanges, which could inhibit our ability to grow, or could experience difficulty integrating any acquired assets and operations. It may be difficult to identify attractive acquisition opportunities and, even if such opportunities are identified, our debt agreements (including the indenture that governs the Senior Notes) contain limitations on our ability to enter into certain transactions, which could limit our future growth.

Our operations are dependent on third-party service providers.

We contract with third-party service providers to support our operations. These contracted services are generally provided pursuant to master services agreements entered into between the third-party service providers and our operating subsidiaries. Although we have our own employees, our ability to conduct operations and generate revenues is dependent on the availability and performance of those third-party service providers and their compliance with the terms of their respective master service agreements. We cannot guarantee that we will be successful in either retaining the services of our current third-party service providers or contracting with alternative service providers in the event that our current contractors discontinue providing

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services to us or fail to meet their obligations under their respective master services agreements. Any failure to retain the services of our current service providers or locate alternatives will negatively affect our ability to generate revenues and continue and expand our operations. Please see Part I, Items 1 and 2. Business and Properties—Employees for more information.

We are not the operator on all of our acreage or drilling locations, and, therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated assets and could be liable for certain financial obligations of the operators or any of our contractors to the extent such operator or contractor is unable to satisfy such obligations.

Some of the properties in which we have an interest are operated by other companies and involve third-party working interest owners. As of December 31, 2021, we have identified 1,528 gross (685 net) undrilled locations, including 567 gross (450 net) operated drilling locations. Of our total 685 net locations, 159 net locations are identified as PUD drilling locations as of December 31, 2021. We do not operate 34% of the total net undrilled locations, and there is no assurance that we will operate all of our other future drilling locations. As a result, we have limited ability to influence or control the operation or future development of certain of these properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures that we will be required to fund with respect to such properties, subject to certain of our election rights. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects. In addition, a third-party operator could also decide to shut-in or curtail production from wells, or plug and abandon marginal wells, on properties in which we own an interest during periods of lower crude oil or natural gas prices. Furthermore, the success and timing of development activities operated by our partners will depend on a number of factors that will be largely outside of our control, including:

•the timing and amount of capital expenditures;

•the operator’s expertise and financial resources;

•the approval of other participants in drilling wells;

•the selection of technology; and

•the rate of production of reserves, if any.

This limited ability to exercise control over the operations and associated costs of some of our drilling locations could prevent the realization of targeted returns on capital in development or acquisition activities. Further, we may be liable for certain financial obligations of the operator of a well in which we own a working interest to the extent such operator becomes insolvent and cannot satisfy such obligations. Similarly, we may be liable for certain obligations of contractors to the extent such contractor becomes insolvent and cannot satisfy their obligations. The satisfaction of such obligations could have a material and adverse effect on our financial condition. For more information, see Part I, Items 1 and 2. Business and Properties and Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Through the Management Agreement, we depend on the Manager and its personnel to manage and operate our business, the loss of any of whom would materially and adversely affect future operations. Additionally, operational risks affecting the Manager, and our ability to work collaboratively with the Manager, including with respect to the allocation of corporate opportunities and other conflicts of interest, may impact our business and have a material effect on our business, financial results and prospects.

Pursuant to the Management Agreement we entered into with the Manager upon consummation of the Merger Transactions, the Manager provides us with its executive management team and provides certain other management services. However, in each case such resources are not fully dedicated to our assets and operations, and the allocation of such resources is generally within the Manager’s discretion. See Part III, Item 13. Certain Relationships and Related Party Transactions and Director Independence—Management Agreements.” Accordingly, our success depends on the efforts, experience, diligence, skill and network of business contacts of the Manager’s personnel. We can offer no assurance that the Manager will continue to provide services to us or that we will continue to have access to the Manager’s personnel. The Management Agreement has an initial three-year term, with automatic three-year renewals thereafter. Upon the written notice to the Manager at least 180 days prior to the expiration of the initial term or any automatic renewal term, we may, without cause, decline to renew the Management Agreement upon the affirmative determination of at least two-thirds of its independent directors reasonably and in good faith, that (1) there has been unsatisfactory long-term performance by the Manager that is materially detrimental to us and our subsidiaries taken as a whole or (2) the fees payable to the Manager, in the aggregate, are materially unfair and excessive

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compared to those that would be charged by a comparable asset manager managing assets comparable to our assets, subject to Manager’s right to renegotiate the fees. If the Management Agreement is terminated and no suitable replacement is found to provide management and operating services for our oil and natural gas assets, we may not be able to execute our business plan, and our financial condition and results of operation may be materially and adversely affected.

Further, our relationship with the Manager presents certain challenges relating to our ability to work collaboratively with the Manager’s broader business. For example, the Manager will source investment opportunities both for our benefit and for the benefit of other KKR investment vehicles. Pursuant to the Management Agreement, investment opportunities in upstream oil and gas assets will be presented to us with the total amount of the available investment allocated between us and EIGF II and the parallel vehicles or alternative vehicles relating thereto in good faith by the Manager on a pro rata basis subject to and taking into account available capital, applicable concentration limits, investment restrictions and other similar considerations. After all available investment capital within EIGF II has been fully deployed, the Manager shall ensure that at least 70% of any such investment amounts are allocated to us. In addition, from time to time, investment opportunities outside of upstream oil and gas assets may arise that are suitable for investment by us, on the one hand, and by EIGF II (and any successor fund) or other KKR Group funds, on the other, that are (A) engaged in an investment strategy that is materially different from our investment strategy (such as distressed debt or special situations investment vehicles) and (B) have pre-existing defined allocation rights pursuant to the KKR Group’s allocation policies or contractual undertakings agreed with the investors in such other KKR Group funds. In such cases, we may elect to co-invest alongside EIGF II and/or such other KKR Group funds in such investments, in which case the Manager will allocate such investment opportunities among us, on the one hand, and EIGF II and/or such other KKR Group funds, on the other hand, in a manner consistent with the priority investment rights of such KKR Group funds, taking into account such factors as the Manager deems appropriate. We shall have no obligation to make any such co-investment.

In addition, other conflicts of interest may arise from time to time in connection with the investment and other activities of us and other members of the KKR Group. With respect to conflicts involving investment opportunities, the Manager will endeavor to resolve any such conflicts of interest in a fair and equitable manner in accordance with the investment allocation policy described above and its prevailing policies and procedures with respect to conflicts resolution among other members of the KKR Group. However, the Manager may have a fiduciary duty to make decisions in the best interests of the Manager's affiliates, including KKR Funds, which may be contrary to our interests. In addition, other conflicts of interest may arise between us, on the one hand, and the Manager or any other member of the KKR Group and their affiliates, including KKR Funds, on the other hand, which may not be resolved in our favor.Further, the Management Agreement provides that nothing shall prevent the Manager from taking certain actions for the sole benefit of the Manager and/or its affiliates. To the fullest extent permitted by law, the Manager and its affiliates, including but not limited to their respective directors, officers, employees, agents, managers, trustees, control persons, partners, stockholders, and equityholders, will not be liable to us or any subsidiary or any of their respective directors, officers, employees, agents, managers, trustees, control persons, partners, stockholders, and equityholders, for any acts or omissions by the Manager or its affiliates, including by their respective directors, officers, employees, agents, managers, trustees, control persons, partners, stockholders, and equityholders, performed in accordance with and pursuant to the Management Agreement, except in cases of bad faith, fraud, willful misconduct or gross negligence. The Management Agreement requires us to reimburse, indemnify and hold harmless the Manager, its affiliates, and their respective directors, officers, employees, managers, trustees, control persons, partners, stockholders, and equityholders, and directors, officers, employees, agents, managers, trustees, control persons, partners, stockholders and equityholders of the foregoing from any and all Losses (as defined in the Management Agreement) arising from any proceeding related to us or acts or omissions of the Manager or its affiliates in connection with the Management Agreement, subject to certain exceptions. However, with the exception of the Manager, no other member of the KKR Group assumes any responsibility to render services to us or to consider our interests and our stakeholders in making any investment or other decisions.

Our certificate of incorporation contains a provision that, to the maximum extent permitted under the law of the State of Delaware, we renounce any interest or expectancy in, or in being offered an opportunity to participate in, business opportunities that are from time to time presented to our officers, directors, the Preferred Stockholder or any partner, manager, member, director, officer, stockholder, employee or agent or affiliate of any such holder. We believe that this provision, which is intended to provide that certain business opportunities are not subject to the “corporate opportunity” doctrine, is appropriate, as the Preferred Stockholder and its affiliates invest in a wide array of companies, including companies with businesses similar to us. As a result of this provision, we may be not be offered certain corporate opportunities which could be beneficial to us and our stockholders.

Properties we have recently acquired or may acquire in the future may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with such properties or obtain protection from sellers against such liabilities.

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Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, future oil and gas prices and their applicable differentials, development and operating costs, and potential liabilities, including environmental liabilities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review may not reveal all existing or potential problems. In the course of due diligence, we may not review every well, pipeline or associated facility. We cannot necessarily observe structural and environmental problems, such as pipe corrosion or groundwater contamination, when a review is performed. We may be unable to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with its expectations. For these reasons, the properties we will acquire in connection with any future acquisitions may not produce as expected, which could have a material and adverse effect on our financial condition and results of operations.

Future commodity price declines may result in write-downs of our asset carrying values.

We follow the successful efforts method of accounting for our oil and gas operations. Under this method, all property acquisition cost and cost of exploratory and development wells are capitalized when incurred, pending determination of whether proved reserves have been discovered. If proved reserves are not discovered with an exploratory well, the cost of drilling the well are expensed. The capitalized costs of our oil and natural gas properties, on a depletion pool basis, cannot exceed the estimated undiscounted future net cash flows of that depletion pool. If net capitalized costs exceed undiscounted future net revenues, we generally must write down the costs of each depletion pool to the estimated fair value (discounted future net cash flows of that depletion pool). Any such charge will not affect our cash flow from operating activities or liquidity, but will reduce our earnings and investors’ equity.

We may also at times record reporting unit goodwill in connection with a business combination. Goodwill has an indefinite useful life but is tested by us for impairment annually, or more frequently if there are changes in future commodity prices, amongst other factors, that may indicate that the fair value of the reporting unit may have been reduced below its carrying value. If the carrying value of the reporting unit exceeds the fair value, we generally must write down goodwill to the estimated fair value of that reporting unit. Any such charge will not affect our cash flow from operating activities or liquidity but will reduce our earnings and investors’ equity.

A decline in oil or natural gas prices from current levels, or other factors, could cause an impairment write-down of capitalized costs, including goodwill, and a non-cash charge against future earnings. For example, for the year ended December 31, 2020, because of significant declines in crude prices, we recorded an impairment charge of $247.2 million to oil and natural gas properties. Once incurred, a write-down of oil and natural gas properties cannot be reversed at a later date, even if oil or natural gas prices increase.

Our business is subject to operational risks that will not be fully insured. If any of the operational risks materialize our financial condition or results of operations could be materially and adversely affected.

Our business activities are subject to operational risks, including, but not limited to:

•damages to equipment caused by natural disasters such as earthquakes, and adverse weather conditions, including tornadoes, hurricanes and flooding;

•facility or equipment malfunctions;

•pipeline ruptures or spills;

•surface fluid spills, produced water contamination and salt water, surface or groundwater contamination resulting from petroleum constituents or hydraulic fracturing chemical additions;

•fires, blowouts, craterings and explosions; and

•uncontrollable flows of oil, natural gas or well fluids.

Any of these events could adversely affect our ability to conduct operations or cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution or other environmental

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contamination, loss of wells, regulatory penalties, suspension or termination of operations, and attorney’s fees and other expenses incurred in the prosecution or defense of litigation.

As is customary in the industry, we maintain insurance against some but not all of these risks. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material and adverse effect on our business, financial condition and results of operations.

We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenues.

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources than us, particularly following recent consolidation within the industry. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties to consummate transactions in a highly competitive market. Many of our larger competitors not only drill for and produce oil and natural gas, but they also engage in refining operations and market petroleum and other products on a regional, national or worldwide basis. Our competitors may be able to pay more for oil and natural gas properties, and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, these companies may have a greater ability to continue drilling activities during periods of low oil and natural gas prices, to contract for drilling equipment, to secure trained personnel, and to absorb the burden of present and future federal, state, local and other laws and regulations. The oil and natural gas industry has periodically experienced shortages of drilling rigs, equipment, pipelines and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases. Competition has been strong in hiring experienced personnel, particularly in the engineering and technical, accounting and financial reporting, tax and land departments. In addition, competition is strong for attractive oil and natural gas properties, oil and natural gas companies, and drilling rights. Our inability to compete effectively with our competitors could have a material and adverse impact on our business activities, financial condition and results of operations.

Deficiencies of title to our leased interests could materially and adversely affect our financial condition.

If an examination of the title history of a property reveals that an oil or natural gas lease or other developed rights has been purchased in error from a person who is not the owner of the mineral interest desired, our interest would substantially decline in value. In such cases, the amount paid for such oil or natural gas lease or leases or other developed rights would be lost. It is management’s practice, in acquiring oil and natural gas leases or undivided interests in oil and natural gas leases or other developed rights, not to incur the expense of retaining lawyers to examine the title to the mineral interest to be acquired. Rather, we rely upon the judgment of oil and natural gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental or county clerk’s office before attempting to acquire a lease or other developed rights in a specific mineral interest.

Prior to drilling an oil or natural gas well, however, it is the normal practice in the oil and natural gas industry for the person or company acting as the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed oil or natural gas well is to be drilled to ensure there are no obvious deficiencies in title to the leasehold. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, such as obtaining affidavits of heirship or causing an estate to be administered. Such curative work entails expense, and it may happen, from time to time, that the operator may elect to proceed with a well despite defects to the title identified in the preliminary title opinion. Our failure to obtain perfect title to our leaseholds may adversely impact our ability in the future to increase production and reserves.

Certain of our properties are subject to land use restrictions, which could limit the manner in which we conduct our business.

Certain of our properties are subject to land use restrictions, including city ordinances, which could limit the manner in which we conduct our business. Such restrictions could affect, among other things, our access to and the permissible uses of our properties as well as the manner in which we produce oil and natural gas and may restrict or prohibit drilling in general. The costs we incur to comply with such restrictions may be significant and our development and production activities may be delayed, curtailed or precluded by such restrictions.

Part of our business strategy will involve using some of the latest available horizontal D&C techniques, which involve risks and uncertainties in their application.

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Our operations will involve utilizing some of the latest D&C techniques as developed by us and our service providers. The difficulties we may face drilling horizontal wells include:

•landing our wellbore in the desired drilling zone;

•staying in the desired drilling zone while drilling horizontally through the formation;

•running our casing through the entire length of the wellbore; and

•being able to run tools and other equipment consistently through the horizontal wellbore.

The difficulties that we will likely face while completing wells include the following:

•the ability to fracture stimulate the planned number of stages;

•the ability to run tools the entire length of the wellbore during completion operations; and

•the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

Use of new technologies may not prove successful and could result in significant cost overruns or delays or reductions in production, and, in extreme cases, the abandonment of a well. In addition, certain of the new techniques we adopt may cause irregularities or interruptions in production due to offset wells being shut in and the time required to drill and complete multiple wells before any such wells begin producing. Furthermore, the results of drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer and emerging formations and areas have limited or no production history and, consequently, we will be more limited in assessing future drilling results in these areas. If its drilling results are less than anticipated, the return on investment for a particular project may not be as attractive as anticipated, and we could incur material write-downs of unevaluated properties and the value of undeveloped acreage could decline in the future.

We may encounter obstacles to marketing our oil and natural gas, which could materially and adversely affect our revenues.

The marketability of our production depends in part upon the availability and capacity of oil and natural gas gathering systems, pipelines and other transportation facilities owned by third parties. Transportation space on the gathering systems and pipelines we utilize is occasionally limited or unavailable due to repairs or improvements to facilities, weather-related operational issues, or due to space being utilized by other companies that have priority transportation agreements. Additionally, new fields may require the construction of gathering systems and other transportation facilities. These facilities may require us to spend significant capital that would otherwise be spent on drilling. The availability of markets is beyond our control. If market factors dramatically change, the impact on our revenues could be substantial and could adversely affect our ability to produce and market oil and natural gas. Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand.

In addition, the amount of oil and natural gas that can be produced and sold may be subject to curtailment in certain other circumstances outside of our or our operators’ control, such as pipeline interruptions due to maintenance, excessive pressure, inability of downstream processing facilities to accept unprocessed gas, physical damage to the gathering system or transportation system or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we and our operators are provided with limited notice, if any, as to when these curtailments will arise and the duration of such curtailments. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our acreage, could materially and adversely affect our financial condition, results of operations and cash available for distribution.

We depend upon one significant purchaser for the sale of a substantial portion of our oil and natural gas production. The loss of this purchaser or other third parties on which we rely could, among other factors adversely affect our revenues.

We depend upon one significant purchaser for the sale of a substantial portion of our oil and natural gas production, and our contract with this customer is on a month-to-month basis. For example, for the year ended December 31, 2021, Shell Trading US Company represented approximately 18% of our consolidated revenues. The loss of this customer could materially and adversely affect our revenues and have a material and adverse effect on our financial condition and results of operations.

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Risks related to regulatory matters

Our drilling and production programs may not be able to obtain access on commercially reasonable terms or otherwise to truck transportation, pipelines, transmission, storage and processing facilities to market our production, and our initiatives to expand our access to midstream and operational infrastructure may be unsuccessful.

The marketing of oil and natural gas production depends in large part on the availability, proximity and capacity of pipelines and storage facilities, gathering systems and other transportation, processing, fractionation, refining and export facilities, as well as the existence of adequate markets. Transportation space on the gathering systems and pipelines we utilize is occasionally limited or unavailable due to repairs or improvements to facilities or due to space being utilized by other companies that have priority transportation agreements. Additionally, new fields may require the construction of gathering systems and other transportation facilities. These facilities may require us to spend significant capital that would otherwise be spent on drilling. We rely, and expect to rely in the future, on facilities developed and owned by third parties in order to store, process, transmit and sell our production. Our plans to develop and sell our reserves could be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient facilities and services to us on commercially reasonable terms or otherwise. If these facilities are unavailable to us on commercially reasonable terms or otherwise, we could be forced to shut in some production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons. The availability of markets is beyond our control. If market factors dramatically change, the impact on our revenues could be substantial and could materially and adversely affect our ability to produce and market oil and natural gas.

Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. The interstate transportation and sale for resale of natural gas are subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by FERC. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. FERC’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas. FERC regulates the rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines under the NGA as well as under Section 311 of the NGPA. Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open-access, nondiscriminatory basis.

Our sales of oil and NGLs are also affected by the availability, terms and costs of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil and NGLs by pipelines are regulated by FERC under the Interstate Commerce Act. FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil and NGL pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil and NGL pipeline rates. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

As an alternative to pipeline transportation, any transportation of our crude oil and NGLs by rail will also be subject to regulation by the PHMSA and the FRA of the DOT under the Hazardous Materials Regulations at 49 CFR Parts 171-180, including Emergency Orders by the FRA and new regulations being proposed by the PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation of flammable liquids.

Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have a material and adverse effect on our financial condition, results of operations and cash flows.

Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners and other sources for use in our operations. Some areas in which we have operations have experienced drought conditions that could result in restrictions on water use. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and natural gas in the affected areas, which could have a material and adverse effect on our financial condition, results of operations and cash flows.

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We may face unanticipated water and other waste disposal costs.

We may be subject to regulation that restricts our ability to discharge water produced as part of our production operations. Productive zones frequently contain water that must be removed in order for the oil and natural gas to produce, and our ability to remove and dispose of sufficient quantities of water from the various zones will determine whether we can produce oil and natural gas in commercial quantities. The produced water must be transported from the leasehold and/or injected into disposal wells. The availability of disposal wells with sufficient capacity to receive all of the water produced from our wells may affect our ability to produce our wells. Also, the cost to transport and dispose of that water, including the cost of complying with regulations concerning water disposal, may reduce our profitability. Where water produced from our projects fails to meet the quality requirements of applicable regulatory agencies, our wells produce water in excess of the applicable volumetric permit limits, the disposal wells fail to meet the requirements of all applicable regulatory agencies, or we are unable to secure access to disposal wells with sufficient capacity to accept all of the produced water, we may have to shut in wells, reduce drilling activities, or upgrade facilities for water handling or treatment. The costs to dispose of this produced water may increase if any of the following occur:

•we cannot obtain future permits from applicable regulatory agencies;

•water of lesser quality or requiring additional treatment is produced;

•our wells produce excess water;

•new laws and regulations require water to be disposed in a different manner; or

•costs to transport the produced water to the disposal wells increase.

The disposal of fluids gathered from oil and natural gas producing operations in underground disposal wells has been pointed to by some groups and regulators as a potential cause of increased induced seismic events in certain areas of the country, particularly in Oklahoma, Texas, Colorado, Kansas, New Mexico and Arkansas. Several states have adopted or are considering adopting laws and regulations that may restrict or otherwise prohibit oilfield fluid disposal in certain areas or underground disposal wells, and state agencies implementing those requirements may issue orders directing certain wells in areas where seismic incidents have occurred to restrict or suspend disposal well operations or impose standards related to disposal well construction and monitoring. For example, in September 2021 the TRC issued a notice to operators in the Midland area to reduce daily injection volumes following multiple earthquakes above a 3.5 magnitude over an 18 month period. The notice also required disposal well operators to provide injection data to TRC staff to further analyze seismicity in the area. Subsequently, the TRC ordered the indefinite suspension of all deep oil and gas produced water injection wells in the area, effective December 31, 2021. While we cannot predict the ultimate outcome of these actions, any action that temporarily or permanently restricts the availability of disposal capacity for produced water or other oilfield fluids may increase our costs or have other adverse impacts on our operations.

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company as defined under that statute. We believe that the Springfield Gathering System in which we own an interest meets the traditional tests FERC has used to establish a pipeline’s status as a gathering pipeline not subject to regulation by FERC. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is fact intensive and the subject of ongoing litigation, so the classification and regulation of our gathering facilities may be subject to change based on future determinations by FERC, the courts or the U.S. Congress. If FERC were to consider the status of the gathering system and determine that it is subject to FERC regulation, the rates for, and terms and conditions of, services provided by that gathering system would be subject to modification by FERC under the NGA or the NGPA. Such regulation could decrease revenue, increase operating costs, and adversely affect our business, financial condition, and results of operations.

While our natural gas gathering operations are generally exempt from FERC regulation under the NGA, our natural gas gathering operations may be subject to certain FERC reporting and posting requirements in a given year. Gathering service, which occurs on pipeline facilities located upstream of FERC-jurisdictional interstate transmission services, is regulated by the states onshore and in state waters. Depending on changes in the function performed by particular pipeline facilities, FERC has in the past reclassified certain FERC-jurisdictional transportation facilities as non-jurisdictional gathering facilities, and FERC

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has reclassified certain non-jurisdictional gathering facilities as FERC-jurisdictional transportation facilities. Any such changes could result in an increase to our costs. Other FERC regulations may indirectly affect our businesses and the markets for products derived from these businesses. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, natural gas quality, ratemaking, capacity release and market center promotion, may indirectly affect the intrastate natural gas market. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to transportation capacity.

In addition, the pipelines used to gather and transport natural gas being produced by us are also subject to regulation by the DOT through PHMSA. PHMSA has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. These standards may be revised by PHMSA over time. For example, in October 2019, PHMSA published three final rules that create or expand reporting, inspection, maintenance, and other pipeline safety obligations. As part of the Consolidated Appropriations Act of 2021, the U.S. Congress reauthorized PHMSA through 2023 and directed the agency to move forward with several regulatory actions, including but not limited to the issuance of final regulations to require operators of non-rural gas gathering lines and new and existing transmission and distribution pipeline facilities to conduct certain leak detection and repair programs and to require facility inspection and maintenance plans to align with those regulations. A rule to address certain of these requirements was issued in November 2021, which modified pipeline repair criteria, increased monitoring and reporting obligations, and expanded regulatory safety requirements to certain gathering lines in rural areas. PHMSA is continuing to work on developing additional regulations related to safety oversight of gas gathering pipelines, and additional future regulatory action expanding PHMSA’s jurisdiction and imposing stricter integrity management requirements is possible. The adoption of laws or regulations that apply more comprehensive or stringent safety standards could require us to install new or modified safety controls, pursue new capital projects, or conduct maintenance programs on an accelerated basis, all of which could require us to incur increased operating costs that could be significant. In addition, should we fail to comply with PHMSA or comparable state regulations, we could be subject to substantial fines and penalties. As of May 3, 2021, the maximum civil penalties PHMSA can impose are $225,134 per violation per day, with a maximum of $2,251,334 for a related series of violations.

Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

Under the Domenici-Barton Energy Policy Act of 2005, FERC has civil penalty authority under the NGA and the NGPA to impose penalties for current violations of up to $1,388,496 per day (adjusted annually for inflation) for each violation and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional operations to FERC annual reporting and posting requirements. We also must comply with the anti-market manipulation rules enforced by FERC. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability, as described in “Part I, Items 1 and 2. Business and Properties – Legislative and regulatory environment.”

Our sales of oil and natural gas, and any hedging activities related to such energy commodities, expose us to potential regulatory risks.

Sales of oil natural gas and NGLs are not currently regulated and are made at negotiated prices. However, the federal government historically has been active in the area of oil and natural gas sales regulation. We cannot predict whether new legislation to regulate oil and natural gas sales might be proposed, what proposals, if any, might actually be enacted by the U.S. Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations.

Additionally, FERC, the FTC and the CFTC hold statutory authority to monitor certain segments of the physical and futures energy commodities markets relevant to our business. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of oil and natural gas, and any hedging activities related to these energy commodities, we are required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority. These agencies have substantial enforcement authority, including the ability to impose penalties for current violations of $1,388,496 per day (adjusted annually for inflation) by FERC, $1,227,202 (adjusted annually for inflation) by the CFTC, and $1,323,791 (adjusted annually for inflation) by the FTC, for each violation. The FERC has also imposed requirements related to reporting of natural gas sales volumes that may impact the formation of prices indices. Additional rules and legislation pertaining to these and other matters may be considered or adopted from time to time. Our failure to comply with these or other laws and regulations administered by these agencies could subject us to criminal and civil penalties, as described in Part I, Items 1 and 2. Business and Properties—Legislative and regulatory environment. Failure to

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comply with such regulations, as interpreted and enforced, could materially and adversely affect our financial condition or results of operations.

The adoption of derivatives legislation and regulations by the U.S. Congress related to derivative contracts could have a material and adverse effect on our ability to hedge risks associated with our business.

Title VII of Dodd-Frank establishes federal oversight and regulation of over-the-counter (“OTC”) derivatives and requires the CFTC and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the OTC market. Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant definitions and/or exemptions still remain to be finalized.

In one of its rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC issued on January 30, 2020, a re-proposed rule imposing position limits for certain futures and option contracts in various commodities (including oil and natural gas) and for swaps that are their economic equivalents. Under the proposed rules on position limits, certain types of hedging transactions are exempt from these limits on the size of positions that may be held, provided that such hedging transactions satisfy the CFTC’s requirements for certain enumerated “bona fide hedging” transactions or positions. A final rule has not yet been issued.

The CFTC has also adopted final rules regarding aggregation of positions, under which a party that controls the trading of, or owns 10% or more of the equity interests in, another party will have to aggregate the positions of the controlled or owned party with its own positions for purposes of determining compliance with position limits unless an exemption applies. The CFTC’s aggregation rules are now in effect, though CFTC staff have granted relief—until August 12, 2022—from various conditions and requirements in the final aggregation rules. With the implementation of the final aggregation rules and upon the adoption and effectiveness of final CFTC position limits rules, our ability to execute our hedging strategies described above could be limited. It is uncertain at this time whether, when and in what form the CFTC’s proposed new position limits rules may become final and effective.

The CFTC issued a final rule on the amount of capital certain swap dealers and major swap participants are required to set aside with respect to their swap business on July 22, 2020. This rule may require our swap dealer counterparties to post additional capital as a result of entering into uncleared financial derivatives with us, which could increase the costs to us of future financial derivatives transactions.

The CFTC issued a final rule on margin requirements for uncleared swap transactions on January 6, 2016, which includes an exemption from any requirement to post margin to secure uncleared swap transactions entered into by commercial end-users to hedge commercial risks affecting their business. In addition, the CFTC has issued a final rule authorizing an exemption from the otherwise applicable mandatory obligation to clear certain types of swap transactions through a derivatives clearing organization and to trade such swaps on a regulated exchange, which exemption applies to swap transactions entered into by commercial end-users to hedge commercial risks affecting their business. The mandatory clearing requirement currently applies only to certain interest rate swaps and credit default swaps, but the CFTC could act to impose mandatory clearing requirements for other types of swap transactions. The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations.

All of the above regulations could increase the costs to us of entering into financial derivative transactions to hedge or mitigate our exposure to commodity price volatility and other commercial risks affecting our business. The Volcker Rule provisions of the Dodd-Frank Act may also require our current bank counterparties that engage in financial derivative transactions to spin off some of their derivatives activities to separate entities, which separate entities may not be as creditworthy as the current bank counterparties. Under such rules, other bank counterparties may cease their current business as hedge providers. These changes could reduce the liquidity of the financial derivatives markets thereby reducing the ability of entities like us, as commercial end-users, to have access to financial derivatives to hedge or mitigate our exposure to commodity price volatility.

As a result, the Dodd-Frank Act and any new regulations issued thereunder could significantly increase the cost of derivative contracts (including through requirements to post cash collateral), which could adversely affect our capital available for other commercial operations purposes, materially alter the terms of future swaps relative to the terms of our existing bilaterally negotiated financial derivative contracts and reduce the availability of derivatives to protect against commercial risks we encounter.

If we reduce our use of derivative contracts as a result of the new requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil, natural gas and NGL prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas and NGL. Our revenues

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could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material and adverse effect on our consolidated financial condition, results of operations or cash flows.

Our ability to pursue our business strategies may be adversely affected if we incur costs and liabilities due to a failure to comply with environmental laws or regulations or a release of hazardous substances or other wastes into the environment.

We may incur significant costs and liabilities as a result of environmental requirements applicable to the operation of our wells, gathering systems and other facilities. These costs and liabilities could arise under a wide range of federal, state and local environmental laws and regulations, including, for example, the following federal laws and their state counterparts, as amended from time to time:

•the CAA, which restricts the emission of air pollutants from many sources, imposes various pre-construction, monitoring and reporting requirements and is relied upon by the EPA as authority for adopting climate change regulatory initiatives relating to GHG emissions;

•the CWA, which regulates discharges of pollutants from facilities to state and federal waters and establish the extent to which waterways are subject to federal jurisdiction and rulemaking as protected waters of the United States;

•the OPA, which imposes liabilities for removal costs and damages arising from an oil spill into waters of the United States;

•the SDWA, which protects the quality of the nations’ public drinking water through adoption of drinking water standards and control over the subsurface injection of fluids into belowground formations;

•the RCRA, which imposes requirements for the generation, treatment, storage, transport disposal and cleanup of non-hazardous and hazardous wastes;

•the CERCLA, which imposes liability without regard for fault on generators, transporters and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur, as well as on present and certain past owners and operators of sites were hazardous substance releases have occurred or are threatening to occur;

•the Emergency Planning and Community Right-to-Know Act, which requires facilities to implement a safety hazard communication program and disseminate information to employees, local emergency planning committees and response departments about toxic chemical uses and inventories; and

•the ESA, which restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating limitations or restrictions or a temporary, seasonal or permanent ban on operations in affected areas. Similar protections are afforded to migratory birds under the MBTA.

These U.S. laws and their implementing regulations, as well as state counterparts, generally restrict the level of pollutants emitted to ambient air, discharges to surface water, and disposals or other releases to surface and below-ground soils and ground water. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective actions obligations, the incurrence of capital expenditures, the occurrence of delays in the permitting, development or expansion of projects and the issuance of orders enjoining some or all of our future operations in a particular area. Compliance with more stringent standards and other environmental regulations could prohibit our ability to obtain permits for operations or require us to install additional pollution control equipment, the costs of which could be significant. Certain environmental laws and analogous state laws and regulations impose strict joint and several liability, without regard to fault or legality of conduct, for costs required to clean up and restore sites where hazardous substances or other wastes have been disposed of or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, wastes or other materials into the environment. In addition, these laws and regulations may restrict the rate of oil or natural gas production. Historically, our environmental compliance costs have not had a material and adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material and adverse effect on our business and operating results.

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Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially and adversely affected. See Part I, Items 1 and 2. Business and Properties—Legislative and regulatory environment.

We are subject to complex federal, state, local and other laws and regulations that could materially and adversely affect the cost, manner or feasibility of conducting our operations.

Our oil and natural gas operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Failure or delay in obtaining regulatory approvals or drilling permits could have a material and adverse effect on our ability to develop our properties, and receipt of drilling permits with onerous conditions could increase our compliance costs. In addition, regulations regarding conservation practices and the protection of correlative rights affect our operations by limiting the quantity of oil and natural gas we may produce and sell.

We are subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration, production and transportation of oil and natural gas. The possibility exists that new laws, regulations or enforcement policies could be more stringent and significantly increase our compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our financial condition could be materially and adversely affected.

For example, the TRC has adopted rules and regulations implementing legislation mandating certain clean-up activities for inactive wells and additional requirements related to the approval of plugging extensions. Failure to comply can result in administrative penalties and the loss of an operator’s ability to conduct operations in Texas. A major component of the law is Rule 15, which requires a well operator to comply with certain inactive well clean-up activities, including the disconnection of electricity, purging of all production fluids from inactive lines and tanks and removal of surface equipment for wells that have not produced oil or gas during the preceding year. Noncompliance with Rule 15 could result in administrative penalties of up to $10,000 per violation per day and the loss of an operator’s ability to conduct operations in Texas.

Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. Various proposals and proceedings that might affect the petroleum industry are pending before the U.S. Congress, FERC, various state legislatures and the courts. The industry historically has been heavily regulated and we cannot provide assurance that the less stringent regulatory approach recently pursued by FERC and the U.S. Congress will continue nor can we predict what effect such proposals or proceedings may have on our operations.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas may have a material and adverse effect on our business, financial condition, results of operations and cash flows.

Our operations are subject to a series of risks arising from climate change.

Climate change continues to attract considerable public and scientific attention. As a result, our operations as well as the operations of our non-operated assets are subject to a series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of GHG. At the federal level, no comprehensive climate change law or regulation has been implemented to date. The EPA has, however, adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, and together with DOT, implement GHG emissions limits on vehicles manufactured for operation in the United States. The federal regulation of methane emissions from oil and gas facilities has been subject to controversy in recent years. For more information, see Part I, Items 1 and 2. Business and Properties—Legislative and regulatory environment—Air emissions.

Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of GHG emissions. For example, California, through CARB, has implemented a cap and trade program for GHG emissions that sets a statewide maximum limit on covered GHG emissions, and this cap declines annually to reach 40% below 1990 levels by 2030. Covered entities must either reduce their GHG emissions or purchase allowances to

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account for such emissions. Separately, California has implemented LCFS and associated tradable credits that require a progressively lower carbon intensity of the state’s fuel supply than baseline gasoline and diesel fuels. CARB has also promulgated regulations regarding monitoring, leak detection, repair and reporting of methane emissions from both existing and new oil and gas production facilities. Similar regulations applicable to oil and gas facilities have been promulgated in Colorado.

Internationally, the United Nations-sponsored “Paris Agreement” requires member states to individually determine and submit non-binding emission reduction targets every five years after 2020. Although the United States had withdrawn from the agreement, President Biden has signed executive orders recommitting the United States to the agreement and, in April 2021, announced a target of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. In November 2021, the international community gathered again in Glasgow at the COP26, during which multiple announcements were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-CO2 GHGs. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. The impacts of these orders, pledges, agreements any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, COP26, or other international conventions cannot be predicted at this time.

Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change related pledges made by the recently elected administration. These have included promises to limit emissions and curtail the production of oil and gas on federal lands, such as through the cessation of leasing public land for hydrocarbon development. For example President Biden has issued several executive orders focused on addressing climate change, including items that may impact our costs to produce, or demand for, oil and gas. Additionally, in November 2021, the Biden Administration released “The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” which establishes a roadmap to net zero emissions in the United States by 2050 through, among other things, improving energy efficiency; decarbonizing energy sources via electricity, hydrogen, and sustainable biofuels; and reducing non-CO2 GHG emissions, such as methane and nitrous oxide. The Biden Administration is also considering revisions to the leasing and permitting programs for oil and gas development on federal lands. For more information, see our regulatory disclosure in Part I, Items 1 and 2. Business and Properties—Hydraulic fracturing. Other actions that could be pursued by the Biden Administration may include the imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities, as well as more restrictive GHG emission limitations for oil and gas facilities. Litigation risks are also increasing, as a number of parties have sought to bring suit against oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed climate change or alleging that companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts.

There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies may elect in the future to shift some or all of their investments into non-fossil fuel related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. For example, at COP26, the GFANZ announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. Recently, President Biden signed an executive order calling for the development of a “climate finance plan” and, separately, the Federal Reserve announced that it has joined the NGFS, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Most recently, in November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities. Additionally, the SEC has announced its intention to promulgate rules requiring climate disclosures. Although the form and substance of these requirements is not yet known, this may result in additional costs to comply with any such disclosure requirements.

The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from oil and natural gas producers, such as ourselves or our operators, or otherwise restrict the areas in which we may produce oil and natural gas or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for or erode value for, the oil and natural gas that we produce. Additionally, political, litigation, and financial risks may result in our restricting or canceling oil and natural gas production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing our ability to continue to operate in an economic manner. Moreover, climate change may also result in various

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physical risks, such as the increased frequency or intensity of extreme weather events (including storms, wildfires, and other natural disasters) or changes in meteorological and hydrological patterns, that could adversely impact our operations, as well as those of our operators and their supply chains. Such physical risks may result in damage to our facilities or otherwise adversely impact our operations, such as if we become subject to water use curtailments in response to drought, or demand for our products, such as to the extent warmer winters reduce the demand for energy for heating purposes. Such physical risks may also impact our supply chain or infrastructure on which we rely to produce or transport our products.One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.

Hydraulic fracturing is an important and common practice that is used to stimulate production of oil, natural gas and NGLs from dense subsurface rock formations. We and the operators of our properties regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into targeted geological formations to fracture the surrounding rock and stimulate production. The U.S. Congress from time to time has considered legislation to amend the SDWA to remove the exemption currently available to hydraulic fracturing, which would place additional regulatory burdens upon hydraulic fracturing operations including requirements to obtain a permit prior to commencing operations adhering to certain construction requirements, to establish financial assurance, and to require reporting and disclosure of the chemicals used in those operations. This legislation has not passed.

Hydraulic fracturing (other than that using diesel) is currently generally exempt from regulation under the SDWA’s UIC program and is typically regulated by state oil and natural gas commissions or similar agencies. However, several federal agencies have asserted regulatory authority or pursued investigations over certain aspects of the process. For example, in June 2016, the EPA published an effluent limitations guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants.

Also, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain limited circumstances. To date, EPA has taken no further action in response to the December 2016 report.

In addition, the BLM finalized a rule in March 2015 for hydraulic fracturing activities on federal and Tribal lands that requires public disclosure of chemicals used in hydraulic fracturing, confirmation that the wells used in fracturing operations meet proper construction standards and development of plans for managing related flowback water. While the BLM rescinded these regulations in 2017, which rescission was upheld, an appeal of this decision is ongoing. Additionally, these regulations may be reconsidered by the Biden Administration. The Biden Administration may also pursue further restriction of hydraulic fracturing and other oil and gas development on federal lands; for more information, see our regulatory disclosure in Part I, Items 1 and 2. Business and Properties—Hydraulic fracturing.

In addition, some states, including Texas, have adopted, and other states are considering adopting, regulations that restrict or could restrict hydraulic fracturing in certain circumstances and that require the disclosure of the chemicals used in hydraulic fracturing operations. Further, state and local governmental entities have exercised the regulatory powers to regulate, curtail or in some cases prohibit hydraulic fracturing. For example, Colorado has adopted, and California is considering adopting, more stringent setbacks for oil and gas development. New laws or regulations that impose new obligations on, or significantly restrict hydraulic fracturing, could make it more difficult or costly for us to perform hydraulic fracturing activities and thereby affect our determination of whether a well is commercially viable and increase our cost of doing business. Such increased costs and any delays or curtailments in our production activities could have a material and adverse effect on our business, prospects, financial condition, results of operations and liquidity.

Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife, such as those restrictions imposed under the federal ESA and MBTA. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. We may conduct operations on oil and natural gas leases in areas where

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certain species that are listed as threatened or endangered are known to exist and where other species, such as the dunes sagebrush lizard, lesser prairie chicken, and greater sage grouse, that potentially could be listed as threatened or endangered under the ESA may exist. A review is currently pending to determine whether the dunes sagebrush lizard should be listed and, on June 1, 2021, the FWS proposed to list two distinct population segments of the lesser prairie-chicken under the ESA. Additionally, the Biden Administration has taken action to broaden enforcement under the ESA, including expanding the definition of “critical habitat.” The designation of previously unprotected species in areas where we operate as threatened or endangered, a recategorization of a species from threatened to endangered, or an expansion of areas designated as “critical habitat” could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration, development and production activities that could have an adverse impact on our ability to develop and produce our reserves. To the extent species are listed under the ESA or similar laws, or previously unprotected species are designated as threatened or endangered in areas where our properties are located, operations on those properties could incur increased costs arising from species protection measures and face delays or limitations with respect to production activities thereon.

Increased attention to ESG matters and conservation measures may adversely impact our business.

Increasing attention to climate change, societal expectations on companies to address climate change, investor and societal expectations regarding voluntary ESG disclosures, and consumer demand for alternative forms of energy may result in increased costs, reduced demand for our products, reduced profits, increased investigations and litigation, and negative impacts on our stock price and access to capital markets. Increasing attention to climate change and environmental conservation, for example, may result in demand shifts for oil and natural gas products and additional governmental investigations and private litigation against us or our operators. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors.

Moreover, while we may create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures are based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters. We may also announce participation in, or certification under, various third-party ESG frameworks in an attempt to improve our ESG profile, but such participation or certification may be costly and may not achieve the desired results. Additionally, while we may announce various voluntary ESG targets, such targets are aspirational. We may not be able to meet such targets in the manner or on such a timeline as initially contemplated, including but not limited to as a result of unforeseen costs or technical difficulties associated with achieving such results. To the extent we meet such targets, it may be achieved through various contractual arrangements, including the purchase of various credits or offsets that may be deemed to mitigate our ESG impact instead of actual changes in our ESG performance. Also, despite these aspirational goals and any other actions taken, we may receive pressure from investors, lenders, or other groups to adopt more aggressive climate or other ESG-related goals, but we cannot guarantee that we will be able to implement such goals because of potential costs or technical or operational obstacles.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our access to and costs of capital. Also, institutional lenders may decide not to provide funding for fossil fuel energy companies based on climate change related concerns, which could affect our access to capital for potential growth projects. Additionally, to the extent ESG matters

negatively impact our reputation, we may not be able to compete as effectively to recruit or retain employees, which may adversely affect our operations. ESG matters may also impact our suppliers and customers, which may ultimately have adverse impacts on our operations.

Risks related to our indebtedness

We are partially dependent on our Revolving Credit Facility and continued access to capital markets to successfully execute our operating strategies.

If we are unable to make capital expenditures or acquisitions because we are unable to obtain capital or financing on satisfactory terms, we may experience a decline in our oil and gas production rates and reserves. We are partially dependent on external capital sources to provide financing for certain projects. The availability and cost of these capital sources is cyclical,

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and these capital sources may not remain available, or we may not be able to obtain financing at a reasonable cost in the future. Over the last few years, conditions in the global capital markets have been volatile, making terms for certain types of financing difficult to predict, and in certain cases, resulting in certain types of financing being unavailable. If our revenues decline as a result of lower oil, gas or NGL prices, operating difficulties, declines in production or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. Our failure to obtain additional financing could result in a curtailment of our operations or not make acquisitions, which in turn could lead to a possible reduction in our oil or gas production, reserves and revenues, not having sufficient liquidity to meet future financial obligations and could negatively impact our results of operations.

The reduction in the borrowing base under our Revolving Credit Facility, and any further reductions as a result of periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

Our primary sources of liquidity are borrowings under our Revolving Credit Facility and cash from operations. The borrowing base under our Revolving Credit Facility is subject to semi-annual redeterminations which occur on or about April 1 and Oct 1 of each year. During a borrowing base redetermination, the lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our Revolving Credit Facility. The borrowing base depends on, among other things, projected revenues from, and asset values of, the oil and natural gas properties securing our loan, many of which factors are beyond our control.

If we experience liquidity concerns, we could face a downgrade in our debt ratings which could restrict our access to, and negatively impact the terms of, current or future financings or trade credit.

Our ability to obtain financings and trade credit and the terms of any financings or trade credit is, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term production growth opportunities, liquidity, asset quality, cost structure, product mix and commodity pricing levels. A ratings downgrade could adversely impact our ability to access financings or trade credit and increase our borrowing costs.

The borrowings under our Revolving Credit Facility expose us to interest rate risk.

We are exposed to interest rate risk associated with borrowings under our Revolving Credit Facility. Borrowings under the Revolving Credit Facility bear interest at either a U.S. dollar alternative base rate (based on the prime rate, the federal funds effective rate or an adjusted LIBOR), plus an applicable margin or LIBOR, plus an applicable margin, at the election of the borrowers. As a result of our variable interest debt, our results of operations could be adversely affected by increases in interest rates.

Risks related to our common stock

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, stockholders could lose confidence in our financial reporting, which would harm our business and the trading price of our Class A Common Stock.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our Class A Common Stock.

An active, liquid and orderly trading market for our Class A Common Stock may not develop or be maintained.

Prior to the Merger Transactions, our Class A Common Stock had not been traded on any market. An active, liquid and orderly trading market for our Class A Common Stock may not be maintained. Active, liquid and orderly trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. Consequently, you may not be able to sell shares of our Class A Common Stock at prices equal to or greater than the assumed price attributable to such shares.

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The stock markets in general have experienced extreme volatility that has often been unrelated or disproportionate to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our Class A Common Stock. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against us could result in very substantial costs, divert management’s attention and resources and harm our business, operating results and financial condition.

Future sales of our Class A Common Stock in the public market, or the perception that such sales may occur, could reduce the price of our Class A Common Stock, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

We may sell additional shares of our Class A Common Stock in subsequent offerings. In addition, subject to certain limitations and exceptions, OpCo Unit Holders may redeem their OpCo Units (together with a corresponding number of shares of our Class B Common Stock) for shares of our Class A Common Stock (on a one-for-one basis, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions) and then sell those shares of our Class A Common Stock. We have 41,954,385 outstanding shares of Class A Common Stock (including 3,270,915 shares of our Class A Common Stock issued to holders of Contango PSU Awards, of which 1,150,991 shares of treasury stock were repurchased to meet employee payroll tax withholding obligations) and 127,536,463 outstanding shares of Class B Common Stock. Independence’s former owners own all of the outstanding shares of our Class B Common Stock, representing approximately 75% of our total outstanding common stock. All such shares are restricted from immediate resale under the federal securities laws and are subject to certain lock-up agreements, but may be sold into the market in the future. The registration rights agreement we entered into at closing of the Merger Transactions requires us to effect the registration of their shares in certain circumstances following the six month anniversary of Closing.

In addition, we filed a registration statement with the SEC on Form S-8 providing for the registration of 4,218,398 shares of our Class A Common Stock issued or reserved for issuance under the Contango Incentive Plan, as proposed to be amended and assumed by us and our Class A Common Stock issued or reserved for issuance under the Equity Incentive Plan. Subject to the satisfaction of vesting conditions, the expiration of lock-up agreements and the requirements of Rule 144, shares registered under the registration statement on Form S-8 have been made available for resale immediately in the public market without restriction.

We cannot predict the size of future issuances of our Class A Common Stock or securities convertible into Class A Common Stock or the effect, if any, that future issuances and sales of shares of our Class A Common Stock will have on the market price of our Class A Common Stock. Sales of substantial amounts of our Class A Common Stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A Common Stock.

If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding the our Class A Common Stock or if our operating results do not meet their expectations, the trading price of our Class A Common Stock could decline.

The trading market for our Class A Common Stock will be influenced by the research and reports that industry or securities analysts publish about us or its business. If one or more of these analysts cease coverage of us or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover us downgrades our Class A Common Stock or if our operating results do not meet their expectations, the trading price of our Class A Common Stock could decline.

Risks related to our financial condition

Our hedging activities could result in financial losses or could reduce our net income.

We enter into derivative instrument contracts for a significant portion of our existing production. We plan to continue the practice of entering into hedging arrangements to reduce near-term exposure to commodity prices, protect cash flow and returns and maintain our liquidity.

Our hedging contracts may result in substantial gains or losses. For example, we had realized commodity derivative losses of $528.3 million in 2021; however, there can be no assurance that we will not realize additional losses due to our hedging activities in the future. In addition, if we enter into any hedging contracts and experience a sustained material interruption in our

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production, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flows from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity.

Our ability to use hedging transactions to protect us from future oil and natural gas price declines will be dependent upon oil and natural gas prices at the time we enter into future hedging transactions and our future levels of hedging and, as a result, our future net cash flows may be more sensitive to commodity price changes. In the future, we may be unable to hedge anticipated production volumes on attractive terms or at all, which would subject us to further potential commodity price uncertainty and could adversely affect our net cash provided by operating activities, financial condition and results of operations.

Our price hedging strategy and future hedging transactions will be determined at our discretion. The prices at which we hedge our production in the future will be dependent upon commodities prices at the time we enter into these transactions, which may be substantially higher or lower than current prices. Accordingly, our price hedging strategy may not protect us from significant declines in prices received for our future production. Conversely, our hedging strategy may limit our ability to realize cash flows from commodity price increases. It is also possible that a substantially larger percentage of our future production will not be hedged as compared with the next few years, which would result in our oil and natural gas revenues becoming more sensitive to commodity price fluctuations.

Our hedging transactions could expose us to counterparty credit risk.

Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. This risk of counterparty non-performance is of particular concern given the historical disruptions that have occurred in the financial markets and the significant decline in oil and natural gas prices which could lead to sudden changes in a counterparty’s liquidity, and impair their ability to perform under the terms of the derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions. Furthermore, the bankruptcy of one or more of our hedge providers or some other similar proceeding or liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of amounts owed to us by the distressed entity or entities.

During periods of falling commodity prices, our hedge receivable positions increase, which increases our exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.

Our cash flow will be entirely dependent upon the ability of our operating subsidiaries to make cash distributions to us, the amount of which will depend on various factors.

We currently anticipate that the only source of our earnings will be cash distributions from our operating subsidiaries. The amount of cash that our operating subsidiaries can distribute each quarter to their owners principally depends upon the amount of cash they generate from their operations, which will fluctuate from quarter to quarter based on, among other things:

•the amount of oil and natural gas our operating subsidiaries produce from existing wells;

•market prices of oil, natural gas and NGLs;

•any restrictions on the payment of distributions contained in covenants in the Revolving Credit Facility;

•our operating subsidiaries’ ability to fund their drilling and development plans;

•the levels of investments in each of our operating subsidiaries, which may be limited and disparate;

•the levels of operating expenses, maintenance expenses and general and administrative expenses;

•regulatory action affecting: (i) the supply of, or demand for, oil, natural gas, and NGLs, (ii) operating costs and operating flexibility;

•prevailing economic conditions; and

•adverse weather conditions and natural disasters.

In addition, we do not wholly own all of our operating subsidiaries. As a result, if such operating subsidiaries make distributions, including tax distributions, they will also have to make distributions to their noncontrolling interest owners.

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Certain employees of our operating subsidiaries have profits interests that may require substantial payouts and result in substantial accounting charges.

Certain employees of our operating subsidiaries have profits interests that may require substantial payouts, particularly upon liquidation of any such operating subsidiary or a disposition of assets, and may result in substantial accounting charges. Such payouts are linked to the achievement of certain return thresholds and would be paid in the event of such liquidation or disposition in a proportionate amount to the amount of cash received in respect of such liquidation or disposition. For additional information, please read “Note 13 – Incentive Compensation Arrangements” in the notes to our audited financial statements for the year ended December 31, 2021 included herein.

Our only principal asset is our interest in OpCo; accordingly, we will depend on distributions from OpCo to pay taxes, make payments under the Management Agreement and cover our corporate and other overhead expenses.

We are a holding company and have no material assets other than its ownership interest in OpCo. We will have no independent means of generating revenue or cash flow. To the extent OpCo has available cash and subject to the terms of any current or future indebtedness agreements, we intend to cause OpCo (i) to make pro rata cash distributions to holders of OpCo Units, including us, in an amount sufficient to allow us to pay our taxes and to make payments under the Management Agreement and (ii) to reimburse us for our corporate and other overhead expenses. We generally expect OpCo to fund such distributions out of available cash. When OpCo makes distributions, the holders of OpCo Units will be entitled to receive proportionate distributions based on their interests in OpCo at the time of such distribution. To the extent that we need funds and OpCo or its subsidiaries are restricted from making such distributions or payments under applicable law or regulation or under the terms of any current or future indebtedness agreements, or are otherwise unable to provide such funds, our liquidity and financial condition could be materially adversely affected.

Moreover, because we have no independent means of generating revenue, our ability to make tax payments and payments under the Management Agreement is dependent on the ability of OpCo to make distributions to us in an amount sufficient to cover our tax obligations and obligations under the Management Agreement. This ability, in turn, may depend on the ability of OpCo’s subsidiaries to make distributions to it. The ability of OpCo, its subsidiaries and other entities in which it directly or indirectly holds an equity interest to make such distributions will be subject to, among other things, (i) the applicable provisions of Delaware law (or other applicable jurisdiction) that may limit the amount of funds available for distribution and (ii) restrictions in relevant debt instruments issued by OpCo or its subsidiaries and other entities in which it directly or indirectly holds an equity interest.

Risks related to our governance structure

We are a “controlled company” within the meaning of NYSE rules and, as a result, qualify for and rely on exemptions from certain corporate governance requirements.

Because the Preferred Stockholder is the sole owner of our Non-Economic Series I Preferred Stock and accordingly has the exclusive right to appoint our Board of Directors, we are a controlled company under the Sarbanes-Oxley Act and New York Stock Exchange rules. A controlled company does not need its board of directors to have a majority of independent directors or to form an independent compensation or nominating and corporate governance committee. As a controlled company, we will remain subject to rules of the Sarbanes-Oxley Act and the New York Stock Exchange that require us to have an audit committee composed entirely of independent directors.

If at any time we cease to be a controlled company, we will take all action necessary to comply with the Sarbanes-Oxley Act and New York Stock Exchange rules, including by appointing a majority of independent directors to the our Board of Directors and ensuring we have a compensation committee and a nominating and corporate governance committee, each composed entirely of independent directors, subject to a permitted “phase-in” period.

Our Certificate of Incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or its directors, officers, employees or agents.

Our Certificate of Incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim arising

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pursuant to any provision of the Delaware General Corporation Law, our Certificate of Incorporation or its Bylaws, or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our restated Certificate of Incorporation described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.

Our Preferred Stockholder’s significant voting power limits the ability of holders of our common stock to influence our business.

Our Preferred Stockholder is the sole holder of our Non-Economic Series I Preferred Stock and is expected to retain its ownership of our Non-Economic Series I Preferred Stock until such time as it ceases to own a number of shares of our common stock equal to or greater than 50% of the shares of our Class A Common Stock and our Class B Common Stock it owns, subject to certain exceptions. Our Non-Economic Series I Preferred Stock entitles the holder thereof to appoint our entire Board of Directors and to certain other to approval rights with respect to certain fundamental corporate actions, including debt incurrence in excess of 10% of then outstanding indebtedness, significant equity raises, preferred equity issuances, adoption of a shareholder rights plan, amendments of our certificate of incorporation and certain sections of its bylaws, a sale of all or substantially all of our assets, mergers involving us, removals of our Chief Executive Officer and the liquidation or dissolution of us. Unlike common equity in traditional corporate structures, holders of our common stock will not vote for the election of directors. As a result, holders of our common stock will have less ability to influence our business than would the holders of common equity in a traditional corporate structure.

The Preferred Stockholder’s controlling ownership position may have the effect of delaying or preventing changes in control or changes in management and may adversely affect the trading price of our Class A Common Stock to the extent investors perceive a disadvantage in owning stock of a company with a controlling shareholder.

Given its ownership of the our Non-Economic Series I Preferred Stock, the Preferred Stockholder would have to approve any potential acquisition of us. The existence of a controlling shareholder may have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other shareholders to approve transactions that they may deem to be in our best interests. Moreover, the Preferred Stockholder’s controlling ownership position may adversely affect the trading price of our Class A Common Stock to the extent investors perceive a disadvantage in owning stock of a company with a controlling shareholder, whether due to a decreased likelihood of a sale of us at a premium to the then-existing trading price of our Class A Common Stock or otherwise.

Our Certificate of Incorporation provides that the Preferred Stockholder is, to the fullest extent permitted by law, under no obligation to consider the separate interests of the other stockholders and will contain provisions limiting the liability of the Preferred Stockholder.

To the fullest extent permitted by applicable law, our Certificate of Incorporation contains provisions limiting the duties owed by the Preferred Stockholder and contain provisions allowing the Preferred Stockholder to favor its own interests and the interests of its controlling persons over us and the holders of our common stock. Our Certificate of Incorporation contains provisions stating that the Preferred Stockholder is under no obligation to consider the separate interests of the other stockholders (including the tax consequences to such stockholders) in deciding whether or not to authorize us to take (or decline to authorize us to take) any action as well as provisions stating that the Preferred Stockholder shall not be liable to the other stockholders for damages or equitable relief for any losses, liabilities or benefits not derived by such stockholders in connection with such decisions.

Our Certificate of Incorporation contains a provision renouncing our interest and expectancy in certain corporate opportunities that may prevent us from receiving the benefit of certain corporate opportunities.

The “corporate opportunity” doctrine provides that corporate fiduciaries, as part of their duty of loyalty to the corporation and its stockholders, may not take for themselves an opportunity that in fairness should belong to the corporation. As such, a corporate fiduciary may generally not pursue a business opportunity which the corporation is financially able to undertake and which, by its nature, falls into the line of the corporation’s business and is of practical advantage to it, or in which the corporation has an actual or expectant interest, unless the opportunity is disclosed to the corporation and the corporation

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determines that it is not going to pursue such opportunity. Section 122(17) of the DGCL, however, expressly permits a Delaware corporation to renounce in its certificate of incorporation any interest or expectancy of the corporation in, or in being offered an opportunity to participate in, specified business opportunities or specified classes or categories of business opportunities that are presented to the corporation or its officers, directors or stockholders.

Our Certificate of Incorporation contains a provision that, to the maximum extent permitted under the law of the State of Delaware, we renounce any interest or expectancy in, or in being offered an opportunity to participate in, business opportunities that are from time to time presented to its officers, directors, the Preferred Stockholder or any partner, manager, member, director, officer, stockholder, employee or agent or affiliate of any such holder. We believe that this provision, which is intended to provide that certain business opportunities are not subject to the “corporate opportunity” doctrine, is appropriate, as the Preferred Stockholder and its affiliates invest in a wide array of companies, including companies with businesses similar to us. As a result of this provision, we may be not be offered certain corporate opportunities which could be beneficial to us and our stockholders.

Tax risks

If OpCo were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, we and OpCo might be subject to potentially significant tax inefficiencies.

We intend to operate such that OpCo does not become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes. A “publicly traded partnership” is a partnership the interests of which are traded on an established securities market or are readily tradable on a secondary market or the substantial equivalent thereof. Under certain circumstances, redemptions of OpCo Units pursuant to the Redemption Right or other transfers of OpCo Units could cause OpCo to be treated as a publicly traded partnership. Applicable U.S. Treasury regulations provide for certain safe harbors from treatment as a publicly traded partnership, and we intend to operate such that redemptions or other transfers of OpCo Units qualify for one or more such safe harbors. For example, we intend to limit the number of holders of OpCo Units, and the OpCo LLC Agreement, provides for limitations on the ability of holders of OpCo Units to transfer their OpCo Units and provides us, as the managing member of OpCo, with the right to impose restrictions (in addition to those already in place) on the ability of holders of OpCo Units to redeem their OpCo Units pursuant to the Redemption Right to the extent we believe it is necessary to ensure that OpCo will continue to be treated as a partnership for U.S. federal income tax purposes.

If OpCo were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, significant tax inefficiencies might result for us and OpCo, including as a result of our inability to file a consolidated U.S. federal income tax return with OpCo.

Changes to applicable tax laws and regulations may adversely affect our business, results of operations, financial condition and cash flow.

U.S. federal, state and local and non-U.S. tax laws, policies, statutes, rules, regulations or ordinances could be interpreted, changed, modified or applied adversely to us, in each case, possibly with retroactive effect, and may have an adverse effect on our business, results of operations, financial condition and cash flow. For example, several tax proposals have been set forth that would, if enacted, make significant changes to U.S. tax laws. Such proposals include (i) an increase in the U.S. income tax rate applicable to corporations (such as us) from 21%, (ii) the imposition of a minimum tax on book income for certain corporations and (iii) the imposition of an excise tax on certain corporate stock repurchases that would be borne by the corporation repurchasing such stock. Additionally, in the past, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws affecting the oil and natural gas industry, including (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) the repeal of the percentage depletion allowance for oil and natural gas properties; and (iii) an extension of the amortization period for certain geological and geophysical expenditures. No accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. These proposed changes in the U.S. tax law, if adopted, or other similar changes that would impose additional tax on our activities or reduce or eliminate deductions currently available with respect to natural gas and oil exploration, development or similar activities, could adversely affect our business, results of operations, financial condition and cash flow.

A change of control could limit our use of net operating losses.

As of December 31, 2021, we had a net operating loss, or NOL, carry forward of approximately $423 million for federal income tax purposes, most of which is already limited by Section 382 of the Code. If we were to experience a further “ownership change,” as determined under Section 382 of the Code, our ability to offset taxable income arising after the

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ownership change with NOLs generated prior to the ownership change would be limited, possibly substantially. In general, an ownership change would establish an annual limitation on the amount of our pre-change NOLs that we could utilize to offset our taxable income in any future taxable year to an amount generally equal to the value of our stock immediately prior to the ownership change multiplied by an interest rate periodically promulgated by the IRS referred to as the long-term tax-exempt rate. In general, an ownership change will occur if there is a cumulative increase in the ownership of our stock totaling more than 50 percentage points by one or more “5% shareholders” (as defined in the Code) at any time during a rolling three-year period.

General risks

Loss of our and our operators’ information and computer systems could adversely affect our business.

We are heavily dependent on our information systems and computer based programs, including with respect to our well operations information, seismic data, electronic data processing and accounting data, and the availability and integrity of these programs and systems are essential for us to conduct our business and operations. If any of such programs or systems were to be subject to a cyberattack, to fail or to create erroneous information in our hardware or software network infrastructure, whether due to telecommunications failures, human error, natural disaster, fire, sabotage, hardware or software malfunction or defects, computer viruses, intentional acts of vandalism or terrorism or similar acts or occurrences, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material and adverse effect on our business.

A terrorist attack or armed conflict or associated economic sanctions resulting therefrom could harm our business.

Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Furthermore, beginning in February 2022, the United States and other countries began imposing meaningful sanctions targeting Russia as a result of actions taken by Russia in Ukraine. These sanctions and actions by Russia in response thereto may cause disruptions in international supply chains, financial activities and operations, the full costs, burdens, and limitations of which are currently unknown and may become significant. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

Our business could be negatively affected by security threats, including cyber security threats, and other disruptions and is subject to complex and evolving laws and regulations regarding privacy and data protection.

We face various security threats, including cyber security threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist or criminal actors. The potential for such security threats has subjected our operations to increased risks that could have a material and adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring, particularly given the unpredictability of the timing, nature, and scope of information technology breaches, attacks, disruptions and other incidents. If any of these incidents were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cyber security attacks in particular are becoming more sophisticated and include, but are not limited to, installation of malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. These events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability. While we maintain insurance that covers certain security and privacy breaches, we may not carry appropriate insurance or maintain sufficient coverage to compensate for all potential liability, and such insurance may not continue to be available to us on reasonable terms, if at all.

The regulatory environment surrounding data privacy and protection is constantly evolving and can be subject to significant change. New laws and regulations governing data privacy and the unauthorized disclosure of personal or confidential

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information pose increasingly complex compliance challenges and could potentially elevate our costs. Any failure to comply with these laws and regulations could result in significant penalties and legal liability. We continue to monitor and assess the impact of these laws, which in addition to penalties and legal liability, could impose significant costs for investigations and compliance, require us to change our business practices and carry significant potential liability for our business should we fail to comply with any such applicable laws.

We may be unable to protect our intellectual property rights or be subject to litigation if another party claims that we have infringed upon its intellectual property rights.

We rely on certain intellectual property rights in the operation of our business. The market success of our operations will depend, in part, on our ability to obtain and enforce our proprietary rights in certain technologies, to preserve rights in our trade secret and non-public information, and to operate without infringing the proprietary rights of others. We may not be able to successfully preserve these intellectual property rights in the future and these rights could be invalidated, circumvented, or challenged. If any of our intellectual property rights are determined to be invalid or unenforceable, our competitive advantages could be significantly reduced, allowing competition for our customer base to increase. The failure of our Company to protect our proprietary information and any successful intellectual property challenges or infringement proceedings against us could adversely affect our competitive position. The tools, techniques, methodologies, programs, and components we use in the operation of our business may infringe, or be alleged to infringe, upon the intellectual property rights of others. Infringement claims generally result in significant legal and other costs, and may distract management from running our core business. Royalty payments under a license from third parties, if available, or an obligation to redesign our operations, would increase our costs. Any of these developments could have a material adverse effect on our business, financial condition, and results of operations.

From time to time, we may be involved in legal proceedings that could result in substantial liabilities.

Similar to many oil and natural gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have a material and adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, resolution of one or more such proceedings could result in liability, loss of contractual or other rights, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices. Accruals for such liability, penalties or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.

The inability of one or more of our customers to meet their obligations may materially and adversely affect our financial results.

We are subject to risk of loss resulting from nonpayment or nonperformance by our customers. Substantially all of our accounts receivable result from our oil and natural gas sales to a small number of third parties in the energy industry. This concentration of customers may affect our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks. If any of our key customers default on their obligations to us, our financial results could be materially and adversely affected.

We may be unable to dispose of non-strategic assets on attractive terms and may be required to retain liabilities for certain matters.

We regularly review our asset base to assess the market value versus holding value of existing assets with a view to optimizing returns on deployed capital. Our ability to dispose of assets could be affected by various factors, including the availability of buyers willing to purchase assets at prices acceptable to us. Sellers typically retain certain liabilities or agree to indemnify buyers for certain matters. The magnitude of any such retained liability or indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a sale, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.

Our operations are subject to catastrophic losses, operational hazards and unforeseen interruptions and other disruptive risks for which we may not be adequately insured.

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Our operations are subject to catastrophic losses, operational hazards, unforeseen interruptions and other disruptive risks such as natural disasters, adverse weather, accidents, maritime disasters (including those involving marine vessels/terminals), fires, explosions, hazardous materials releases, terror or cyberattacks, domestic vandalism, power failures, mechanical failures and other events beyond our control. These events could result in an injury, loss of life, property damage or destruction, as well as a curtailment or an interruption in our operations and may affect our ability to meet marketing commitments.

Item 1B. Unresolved Staff Comments

None.

Item 3. Legal Proceedings

The Company may, from time to time, be involved in litigation and claims arising out of its operations in the normal course of business. We are currently unaware of any proceedings that, in the opinion of management, will individually or in the aggregate have a material adverse effect on our financial position, results of operations or cash flows.

The Company, as an owner and operator of oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution cleanup resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. The Company maintains insurance coverage that is customary in the industry, although the Company is not fully insured against all environmental risks.

We were engaged with the Environmental Protection Agency (“EPA”) for alleged violations of the Federal Water Pollution Control Act, as amended, between 2016 and 2018. We have settled these allegations with the EPA and recorded $1.4 million as a liability and expense as of and for the year ended December 31, 2020, all of which was paid in 2021.

On February 14, 2022, the New Mexico Energy, Minerals and Natural Resources Department’s Oil Conservation Division (“OCD”) issued a Notice of Violation to Contango for failure to file form C-115 according to required deadlines and having too many inactive wells. OCD has proposed a civil penalty of $913,200, the plugging and abandonment of certain inactive wells, and the imposition of certain other restrictions on our operations. The parties are discussing a resolution to the matter.

Following the filing of the preliminary joint proxy statement/prospectus related to the Merger Transactions on July 26, 2021, four lawsuits have been filed in the United States District Court for the Southern District of New York, and one lawsuit has been filed in the United States District for the Eastern District of New York, each in connection with the Merger Transactions (the “Shareholder Actions”): Stein v. Contango Oil & Gas Co., et al., No. 1:21-cv-06769 (S.D.N.Y. Aug. 11, 2021) (the “Stein Action”); Prus v. Contango Oil & Gas Co., et al., No. 1:21-cv-04656 (E.D.N.Y. Aug. 18, 2021) (the “Prus Action”); Whitfield v. Contango Oil & Gas Co., et al., No. 1:21-cv-0700 (S.D.N.Y. Aug. 19, 2021) (the “Whitfield Action”); Byerly v. Contango Oil & Gas Co., et al., 1:21-cv-07327 (S.D.N.Y. Aug. 31, 2021) (the “Byerly Action”); Provost v. Contango Oil & Gas Co., et al., 1:21-cv-07874 (S.D.N.Y. Sept. 21, 2021) (the “Provost Action”). Each of the Shareholder Actions names Contango and the members of the Contango board as defendants, and the Whitfield Action names Independence Energy, LLC, OpCo, Crescent Energy Company (f/k/a IE PubCo Inc.) and other affiliates as additional defendants. Each of the Shareholder Actions alleges, among other things, that the registration statement on Form S-4 filed by IE PubCo Inc. on July 26, 2021 in connection with the Merger Transactions (the “Registration Statement”) is false and misleading and/or omits certain information allegedly material to Contango shareholders in violation of Sections 14(a) and 20(a) of the Securities and Exchange Act of 1934 (as amended, the “Exchange Act”) and Rule 14a-9 promulgated thereunder. The plaintiffs in the Shareholder Actions seek, among other relief, an injunction enjoining the Merger Transactions unless and until the defendants disclose the allegedly omitted material information, a rescission of the Contango Agreement to the extent already implemented (or an award of rescissory damages), an order directing the defendants to account for all damages resulting from the alleged wrongdoing, and an award of plaintiffs’ attorneys’ and experts’ fees and other relief. The Byerly Action also requests that the court determine that the lawsuit is a proper class action and certify Byerly as class representative and his counsel as class counsel. On September 20, 2021, the court consolidated the Stein and Whitfield Actions with the Byerly Action. On October 13, 2021, the court consolidated the Provost Action with the Byerly Action. Contango has also received a demand letter sent on behalf of Catherine Coffman, a purported Contango shareholder. The letter demanded that Contango make supplemental disclosures to investors regarding the Merger Transactions based on factual and legal arguments that are substantially similar to those in the Stein, Prus, Whitfield, Byerly, and Provost Actions.

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On November 26, 2021, in order to avoid the risk of the Shareholder Actions delaying the Merger Transactions and to minimize the expense of defending the Shareholder Actions, and without admitting any liability or wrongdoing, Contango and Independence voluntarily made certain disclosures that supplement those contained in the joint proxy statement/prospectus. Thereafter, plaintiffs filed voluntary notices of dismissal dismissing the Whitfield and Prus Actions. Pursuant to a scheduling order issued in the consolidated Byerly Action, plaintiff is required to file a Consolidated Amended Complaint within 10 days of an order appointing Byerly as lead plaintiff in the consolidated action.

We believe that the Shareholder Actions are without merit and, along with the individual and other defendants intend to defend against the Shareholder Actions; however, Crescent cannot predict the amount of time and expense that will be required to resolve the Shareholder Actions nor their outcomes. Additional lawsuits arising out of or related to the Merger Transactions may also be filed in the future.

Item 4. Mine Safety Disclosures

Not applicable

Part II

Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our Class A Common Stock is listed and traded on the NYSE under the ticker symbol "CRGY." As of January 31, 2021, we had 122 Class A common stock shareholders of record and two Class B common stock shareholders of record. We target future dividends to shareholders of 10% of Adjusted EBITDAX, but payments of dividends will depend on our level of earnings, financial requirements and other factors and will be subject to approval by our Board of Directors, applicable law and the terms of our existing debt documents, including the Revolving Credit Facility and the indenture governing the Senior Notes.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table sets forth information with respect to our repurchases of shares of Class A common stock during the quarter ended December 31, 2021.

Period	Total number of shares purchased (1)	Average price paid per share	Total number of shares purchased as part of publicly announced plans or programs	Approximate dollar value of shares that may yet be purchased under the plans or programs.
10/1/2021 - 10/31/2021	—	—	—	—
11/1/2021 - 11/30/2021	—	—	—	—
12/1/2021 - 12/31/2021	1,150,991	$16.03	—	—

(1)     Consists of Class A Common Stock repurchased from employees in order for the employee to satisfy tax withholding obligations related to stock-based compensation that vested during the period.

Recent Sales of Unregistered Equity Securities

We had no sales of unregistered equity securities during the period covered by this Annual Report that were not previously reported in a Current Report on Form 8-K or Quarterly Report on Form 10-Q.

Item 6. Reserved

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

Management's Discussion and Analysis of Financial Condition and Results of Operations ("MD&A") is intended to provide the reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Company's operating results. The following discussion and analysis should be read in conjunction with the Combined and Consolidated Financial Statements and related Notes included in Part II, Item 8 of Part II of this Annual Report and also with "Risk Factors" in Item 1A of this Annual Report. The following information updates the discussion of our financial condition provided in our previous filings, and analyzes the changes in the results of operations between the years ended December 31, 2021 and 2020. Refer to our proxy statement/prospectus (File No.

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333-258157), dated November 3, 2021 for discussion and analysis of the changes in results of operations between the years ended December 31, 2020 and 2019. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward- looking statements. Factors that could cause or contribute to such differences include, but are not limited to, commodity price volatility, capital requirements and uncertainty of obtaining additional funding on terms acceptable to the Company, realized oil, natural gas and NGL prices, the timing and amount of future production of oil, natural gas and NGLs, shortages of equipment, supplies, services and qualified personnel, as well as those factors discussed below and elsewhere in this Annual Report , particularly under “Risk Factors” and “Cautionary Statement Regarding Forward Looking statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Business overview

We are a well-capitalized U.S. independent energy company with a portfolio of assets in key proven basins across the lower 48 states, including the Eagle Ford, Rockies, Barnett, Permian and Mid-Con.

Our approach includes a cash flow-based investment mandate with a focus on operated working interests and is complemented by non-operated working interests, mineral and royalty interests, and midstream infrastructure, as well as an active risk management strategy. We pursue our strategy through the production, development and acquisition of oil, natural gas and NGL reserves.

Merger Transactions

On December 7, 2021, we completed the Merger Transactions, pursuant to which Contango’s business combined with Independence's business under a new publicly traded holding company named "Crescent Energy Company." Our Class A Common Stock is listed on the NYSE under the symbol “CRGY.” The combined company is structured as an “Up-C,” with all of our assets and operations (including those of Crescent Finance, the issuer of the Senior Notes) and those of Contango held by us, as the sole managing member of OpCo and indirect sole managing member of Crescent Finance. Former Contango shareholders now own shares of our Class A Common Stock, which has both voting and economic rights with respect to our Company. The former owners of Independence now own OpCo Units and Class B Common Stock, which have voting (but no economic) rights with respect to our Company. We are a holding company. Our sole material assets consist of OpCo Units. We are the sole managing member of OpCo and are responsible for all operational, management and administrative decisions relating to OpCo's business and consolidate the financial results of OpCo and its subsidiaries, including Crescent Finance, the issuer of the Senior Notes.

For the year ended and month ended December 31, 2021, our results only include 25 days of impact for the assets acquired in the Merger Transactions.

Reorganizations

In August 2020, through a series of transactions, we underwent a reorganization (the "Independence Reorganization") in connection with the Titan Acquisition, carried out under the direction of Independence's Managing Member, as provided within its Amended and Restated Limited Liability Company Agreement dated August 18, 2020, whereby certain entities previously owned and under the common control of affiliates of the KKR Group (the "Contributed Entities") were contributed to us. The financial statements include the accounts of the Contributed Entities from the date of the Independence Reorganization, which is the date we obtained a controlling financial interest in the Contributed Entities on a consolidated basis. As required by GAAP, the contributions of the Contributed Entities in connection with the Independence Reorganization were accounted for as a reorganization of entities under common control, in a manner similar to a pooling of interests, with all assets and liabilities transferred to us at their carrying amounts. The merger of Independence with and into OpCo on December 7, 2021, (as a part of the Merger Transactions) was also accounted for as a reorganization of entities under common control. Because the Independence Reorganization and the Merger Transactions resulted in changes in the reporting entity, and in order to furnish comparative financial information prior to the Independence Reorganization and the Merger Transactions, our financial statements have been retrospectively recast to reflect the historical accounts of the Contributed Entities and Independence, our accounting predecessor (the "Predecessor"), on a combined basis.

Noncontrolling interests

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We record noncontrolling interest associated with third party ownership interests in our subsidiaries. Income or loss associated with these interests is classified as net income (loss) attributable to noncontrolling interest on our combined and consolidated statements of operations.

In April 2021, certain minority interest owners exchanged 100% of their interests in our Barnett basin natural gas assets for 9,508 of our Predecessor's Class A Units as part of the April 2021 Exchange. Since we already consolidate the results of these assets, this transaction was accounted for as an equity transaction and reflected as a reclassification from noncontrolling interests to members’ equity with no gain or loss recognized on exchange.

In December 2020, certain owners of noncontrolling equity interests in certain of our consolidated subsidiaries elected to exchange 100% of their interests in those individual consolidated subsidiaries for 220,421 of our Predecessor's Class A Units (the "December 2020 Exchange"). Since we already consolidate the results of these subsidiaries, this transaction was accounted for as a reclassification of $657.4 million from noncontrolling interest to members’ equity with no gain or loss recognized on the exchange.

In August 2020, in connection with the Independence Reorganization, certain interests in our consolidated subsidiaries owned by a third-party investor were not contributed to the Predecessor. These interests were reclassified from members’ equity to noncontrolling interest as of the date of the Independence Reorganization and all income and loss attributable to these interests is recorded as net income (loss) attributable to noncontrolling interests for the period from the date of the Independence Reorganization through the year-ended December 31, 2021. In May 2021, these noncontrolling equity interests were redeemed in exchange for the third-party investor’s proportionate share of the underlying oil and natural gas interests held by its consolidated subsidiaries (the "Noncontrolling Interest Carve-out"). Additionally, the third-party investor contributed cash of approximately $35.5 million to repay its proportionate share of the underlying debt outstanding under the various agreements to which certain of our operating subsidiaries had historically been party to (the "Prior Credit Agreements") and other liabilities. The percentage ownership of these certain consolidated subsidiaries owned by the third-party investor ranges from 2.21% to 7.38%.

COVID-19 impact

In early 2020, the World Health Organization declared the COVID-19 outbreak a pandemic. There have been mandates from international, federal, state and local authorities requiring forced closures of various schools, businesses and other facilities and organizations. Our workforce worked remotely for a period of time since the pandemic began. Working remotely did not significantly impact our ability to maintain operations and did not cause us to incur significant additional expenses.

The initial spread of the COVID-19 virus in 2020 had a negative impact on the global demand for oil and natural gas, while the increase in domestic vaccination programs and reduced spread of the COVID-19 virus has contributed to an improvement in the economy and higher realized prices for commodities since the beginning of 2021. However, the current price environment remains uncertain as responses to the COVID-19 pandemic and newly emerging variants of the virus continue to evolve. Given the dynamic nature of these events, we cannot reasonably estimate the period of time that the COVID-19 pandemic and related market conditions will persist. While we use derivative instruments to partially mitigate the impact of commodity price volatility, our revenues and operating results depend significantly upon the prevailing prices for oil and natural gas.

Acquisitions, divestitures and related reorganization

Acquisitions and related reorganization

In February 2022, we entered into a Membership Interest Purchase Agreement (the “Purchase Agreement” and the transactions contemplated therein, the “Uinta Transaction”) with Verdun Oil Company II LLC, a Delaware limited liability company (the “Seller”), pursuant to which we agreed to purchase from Seller all of the issued and outstanding membership interests of Uinta AssetCo, LLC, a to-be formed Texas limited liability company which will hold all exploration and production assets of and certain obligations of EP Energy E&P Company, L.P. ("EP") located in the State of Utah (the “Utah Assets”). Upon closing of the Uinta Transaction, Seller will receive aggregate consideration of approximately $815 million in cash and the assumption of certain hedges, subject to certain customary purchase price adjustments set forth in the Purchase Agreement.

The Uinta Transaction is subject to customary closing conditions, including approval by the US Federal Trade Commission of the Transaction or the expiration or termination of any applicable waiting period under the HSR Act (as defined in the Purchase Agreement), and the closing of a transaction between Seller and EP pursuant to which Seller will receive the Utah Assets.

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In connection with the closing of the Uinta Transaction, we anticipate entering into an amendment to our Revolving Credit Facility to, among other things, increase the elected commitment amount to $1.3 billion. However, there can be no assurances we will consummate the Uinta Transaction or that we will enter into such amendment to our Revolving Credit Facility.

In December 2021, we acquired from an unrelated third-party certain operated producing oil and natural gas properties predominately located in the Central Basin Platform in Texas and New Mexico, with additional properties in the southwestern Permian and Powder River Basins, for total cash consideration of $60.4 million, including customary purchase price adjustments (the "Central Basin Platform Acquisition"). The purchase price was funded using cash on hand and borrowings under our Revolving Credit Facility (as defined in NOTE 8 – Debt). We accounted for the Central Basin Platform Acquisition as an asset acquisition.

In May 2021, certain of our consolidated subsidiaries redeemed the noncontrolling equity interests held in such subsidiaries by a third-party investor in exchange for the third-party investor’s proportionate share of the underlying oil and natural gas interests held by its consolidated subsidiaries as part of the "Noncontrolling Interest Carve-out". Additionally, the third-party investor contributed cash of approximately $35.5 million to repay its proportionate share of the underlying debt outstanding under the "Prior Credit Agreements" and other liabilities. The percentage ownership of these certain consolidated subsidiaries owned by the third-party investor ranges from 2.21% to 7.38%.

In April 2021, certain minority investors exchanged 100% of their interests in our Barnett basin natural gas assets for 9,508 of our Class A Units, representing 0.77% of our consolidated ownership pursuant to (the "April 2021 Exchange"). Since we already consolidate the results of these assets, this transaction was accounted for as an equity transaction and reflected as a reclassification from noncontrolling interests to members’ equity with no gain or loss recognized on the April 2021 Exchange.

In March 2021, we acquired a portfolio of oil and natural gas mineral assets located in the DJ Basin from an unrelated third-party operator for total consideration of $60.8 million (the "DJ Basin Acquisition"). The DJ Basin Acquisition was funded using cash on hand and borrowings under our Prior Credit Agreements. We accounted for the DJ Basin Acquisition as an asset acquisition.

In August 2020, we consummated the Titan Acquisition, pursuant to which we acquired of all of the outstanding membership interests in Liberty Energy LLC (and the oil and natural gas assets owned thereby) pursuant to the Contribution Agreement, dated as of July 19, 2020, by and among Independence Energy LLC, Liberty Energy Holdings, LLC (“Liberty Holdco”) and the other parties thereto, in consideration for the issuance of certain membership interests in Independence to an entity substantially owned by Liberty Holdco. Subsequent to the Titan Acquisition, we changed the name of Liberty Energy, LLC to Titan. Titan owns certain working interests in non-operated producing and non-producing oil and natural gas properties in the Permian, DJ and Eagle Ford Basins, which includes a 50% interest in the DJ Basin Erie Hub Gathering System. As a part of the Titan Acquisition, during the year ended December 31, 2020, we transferred $455.1 million of equity consideration in the form of 0.4 million Class A units of our Predecessor.

Divestitures

In December 2021, we entered into an assignment, conveyance and bill of sale with an unaffiliated third-party that encompassed the sale of certain producing properties and oil and natural gas leases in Payne County, Oklahoma in exchange for cash consideration, net of closing adjustments, of $4.3 million.

In May 2021, we executed a purchase and sale agreement with an unaffiliated third-party that encompassed the sale of certain producing properties and oil and natural gas leases in the Arkoma Basin in exchange for cash consideration, net of closing adjustments, of $22.1 million. We recognized a $8.8 million gain on sale of assets in our combined and consolidated statements of operations for the year ended December 31, 2021, as a result of the transaction.

In December 2019, we entered into a term assignment of oil and gas leases conveying all of our interest in the Midland and Ector county leases between the top of the Mississippian formation down to the base of the Woodford formation, “deep rights”, for total bonus consideration of $7.9 million and a primary term of four years from the effective date, January 1, 2020.

In September 2019, we entered into a purchase, sale and exchange agreement with an unaffiliated third-party which encompassed the sale of certain producing properties and exchange of oil and gas leases in the Eagle Ford for consideration of $15.2 million and additional post-closing settlement consideration of $1.8 million.

Environmental, social and corporate governance initiatives

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We are committed to developing industry-leading ESG programs and continually improving our ESG performance. We view exceptional ESG performance as an opportunity to differentiate Crescent from our peers, provide for increased access to capital markets, mitigate risks and strengthen operational performance as well as benefit our stakeholders and the communities in which we operate. In December 2021, we released our inaugural ESG report, which included key performance metrics according to Value Reporting Foundation’s SASB Standard for Oil & Gas – Exploration & Production and also established our key ESG priorities. We also established an ESG Advisory Council to advise management and Crescent Energy Company’s Board of Directors on ESG-related issues. We are working to reduce greenhouse gas (“GHG”) emissions by implementing aggressive methane reduction targets and eliminating routine flaring, among other initiatives.

How we evaluate our operations

We use a variety of financial and operational metrics to assess the performance of our oil, natural gas and NGL operations, including:

•Production volumes sold;

•Commodity prices and differentials;

•Operating expenses;

•Adjusted EBITDAX (non-GAAP); and

•Levered Free Cash Flow (non-GAAP)

Development program and capital budget

Our development program is designed to prioritize the generation of attractive risk-adjusted returns and meaningful free cash flow and is inherently flexible, with the ability to modify our capital program as necessary to react to the current market environment.

We expect to incur approximately $375 million to $425 million, excluding acquisition capital and any development capital related to acquisitions, for our 2022 capital program. Our program is allocated 70 to 75% to our operated assets primarily in the Eagle Ford, 15 to 20% to non-operated activity and approximately 10% to other capital expenditures. We expect to fund our 2022 capital program through cash flow from operations. Due to the flexible nature of our capital program and the fact that our acreage is 98% held by production, we could choose to defer a portion or all of these planned capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing and anticipated prices for oil, gas and NGLs and resulting well economics, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners.

Sources of revenues

Our revenues are primarily derived from the sale of our oil, natural gas and NGL production and are influenced by production volumes and realized prices, excluding the effect of our commodity derivative contracts. Pricing of commodities are subject to supply and demand as well as seasonal, political and other conditions that we generally cannot control. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. The following table illustrates our production revenue mix for each of the periods presented:

	Year Ended December 31,
	2021		2020		2019
Oil	62	%	69	%	75	%
Natural gas	25	%	21	%	17	%
NGLs	13	%	10	%	8	%

In addition, revenue from our midstream assets is supported by commercial agreements that have established minimum volume commitments. These midstream revenues comprise the majority of our midstream and other revenue. Midstream and other revenue accounts for 6% or less of our total revenues for each of the years ended December 31, 2021, 2020 and 2019.

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Production volumes sold

The following table presents historical sales volumes for our properties:

	Year Ended December 31,
	2021	2020	2019
Oil (MBbls)	13,237	13,132	13,752
Natural gas (MMcf)	89,455	78,541	73,747
NGLs (MBbls)	6,099	5,078	5,188
Total (MBoe)	34,245	31,300	31,232
Daily average (MBoe/d)	94	86	86

Total sales volume increased 2,945 MBoe during the year ended December 31, 2021 compared to 2020. The increase is primarily due to the Titan Acquisition, which contributed an additional 5,912 MBoe, and the DJ Basin Acquisition, Central Basin Platform Acquisition and Merger Transactions (combined the "2021 Acquisitions"), which contributed an additional 1,266 MBoe. Sales volumes from our other assets decreased by 4,233 MBoe primarily due to the natural decline from our existing asset base that resulted from the reduction in development capital expenditures in 2020 as a response to the low commodity price environment.

Commodity prices and differentials

Our results of operations depend upon many factors, particularly the price of commodities and our ability to market our production effectively.

The oil and natural gas industry is cyclical and commodity prices can be highly volatile. In recent years, commodity prices have been subject to significant fluctuations. The outbreak of the COVID-19 virus followed by certain actions taken by OPEC caused crude oil prices to decline significantly beginning in the first half of 2020 and prices remained below pre-pandemic levels for a prolonged period of time. Although commodity prices increased during 2021, uncertainty persists regarding OPEC’s actions and continued effect from the COVID-19 pandemic.

In order to reduce the impact of fluctuations in oil and natural gas prices on revenues, we regularly enter into derivative contracts with respect to a portion of the estimated oil, natural gas and NGL production through various transactions that fix the future prices received. We plan to continue the practice of entering into economic hedging arrangements to reduce near-term exposure to commodity prices, protect cash flow and corporate returns and maintain our liquidity.

The following table presents the percentages of our production that was economically hedged through the use of derivative contracts:

	Year Ended December 31,
	2021		2020		2019
Oil	81	%	81	%	74	%
Natural gas	83	%	76	%	81	%
NGLs	67	%	60	%	55	%

The following table sets forth the average NYMEX oil and natural gas prices and our average realized prices for the periods presented:

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	Year Ended December 31,
	2021		2020		2019
Oil (Bbl):
Average NYMEX	$	68.04	$	39.40	$	57.03
Realized price (excluding derivative settlements)	66.71		37.45		57.14
Realized price (including derivative settlements) (1)	53.07		48.85		53.92
Natural Gas (Mcf):
Average NYMEX	$	3.91	$	2.08	$	2.63
Realized price (excluding derivative settlements)	3.96		1.90		2.35
Realized price (including derivative settlements)	3.06		2.32		2.41
NGLs (Bbl):
Realized price (excluding derivative settlements)	$	30.42	$	13.77	$	16.67
Realized price (including derivative settlements)	19.15		16.61		19.18

(1)For the year ended December 31, 2021, the realized price excludes the impact of the settlement of certain of our outstanding derivative oil commodity contracts associated with calendar years 2022 and 2023 for $198.7 million in June 2021. Subsequent to the settlement, we entered into new commodity derivative contracts at prevailing market prices.

Results of operations:

Year ended December 31, 2021 compared to year ended December 31, 2020

Revenues

The following table provides the components of our revenues, respective average realized prices and net sales volumes for the periods indicated:

	Year Ended December 31,
	2021		2020		$ Change		% Change
Revenues (in thousands):
Oil	$	883,087	$	491,780	$	391,307	80	%
Natural gas	354,298		149,317		204,981		137	%
Natural gas liquids	185,530		69,902		115,628		165	%
Midstream and other	54,062		43,222		10,840		25	%
Total revenues	$	1,476,977	$	754,221	$	722,756	96	%
Average realized prices, before effects of derivative settlements:
Oil ($/Bbl)	$	66.71	$	37.45	$	29.26	78	%
Natural gas ($/Mcf)	$	3.96	$	1.90	$	2.06	108	%
NGLs ($/Bbl)	$	30.42	$	13.77	$	16.65	121	%
Total ($/Boe)	$	41.55	$	22.72	$	18.83	83	%
Net sales volumes:
Oil (MBbls)	13,237		13,132		105		1	%
Natural gas (MMcf)	89,455		78,541		10,914		14	%
NGLs (MBbls)	6,099		5,078		1,021		20	%
Total (MBoe)	34,245		31,300		2,945		9	%
Average daily net sales volumes:
Oil (MBbls/d)	36		36		—		—	%
Natural gas (MMcf/d)	245		215		30		14	%
NGLs (MBbls/d)	17		14		3		21	%
Total (MBoe/d)	94		86		8		9	%

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Oil revenue. Oil revenue increased $391.3 million, or 80%, in 2021 compared to 2020, driven by $387.4 million of higher realized oil prices (an increase of 78%) and a $3.9 million increase in sales volumes (0.3 MBbl/d, or 1%). The increase in sales volumes was primarily driven by our Titan Acquisition (1,708 MBbls of the increase) and our 2021 Acquisitions (430 MBbls of the increase), partially offset by the natural decline from our existing assets that resulted from the reduction in development capital expenditures in 2020.

Natural gas revenue. Natural gas revenue increased $205.0 million, or 137%, in 2021 compared to 2020, driven by $184.3 million of higher realized natural gas prices (an increase of 108%), and a $20.7 million increase in sales volumes (30 MMcf/d, or 14%). The price increase was due in part to the severe winter storms in February 2021 and the increase in sales volumes was primarily driven by our Titan Acquisition (15,807 MMcf of the increase) and our 2021 Acquisitions (4,060 MMcf of the increase), partially offset by the natural decline from our existing assets.

NGL revenue. NGL revenue increased $115.6 million, or 165%, in 2021 compared to 2020, driven by $101.5 million of higher realized NGL prices (an increase of 121%) and a $14.1 million increase in sales volumes (3 MBbl/d, or 20%). The increase in sales volumes was primarily driven by our Titan Acquisition (1,570 MBbls of the increase) and our 2021 Acquisitions (159 MBbls) partially offset by the natural decline from our existing assets.

Midstream and other revenue. Midstream and other revenue increased $10.8 million, or 25%, in 2021 compared to 2020, driven primarily by additional revenue of $4.3 million from the midstream assets acquired in the Titan Acquisition, $2.7 million from lease bonus revenue, and $1.2 million from additional midstream processing revenue.

Expenses

The following table summarizes our expenses for the periods indicated and includes a presentation on a per Boe basis, as we use this information to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis:

	Year Ended December 31,
	2021		2020		$ Change		% Change
Expenses (in thousands):
Operating expense	$	596,334	$	481,834	$	114,500	24	%
Depreciation, depletion and amortization	312,787		372,300		(59,513)		(16	%)
Impairment of oil and natural gas properties	—		247,215		(247,215)		NM*
General and administrative expense	78,342		16,542		61,800		374	%
Other operating costs	5,775		9,958		(4,183)		(42	%)
Total expenses	$	993,238	$	1,127,849	$	(134,611)	(12	%)
Expenses per Boe:
Operating expense	$	17.41	$	15.39	$	2.02	13	%
Depreciation, depletion and amortization	9.13		11.89		(2.76)		(23	%)
Impairment of oil and natural gas properties	—		7.90		(7.90)		NM*
General and administrative expense	2.29		0.53		1.76		332	%
Other operating costs	0.17		0.32		(0.15)		(47	%)
Total expenses per Boe	$	29.00	$	36.03	$	(7.03)	(20	%)

*NM = Not meaningful.

Operating expense. Total operating expense increased $114.5 million, or 24%, in 2021 compared to 2020, driven primarily by the following factors:

(i)Total lease and asset operating expenses increased $48.2 million, or 20%, in 2021 compared to 2020. This increase was driven primarily by higher production during 2021, due in part to the Titan Acquisition, which contributed $16.4 million to the increase, the 2021 Acquisitions, which contributed $11.2 million to the increase, and certain costs are indexed to oil commodity prices, such as CO2 purchase costs related to our CO2 flood asset in Wyoming. These commodity indexed operating expenses move in tandem with oil commodity prices and are partially offset by changes in our price realizations.

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(ii)Gathering, transportation and marketing expense increased $13.9 million, or 8%, in 2021 compared to 2020. This increase was driven primarily by increased production and higher gathering and processing expenses of $35.8 million associated with the Titan Acquisition, which included assets that have a higher mix of natural gas and NGLs. This increase was offset by $12.0 million of nonrecurring expense incurred during 2020 associated with the termination of a midstream contract at our Eagle Ford business. In addition, during 2021, we reached a settlement with a third-party operator to recoup $3.4 million of disputed gathering charges that we had paid in historical periods.

(iii)Production and other taxes increased $47.9 million, or 78%, in 2021 compared to 2020, driven primarily by higher oil and natural gas revenues, which increased the tax base upon which production and other taxes are calculated.

(iv)Workover expense increased $4.5 million, or 70%, due to higher well workover activity.

Depreciation, depletion and amortization. Depreciation, depletion and amortization decreased $59.5 million, or 16%, compared to 2020, driven by a reduction in the rate from our impairment in 2020 offset by an increase in our total production from the Titan Acquisition and 2021 Acquisitions.

Impairment of oil and natural gas properties. In 2020, because of significant declines in crude prices as a result of the COVID-19 pandemic, we recorded an impairment charge of $247.2 million to oil and natural gas properties. We did not record impairment expense in 2021 or 2019. See Part II, Item 8. “Notes to the combined and consolidated financial statements - NOTE 6 – Fair Value Measurements” for additional discussion regarding the impairment in 2020.

General and administrative expense. General and administrative expense increased $61.8 million, or 374%, in 2021 compared to 2020, driven primarily by an increase in our equity-based compensation of $40.7 million primarily due to the Merger Transactions and the additional cost recognized due to the modification of Contango equity-classified PSUs (see Item 8. Financial Statements, NOTE 13 – Incentive Compensation Arrangements for additional information) and an increase in legal, accounting and other nonrecurring transaction-related costs of $21.1 million.

	Year Ended December 31,
	2021		2020		$ Change		% Change
General and administrative expense (in thousands)
Recurring general and administrative expense	$	14,359	$	14,339	$	20	—	%
Nonrecurring and transaction expenses	24,064		3,000		21,064		702	%
Equity-based compensation	39,919		(797)		40,716		5109	%
Total expense	$	78,342	$	16,542	$	61,800	374	%

Other operating costs. Other operating costs include midstream operating expense, exploration expense and gain on sale of assets. Other operating costs decreased $4.2 million, or 42%, in 2021 compared to 2020, driven primarily by the recognition of a $8.8 million gain on sale of assets during 2021, partially offset by $2.2 million of additional midstream expenses from our Titan Acquisition and $1.6 million of additional midstream expense from our 2021 Acquisitions.

Interest expense

In 2021, we incurred interest expense of $50.7 million, as compared to $38.1 million in 2020, a 33% increase. The increase was primarily driven by the write-off of deferred financing charges associated with our Prior Credit Agreements in May 2021 and higher interest rates associated with the issuance of the Senior Notes in April of 2021.

Gain (loss) on derivatives

We have entered into derivative contracts to manage our exposure to commodity price risks that impact our revenues and interest rate risks on our variable interest rate debt. In June 2021, we settled certain of our outstanding derivative oil contracts associated with calendar years 2022 and 2023 for $198.7 million, using cash on hand and borrowings of $160.0 million from our Revolving Credit Facility. The following table presents our total unrealized and realized gain (loss) on derivatives for the periods presented:

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	Year Ended December 31,
	2021		2020		$ Change		% Change
Gain (loss) on derivatives (in thousands)
Gain (loss) on commodity derivatives	$	(865,994)	$	205,645	$	(1,071,639)	(521	%)
Gain (loss) on interest rate derivatives	(26)		(10,361)		10,335		(100	%)
Total gain (loss) on derivatives	$	(866,020)	$	195,284	$	(1,061,304)	(543	%)

Adjusted EBITDAX (non-GAAP) and Levered Free Cash Flow (non-GAAP)

Adjusted EBITDAX and Levered Free Cash Flow are supplemental non-GAAP financial measures used by our management to assess our operating results. See “—Non-GAAP Financial Measures” section below for their definitions and application.

The following table presents a reconciliation of Adjusted EBITDAX (non-GAAP) and Levered Free Cash Flow (non-GAAP) to net income (loss), the most directly comparable financial measure calculated in accordance with GAAP:

	Year Ended December 31,
	2021		2020		$ Change		% Change
(in thousands)
Net income (loss)	$	(432,227)	$	(216,124)	$	(216,103)	100	%
Adjustments to reconcile to Adjusted EBITDAX:
Interest expense	50,740		38,107
Realized (gain) loss on interest rate derivatives	7,373		12,435
Income tax expense (benefit)	(306)		14
Depreciation, depletion and amortization	312,787		372,300
Exploration expense	1,180		486
Non-cash (gain) loss on derivatives	330,368		(10,910)
Impairment of oil and natural gas properties	—		247,215
Non-cash equity-based compensation expense	39,919		(797)
(Gain) loss on sale of assets	(8,794)		—
Other (income) expense	(120)		(341)
Certain redeemable noncontrolling interest distributions made by OpCo related to Management Compensation	(2,706)		—
Transaction and nonrecurring expenses (1)	23,149		22,679
Early settlement of derivative contracts (2)	198,688		—
Adjusted EBITDAX (non-GAAP)	$	520,051	$	465,064	$	54,987	12	%
Adjustments to reconcile to Levered Free Cash Flow:
Interest expense, excluding non-cash deferred financing cost amortization	(40,551)		(33,166)
Realized (gain) loss on interest rate derivatives	(7,373)		(12,435)
Current income tax provision	(629)		(14)
Current tax-related redeemable noncontrolling interest distributions by OpCo	—		—
Development of oil and natural gas properties	(194,828)		(110,126)
Levered Free Cash Flow (non-GAAP)	$	276,670	$	309,323	$	(32,653)	(11	%)

(1)Transaction expenses of $23.1 million during the year ended December 31, 2021 were primarily related to legal, consulting and other fees incurred for the Noncontrolling Interest Carve-out, the April 2021 Exchange and the Merger Transactions, partially offset by $3.4 million received in connection with a midstream legal settlement. Transaction expenses of $22.7 million for the year ended December 31, 2020 included (i) $7.9 million related to the formation of Independence, the Titan Acquisition and the related reorganization transactions, (ii) $12.0 million for the termination of a midstream contract at our Eagle Ford business, (iii) $1.9 million of severance costs and (iv) $0.9 million for settlement of a royalty owner lawsuit.

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(2)Represents the settlement in June 2021 of certain outstanding derivative oil commodity contracts for open positions associated with calendar years 2022 and 2023. Subsequent to the settlement, we entered into new commodity derivative contracts at prevailing market prices.

Adjusted EBITDAX increased by $55.0 million or 12% in 2021, compared to 2020, primarily driven primarily by higher revenue associated with our oil, natural gas and NGL production as a result of (i) realized prices and (ii) sales volume driven by the Titan Acquisition and our 2021 Acquisitions. This increase was partially offset by a corresponding increase in lease operating expense and production tax from increased production volumes and commodity prices, as well as realized losses on our commodity derivatives in 2021 compared to 2020.

Levered Free Cash Flow decreased by $32.7 million or 11% in 2021 compared to 2020, driven primarily by $84.7 million of increased capital expenditures related to 2021 development activities following the increase in commodity prices, partially offset by increased Adjusted EBITDAX of $55.0 million.

Liquidity and capital resources

Our primary sources of liquidity are cash flow from operations and borrowings under the Revolving Credit Facility. Our primary use of capital is for dividends to shareholders, debt repayment, development of our existing assets and acquisitions.

Our development program is designed to prioritize the generation of meaningful free cash flow, attractive risk-adjusted returns and is inherently flexible, with the ability to scale our capital program as necessary to react to the existing market environment and ongoing asset performance. Our 2021 capital program reflected that flexibility; our capital expenditures incurred during the second half of 2021 were higher than the first half of 2021 as we elected to increase capital spend as the commodity price environment improved.

We plan to continue our practice of entering into economic hedging arrangements to reduce the impact of the near-term volatility of commodity prices and the resulting impact on our cash flow from operations. A key tenet of our focused risk management effort is an active economic hedge strategy to mitigate near-term price volatility while maintaining long-term exposure to underlying commodity prices. Our commodity derivative program focuses on entering into forward commodity contracts when investment decisions regarding reinvestment in existing assets or new acquisitions are finalized, targeting economic hedges for a portion of expected production as well as adding incremental derivatives to our production base over time. Our active derivative program allows us to preserve capital and protect margins and corporate returns through commodity cycles. For information regarding risks related to our derivative program, see Part I, Item 1A. Risk Factors.

The following table presents our cash balances and outstanding borrowings at the end of each period presented:

	At December 31,
(in thousands)	2021		2020
Cash and cash equivalents	$	128,578	$	36,861
Long-term debt	1,030,406		751,075

Based on our planned capital spending, our forecasted cash flows and projected levels of indebtedness, we expect to maintain compliance with the covenants under our debt agreements. Further, based on current market indications, we expect to meet in the ordinary course of business other contractual cash commitments to third parties pursuant to the various agreements subsequently described under the heading “Contractual obligations,” recognizing we may be required to meet such commitments even if our business plan assumptions were to change.

Cash flows

The following table summarizes our cash flows for the periods indicated:

	Year Ended December 31,
(in thousands)	2021		2020
Net cash provided by operating activities	$	233,147	$	411,028
Net cash used in investing activities	(244,595)		(124,940)
Net cash (used in) provided by financing activities	105,145		(272,089)

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Net cash provided by operating activities. Net cash provided by operating activities for the year ended December 31, 2021 decreased by $177.9 million, or 43%, compared to 2020, primarily due to cash payments of $198.7 million associated with the early settlement of certain outstanding oil commodity derivative contracts in June 2021.

Net cash used in investing activities. Net cash used in investing activities for the year ended December 31, 2021 increased by $119.7 million, or 96%, compared to 2020, primarily due to $115.1 million net cash used in the 2021 Acquisitions and $29.4 million of additional development capital expenditures. These uses of cash were partially offset by $16.4 million additional cash proceeds in 2021 from our divestitures.

Net cash provided by (used in) financing activities. Net cash provided by financing activities for the year ended December 31, 2021 was $105.1 million, as compared to $272.1 million net cash used in financing activities in 2020. The increase was primarily due to net cash inflows as a result of our debt borrowings exceeding our repayments during 2021 compared to net long-term debt repayments cash outflow of $224.4 million in 2020.

Debt agreements

Prior Credit Agreements

Certain of our subsidiaries entered into the Prior Credit Agreements with syndicates of lenders with original expiration dates between 2022 and 2024. The amounts we were able to borrow under each of the Prior Credit Agreements was limited by a borrowing base, which was based on our oil and natural gas properties, proved reserves and total indebtedness, as well as other factors, and was consistent with customary lending criteria. On May 6, 2021, we terminated the Prior Credit Agreements with the proceeds from the issuance of the Senior Notes and the Noncontrolling Interest Carve-Out and borrowings under the Revolving Credit Facility (as discussed below).

The Prior Credit Agreements contained certain covenants that restricted the payment of cash dividends, certain borrowings, sales of assets, loans to others, investments, merger activity, commodity swap agreements, liens and other transactions. We were in compliance with the covenants of the Prior Credit Agreements at December 31, 2020 and 2019 and through the termination of the Prior Credit Agreements in May 2021.

Senior Notes

On May 6, 2021, Crescent Finance issued $500.0 million aggregate principal amount of the Senior Notes. The Senior Notes bear interest at an annual rate of 7.250%, which is payable on May 1 and November 1 of each year and mature on May 1, 2026.

The Senior Notes are our senior unsecured obligations, and the notes and the guarantees issued in connection with the issuance of the Senior Notes rank equally in right of payment with the borrowings under the Revolving Credit Facility and all of its other future senior indebtedness and senior to any of its future subordinated indebtedness. The Senior Notes are guaranteed on a senior unsecured basis by each of our existing and future subsidiaries that guarantee the Revolving Credit Facility. The Senior Notes and the guarantees are effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under the Revolving Credit Facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any future subsidiaries that do not guarantee the Senior Notes.

We may, at our option, redeem all or a portion of the Senior Notes at any time on or after May 1, 2023 at certain redemption prices. We may also redeem up to 40% of the aggregate principal amount of the Senior Notes before May 1, 2023 with an amount of cash not greater than the net proceeds that we raise in certain equity offerings at a redemption price equal to 107.250% of the principal amount of the Senior Notes being redeemed, plus accrued and unpaid interest, if any, to, but excluding the redemption date. In addition, prior to May 1, 2023, we may redeem some or all of the Senior Notes at a price equal to 100% of the principal amount thereof, plus a “make-whole” premium, plus accrued and unpaid interest, if any, to, but excluding the redemption date.

If we experience certain kinds of changes of control accompanied by a ratings decline, holders of the Senior Notes may require us to repurchase all or a portion of their notes at certain redemption prices. The Senior Notes are not listed, and we do not intend to list the Senior Notes in the future, on any securities exchange, and currently there is no public market for the Senior Notes.

In February 2022 Crescent Finance issued an additional $200.0 million aggregate principal amount of our Senior Notes (the “New Notes”). The New Notes were issued as additional notes pursuant to our $500.0 million issuance in May 2021 described

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above. The New Notes will be treated as a single series and will vote together as a single class with the Senior Notes, and have identical terms and conditions, other than the issue date, the issue price and the first interest payment, as the Senior Notes.

Revolving Credit Facility

In connection with the issuance of the Senior Notes, Crescent Finance entered into a credit agreement (as amended, restated or otherwise modified to date, the “Revolving Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent for the lenders and letter of credit issuer, and the lenders from time to time party thereto. The initial committed amount and borrowing base under the Revolving Credit Facility are $500.0 million and $850.0 million, respectively. The Revolving Credit Facility matures on May 6, 2025. In September 2021, we entered into the first amendment to the Revolving Credit Facility, which amongst other things, increased our committed amount from $500.0 million to $700.0 million, increased our borrowing base from $850.0 million to $1.3 billion and permitted the issuance of up to $300 million of additional senior notes (including the New Notes described above) without causing a reduction in our borrowing base. At December 31, 2021, we had $543.0 million of outstanding borrowings under the Revolving Credit Facility and $20.7 million in outstanding letters of credit.

In connection with the closing of the Uinta Transaction, we anticipate entering into an amendment to our Revolving Credit Facility to, among other things, increase the elected commitment amount to $1.3 billion. However, there can be no assurances we will consummate this transaction or that we will enter into such amendment to our Revolving Credit Facility.

Borrowings under the Revolving Credit Facility bear interest at either a U.S. dollar alternative base rate (based on the prime rate, the federal funds effective rate or an adjusted LIBOR), plus an applicable margin or LIBOR, plus an applicable margin, at the election of the borrowers. The applicable margin varies based upon our borrowing base utilization then in effect. The fee payable for the unused revolving commitments is 0.50% per year. Our weighted average interest rate on loan amounts outstanding as of December 31, 2021 was 3.125%.

The borrowing base is subject to semi-annual scheduled redeterminations on or about April 1 and October 1 of each year, as well as (i) elective borrowing base interim redeterminations at our request not more than twice during any consecutive 12-month period or the required lenders not more than once during any consecutive 12-month period and (ii) elective borrowing base interim redeterminations at our request following any acquisition of oil and natural gas properties with a purchase price in the aggregate of at least 5.0% of the then effective borrowing base. The borrowing base will be automatically reduced upon (a) the issuance of certain permitted junior lien debt and other permitted additional debt, (b) the sale or other disposition of borrowing base properties if the aggregate net present value, discounted at 9% per annum (“PV-9”) of such properties sold or disposed of is in excess of 5.0% of the borrowing base then in effect and (c) early termination or set-off of swap agreements (x) the administrative agent relied on in determining the borrowing base or (y) if the value of such swap agreements so terminated is in excess of 5.0% of the borrowing base then in effect.

The obligations under the Revolving Credit Facility remain secured by first priority liens on substantially all of our and the guarantors’ tangible and intangible assets, including without limitation, oil and natural gas properties and associated assets and equity interests owned by us and such guarantors. In connection with each redetermination of the borrowing base, we must maintain mortgages on at least 85% of the PV-9 of the oil and gas properties that constitute borrowing base properties. Our domestic direct and indirect subsidiaries are required to be guarantors under the Revolving Credit Facility, subject to certain exceptions.

The Revolving Credit Facility contains certain covenants that restrict the payment of cash dividends, certain borrowings, sales of assets, loans to others, investments, merger activity, commodity swap agreements, liens and other transactions without the adherence to certain financial covenants or the prior consent of our lenders. We are subject to (i) maximum leverage ratio and (ii) current ratio financial covenants calculated as of the last day of each fiscal quarter. The Revolving Credit Facility also contains representations, warranties, indemnifications and affirmative and negative covenants, including events of default relating to nonpayment of principal, interest or fees, inaccuracy of representations or warranties in any material respect when made or when deemed made, violation of covenants, bankruptcy and insolvency events, certain unsatisfied judgments and a change of control. If an event of default occurs and we are unable to cure such default, the lenders will be able to accelerate maturity and exercise other rights and remedies.

Capital expenditures

Our acquisition and development expenditures consist of acquisitions of proved and unproved property, expenditures associated with the development of our oil and natural gas properties and other asset additions. Cash expenditures for drilling, completion and recompletion activities are presented as "development of oil and natural gas properties" in investing activities on our combined and consolidated statements of cash flows.

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We expect to fund our 2022 capital program through cash flow from operations. The amount and timing of capital expenditures on development of oil and natural gas properties is substantially within our control due to the held-by-production nature of our assets. We regularly review our capital expenditures throughout the year and could choose to adjust our investments based on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil, natural gas and NGLs, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. Any postponement or elimination of our development drilling program could result in a reduction of proved reserve volumes and related standardized measure. These risks could materially affect our business, financial condition and results of operations.

The table below presents our capital expenditures and related metrics that we use to evaluate our business for the periods presented:

	Year Ended December 31,
(in thousands)	2021		2020		2019
Total development of oil and natural gas properties	$	194,828	$	110,126	$	315,430
Change in accruals and other non-cash adjustments	(39,221)		16,038		23,216
Cash used in development of oil and natural gas properties	155,607		126,164		338,646
Cash used in acquisition of oil and natural gas properties	115,076		—		—
Non-cash acquisition of oil and natural gas properties	647,579		454,599		—
Total expenditure on acquisition and development of oil and natural gas properties	$	918,262	$	580,763	$	338,646

Our development of oil and natural gas properties was higher during the year ended December 31, 2021, compared to the year ended December 31, 2020. Due to the low commodity price environment experienced throughout 2020 resulting from the COVID-19 pandemic and the actions from OPEC, we significantly reduced our development capital expenditures starting in the second quarter of 2020 but have resumed development activities in 2021 as commodity prices have recovered. We used cash of $115.1 million in 2021 for the acquisition of oil and natural gas properties, primarily related to our DJ Basin and Central Basin Acquisitions, and had non-cash acquisitions of $647.6 million and $454.6 million in 2021 and 2020 related to our Merger Transactions and the Titan Acquisition (see Our Combined and Consolidated Financial Statements—NOTE 3 - Acquisitions and Divestitures).

Contractual obligations

The following table presents our material contractual obligations at December 31, 2021:

(in thousands)	Due within one year		Due after one year		Total
Long-term debt – principal (1)	$	—	$	1,043,000	$	1,043,000
Derivative liabilities	253,525		133,471		386,996
Asset retirement obligations (2)	7,905		258,102		266,007
Process, transportation and storage contracts (3)	105,606		303,143		408,749
Total	$	367,036	$	1,737,716	$	2,104,752

(1)Long-term debt represents our outstanding borrowings as of December 31, 2021 consisting of our Senior Notes (maturing on May 1, 2026) and borrowings under our Revolving Credit Facility (maturing on May 6, 2025).

(2)Amounts represent estimated discounted costs for future dismantlement and abandonment of our crude oil and natural gas properties. See “Notes to the combined and consolidated financial statements—NOTE 9 - Asset Retirement Obligation” for additional discussion of our asset retirement obligations.

(3)Amounts include payments which will become due under long-term agreements to purchase goods and services used in the normal course of business to secure transportation of our natural gas production to market, as well as, pipeline, processing and storage capacity.

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Dividends

We target future dividends to shareholders of 10% of Adjusted EBITDAX, but payments will depend on our level of earnings, financial requirements and other factors and will be subject to approval by our Board of Directors, applicable law and the terms of our existing debt documents, including the indenture governing the Senior Notes.

On March 9, 2022, the Board approved a quarterly cash dividend of $0.12 per share, or $0.48 per share on an annualized basis, to be paid to our shareholders with respect to the fourth quarter of 2021. The quarterly dividend is payable on March 31, 2022 to shareholders of record as of the close of business on March 18, 2022.

The payment of quarterly cash dividends is subject to management’s evaluation of our financial condition, results of operations and cash flows in connection with such payments and approval by our Board of Directors. In light of current economic conditions, management will evaluate any future increases in cash dividend on a quarterly basis.

Critical accounting estimates

Our significant accounting policies are described in NOTE 2 – Summary of Significant Accounting Policies, in Item 8 of Part II of this Annual Report. The Company's combined and consolidated financial statements are prepared in accordance with GAAP. The preparation of combined and consolidated financial statements requires management to make assumptions and estimates that affect the reported results of operations and financial position. The following is a discussion of the accounting policies, estimates and judgments that management believes are most significant in the application of GAAP used in the preparation of our combined and consolidated financial statements. These accounting policies, among others, may involve a high degree of complexity and judgment on the part of management. Further, these estimates and other factors, including those outside of our control could have significant adverse impact to our financial condition, results of operations and cash flows.

Crude oil, natural gas and NGL reserves

One of the most significant estimates the Company makes is the estimate of proved crude oil, natural gas and NGL reserves. Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. Our crude oil and natural gas reserves are based on a combination of proved reserves and risk-weighted probable reserves and require significant judgment. Technologies used in our reserves estimation includes decline curve analysis, statistical analysis of production performance, pressure and rate transient analysis, pressure gradient analysis, reservoir simulation and volumetric analysis. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. In addition, periodic revisions of our estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, crude oil and natural gas prices, changes in costs, capital funding and drilling plans (including our five-year development plan), technological advances, new geological or geophysical data, or other economic factors. Accordingly, reserve estimates often differ from the quantities of crude oil and natural gas that are ultimately recovered. We cannot predict the amounts or timing of future reserve revisions.

When determining the December 31, 2021 proved reserves for each property, the benchmark prices issued by the SEC were adjusted using price differentials that account for property-specific quality and location differences. If the future average crude oil prices are below the average prices used to determine proved reserves at December 31, 2021, it could have an adverse effect on our estimates of proved reserve volumes and the value of our business. It is difficult to estimate the magnitude of any potential price change and the effect on proved reserves, due to numerous factors (including future crude oil price and performance revisions). For further discussion of risks associated with our estimation of proved reserves, see Part I, Item 1A. Risk Factors.

Estimates of proved reserves are key components of our most significant financial estimates including the computation of depreciation, depletion and amortization (DD&A) and impairment of proved crude oil and natural gas properties.

Oil and natural gas properties

Oil and natural gas producing activities are accounted for under the successful efforts method of accounting. See Part II, Item 8. Financial Statements of this Annual Report, “Notes to our Combined and Consolidated Financial Statements—NOTE 2 – Summary of Significant Accounting Policies” for further discussion of the accounting policies applicable to the successful efforts method of accounting.

The successful efforts method inherently relies on the estimation of proved crude oil, natural gas and NGL reserves. The amount of estimated proved reserve volumes affect, among other things, whether certain costs are capitalized or expensed, the

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amount and timing of costs depreciated, depleted or amortized into net income and the presentation of supplemental information on oil and gas producing activities. In addition, the expected future cash flows to be generated by producing properties used for testing impairment, also in part, rely on estimates of quantities of net reserves.

Depreciation, depletion and amortization

DD&A of oil and natural gas producing properties is determined on a field-by-field basis using the units-of-production method. During the years ended December 31, 2021, 2020, and 2019, we recognized DD&A expense of $312.8 million, $372.3 million, and $311.2 million, respectively.

While revisions of previous reserve estimates have not historically been significant to the depreciation and depletion rates, any reduction in proved reserves, could result in an acceleration of future DD&A expense. Holding all other factors constant, if proved reserves are revised downward, the rate at which we record DD&A expense would increase, reducing net income. Conversely, if proved reserves are revised upward, the rate at which we record DD&A expense would decrease. However, a sensitivity analysis is not practicable, given the numerous assumptions required to calculate proved reserves. In addition, any unfavorable adjustments to some of the above listed assumptions (e.g. commodity prices) would likely be offset by favorable adjustments in other assumptions (e.g. lower costs) as we have historically seen in our industry.

Impairment of oil and natural gas properties

Proved and unproved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. When a triggering event is identified, we compare the carrying amount of our oil and natural gas properties to the estimated undiscounted cash flows our oil and natural gas properties will generate to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted cash flows, we will write-down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include:

•Estimates of oil and natural gas reserves and expected timing of production. Our oil and natural gas reserves are based on a combination of proved reserves and risk-weighted probable reserves and require significant judgment. Reserve engineering is a subjective process, which requires assumptions associated with the underground accumulations of oil and natural gas, development costs, future commodity prices and the future regulatory and political environment. Any significant variance in these assumptions could materially affect the estimated quantity and value of the reserves, which would affect the fair value of our oil and natural gas properties. The estimates of our reserves help to inform our expectation of future oil and natural gas production, which will likely vary from our actual production.

•Future commodity prices, which are based on publicly available forward commodity prices for a period of time and then escalated at 2.5% thereafter. A decrease in estimated future commodity prices will decrease the fair value of our oil and natural gas properties.

•Future capital requirements, which are based on our internal forecasts and supported by the underlying cash flows generated from our oil and natural gas assets.

•Discount rate commensurate with the risk associated with realizing projected cash flows, which is based on a variety of factors, including market and economic conditions, as well as operational and regulatory risk.

In March 2020, crude oil demand experienced significant declines due to the COVID-19 pandemic and resulting governmental led shut-downs in economic activity. During the second quarter of 2020, as it become apparent that the pandemic would continue with sustained significant decline in crude oil prices, we assessed our oil and natural gas properties for impairment and recorded impairment expense of $247.2 million during the year ended December 31, 2020. An estimate of the sensitivity to changes in assumptions in our fair value calculations is not practicable, given the numerous assumptions (e.g. reserves, pace and timing of development plans, commodity prices, capital expenditures, operating costs, drilling and development costs, inflation and discount rates) that can materially affect our estimates. Unfavorable adjustments to some of the above listed assumptions would likely be offset by favorable adjustments in other assumptions. For example, the impact of sustained reduced commodity prices would likely be partially offset by lower costs.

We did not incur any impairment expense during the years ended December 31, 2021 and 2019.

Properties acquired in business combinations

When sufficient market data is not available, we determine the fair values of proved and unproved oil and natural gas properties acquired in transactions accounted for as business combinations by preparing estimates of cash flows from the production of

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crude oil, natural gas and NGL reserves. We estimate future prices to apply to the estimated reserves quantities acquired, and estimates future operating and development costs, to arrive at estimates of future net cash flows. For the fair value assigned to proved reserves, future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the business combination. When estimating and valuing unproved reserves, discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors. For other assets acquired in business combinations, we use a combination of available cost and market data and/or estimated cash flows to determine the fair values.

Significant reductions in the proved reserves used to determine the fair value of the acquired properties could result in future impairments of the properties. See the discussion above under "Depreciation, depletion and amortization: on the practicability of a sensitivity analysis due to changes in our fair value calculations.

Income taxes

Prior to the Merger Transactions, we were organized as Delaware limited liability companies and Delaware limited partnerships and were treated as flow-through entities for U.S. federal income tax purposes. As a result, our tax provision for the years ended December 31, 2020 and 2019 were minimal. Subsequent to the Merger Transactions, we are subject to U.S. federal income and state tax on our allocable share of any taxable income of OpCo. The amount of income taxes recorded by the Company requires interpretations of complex rules and regulations of various tax jurisdictions throughout the United States. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and tax credit carryforwards. We routinely assesses the realizability of our deferred tax assets and reduce such assets by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. We routinely assess potential uncertain tax positions and, if required, establish accruals for such amounts. The accruals for deferred tax assets and liabilities, including deferred state income tax assets and liabilities, are subject to significant judgment and are reviewed and adjusted routinely based on changes in facts and circumstances. Although we consider our tax accruals adequate, material changes in these accruals may occur in the future, based on the impact of tax audits, changes in legislation and resolution of pending or future tax matters. Refer to NOTE 10 – Income Taxes in Part II, Item 8 of this Annual Report for more information.

New and revised accounting standards

See “Notes to the combined and consolidated financial statements—NOTE 2-Summary of Significant Accounting Policies.”

Non-GAAP financial measures

Our “Management’s Discussion and Analysis of Financial Condition and Results of Operations” includes financial measures that have not been calculated in accordance with U.S. GAAP. These non-GAAP measures include the following:

•Adjusted EBITDAX; and

•Levered Free Cash Flow

These are supplemental non-GAAP financial measures used by our management to assess our operating results and assist us make our investment decisions. We believe that the presentation of these non-GAAP financial measures provides investors with greater transparency with respect to our results of operations, as well as liquidity and capital resources, and that these measures are useful for period-to-period comparison of results.

We define Adjusted EBITDAX as net income (loss) before interest expense, realized (gain) loss on interest rate derivatives, income tax expense, depreciation, depletion and amortization, exploration expense, non-cash gain (loss) on derivative contracts, impairment of oil and natural gas properties, non-cash equity-based compensation, write-offs of other long-term assets, (gain) loss on sale of assets, other (income) expense, certain redeemable noncontrolling interest distributions made by OpCo related to Management Compensation, transaction and nonrecurring expenses and early settlement of derivative contracts. We believe Adjusted EBITDAX is a useful performance measure because it allows for an effective evaluation of our operating performance when compared against our peers, without regard to our financing methods, corporate form or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDAX because these amounts can vary substantially within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP, of which such measure is the most comparable GAAP measure. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax burden, as well as the historic costs of depreciable assets, none of which are reflected in Adjusted EBITDAX. Our presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or nonrecurring items. Our computations of Adjusted EBITDAX may not be

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identical to other similarly titled measures of other companies. In addition, the Revolving Credit Facility and Senior Notes include a calculation of Adjusted EBITDAX for purposes of covenant compliance.

We define Levered Free Cash Flow as Adjusted EBITDAX less interest expense, excluding non-cash deferred financing cost amortization, realized gain (loss) on interest rate derivatives, current income tax benefit (provision), tax-related redeemable noncontrolling interest distributions made by OpCo and development of oil and natural gas properties. Levered Free Cash Flow does not take into account amounts incurred on acquisitions. Levered Free Cash Flow is not a measure of performance as determined by GAAP. Levered Free Cash Flow is a supplemental non-GAAP performance measure that is used by our management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Levered Free Cash Flow is a useful performance measure because it allows for an effective evaluation of our operating and financial performance and the ability of our operations to generate cash flow that is available to reduce leverage or distribute to our equity holders. Levered Free Cash Flow should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP, of which such measure is the most comparable GAAP measure, or as an indicator of actual operating performance or investing activities. Our computations of Levered Free Cash Flow may not be comparable to other similarly titled measures of other companies.

Adjusted EBITDAX and Levered Free Cash Flow should be read in conjunction with the information contained in our combined and consolidated financial statements prepared in accordance with GAAP.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in commodity prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses but rather indicators of reasonably possible losses.

Commodity price risk

Our major market risk exposure is in the pricing that we receive for our oil, natural gas and NGLs production.

Pricing for oil, natural gas and NGLs has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for our production depend on many factors outside of our control, such as the strength of the global economy and global supply and demand for the commodities we produce.

To reduce the impact of fluctuations in oil, natural gas and NGLs prices on our cash flows, we regularly enter into commodity derivative contracts with respect to certain of our oil, natural gas and NGL production through various transactions that limit the risks of fluctuations of future prices. A key tenet of our focused risk management effort is an active economic hedge strategy to mitigate near-term price volatility while maintaining long-term exposure to underlying commodity prices. Our hedging program allows us to preserve capital, protect margins and corporate returns through commodity cycles and return capital to investors. Future transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into collars, whereby we receive the excess, if any, of the fixed

floor over the floating rate or pay the excess, if any, of the floating rate over the fixed ceiling. These economic hedging activities are intended to limit our near-term exposure to product price volatility and to maintain stable cash flows, a strong balance sheet and attractive corporate returns.

As of December 31, 2021, our derivative portfolio had an aggregate notional value of approximately $1.8 billion, and the fair market value of our commodity derivative contracts was a net liability of $386.4 million. We determine the fair value of our oil and natural gas commodity derivatives using valuation techniques that utilize market quotes and pricing analysis. Inputs include publicly available prices and forward price curves generated from a compilation of data gathered from third parties.

Based upon our open commodity derivative positions at December 31, 2021, a hypothetical 10% increase or decrease in the NYMEX WTI, Brent price, Henry Hub Index price, NGL prices and basis prices would change our net commodity derivative position by approximately $213.7 million. The hypothetical change in fair value could be a gain or a loss depending on whether commodity prices decrease or increase.

Derivative assets and liabilities are classified on the consolidated balance sheets as risk management assets and liabilities. We use derivative instruments and enter into swap contracts which are governed by International Swaps and Derivatives

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Association (“ISDA”) master agreements. Amounts not offset on the consolidated balance sheets represent positions that do not meet all of the conditions to be netted on such balance sheet, such as the legally enforceable right of offset or the execution of a master netting arrangement. See Notes to the Financial Statements, NOTE 5 – Derivatives in Part II, Item 8. Financial Statements of this Annual Report for additional discussion.

Counterparty and customer credit risk

Our cash and cash equivalents are exposed to concentrations of credit risk. We manage and control this risk by investing these funds with major financial institutions. We often have balances in excess of the federally insured limits.

We sell oil, natural gas and NGLs to various types of customers. Credit is extended based on an evaluation of our customer’s financial conditions and historical payment record. The future availability of a ready market for oil, natural gas and NGLs depends on numerous factors outside of our control, none of which can be predicted with certainty.

For the year ended December 31, 2021, 2020 and 2019, we had certain major customers that exceeded 10% of total revenues. See Part I, Items 1 and 2. Business and Properties "Marketing and customers.” We do not believe the loss of any single customer would materially impact its operating results because oil, natural gas and NGLs are fungible products with well-established markets and numerous purchasers.

To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by our management as competent and competitive market makers. Additionally, our ISDAs allow us to net positions with the same counterparty to minimize credit risk exposure. The creditworthiness of our counterparties is subject to periodic review.

Interest rate risk

At December 31, 2021, we had $543.0 million of variable rate debt outstanding. Assuming no change in the amount outstanding, the impact on interest expense of a 1% increase or decrease in the average interest rate would be approximately $5.4 million increase or decrease in 2021 interest expense.

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Item 8. Financial Statements and Supplementary Data

INDEX TO FINANCIAL STATEMENTS

CRESCENT ENERGY COMPANY

	Page
Report of Independent Registered Public Accounting Firm	87
Combined and Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 2021 and 2020	90
Combined and Consolidated Statements of Operations for the Years Ended December 31, 2021, 2020 and 2019	92
Combined and Consolidated Statements of Changes in Equity for the Years Ended December 31, 2021, 2020 and 2019	93
Combined and Consolidated Statements of Cash Flows for the Years Ended December 31, 2021, 2020 and 2019	94
Notes to Combined and Consolidated Financial Statements	95
Financial Statement Schedules:
Schedule I - Condensed Financial Information of Registrant	132

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of Crescent Energy Company

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Crescent Energy Company and subsidiaries (the "Company") as of December 31, 2021 and 2020, the related combined and consolidated statements of operations, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2021, and the related notes and the schedule listed in the Index at Item 8 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Proved Oil and Natural Gas Properties – Oil and Natural Gas Reserves Quantities – Refer to Notes 2 and 4 to the financial statements

Critical Audit Matter Description

The Company’s proved oil and natural gas properties are depleted on a field-by-field basis using the units of production method based on estimated oil and natural gas reserves. The development of the Company’s estimated proved oil and natural gas reserve volumes requires management to make significant estimates and assumptions, including the Company’s ability to convert proved undeveloped reserves to producing properties within five years of their initial proved reserves bookings. As of December 31, 2021, 14% of the estimated proved oil and natural gas reserves were attributable to proved undeveloped reserves.

The Company engaged independent reserve engineers to either independently engineer or audit their proved oil and natural gas quantities in accordance with Securities and Exchange Commission Regulation S-X and other sources of accounting principles generally accepted in the United States of America. Changes in these assumptions or engineering data could materially affect the Company’s estimated reserves quantities and depletion expense. The proved oil and natural gas properties balance was $4,470 million as of December 31, 2021, net of accumulated depreciation, depletion, amortization and impairment.

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Given the significant judgments made by management, performing audit procedures to evaluate the Company’s estimated proved crude oil and natural gas reserve quantities, including management’s estimates and assumptions related to converting proved undeveloped reserves to producing properties within five years, required a high degree of auditor judgment and an increased extent of effort.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to management’s significant judgments and assumptions related to oil and natural gas reserves quantities included the following, among others:

•We evaluated the reasonableness of management’s estimated reserve quantities by performing the following:

•Evaluating the experience, qualifications and objectivity of management’s experts, independent reservoir engineers, including the methodologies used to estimate oil and natural gas reserves quantities.

•Comparing the Company’s estimated future production volumes of oil and natural gas reserves to historical production volumes.

•Assessing the reasonableness of the production volume decline curves by comparing to historical decline curve estimates.

•We evaluated the reasonableness of management’s estimates and assumptions related to converting proved undeveloped reserves to producing properties within five years, by performing the following:

•Comparing historical conversions of proved undeveloped oil and gas reserves into proved developed oil and gas reserves to management’s forecasts of conversions.

•Comparing management’s forecasts to the Company’s drill plan and the availability of capital relative to the drill plan.

•Evaluating whether the forecasted date of development for the proved undeveloped locations are within five years of their original booking date.

•Reviewing internal communications to management and the Board of Directors.

Acquisitions and Divestitures – Contango Merger – Valuation of Oil and Natural Gas Properties – Refer to Notes 2 and 3 to the financial statements

Critical Audit Matter Description

On December 7, 2021, the Company closed on an all-stock merger with Contango Oil and Gas Company (“Contango”) for aggregate consideration of $654.6 million. Management of the Company accounted for the acquisition of Contango as a business combination. Accordingly, the assets acquired, and liabilities assumed were recorded based on their estimated fair values at the date of acquisition with goodwill recorded for the excess of the consideration transferred over the estimated fair value of the net assets. The primary assets acquired were proved oil and natural gas properties with a fair value of $1,002 million, estimated utilizing an income valuation technique that incorporates future oil and natural gas prices, reserves risk adjustment factors and a discount rate. Management applied significant judgment and assumptions in estimating the fair value of the oil and natural gas properties acquired.

Given the significant judgments made by management, including the development of oil and natural gas reserves estimates using management’s experts as defined in the previous Critical Audit Matter, in developing estimates of future oil and natural gas prices, reserves risk adjustment factors and an appropriate discount rate, auditing these management’s estimates required a higher degree of auditor judgment and an increased extent of effort, and the use of professionals with specialized skill and knowledge.

How the Critical Audit Matter Was Addressed in the Audit

In addition to the procedures specified in the previous Critical Audit Matter, our audit procedures related to the risk adjustment factors, discount rate, and future oil and natural gas prices used within the estimation of the valuation of oil and natural gas properties acquired, included the following, among others:

•With the assistance of our fair value specialist, we evaluated the reasonableness of future oil and natural gas prices within the cash flow model by evaluating the reasonableness of significant assumptions used by management related to the estimated future oil and natural gas prices by comparing estimates to third-party publications.

•Additionally, with the assistance of our fair value specialist, we evaluated the reasonableness of reserves risk adjustment factors used within the cash flow model by:

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•Evaluating the appropriateness of the mathematical accuracy of the application of the reserves risk adjustment factors.

•Comparing the reserves risk adjustment factors by reserves category to industry publications.

•Lastly, with the assistance of our fair value specialist, we evaluated the appropriateness of the discount rate by:

•Evaluating the appropriateness of the mathematical model used to develop the discount rate.

•Evaluating the guideline public companies selected by management and used in the selection of the discount rate considering the comparability of operations to the Company.

•Comparing the selected discount rate to published discount rate estimates for the industry.

•Developing a range of independent estimates of the discount rate by independently obtaining information to estimate components of the discount rate, including the cost of debt capital, the cost of equity capital, and debt-to-equity ratio.

•Comparing the discount rate selected by management with the range of independent estimates.

•Recomputing the mathematical accuracy of the calculation of the discount rate.

/s/ Deloitte & Touche LLP

Houston, Texas

March 9, 2022

We have served as the Company’s auditor since 2021.

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CRESCENT ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS
	December 31, 2021		December 31, 2020
	(in thousands, except share and unit data)
ASSETS
Current assets:
Cash and cash equivalents	$	128,578	$	36,861
Accounts receivable, net	321,855		111,821
Accounts receivable – affiliates	20,341		—
Derivative assets – current	—		30,926
Drilling advances	200		38,892
Prepaid and other current assets	8,644		1,948
Total current assets	479,618		220,448
Property, plant and equipment:
Oil and natural gas properties at cost, successful efforts method
Proved	6,043,602		4,910,059
Unproved	308,721		288,459
Oil and natural gas properties at cost, successful efforts method	6,352,323		5,198,518
Field and other property and equipment, at cost	144,318		138,371
Total property, plant and equipment	6,496,641		5,336,889
Less: accumulated depreciation, depletion, amortization and impairment	(1,941,528)		(1,694,742)
Property, plant and equipment, net	4,555,113		3,642,147
Goodwill	76,564		—
Derivative assets – noncurrent	579		22,352
Investment in equity affiliates	15,415		—
Other assets	30,173		22,422
TOTAL ASSETS	$	5,157,462	$	3,907,369
The accompanying notes to financial statements are an integral part of these combined and consolidated financial statements

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CRESCENT ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS
	December 31, 2021		December 31, 2020
	(in thousands, except share and unit data)
LIABILITIES, REDEEMABLE NONCONTROLLING INTERESTS AND EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	337,881	$	80,688
Accounts payable – affiliates	8,675		9,019
Derivative liabilities – current	253,525		26,392
Financing lease obligations – current	1,606		—
Other current liabilities	14,438		4,572
Total current liabilities	616,125		120,671
Long-term debt	1,030,406		751,075
Derivative liabilities – noncurrent	133,471		23,958
Asset retirement obligations	258,102		106,403
Deferred tax liability	82,537		—
Financing lease obligations – noncurrent	3,512		—
Other liabilities	13,652		12,102
Total liabilities	2,137,805		1,014,209
Commitments and contingencies (Note 12)
Redeemable noncontrolling interests	2,325,013		—
Equity:
Members’ equity – Class A units, no units and 1,220,421 units outstanding as of December 31, 2021 and 2020, respectively	—		2,716,892
Class A common stock, $0.0001 par value; 1,000,000,000 shares authorized and 43,105,376 shares issued and 41,954,385 shares outstanding as of December 31, 2021; no shares issued and outstanding as of December 31, 2020	4		—
Class B common stock, $0.0001 par value; 500,000,000 shares authorized and 127,536,463 shares issued and outstanding as of December 31, 2021; no shares issued and outstanding as of December 31, 2020	13		—
Preferred stock, $0.0001 par value; 500,000,000 shares authorized and 1,000 Series I preferred shares issued and outstanding as of December 31, 2021; no shares issued and outstanding as of December 31, 2020	—		—
Treasury stock, at cost; 1,150,991 shares of Class A common stock as of December 31, 2021 and no shares of Class A Common Stock as of December 31, 2020	(18,448)		—
Additional paid-in capital	720,016		—
Accumulated deficit	(19,376)		—
Noncontrolling interests	12,435		176,268
Total equity	694,644		2,893,160
TOTAL LIABILITIES, REDEEMABLE NONCONTROLLING INTERESTS AND EQUITY	$	5,157,462	$	3,907,369

The accompanying notes to financial statements are an integral part of these combined and consolidated financial statements

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CRESCENT ENERGY COMPANY

COMBINED AND CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2021		2020		2019
	(in thousands, except per share amounts)
Revenues:
Oil	$	883,087	$	491,780	$	785,750
Natural gas	354,298		149,317		173,386
Natural gas liquids	185,530		69,902		86,473
Midstream and other	54,062		43,222		41,631
Total revenues	1,476,977		754,221		1,087,240
Expenses:
Lease operating expense	243,501		202,180		255,106
Workover expense	10,842		6,385		9,789
Asset operating expense	45,940		39,023		40,364
Gathering, transportation and marketing	187,059		173,122		142,214
Production and other taxes	108,992		61,124		88,696
Depreciation, depletion and amortization	312,787		372,300		311,185
Impairment of oil and natural gas properties	—		247,215		—
Exploration expense	1,180		486		469
Midstream operating expense	13,389		9,472		9,968
General and administrative expense	78,342		16,542		2,357
Gain on sale of assets	(8,794)		—		(22)
Total expenses	993,238		1,127,849		860,126
Income (loss) from operations	483,739		(373,628)		227,114
Other income (expense):
Interest expense	(50,740)		(38,107)		(53,577)
Other income (expense)	120		341		402
Income from equity method investments	368		—		—
Gain (loss) on derivatives	(866,020)		195,284		(127,202)
Total other income (expense)	(916,272)		157,518		(180,377)
Income (loss) before taxes	(432,533)		(216,110)		46,737
Income tax benefit (expense)	306		(14)		(28)
Net income (loss)	(432,227)		(216,124)		46,709
Less: net (income) loss attributable to Predecessor	339,168		118,649		(45,839)
Less: net (income) loss attributable to noncontrolling interests	14,922		97,475		(870)
Less: net loss attributable to redeemable noncontrolling interests	58,761		—		—
Net loss attributable to Crescent Energy	$	(19,376)	$	—	$	—
Net Loss per Share:
Class A common stock - basic and diluted	$	(0.46)
Class B common stock - basic and diluted	$	—
Weighted Average Shares Outstanding:
Class A common stock - basic and diluted	41,954
Class B common stock - basic and diluted	127,536

The accompanying notes to financial statements are an integral part of these combined and consolidated financial statements

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CRESCENT ENERGY COMPANY

COMBINED AND CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(in thousands)

	Predecessor			Crescent Energy Company
	Class A Units	Members' Equity		Class A Common Stock			Class B Common Stock			Series I Preferred Stock			Treasury Stock			Additional Paid-in Capital		Accumulated Deficit		Noncontrolling Interest		Total
				Shares	Amount		Shares	Amount		Shares	Amount		Shares	Amount
Balance at January 1, 2019	—	$	1,960,730	—	$	—	—	$	—	—	$	—	—	$	—	$	—	$	—	$	847,114	$	2,807,844
Net income	—	45,839		—	—		—	—		—	—		—	—		—		—		870		46,709
Contributions	—	—		—	—		—	—		—	—		—	—		—		—		250		250
Distributions	—	(124,836)		—	—		—	—		—	—		—	—		—		—		(17,901)		(142,737)
Balance at December 31, 2019	—	1,881,733		—	—		—	—		—	—		—	—		—		—		830,333		2,712,066
Net loss	—	(118,649)		—	—		—	—		—	—		—	—		—		—		(97,475)		(216,124)
Contributions	—	4,704		—	—		—	—		—	—		—	—		—		—		—		4,704
Distributions	—	(61,421)		—	—		—	—		—	—		—	—		—		—		(1,146)		(62,567)
Issuance of Class A Units in exchange for the Contributed Entities	620	—		—	—		—	—		—	—		—	—		—		—		—		—
Reclassification of noncontrolling interests	—	(101,926)		—	—		—	—		—	—		—	—		—		—		101,926		—
Issuance of Class A Units in exchange for the acquisition of Titan Energy	380	455,081		—	—		—	—		—	—		—	—		—		—		—		455,081
December 2020 Exchange	220	657,370		—	—		—	—		—	—		—	—		—		—		(657,370)		—
Balance at December 31, 2020	1,220	2,716,892		—	—		—	—		—	—		—	—		—		—		176,268		2,893,160
Net loss attributable to Predecessor	—	(339,168)		—	—		—	—		—	—		—	—		—		—		—		(339,168)
Contributions	—	7,275		—	—		—	—		—	—		—	—		—		—		35,460		42,735
Distributions	—	(35,331)		—	—		—	—		—	—		—	—		—		—		(1,175)		(36,506)
Noncontrolling Interest Carve-out	—	—		—	—		—	—		—	—		—	—		—		—		(121,872)		(121,872)
April 2021 exchange	10	62,051		—	—		—	—		—	—		—	—		—		—		(62,051)		—
Repurchase of noncontrolling interest	—	—		—	—		—	—		—	—		—	—		—		—		(2,462)		(2,462)
Merger Transactions	(1,230)	(2,411,719)		43,105	4		127,536	13		1	—		—	—		712,341		—		—		(1,699,361)
Net loss	—	—		—	—		—	—		—	—		—	—		—		(19,376)		(14,922)		(34,298)
Equity-based compensation, net of withholding taxes	—	—		(1,151)	—		—	—		—	—		1,151	(18,448)		23,987		—		3,189		8,728
Cancellation of OpCo Units associated with repurchase of treasury stock	—	—		—	—		—	—		—	—		—	—		(16,091)		—		—		(16,091)
Change in deferred taxes attributable to change in OpCo ownership	—	—		—	—		—	—		—	—		—	—		(221)		—		—		(221)
Balance at December 31, 2021	—	$	—	41,954	$	4	127,536	$	13	1	$	—	1,151	$	(18,448)	$	720,016	$	(19,376)	$	12,435	$	694,644

The accompanying notes to financial statements are an integral part of these combined and consolidated financial statements

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CRESCENT ENERGY COMPANY

COMBINED AND CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2021		2020		2019
Cash flows from operating activities:	(in thousands)
Net income (loss)	$	(432,227)	$	(216,124)	$	46,709
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	312,787		372,300		311,185
Impairment of oil and natural gas properties	—		247,215		—
Deferred income taxes (benefit)	(935)		—		—
Gain on sale of oil and natural gas properties	(8,794)		—		(22)
(Gain) loss on derivatives	866,020		(195,284)		127,202
Net cash (paid) received on settlement of derivatives	(535,269)		186,495		(22,743)
Non-cash equity-based compensation expense	39,919		(797)		(2,721)
Amortization of debt issuance costs and discount	7,647		4,941		4,730
Write-off of debt issuance costs	2,541		—		—
Write-off of other long-term assets and other	(928)		(29)		3,909
Changes in operating assets and liabilities:
Accounts receivable	(71,301)		14,652		24,104
Accounts receivable – affiliates	(20,333)		—		—
Prepaid and other current assets	39,986		17,886		(1,088)
Accounts payable and accrued liabilities	31,110		(15,138)		(5,514)
Accounts payable – affiliates	(358)		657		27
Other	3,282		(5,746)		(263)
Net cash provided by operating activities	233,147		411,028		485,515
Cash flows from investing activities:
Development of oil and natural gas properties	(155,607)		(126,164)		(338,646)
Acquisitions of oil and natural gas properties, net of cash acquired	(115,076)		—		—
Proceeds from the sale of oil and natural gas properties	25,723		9,362		15,798
Purchases of restricted investment securities – HTM	(8,537)		(9,071)		(5,412)
Maturities of restricted investment securities – HTM	11,703		9,052		5,414
Due from related party and other	(2,801)		(8,119)		(5,312)
Net cash used in investing activities	(244,595)		(124,940)		(328,158)
Cash flows from financing activities:
Proceeds from issuance of the Senior Notes, net of discount	490,625		—		—
Revolving Credit Facility borrowings	702,000		—		—
Revolving Credit Facility repayments	(159,000)		—		—
Payment of debt issuance costs	(14,611)		(3,333)		(1,619)
Prior Credit Agreement borrowings	53,900		275,850		553,300
Prior Credit Agreement repayments	(804,975)		(496,875)		(564,900)
Repayments of debt acquired in Merger Transactions	(140,000)		—		—
Member contributions	110		5,186		—
Noncontrolling interest contributions	35,460		—		250
Repurchase of noncontrolling interest	(2,462)		—		—
Member distributions	(35,331)		(61,422)		(124,837)
Noncontrolling interest distributions	(1,695)		(1,145)		(17,901)
Cash paid for treasury stock acquired for equity-based compensation tax withholding	(18,448)		—		—
Due to related party and other	(428)		9,650		2,515
Net cash provided by (used in) financing activities	105,145		(272,089)		(153,192)
Net change in cash, cash equivalents and restricted cash	93,697		13,999		4,165
Cash, cash equivalents and restricted cash, beginning of period	41,420		27,421		23,256
Cash, cash equivalents, and restricted cash, end of period	$	135,117	$	41,420	$	27,421

The accompanying notes to financial statements are an integral part of these combined and consolidated financial statements

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CRESCENT ENERGY COMPANY

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS

(Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.)

Unless otherwise stated or the context otherwise indicates, all references to “we,” “us,” “our,” "Crescent" and the “Company” or similar expressions for time periods prior to the Merger Transactions refer to Crescent Energy OpCo LLC (f/k/a Independence Energy LLC) and its subsidiaries, our predecessor for accounting purposes. For time periods subsequent to the Merger Transactions, these terms refer to Crescent Energy Company and its subsidiaries.

NOTE 1 – Organization and Basis of Presentation

Organization

We are a well-capitalized U.S. independent energy company with a portfolio of assets in key proven basins across the lower 48 states with substantial cash flow supported by a predictable base of production. We seek to generate attractive risk-adjusted investment returns and predictable cash flows across cycles by employing our differentiated approach to investing in the oil and natural gas industry. Our approach includes a cash flow-based investment mandate with a focus on operated working interests and is complemented by non-operated working interests, mineral and royalty interests and midstream infrastructure, as well as an active risk management strategy. We pursue our strategy through the production, development and acquisition of crude oil, natural gas and natural gas liquids ("NGLs") reserves. We maintain a diverse portfolio of assets in key proven basins across the United States, including the Eagle Ford, Rockies, Barnett, Permian and Mid-Con.

We have evaluated how we are organized and managed and have identified only one reportable segment, which is the exploration and production of crude oil, natural gas and NGLs. We consider our gathering, processing and marketing functions as ancillary to our oil and gas producing activities. All of our operations and assets are located in the United States, and our revenues are attributable to United States customers.

Merger Transactions

On December 7, 2021, we completed the Merger Transactions, pursuant to which Contango’s business combined with Independence's business under a new publicly traded holding company named "Crescent Energy Company." Our Class A Common Stock is listed on The New York Stock Exchange under the symbol “CRGY.” The new combined company is structured as an “Up-C,” with all of our assets and operations and those of Contango held by Crescent, which is the sole managing member of Crescent Energy OpCo LLC ("OpCo"). Crescent is a holding company, the sole material asset of which consists of units of OpCo ("OpCo Units"). Crescent is the sole managing member of OpCo and is responsible for all operational, management and administrative decisions related to OpCo’s business. Because the unit holders of OpCo lack the characteristics of a controlling financial interest, OpCo was determined to be a variable interest entity. Crescent is considered the primary beneficiary of OpCo as it has both the power to direct OpCo and the right to receive benefits from OpCo. As a result, Crescent consolidates the financial results of OpCo and its subsidiaries. The assets and liabilities of OpCo represent substantially all of our consolidated assets and liabilities with the exception of certain current and deferred taxes and certain liabilities under the Management Agreement, as defined within NOTE 14 - Related Party Transactions. Certain restrictions and covenants related to the transfer of assets from OpCo are discussed further in NOTE 8 - Debt. Former Contango shareholders now own shares of Crescent Class A Common Stock, which have both voting and economic rights with respect to Crescent. The former owners of our predecessor, Independence Energy LLC, now own economic, non-voting OpCo Units and corresponding shares of Crescent Class B Common Stock, which have voting (but no economic) rights with respect to Crescent.

As a result of the Merger Transactions, (a) former owners of Independence own approximately 75% of OpCo, 100% of the total outstanding Crescent Class B Common Stock and approximately 75% of the total outstanding Crescent Energy Class A Common Stock and Crescent Class B Common Stock taken together, (b) former stockholders of Contango own Crescent Class A Common Stock representing approximately 25% of the outstanding Crescent Class A Common Stock and Crescent Class B Common Stock, taken together and (c) Crescent owns approximately 25% of the OpCo Units. Additionally, Independence Energy Aggregator LP, an affiliate of certain former owners of Independence, is the sole holder of Crescent's non-economic Series I preferred stock, $0.0001 par value per share, which entitles the holder thereof to appoint the Board of Directors of Crescent and to certain other approval rights.

Basis of Presentation

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Our combined and consolidated financial statements (the “financial statements”) include the accounts of the Company and its subsidiaries after the elimination of intercompany transactions and balances and are presented in accordance with U.S. general accepted accounting principles (“GAAP”). We have no elements of other comprehensive income for the periods presented.

In August 2020, through a series of transactions, we underwent a reorganization (the “Independence Reorganization”) in connection with the Titan Acquisition (as defined in NOTE 3 – Acquisitions and Divestitures), carried out under the direction of our Managing Member (as defined in our Amended and Restated Limited Liability Company Agreement, dated August 18, 2020), whereby certain entities (the “Contributed Entities”) previously owned and under the common control of affiliates of Kohlberg Kravis Roberts & Co. L.P. ("KKR Group") were contributed to us. The financial statements include the accounts of the Contributed Entities from the date of the Independence Reorganization, which is the date the Company obtained a controlling financial interest in the Contributed Entities on a consolidated basis. As required by GAAP, the contributions of the Contributed Entities in connection with the Independence Reorganization were accounted for as a reorganization of entities under common control, in a manner similar to a pooling of interests, with all assets and liabilities transferred to us at their carrying amounts. The Isla Merger, whereby Independence merged with and into OpCo on December 7, 2021 in connection with the Merger Transactions, was also accounted for as a reorganization of entities under common control. Because the Independence Reorganization and the Isla Merger resulted in changes in the reporting entity, and in order to furnish comparative financial information prior to the Independence Reorganization and the Isla Merger, our financial statements have been retrospectively recast to reflect the historical accounts of the Contributed Entities and Independence, our accounting predecessor (the "Predecessor"), on a combined basis.

Crescent is a holding company that conducts substantially all of its business through its consolidated subsidiaries, including OpCo, which is owned approximately 25% by Crescent and approximately 75% by holders of our redeemable noncontrolling interests representing former owners of Independence, and Crescent Energy Finance LLC, OpCo's wholly owned subsidiary. Crescent and OpCo have no operations, or material cash flows, assets or liabilities other than their investment in Crescent Energy Finance LLC.

The financial statements include undivided interests in oil and natural gas properties. We account for our share of oil and natural gas properties by reporting our proportionate share of assets, liabilities, revenues, costs, and cash flows within the accompanying consolidated balance sheets, combined and consolidated statements of operations, and combined and consolidated statements of cash flows.

NOTE 2 – Summary of Significant Accounting Policies

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make use of estimates and assumptions that affect the reported amount of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We use historical experience and various other assumptions and information that are believed to be reasonable under the circumstances in developing our estimates and judgments. Estimates and assumptions about future events and their effects cannot be predicted with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. While we believe that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results may differ from these estimates. Our significant estimates include the fair value of acquired assets and liabilities, oil and natural gas reserves, impairment of proved and unproved oil and natural gas properties and valuation of derivative instruments.

Cash and Cash Equivalents

Cash and cash equivalents consist of cash deposited in commercial bank accounts and highly liquid investments purchased with an original maturity of three months or less at the date of purchase. Cash and cash equivalents are maintained with major financial institutions in the U.S. Deposits with these financial institutions may exceed the amount of insurance provided on such deposits; however, the financial stability of the financial institutions is regularly monitored, and we believe that we do not have exposure to any significant default risk.

Restricted Cash

Restricted cash consists of funds earmarked for a special purpose and therefore not available for immediate and general use. The majority of our restricted cash is comprised of cash that is contractually required to be restricted to pay for the future

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abandonment of certain wells in California. Restricted cash is included in other current assets and other assets on our balance sheets.

The following table provides a reconciliation of cash and restricted cash presented on our balance sheets to amounts shown in the statements of cash flows:

	As of December 31,
	2021		2020		2019
	(in thousands)
Cash and cash equivalents	$	128,578	$	36,861	$	19,894
Restricted cash – current	—		—		3,932
Restricted cash – noncurrent	6,539		4,559		3,595
Total cash, cash equivalents and restricted cash	$	135,117	$	41,420	$	27,421

Accounts Receivable

We routinely assess the recoverability of our accounts receivable, which primarily comprise amounts due from (i) purchasers of our oil, natural gas and NGL production and (ii) joint interest owners on properties that we operate. We monitor our exposure to credit risk primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s creditworthiness. Generally, our oil and natural gas receivables are collected within 45 to 60 days of production. Our joint interest billings are collected within the month after they are billed, and we have the ability to withhold future revenue distributions to recover any nonpayment of our joint interest billings.

As a result of adopting ASU 2016-13, Measurement of Credit Losses on Financial Instruments, we establish allowances for credit losses equal to the estimable portions of accounts receivable for which failure to collect is expected to occur primarily based on a historical loss rate analysis. We estimate uncollectible amounts based on the length of time that the accounts receivables have been outstanding, historical collection experience and current and future economic and market conditions. We consider forecasts of future economic conditions in the estimate of our expected credit losses, in particular whether there is an increase in the probability that our counterparties will be unable to pay their obligations when due, and adjust our allowance for expected credit losses, when necessary. Our allowances for expected credit losses and bad debt were immaterial as of December 31, 2021 and 2020. We did not incur credit loss expense or bad debt expense related to our accounts receivable during the years ended December 31, 2021, 2020, and 2019. We do not have any off-balance sheet credit exposure related to our customers.

Restricted Investment Securities

We hold U.S. Treasury securities, which are contractually required to be set aside to pay for the future abandonment of certain wells in California. Due to this restriction, we report these investment securities as noncurrent and include them within other assets on our consolidated balance sheets.

We classify our investment in these debt securities at the acquisition date and re-evaluate the classification at each balance sheet date. We classify debt securities purchased with the positive intent and ability to hold until their maturity date as held-to-maturity investments (“HTM”) and carry these investments at amortized cost. Premiums and discounts on purchases are amortized over the remaining time to maturity of the security and the amortization is recorded as an adjustment to interest income. At December 31, 2021 and 2020, we had restricted investment securities – HTM with a carrying value of

$5.3 million and $8.5 million, respectively.

Oil and Natural Gas Properties

Oil and natural gas producing activities are accounted for under the successful efforts method of accounting. Under this method, exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. Costs that are associated with the drilling of successful exploration wells are capitalized if proved reserves are found. Capitalized costs attributed to the properties are charged as an operating expense through depreciation, depletion and amortization (“DD&A”). Dry hole costs associated with developing proved fields are capitalized. Costs associated with the drilling of exploratory wells that do not find proved reserves, geological and geophysical costs and costs of certain nonproducing leasehold costs are expensed once evaluated and determined to be a dry hole. We incurred exploration expense of $1.2 million, $0.5 million, and $0.5 million for the years ended December 31, 2021, 2020 and 2019, respectively.

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Delay and surface rentals are charged to expense as incurred. The costs to acquire mineral interests in oil and natural gas properties and lease acquisition costs are capitalized when incurred. If proved reserves are found on an undeveloped property, leasehold costs are transferred to proved properties.

The capitalized costs of producing oil and natural gas properties are depleted on a field-by-field basis using the units-of-production method based on the ratio of current production to estimated total net proved oil, natural gas and NGL reserves. Proved developed reserves are used in computing depletion rates for drilling and development costs and total proved reserves are used for depletion rates of leasehold costs.

Upon the sale of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated DD&A are removed from the property accounts and any gain or loss is recognized.

Estimated dismantlement and abandonment costs for oil and natural gas properties are capitalized at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. See discussion of Asset Retirement Obligations below for additional discussion.

During the years ended December 31, 2021, 2020 and 2019, we recognized depletion expense of $300.0 million, $364.7 million and $300.9 million, respectively.

Other Property, Plant and Equipment

We have other property, plant, and equipment that consists principally of gathering and processing facilities, vehicles, computer hardware and software, office furniture and equipment, buildings and leasehold improvements. Other property, plant, and equipment is recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the respective assets which range from three to thirty years. Leasehold improvements are amortized over the shorter of their economic lives or the lease term. The cost of maintenance and repairs are expensed in the period incurred. Expenditures that extend the life or improve existing property and equipment are capitalized.

Impairment

Proved and unproved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. When a triggering event is identified, we compare the carrying amount of our oil and natural gas properties to the estimated undiscounted cash flows our oil and natural gas properties will generate to determine if the carrying amount is recoverable. We perform this analysis on a field-by-field basis. If the carrying amount exceeds the estimated undiscounted cash flows, we will write-down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, and discount rates commensurate with the risk associated with realizing the projected cash flows.

In March 2020, crude oil demand experienced significant declines due to the coronavirus disease 2019 (COVID-19) global pandemic and resulting governmental led shut-downs in economic activity. During the second quarter of 2020, as it became apparent that the pandemic would continue indefinitely with sustained significant decline in crude oil prices, we assessed our oil and natural gas properties for impairment and incurred impairment expense of $247.2 million during the year ended December 31, 2020. We did not incur any impairment expense during the years ended December 31, 2021 and 2019.

Drilling Advances

We pay advances for certain D&C costs on our non-operated properties, as required by our joint operating agreements. At December 31, 2021 and 2020, we had $0.2 million and $38.9 million, respectively, of outstanding advances on our consolidated balance sheets.

Equity Method Investments

If an entity is organized as a limited partnership or limited liability company and maintains separate ownership accounts, we generally account for our investment using the equity method if our ownership interest is between 3% and 50%, unless our interest is so minor that we have virtually no influence over the investee’s operating and financial policies. For all other types of investments, we generally apply the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the investee’s operating and financial policies. We eliminate our proportionate share of

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profits and losses from transactions with equity affiliates to the extent such amounts remain on our consolidated balance sheets (or those of our equity affiliates).

Under the equity method, our proportionate share of each investees' net income increases the balance of our investment, while a net loss or receipt of dividends decreases the balance of our investment. Our proportionate share of net income from our equity affiliates are reported as a single line item within income (loss) from equity method investments in our combined and consolidated statements of operations.

Subsequent to the Merger Transactions, we have significant influence, but not control, over Exaro Energy III, LLC ("Exaro") and Lost Creek Gathering LLC ("Lost Creek"). We have a 37% ownership interest in Exaro and a 65% ownership interest in Lost Creek, but we do not control this entity as our partner has substantive participating rights. As a result, our investments in Exaro of $4.7 million and Lost Creek of $10.7 million are accounted for using the equity method within investments in equity affiliates in our consolidated balance sheet as of December 31, 2021.

Other Long-Term Assets

We acquired certain long-term joint interest receivables that are settled through the underlying oil and natural gas interests of certain joint interest owners. The outstanding balance of these long-term receivables was $1.2 million and $1.3 million as of December 31, 2021 and 2020. We recognized write-offs of acquired long-term joint interest receivables totaling $3.8 million within operating expense in the combined and consolidated statement of operations for the year ended December 31, 2019.

Redeemable Noncontrolling Interests

In connection with the Merger Transactions, 127.5 million OpCo Units were issued to the former owners of Independence. The former owners of Independence also own all outstanding shares of our Class B Common Stock. Pursuant to the OpCo LLC Agreement, holders of OpCo Units, other than the Company, may redeem all or a portion of their OpCo Units, together with a corresponding number of shares of Class B Common Stock, for either (a) shares of Class A Common Stock or (b) an approximately equivalent amount of cash as determined pursuant to the terms of the OpCo LLC Agreement, at the election of the Company. In connection with the exercise of such redemption, a corresponding number of shares of Class B Common Stock will be cancelled. The redemption election is not considered to be within the control of the Company because the holders of Class B Common Stock and their affiliates control the Company through direct representation on the Board of Directors. As a result, we present the noncontrolling interests in OpCo as redeemable noncontrolling interests outside of permanent equity. Redeemable noncontrolling interest is recorded at the greater of the carrying value or redemption amount with a corresponding adjustment to additional paid-in capital.

From the date of the Merger Transactions through December 31, 2021, we recorded adjustments to the value of our redeemable noncontrolling interests as shown below:

	Redeemable Noncontrolling Interest
	(in thousands)
Balance as of December 7, 2021	$	2,353,977
Net loss attributable to redeemable noncontrolling interests	(58,761)
Accrued OpCo distribution	(2,706)
Equity-based compensation, net of withholding taxes	16,412
Cancellation of OpCo Units associated with repurchase of treasury stock	16,091
Balance as of December 31, 2021	$	2,325,013

Stockholders' Equity

Class A and Class B Common Stock

As of December 31, 2021, we had 41,954,385 and 127,536,463 shares of Class A Common Stock and Class B Common Stock outstanding, respectively. Our Class A Common Stock is publicly traded, while our Class B Common Stock is 100% owned by the former owners of Independence.

As a result of the Merger Transactions, (a) former owners of Independence own 100% of the total outstanding Class B Common Stock and approximately 75% of the total outstanding Class A Common Stock and Class B Common Stock taken

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together, and (b) former stockholders of Contango own Class A Common Stock that represents approximately 25% of the outstanding Class A Common Stock and Class B Common Stock, taken together.

Treasury stock

Treasury stock shares represent shares we withheld associated with the payroll tax withholding obligations due from employees upon the vesting of stock awards. We include the shares withheld as treasury stock on our consolidated balance sheets and separately pay the payroll tax obligation. These retained shares are not part of a publicly announced program to repurchase shares of our Class A Common Stock and are accounted for at cost. We do not have a publicly announced program to repurchase shares of our Class A Common Stock.

Predecessor members' equity

Prior to the Merger Transactions, Independence had two classes of equity in the form of Class A Units and Class B Units. Both Class A Units and Class B Units were considered common units, and distributions were made pro rata in accordance with each unit’s respective ownership percentage. At the time of the Merger Transactions, only Class A Units were issued and outstanding. As a result of the Merger Transactions, all Class A Units were exchanged for our Class B Common Stock and no Class A Units or Class B Units remain issued or outstanding.

Noncontrolling interest

We record noncontrolling interest associated with third party ownership interests in our subsidiaries. Income or loss associated with these interests is classified as net income (loss) attributable to noncontrolling interest on our combined and consolidated statements of operations.

In April 2021, certain minority investors exchanged 100% of their interests in our Barnett Basin natural gas assets for 9,508 of our Predecessor's Class A Units ("April 2021 Exchange"). Since we already consolidate the results of these assets, this transaction was accounted for as an equity transaction and reflected as a reclassification from noncontrolling interests to members’ equity with no gain or loss recognized on exchange.

In December 2020, certain other minority owners of our consolidated subsidiaries elected to exchange 100% of their interests in those individual consolidated subsidiaries for 220,421 of our Predecessor's Class A Units (“December 2020 Exchange”). Since we already consolidate the results of these subsidiaries, this transaction was accounted for as a reclassification of $657.4 million from noncontrolling interest to members’ equity with no gain or loss recognized on the exchange.

In August 2020, in connection with the Independence Reorganization, certain interests in our consolidated subsidiaries owned by a third-party investor were not contributed to the Predecessor. These interests were reclassified from members’ equity to noncontrolling interest as of the date of the Independence Reorganization and all income and loss attributable to these interests is recorded as net income (loss) attributable to noncontrolling interests from the date of the Independence Reorganization. In May 2021, these noncontrolling equity interests were redeemed in exchange for the third-party investor’s proportionate share of the underlying oil and natural gas interests held by its consolidated subsidiaries ("Noncontrolling Interest Carve-out"). Additionally, the third-party investor contributed cash of approximately $35.5 million to repay its proportionate share of the underlying debt outstanding under our Prior Credit Agreements and other liabilities. The percentage ownership of these certain consolidated subsidiaries owned by the third-party investor ranges from 2.21% to 7.38%.

The following table discloses the effects on equity of changes in our ownership interest in our subsidiaries related to transactions with holders of noncontrolling interests:

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	Year Ended December 31,
	2021		2020		2019
	(in thousands)
Net income (loss) attributable to Crescent Energy and its Predecessor	$	(358,544)	$	(118,649)	$	45,839
Transfers (to) from noncontrolling interest
Decrease in Predecessor members’ equity related to the Independence Reorganization	—		(101,926)		—
Increase in Predecessor members’ equity related to the December 2020 Exchange	—		657,370		—
Increase in Predecessor members’ equity related to the April 2021 Exchange	62,051		—		—
Net transfers (to) from noncontrolling interest	62,051		555,444		—
Changes from net income (loss) attributable to Crescent Energy and its Predecessor and transfers (to) from noncontrolling interest	$	(296,493)	$	436,795	$	45,839

Debt Issuance Costs

We capitalize costs incurred in connection with obtaining financing associated with our revolving credit facilities and amortize such costs as additional interest expense over the life of the underlying indebtedness. These costs include fees paid to financial institutions and legal fees and are included in other assets in our consolidated balance sheets.

Revenue Recognition

Oil, Gas and NGL Revenues

We hold operated and non-operated working interests and mineral and royalty interests in producing assets that function as follows:

Operated working interests: We are responsible for the day-to-day management and operation of the field as well as negotiations required for post-production transportation, gathering, processing and marketing; we remit proceeds from sales of resulting hydrocarbons to third parties back to non-operators less costs as agreed in the applicable joint operating agreement.

Non-operated working interests: An operator of these assets is responsible for the day-to-day management and operation of the field as well as negotiations required for post-production transportation, gathering, processing, and marketing; the operator then remits proceeds from sales of resulting hydrocarbons to third parties back to non-operators less costs as agreed in the applicable joint operating agreement.

Mineral and royalty interests: Ownership of a percentage of production or production revenues produced from leased acreage. The owner of this share of production does not bear any of the cost of exploration, drilling, producing, operating or any other expense associated with drilling and producing an oil and gas well. Mineral and royalty interests may be burdened by some or all of the post-production costs related to gathering, processing and marketing.

We sell oil production at the lease and collect an agreed-upon index price, net of pricing differentials.

Under our natural gas contracts, we deliver natural gas to a midstream processor at a contractually specified delivery point. The midstream processor gathers and processes the natural gas and then markets and remits proceeds to us for the resulting sale of the residue gas and NGLs.

Our non-operated production is marketed by operators, after which the operators remit net proceeds from the sale of our share of production to us. Proceeds reflect post-production expenses such as gathering, processing and other expenses incurred in marketing of that production.

Performance Obligations

Under product sales contracts, each unit of product generally represents a separate performance obligation. We record revenue for our product sales contracts at the point-in-time control of a commodity is transferred to the customer. However, settlement statements from non-operated working interests may not be received for 30 to 60 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the customer and the net commodity price that will be received for the sale of these commodity products.

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At the end of the reporting period, we did not have any unsatisfied performance obligations. Our contracts with customers typically include variable consideration based on monthly pricing tied to local indices and volumes delivered in the current month. The nature of our contracts with customers does not require us to constrain variable consideration for accounting purposes.

Revenue is recognized to the extent it is determined that it is probable that a significant reversal will not occur. We record the differences between our revenue estimates and the actual amounts received in the month that payment is received from the operator.

Incentive Compensation Arrangements

Incentive compensation includes share-based payment awards and incentive cash bonus plans that are issued to employees and non-employees in exchange for services provided to us. Equity-classified share-based payment awards are recognized at fair value on the grant date, and amortized over the life of the award. Liability-classified share-based payment awards are remeasured at fair value until settlement. For awards with service-based vesting conditions only, we recognize compensation cost using straight-line attribution. For awards that contain market or performance conditions we use accelerated attribution. Our policy is to recognize forfeitures as they occur. Certain of our consolidated subsidiaries have also issued incentive awards that are accounted for similar to cash bonus plans, whereby compensation cost is measured based on the present value of probable expected benefits to be paid and recognized over the period services are provided. Incentive awards similar to cash bonus plans may also have market-based or time-based vesting conditions and are included in accounts payable and accrued liabilities on our consolidated balance sheets.

Incentive compensation cost is presented as general and administrative expense on our combined and consolidated statements of operations. See NOTE 13 – Incentive Compensation Arrangements for additional discussion.

Defined Contribution Plan

In conjunction with the Merger Transactions we will begin offering our employees a defined contribution 401(k) Plan (the “401(k) Plan”) for the benefit of substantially all of our employees. The 401(k) Plan allows eligible employees to make tax-deferred contributions, not to exceed annual limits established by the Internal Revenue Service. The Company matches contributions of 100% of employee contributions, up to 5% of compensation with immediate vesting for existing employees. The Company did not make any contributions to the 401(k) Plan for the years ended December 31, 2021, 2020 and 2019 since the plan's inception began in January 2022 in conjunction with the start of the benefit plan year; however, the Company expects to make contributions to the plan in 2022.

Business Combinations

We recognize the identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values. Fair value is the price that would be received to sell an asset or would be paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value measurement is based on the assumptions of market participants and not those of the reporting entity. Therefore, entity-specific intentions do not impact the measurement of fair value. These fair values are accounted for at the date of acquisition and included in our consolidated balance sheets as of December 31, 2021 and 2020. The results of operations of an acquired business are included in our combined and consolidated statements of operations from the date of the acquisition.

Credit and Concentration Risk

We sell a significant amount of our oil, natural gas and NGL production to a limited number of purchasers. This concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our purchasers may be similarly affected by changes in economic, industry or other conditions. If these counterparties were to fail to pay amounts due to us, our financial position and results of operations could be materially affected.

The below purchasers represented greater than 10% of our revenues during the years ended December 31, 2021, 2020 and 2019:

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	2021		2020		2019
SN EF Maverick, LLC	*		15.5	%	20.0	%
Eighty Eight Oil	*		11.7	%	*
Shell Trading US Company	18.3	%	10.4	%	*
Cokinos Energy Corporation	*		*		18.1	%
BP Products North America	*		*		13.1	%

*Purchaser did not account for greater than 10% of revenue for the year

We believe that the loss of any of our purchasers would not result in a material adverse effect on our ability to market future oil and natural gas production.

Risks and Uncertainties

Our future financial condition, results of operations and cash flows are dependent on the demand and prices received for oil, natural gas and NGL production. These prices historically have been volatile, and we expect such volatility to continue in the future, as they are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for oil, natural gas and NGL, market uncertainty and a variety of additional factors beyond our control. These factors include weather conditions, government regulations and taxes, the price and availability of alternative fuels and overall economic conditions. A decline in oil, natural gas or NGL prices may adversely affect our financial position, cash flows and results of operations. Lower oil, natural gas or NGL prices also may reduce the amount of oil, natural gas and NGL that can be produced economically.

Our revenues are derived principally from uncollateralized sales to numerous companies in the oil and natural gas industry; therefore, our customers may be similarly affected by changes in economic and other conditions within the industry.

Risk Management

We periodically enter into derivative contracts to manage our exposure to commodity price and interest rate changes. These derivative contracts may take the form of forward contracts, futures contracts, swaps, swaptions, collars or other options. We do not use derivative contracts for speculative purposes and have not designated any derivative instruments as hedging instruments for accounting purposes. As such, unrealized gains and losses from changes in the valuation of our unsettled derivative contracts, as well as realized gains and losses on the settlement of derivative contracts, are reported in gain (loss) on derivatives in our combined and consolidated statements of operations.

Such derivative instruments are initially recorded at fair value on the date on which a derivative contract is entered into and are subsequently remeasured at fair value at each reporting date. Derivatives are carried as assets when the fair value is positive or as liabilities when the fair value is negative and are classified as current and long term based on the delivery periods of the financial instruments. If the right of offset exists and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on our consolidated balance sheets.

See NOTE 6 – Fair Value Measurements for additional discussion.

Contingencies

Certain conditions may exist as of the date our financial statements are issued, which may result in a loss to us but which will only be resolved when one or more future events occur or fail to occur. In the preparation of our financial statements, management assesses the need for accounting recognition or disclosure of these contingencies, if any, and such assessment inherently involves an exercise in judgment. In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in such proceedings, our management and legal counsel evaluate the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.

When applicable, we will accrue an undiscounted liability for contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum amount within the range is accrued. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when it is believed to be only reasonably possible or remote.

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For contingencies where an unfavorable outcome is reasonably possible and the impact would be material, we disclose the nature of the contingency and, if feasible, an estimate of the possible loss or range of loss. Loss contingencies considered remote are generally not disclosed. See NOTE 12 – Commitments and Contingencies.

Income Taxes

Crescent is a holding company of which our sole material assets are OpCo Units. OpCo is a partnership and is generally not subject to U.S. federal and certain state taxes. Crescent is subject to U.S. federal and certain state taxes on our allocable share of any taxable income of OpCo. Taxable income or loss generated by OpCo is generally allocated and passed through to Crescent at our proportionate share of OpCo unit ownership, except for activity related to items contributed by Contango with a pre-contribution gain which are allocated solely to Crescent.

The amount of income taxes we record requires interpretations of complex rules and regulations of various tax jurisdictions throughout the United States. We recognize deferred tax assets and liabilities for temporary differences, operating losses and tax credit carryforwards. Temporary differences arise when there are differences between the financial statement carrying amount and the tax basis of existing assets and liabilities as these differences create taxable or tax-deductible amounts for future periods. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized. For additional information regarding income taxes, see NOTE 10 – Income Taxes.

ASC 740, Income Taxes, specifies the accounting for uncertainty in income taxes by prescribing a minimum recognition threshold for a tax position to be reflected in the financial statements. If recognized, the tax benefit is measured as the largest amount of tax benefit that is more likely than not to be realized upon ultimate settlement. Management has considered the amounts and the probabilities of the outcomes that could be realized upon ultimate settlement and believes that it is more likely than not that the Company's recorded income tax benefits will be fully realized, or recognizes a valuation allowance against deferred tax assets in cases where we do not forecast sufficient future income to recognize the deferred tax asset.

Goodwill

Goodwill represents the excess of the consideration transferred for business combinations over the fair value of the identifiable net assets acquired. We test goodwill for impairment annually or more frequently if events or changes in circumstances indicate that the asset might be impaired.

Asset Retirement Obligations

An ARO represents the legal obligation associated with the future abandonment of tangible assets, such as wells, service assets, pipelines, and other facilities. We record an ARO and capitalize the asset retirement cost in oil and natural gas properties in the period in which the ARO is incurred based upon the estimated fair value of the obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO liability is accreted to its future estimated value using an estimated credited-adjusted risk-free rate and the capitalized asset retirement cost is depleted on a unit-of-production basis. Both the accretion expense and the depletion expense are included in depreciation, depletion and amortization expense on our combined and consolidated statements of operations.

Measuring the future ARO requires management to make estimates, assumptions and judgments inherent in the present value calculation including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the related asset. If the ARO is settled for an amount other than the recorded amount, a gain or loss is recognized at settlement.

See NOTE 9 – Asset Retirement Obligations.

Environmental Expenditures

In addition to ARO, management also reviews our estimates of the cleanup costs of various sites on an annual basis. When it is probable that obligations have been incurred, and where a reasonable estimate of the cost of compliance or remediation can be determined, the applicable amount is accrued. For other potential liabilities, the timing of accruals coincides with the related

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ongoing site assessments. We do not discount any of these liabilities. Recoveries for environmental remediation costs from third parties, which are probable of realization, are separately recorded and are not offset against the related environmental liability. As of December 31, 2021 and 2020, we did not have any significant probable environmental remediation costs.

Supplemental Cash Flow Disclosures

The following are our supplemental cash flow disclosures for the years ended December 31, 2021, 2020 and 2019:

	Year Ended December 31,
	2021		2020		2019
	(in thousands)
Supplemental cash flow disclosures:
Interest paid, net of amounts capitalized	$	35,055	$	33,902	$	49,397
Income taxes paid	562		14		28
Non-cash investing and financing activities:
Capital expenditures included in accounts payable and accrued liabilities	47,173		12,267		28,305
Equity consideration for acquisitions, net of cash acquired	647,579		454,599		—
Right-of-use assets obtained in exchange for leases	8,573		—		—
April 2021 Exchange and December 2020 Exchange	62,051		657,370		—
Noncontrolling Interest Carve-out	(121,872)		—		—
Capitalized non-cash equity-based compensation	3,373		—		—

Recent Accounting Standards

In February 2016, the FASB issued ASU 2016-02, Leases, ("ASC Topic 842") which establishes comprehensive accounting and financial reporting requirements for leasing arrangements. ASC Topic 842 requires lessees to recognize substantially all lease assets and lease liabilities on the balance sheets. Additional disclosures about an entity’s lease transactions will also be required. ASC Topic 842 defines a lease as “a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment (an identified asset) for a period of time in exchange for consideration.” Lessees and lessors can elect to recognize and measure leases as of the date of adoption using a modified retrospective approach. We adopted ASC Topic 842 effective January 1, 2021. Adoption of ASC Topic 842 resulted in the recognition of additional lease assets and liabilities on our consolidated balance sheets as well as additional disclosures. The adoption did not have a material impact to our combined and consolidated financial statements.

In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848) - Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”). ASU 2020-04 provides optional guidance, for a limited period of time, to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. The amendments in ASU 2020-04 provide optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by reference rate reform if certain criteria are met. The amendments in this ASU apply only to contracts, hedging relationships and other transactions that reference LIBOR, or another reference rate, expected to be discontinued because of reference rate reform. The guidance was effective beginning March 12, 2020 and can be applied prospectively through December 31, 2022. In January 2021, the FASB issued ASU 2021-01, Reference Rate Reform - Scope, which clarified the scope and application of the original guidance. The Company is currently assessing the potential impact of ASU 2020-04 on its consolidated financial statements.

NOTE 3 – Acquisitions and Divestitures

During the three years ended December 31, 2021, we completed the following acquisitions and divestitures:

Contango Merger

In December 2021, we acquired all of Contango's outstanding common stock through the issuance of 39,834,461 shares of Crescent Class A Common Stock and settled Contango's equity-based compensation plans through the issuance of 3,270,915 shares of Crescent Class A Common Stock, of which 1,150,991 shares of treasury stock were repurchased to meet employee payroll tax withholding obligations. Contango's properties are primarily located in Oklahoma, Texas, Wyoming and Louisiana. We accounted for the Contango Merger as a business combination using the acquisition method under GAAP. The fair value of consideration transferred totaled $654.6 million based on the closing share price of Contango's common stock on the date of the

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Merger Transactions as shares of Crescent Class A common stock were not yet publicly traded. The purchase price allocation for the acquisition is preliminary for assets acquired and liabilities assumed. We expect to complete a final valuation analysis during the second half of 2022. As a result of the acquisition, we recognized $76.6 million of goodwill that is primarily attributable to deferred tax liabilities associated with the transaction and expected synergies from our combined operations. This goodwill is not expected to be deductible for income tax reporting purposes.

From the date of the Contango acquisition through December 31, 2021, revenues and net income associated with the operations acquired through the acquisition were $36.4 million and $5.6 million, respectively. We recognized transaction related expenses of $12.9 million for the year ended December 31, 2021.

The following table summarizes our unaudited pro forma financial information for the years ended December 31, 2021 and 2020 as if the Contango acquisition occurred on January 1, 2020 (unaudited):

	Year Ended December 31,
	2021		2020
	(in thousands)
Revenues	$	1,943,741	$	970,921
Net loss	$	(432,328)	$	(507,837)

The unaudited pro forma information is presented for illustration purposes only and is not necessarily indicative of the operating results that would have occurred had the acquisition been completed on January 1, 2020, nor is it necessarily indicative of future operating results of the combined entity.

Central Basin Platform Acquisition

In December 2021, we acquired from an unrelated third-party certain operated producing oil and natural gas properties predominately located in the Central Basin Platform in Texas and New Mexico, with additional properties in the southwestern Permian and Powder River Basins, for total cash consideration of $60.4 million, including customary purchase price adjustments. The purchase price was funded using cash on hand and borrowings under our Revolving Credit Facility (as defined in NOTE 8 – Debt). We accounted for the Central Basin Platform Acquisition as an asset acquisition and recorded an additional $73.7 million of proved oil and natural gas properties, including an ARO asset of $12.6 million.

DJ Basin Acquisition

In March 2021, we acquired a portfolio of oil and natural gas mineral assets located in the DJ Basin from an unrelated third-party operator for total consideration of $60.8 million (the "DJ Basin Acquisition"). The DJ Basin Acquisition was funded using cash on hand and borrowings under our Prior Credit Agreements. We accounted for the DJ Basin Acquisition as an asset acquisition and the purchase price was allocated 35.6% to proved oil and natural gas properties and 64.4% to unproved oil and natural gas properties. In conjunction with the DJ Basin Acquisition, we issued equity-based compensation, a portion of which is classified within permanent equity as noncontrolling interest and the remainder of which is classified as other liabilities, to certain parties of the transaction. See NOTE 13 – Incentive Compensation Arrangements.

Titan Acquisition

In August 2020, through a series of transactions, we consummated the acquisition of all of the outstanding membership interests in Liberty Energy LLC (and the oil and natural gas assets owned thereby) pursuant to the Contribution Agreement, dated as of July 19, 2020, by and among Independence Energy LLC, Liberty Energy Holdings, LLC (“Liberty Holdco”) and the other parties thereto, in consideration for the issuance of certain membership interests in Independence Energy LLC to an entity substantially owned by Liberty Holdco. Subsequent to the acquisition, we changed the name of Liberty Energy, LLC to Titan. Titan owns certain working interests in non-operated producing and non-producing oil and natural gas properties in the Permian, Rockies, Eagle Ford and Arkoma Basins, which includes a 50% interest in the DJ Basin Erie Hub Gathering System. During the year ended December 31, 2020, we transferred $455.1 million of equity consideration in the form of 0.4 million Class A units of our Predecessor. During the year ended December 31, 2021, due to post-closing adjustments that increased the purchase price, we issued an additional $7.2 million in equity consideration in our Predecessor. We recognized transaction related expenses of $8.7 million for the year ended December 31, 2020.

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The following table summarizes the consideration transferred and the estimated fair value of identified assets acquired and liabilities assumed for the Contango and Titan business combinations:

	Contango		Titan
	(in thousands)
Consideration transferred:
Equity consideration	$	654,616	$	461,983
Total	$	654,616	$	461,983
Assets acquired and liabilities assumed:
Cash and cash equivalents	$	14,202	$	482
Accounts receivable, net	145,727		29,044
Derivative assets – current	—		12,000
Prepaid and other current assets	8,275		49,079
Oil and natural gas properties - proved	1,002,165		375,014
Field and other property and equipment	6,955		30,232
Derivative assets – noncurrent	—		114
Goodwill	76,564		—
Investment in equity affiliates	15,047		—
Other assets	3,514		—
Accounts payable and accrued liabilities	(186,689)		(6,539)
Derivative liabilities – current	(44,002)		(4,550)
Long-term debt	(140,000)		—
Deferred tax liability	(83,250)		—
Derivative liabilities – noncurrent	(14,592)		(1,484)
Asset retirement obligations	(142,100)		(21,409)
Other liabilities	(7,200)		—
Fair value of net assets acquired	$	654,616	$	461,983

Claiborne Parish Divestiture

Certain producing properties and oil and natural gas leases in Claiborne Parish, Louisiana were acquired in the Contango Merger and were classified as held for sale and included within “Oil and natural gas properties – proved” in our preliminary purchase price allocation. In December 2021, we entered into a purchase and sale agreement with an unaffiliated third-party that encompassed the sale of certain producing properties and oil and natural gas leases in Claiborne Parish, Louisiana in exchange for cash consideration, net of closing adjustments, of $4.3 million. We did not recognize a gain or loss for the year ended December 31, 2021 as a result of the transaction.

Arkoma Basin Divestiture

In May 2021, we executed a purchase and sale agreement with an unaffiliated third-party that encompassed the sale of certain producing properties and oil and natural gas leases in the Arkoma Basin in exchange for cash consideration, net of closing adjustments, of $22.1 million. We recognized a $8.8 million gain on sale of assets in our combined and consolidated statements of operations for the year ended December 31, 2021, as a result of the transaction.

Midland and Ector County Divestiture

In March 2020, we received the remaining $3.9 million from the deep rights sale, described further below, and recognized the reduction to our oil and gas properties for the full sale of $7.9 million.

In December 2019, we entered into a Term Assignment of Oil and Gas Lease conveying all of our interest in the Midland and Ector county leases between the top of the Mississippian formation down to the base of the Woodford formation, “deep rights”, for total bonus consideration of $7.9 million and a primary term of four years from the effective date, January 1, 2020. We received $4.0 million in December 2019 when the agreement was signed and the remainder was received in March 2020.

Eagle Ford Divestiture

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In September 2019, we entered into a purchase, sale and exchange agreement with an unaffiliated third party, which encompassed the sale of certain producing properties and exchange of oil and gas leases in the Eagle Ford area of South Texas in exchange for cash consideration of $15.2 million and additional post-closing settlement consideration of $1.8 million, $1.2 million of which was received in 2021.

NOTE 4 – Property, Plant and Equipment

The following table summarizes our oil and natural gas properties as of December 31, 2021 and 2020:

	As of December 31,
	2021		2020
	(in thousands)
Proved oil and natural gas properties (successful efforts method)	$	6,043,602	$	4,910,059
Unproved oil and natural gas properties	308,721		288,459
Oil and natural gas properties, at cost	6,352,323		5,198,518
Less accumulated depreciation, depletion, amortization and impairment	(1,881,934)		(1,633,664)
Oil and natural gas properties, net	$	4,470,389	$	3,564,854

Other Property

The following table summarizes other property, plant and equipment as of December 31, 2021 and 2020:

	Estimated useful life	As of December 31,
		2021		2020
	(years)	(in thousands)
Gathering and pipeline system	30	$	106,023	$	108,777
Vehicles	3-5	10,836		7,273
Computers, furniture, and equipment	3-10	7,175		6,812
Buildings and improvements	5-30	6,641		6,797
Land		5,467		5,700
Financing right of use asset		5,249		—
Field inventory		2,927		3,012
Total field and other property and equipment, at cost		144,318		138,371
Less: accumulated depreciation, amortization and impairment		(59,594)		(61,078)
Total field and other property and equipment, net		$	84,724	$	77,293

Capitalized Exploratory Well Costs

Capitalized exploratory well costs are included in unproved oil and natural gas properties. The following table reflects the net changes in capitalized exploratory well costs for the years ended December 31, 2021 and 2020:

	As of December 31,
	2021		2020
	(in thousands)
Balance at beginning of period	$	—	$	—
Additions pending the determination of proved reserves	—		—
Reclassifications to proved properties	—		—
Cost charged to expense	—		—
Balance at end of period	$	—	$	—

As of December 31, 2021, we did not have any capitalized exploratory well costs.

NOTE 5 – Derivatives

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In the normal course of business, we are exposed to certain risks including changes in the prices of oil, natural gas and NGLs which may impact the cash flows associated with the sale of our future oil and natural gas production. We enter into derivative contracts with lenders under our revolving credit facilities that consist of either a single derivative instrument or a combination of instruments to manage our exposure to these risks.

As of December 31, 2021, our commodity derivative instruments consisted of fixed price swaps and collars which are described below:

Fixed Price and Basis Swaps: Fixed price swaps receive a fixed price and pay a floating market price to counterparty on the notional amount. Our basis swaps fix the basis differentials between the index price at which we sell our production as compared to the index price used in the basis swap. Under a swap contract, we will receive payment if the settlement price is less than the fixed price and would be required to make a payment to the counterparty if the settlement price is greater than the fixed price.

Collars: Collars provide a minimum and maximum price on a notional amount of sales volume. Under a collar, we will receive payment if the settlement price is less than the minimum price of the range and make a payment to the counterparty if the settlement price is greater than the maximum price of the range. We would not be required to make a payment or receive payment if the settlement price falls within the range.

The following table details our net volume positions by commodity as of December 31, 2021:

Production Period	Volumes	Weighted Average Fixed Price			Fair Value
	(in thousands)				(in thousands)
Crude oil swaps (Bbls):
WTI
2022	10,464	$60.63			$	(121,508)
2023	7,627	$58.50			(59,395)
2024	2,975	$57.35			(16,542)
Brent
2022	500	$56.36			(9,258)
2023	527	$52.52			(9,103)
2024	189	$63.71			(766)
Natural gas swaps (MMBtu):
2022	84,527	$2.77			(76,861)
2023	56,728	$2.54			(47,722)
2024	454	$2.94			(82)
NGL swaps (Bbls):
2022	2,983	$22.23			(38,596)
Crude oil basis swaps (Bbls):
2022	5,843	$(0.11)			(4,403)
Natural gas basis swaps (MMBtu):
2022	26,061	$(0.17)			(3,243)
CMA roll swaps (Bbls):
2022	1,468	$1.08			563
Natural gas collars (MMBtu):
2022	510	$3.00	-	$3.41	(220)
2023	550	$2.63	-	$3.01	(469)
2024	9,150	$3.00		$3.87	1,187
Total					$	(386,418)

We have variable rate debt outstanding, which is subject to interest rate risk based on volatility in underlying interest rates. As of December 31, 2020, the fair value of our pay-fixed, receive-variable interest rate swaps was an unrealized loss of $7.0 million. Our interest rate swaps matured in 2021.

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We use derivative commodity instruments and enter into swap contracts which are governed by International Swaps and Derivatives Association master agreements. The following table shows the effects of master netting arrangements on the fair value of our derivative contracts at December 31, 2021 and 2020:

	Gross Fair Value		Effect of Counterparty Netting		Net Carrying Value
	(in thousands)
December 31, 2021
Assets:
Derivative assets – current	$	2,983	$	(2,983)	$	—
Derivative assets – noncurrent	4,834		(4,255)		579
Total assets	$	7,817	$	(7,238)	$	579
Liabilities:
Derivative liabilities – current	$	(256,508)	$	2,983	$	(253,525)
Derivative liabilities – noncurrent	(137,726)		4,255		(133,471)
Total liabilities	$	(394,234)	$	7,238	$	(386,996)

	Gross Fair Value		Effect of Counterparty Netting		Net Carrying Value
	(in thousands)
December 31, 2020
Assets:
Derivative assets – current	$	52,833	$	(21,907)	$	30,926
Derivative assets – noncurrent	34,257		(11,905)		22,352
Total assets	$	87,090	$	(33,812)	$	53,278
Liabilities:
Derivative liabilities – current	$	(48,299)	$	21,907	$	(26,392)
Derivative liabilities – noncurrent	(35,863)		11,905		(23,958)
Total liabilities	$	(84,162)	$	33,812	$	(50,350)

The amount of gain (loss) recognized in gain (loss) on derivatives in our combined and consolidated statements of operations was as follows for the years ended December 31, 2021, 2020 and 2019:

	Years ended December 31,
	2021		2020		2019
	(in thousands)
Derivatives not designated as hedging instruments:
Realized gain (loss) on oil positions	$	(180,572)	$	149,713	$	(44,265)
Realized loss on early settlement of certain oil positions	(198,688)		—		—
Realized gain (loss) on natural gas positions	(80,253)		32,638		4,245
Realized gain (loss) on NGL positions	(68,766)		14,458		13,033
Realized gain (loss) on interest hedges	(7,373)		(12,435)		(2,189)
Total realized gain (loss)	(535,652)		184,374		(29,176)
Unrealized gain (loss) on commodity hedges	(337,715)		8,836		(94,766)
Unrealized gain (loss) on interest hedges	7,347		2,074		(3,260)
Total unrealized gain (loss)	(330,368)		10,910		(98,026)
Total gain (loss) on derivatives	$	(866,020)	$	195,284	$	(127,202)

During the year ended December 31, 2021, we settled certain of our outstanding derivative oil commodity contracts for open positions associated with calendar years 2022 and 2023. Subsequent to the settlement, we entered into new commodity derivative contracts at prevailing market prices.

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See NOTE 6 – Fair Value Measurements.

NOTE 6 – Fair Value Measurements

GAAP defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Generally, the determination of fair value requires the use of significant judgment and different approaches and models under varying circumstances. Under a market-based approach, we consider prices of similar assets, consult with brokers and experts, or employ other valuation techniques. Under an income-based approach, we generally estimate future cash flows and then discount them at a risk-adjusted rate. We classify the inputs used to measure the fair value of our financial assets and liabilities into the following hierarchy:

Level 1: Quoted prices (unadjusted) in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2: Quoted market prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets and liabilities in markets that are not active or other than quoted prices that are observable, either directly or indirectly, and can be corroborated by observable market data.

Level 3: Unobservable inputs that reflect management’s best estimates and assumptions of what market participants would use in measuring the fair value of an asset or liability.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of significance for a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities within the fair value hierarchy levels.

Recurring Fair Value Measurements

The following table presents the location and fair value of our derivative assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2021 and 2020, by level within the fair value hierarchy:

	Fair Value Measurement Using
	Level 1		Level 2		Level 3		Total
	(in thousands)
December 31, 2021
Financial assets:
Derivative assets	$	—	$	7,817	$	—	$	7,817
Financial Liabilities:
Derivative liabilities	$	—	$	(394,234)	$	—	$	(394,234)
December 31, 2020
Financial assets:
Derivative assets	$	—	$	87,090	$	—	$	87,090
Financial Liabilities:
Derivative liabilities	$	—	$	(84,162)	$	—	$	(84,162)

Non-Recurring Fair Value Measurements

Certain nonfinancial assets and liabilities are measured at fair value on a non-recurring basis. We utilize fair value measurement on a non-recurring basis to value our oil and natural gas properties when the carrying value of such property exceeds the respective undiscounted future cash flows. The inputs used to determine such fair value are primarily based upon internally developed cash flow models, as well as market-based valuations as discussed in Note 2 and are classified within Level 3.

As stated in NOTE 2 - Summary of Significant Accounting Policies, oil and natural gas properties were written down to their fair value resulting in an impairment expense of $247.2 million in 2020. The fair value was determined using a discounted cash flow model based on the expected present value of the future net cash flows from our oil and natural gas reserves. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis include estimates

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of future prices, production costs, development expenditures, anticipated production, appropriate risk-adjusted discount rates and other relevant data.

Our other non-recurring fair value measurements include the estimates of the fair value of assets and liabilities acquired through business combinations. Both the Contango Merger and Titan Acquisition were accounted for using the acquisition method under GAAP, which requires all assets acquired and liabilities assumed in the acquisitions to be recorded at fair values at the acquisition date of each transaction. Oil and natural gas properties were valued based on an income approach using a discounted cash flow model utilizing Level 3 inputs, including internally generated development and production profiles and price and cost assumptions. Net derivative liabilities assumed in the acquisitions were valued based on Level 2 inputs similar to the Company's other commodity price derivatives. See NOTE 3 – Acquisitions and Divestitures.

Other Fair Value Measurements

The carrying value of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate their fair values due to the short-term maturities of these instruments. Our long-term debt obligations under our Revolving Credit Facility also approximate fair value because the associated variable rates of interest are market based. The fair value of the Senior Notes (as defined in NOTE 8 – Debt) as of December 31, 2021 was $521.5 million based on quoted market prices.

NOTE 7 – Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities consisted of the following as of December 31, 2021 and 2020:

	As of December 31,
	2021		2020
	(in thousands)
Accounts payable and accrued liabilities:
Accounts payable	$	87,336	$	15,019
Accrued lease operating expense	46,231		20,126
Accrued asset operating expense	8,997		3,591
Accrued capital expenditure	60,647		12,267
Accrued general and administrative	12,193		9,549
Accrued transportation expense	19,684		8,399
Accrued deficiency fees	955		5,050
Accrued revenue and royalties payable	75,827		2,142
Accrued interest and other	26,011		4,545
Total accounts payable and accrued liabilities	$	337,881	$	80,688

NOTE 8 – Debt

$500.0 million Senior Notes Issuance

On May 6, 2021, Independence Energy Finance LLC (n/k/a Crescent Energy Finance LLC), our wholly owned subsidiary, issued $500.0 million aggregate principal amount of 7.25% Senior Notes due 2026 (the "Senior Notes"). The Senior Notes bear interest at an annual rate of 7.25%, which is payable on May 1 and November 1 of each year and mature on May 1, 2026.

The Senior Notes are our senior unsecured obligations and the Senior Notes and the related guarantees rank equally in right of payment with the borrowings under our Revolving Credit Facility and any of our other future senior indebtedness and senior to any of our future subordinated indebtedness. The Senior Notes are guaranteed on a senior unsecured basis by each of our existing and future subsidiaries that will guarantee our Revolving Credit Facility. The Senior Notes and the guarantees are effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under our Revolving Credit Facility) to the extent of the value of the collateral securing such indebtedness and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any future subsidiaries that do not guarantee the Senior Notes.

The Senior Notes indenture contains covenants that, among other things, limit the ability of the our restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends or distributions in respect of its equity or redeem, repurchase or retire its equity or subordinated indebtedness; (iii) transfer or sell assets; (iv) make

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investments; (v) create certain liens; (vi) enter into agreements that restrict dividends or other payments from any non-Guarantor restricted subsidiary to it; (vii) consolidate, merge or transfer all or substantially all of its assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries.

We may, at our option, redeem all or a portion of the Senior Notes at any time on or after May 1, 2023 at certain redemption prices. We may also redeem up to 40% of the aggregate principal amount of the Senior Notes before May 1, 2023 with an amount of cash not greater than the net proceeds that we raise in certain equity offerings at a redemption price equal to 107.250% of the principal amount of the Senior Notes being redeemed, plus accrued and unpaid interest, if any, to, but excluding, the redemption date. In addition, prior to May 1, 2023, we may redeem some or all of the Senior Notes at a price equal to 100% of the principal amount thereof, plus a "make-whole" premium, plus accrued and unpaid interest, if any, to, but excluding, the redemption date.

If we experience certain kinds of changes of control accompanied by a ratings decline, holders of the Senior Notes may require us to repurchase all or a portion of their notes at certain redemption prices. The Senior Notes are not listed, and we do not intend to list the notes in the future, on any securities exchange, and currently there is no public market for the notes.

See NOTE 16 – Subsequent Events for discussion of the issuance of an additional $200.0 million in aggregate principal amount of 7.25% Senior Notes due 2026 during 2022.

Revolving Credit Facility

Overview

In connection with the Senior Notes issuance, we entered into a senior secured reserve-based revolving credit agreement (as amended, restated, amended and restated or otherwise modified to date, the "Revolving Credit Facility") with Wells Fargo Bank, N.A., as administrative agent for the lenders and letter of credit issuer, and the lenders from time to time party thereto. The Revolving Credit Facility matures on May 6, 2025. In September 2021, we entered into the first amendment to the Revolving Credit Facility. The first amendment to the Revolving Credit Facility, amongst other things, increased the committed amount from $500.0 million up to $700.0 million and increased our borrowing base from $850.0 million to $1.3 billion. At December 31, 2021, we had $543.0 million of borrowings under the Revolving Credit Facility and $20.7 million in outstanding letters of credit.

The obligations under the Revolving Credit Facility remain secured by first priority liens on substantially all of the Company’s and the guarantors’ tangible and intangible assets, including without limitation, oil and natural gas properties and associated assets and equity interests owned by the Company and such guarantors. In connection with each redetermination of the borrowing base, the Company must maintain mortgages on at least 85% of the net present value, discounted at 9% per annum (“PV-9”) of the oil and natural gas properties that constitute borrowing base properties. The Company’s domestic direct and indirect subsidiaries are required to be guarantors under the Revolving Credit Facility, subject to certain exceptions.

The borrowing base is subject to semi-annual scheduled redeterminations on or about April 1 and October 1 of each year, as well as (i) elective borrowing base interim redeterminations at our request not more than twice during any consecutive 12-month period or the required lenders not more than once during any consecutive 12-month period and (ii) elective borrowing base interim redeterminations at our request following any acquisition of oil and natural gas properties with a purchase price in the aggregate of at least 5.0% of the then effective borrowing base. The borrowing base will be automatically reduced upon (i) the issuance of certain permitted junior lien debt and other permitted additional debt, (ii) the sale or other disposition of borrowing base properties if the aggregate PV-9 of such properties sold or disposed of is in excess of 5.0% of the borrowing base then in effect and (iii) early termination or set-off of swap agreements (a) the administrative agent relied on in determining the borrowing base or (b) if the value of such swap agreements so terminated is in excess of 5.0% of the borrowing base then in effect.

,.

The combined proceeds from the Senior Notes issuance, Revolving Credit Facility and Noncontrolling Interest Carve-Out were used to fully repay all amounts outstanding under our Prior Credit Agreements (as defined below), which were then terminated upon the repayment of the remaining principal and accrued interest.

Interest

Borrowings under the Revolving Credit Facility bear interest at either a U.S. dollar alternative base rate (based on the prime rate, the federal funds effective rate or an adjusted London Interbank Offered Rate (“LIBOR”)), plus an applicable margin or LIBOR, plus an applicable margin, at the election of the borrowers. The applicable margin varies based upon our borrowing base utilization then in effect. The fee payable for the unused revolving commitments is 0.5% per year and is included within

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interest expense on our combined and consolidated statements of operations. Our weighted average interest rate on loan amounts outstanding as of December 31, 2021 was 3.125%.

Covenants

The Revolving Credit Facility contains certain covenants that restrict the payment of cash dividends, certain borrowings, sales of assets, loans to others, investments, merger activity, commodity swap agreements, liens and other transactions without the adherence to certain financial covenants or the prior consent of our lenders. We are subject to (i) maximum leverage ratio and (ii) current ratio financial covenants calculated as of the last day of each fiscal quarter. The Revolving Credit Facility also contains representations, warranties, indemnifications and affirmative and negative covenants, including events of default relating to nonpayment of principal, interest or fees, inaccuracy of representations or warranties in any material respect when made or when deemed made, violation of covenants, bankruptcy and insolvency events, certain unsatisfied judgments and change of control. If an event of default occurs and we are unable to cure such default, the lenders will be able to accelerate maturity and exercise other rights and remedies.

Letters of Credit

From time to time, we may request the issuance of letters of credit for our own account. Letters of credit accrue interest at a rate equal to the margin associated with LIBOR borrowings. At December 31, 2021, we had letters of credit outstanding of $20.7 million, which reduces the amount available to borrow under our Revolving Credit Facility.

Prior Credit Agreements

At December 31, 2020, certain of our subsidiaries had revolving credit facilities with syndicates of lenders. The amounts we were able to borrow under each of the Prior Credit Agreements was limited by a borrowing base, which was based on the oil and natural gas properties, proved reserves, total indebtedness and other factors and was consistent with customary lending criteria. On May 6, 2021, we early terminated the Prior Credit Agreements with the proceeds from the issuance of the Senior Notes and the Noncontrolling Interest Carve-out and borrowings under our Revolving Credit Facility.

The following table summarizes our debt balances as of December 31, 2021 and 2020:

	As of December 31, 2021
	Debt Outstanding		Letters of Credit Issued		Borrowing Base		Maturity
	(in thousands)
Revolving Credit Facility	$	543,000	$	20,653	$	1,300,000	5/6/2025
7.25% Senior Notes due 2026	500,000		—		—		5/1/2026
Less: Unamortized discount and issuance costs	(12,594)
Total long-term debt	$	1,030,406

	As of December 31, 2020
	Debt Outstanding		Letters of Credit Issued		Borrowing Base		Maturity
	(in thousands)
Independence Upstream Holdings LLC	$	32,500	$	—	$	100,000	6/7/2022
Independence Minerals Holdings LLC	15,000		—		37,000		10/25/2024
KNR Resource Investors LP	5,565		250		12,000		6/7/2022
Renee Acquisition LLC	101,310		5,667		145,000		1/31/2023
Newark Acquisition I LP	135,400		6,280		190,000		5/31/2023
Bridge Energy Holdings LLC	35,800		5,574		50,000		7/21/2022
Venado EF LP	156,500		—		160,000		3/10/2022
VOG Palo Verde LP	269,000		—		320,000		2/28/2023
Total long-term debt	$	751,075

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NOTE 9 – Asset Retirement Obligations

Our ARO liabilities are based on our net ownership in wells and facilities and management’s estimate of the costs to abandon and remediate those wells and facilities together with management’s estimate of the future timing of the costs to be incurred. The following table summarizes activity related to our ARO liabilities for the years ended December 31, 2021 and 2020:

	Year Ended December 31,
	2021		2020
	(in thousands)
Balance at beginning of period	$	109,616	$	83,141
Additions(1)	156,201		21,860
Retirements	(1,252)		(881)
Accretion expense	7,121		5,694
Revisions	—		(198)
Noncontrolling Interest Carve-out	(3,810)		—
Sale	(1,869)		—
Balance at end of period	266,007		109,616
Less: current portion	(7,905)		(3,213)
Balance at end of period, noncurrent portion	$	258,102	$	106,403

(1)During the year ended December 31, 2021, our ARO additions related to properties acquired in our 2021 acquisitions. During the year ended December 31, 2020, our ARO additions primarily related to properties acquired in the Titan Acquisition. See NOTE 3 – Acquisitions and Divestitures for additional information.

NOTE 10 – Income Taxes

Prior to the Merger Transactions, we were organized as Delaware limited liability companies and Delaware limited partnerships and were treated as flow-through entities for U.S. federal income tax purposes. As a result, our tax provisions for the years ended December 31, 2020 and 2019 were minimal. Subsequent to the Merger Transactions we are subject to U.S. federal income and state tax on our allocable share of any taxable income of OpCo. Details of income tax provisions and deferred income taxes are provided in the following tables:

	Year Ended December 31,
	2021		2020		2019
Federal income tax provision (benefit)	(in thousands)
Current	$	—	$	—	$	—
Deferred	(935)		—		—
State income tax provision (benefit)
Current	629		14		28
Deferred	—		—		—
Total income tax provision (benefit)	$	(306)	$	14	$	28

The difference between the statutory federal income tax rate and the Company's effective income tax rate is explained as follows:

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	Year Ended December 31,
	2021		2020		2019
Federal income taxes statutory rate	21.0	%	—	%	—	%
Increase (decrease) in rate as a result of:
State current income tax provision, net of federal benefit	(0.1)	%	—	%	—	%
Permanent adjustments (1)	(1.7)	%	—	%	—	%
Income attributable to Predecessor that was not subject to corporate income tax (2)	(18.4)	%	—	%	—	%
Income attributable to noncontrolling interests	(0.7)	%	—	%	—	%
Effective income tax rate	0.1	%	—	%	—	%

(1)During the year ended December 31, 2021, the permanent items primarily related to disallowed officer compensation under Section 162(m) of the Internal Revenue Code.

(2)    During the year ended December 31, 2021, the income attributable to Predecessor was not subject to corporate income tax as we were organized as limited liability companies and limited partnerships that were treated as flow-through entities for U.S federal income tax purposes prior to the Merger Transactions.

Significant components of the Company's deferred income taxes were as follows:

	Year Ended December 31,
	2021		2020
Deferred tax liabilities	(in thousands)
Outside Basis in OpCo	$	98,079	$	—
Deferred tax assets
Federal and state NOL (1)	38,317		—
Federal and state NOL valuation allowance	(30,567)		—
Recognized built-in loss carryforward	6,872		—
Other	920		—
Total deferred tax assets, net of valuation allowance	15,542		—
Net deferred income tax liability	$	82,537	$	—

(1)We have Federal NOLs of $1.9 million, net of tax, that have expiration dates beginning in 2026. We also have NOLs of $36.4 million, net of tax, that were generated after 2017 and have indefinite lives but are limited to offsetting 80% of taxable income in a given tax year.

We assess the available positive and negative evidence to determine if sufficient future taxable income will be generated to use the existing deferred tax assets. On the basis of this evaluation, as of December 31, 2021, a valuation allowance has been recorded to recognize only the portion of the deferred tax assets that are more likely than not to be realized. The amount of the deferred tax asset considered realizable, however, could be adjusted in the future.

As part of the Merger Transactions, we acquired the federal and state NOLs subject to a valuation allowance of $30.6 million due to the Section 382 limitation. During the year ended December 31, 2021, after the Merger Transactions, we recorded an additional valuation allowance related to additional state NOLs incurred that we do not believe are recoverable.

Pursuant to Sections 382 and 383 of the Internal Revenue Code, utilization of our NOLs and credits is subject to a small annual limitation. These annual limitations may result in the expiration of NOLs and credits prior to utilization.

As of December 31, 2021 and 2020, we did not have any uncertain tax positions.

NOTE 11 - Leases

Adoption of ASC Topic 842, Leases

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On January 1, 2021, we adopted ASC Topic 842 using the modified retrospective method. We elected the package of practical expedients, including the hindsight and land easement expedients, upon transition which will retain the lease classification for leases and any unamortized initial direct costs that existed prior to the adoption of this standard.

In accordance with the adoption of ASC Topic 842, we now record a net operating lease right-of-use ("ROU") asset and operating lease liability on the consolidated balance sheets for all operating leases with a lease term in excess of 12 months. Prior to the adoption of ASC Topic 842, these same leases were treated as operating leases under ASC Topic 840 and therefore were not recorded on the consolidated balance sheets as of December 31, 2020. There was no impact to retained earnings and no significant impact on the combined and consolidated statements of operations or the combined and consolidated statements of cash flows as a result of adopting ASC Topic 842.

Lease Recognition

We enter into contractual lease arrangements to rent buildings, compressors, drilling rigs, office and rental equipment and vehicles from third-party lessors. ROU assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make future lease payments arising from the lease. Operating lease ROU assets and liabilities are recorded at commencement date based on the present value of lease payments over the lease term. Leases with an initial term of 12 months or less are not recorded on the consolidated balance sheets. The Company recognizes lease expense for these short-term leases on a straight-line basis over the lease term. We use our incremental borrowing rate based on the information available at commencement date of the contract in determining the present value of future lease payments. The incremental borrowing rate is calculated using our collateralized incremental borrowing rate based on our debt structure. The operating lease ROU asset also includes any lease incentives received in the recognition of the present value of future lease payments. Certain of our leases may also include escalation clauses or options to extend or terminate the lease. These options are included in the present value recorded for the leases when it is reasonably certain that we will exercise that option. Lease expense for lease payments is recognized on a straight-line basis over the lease term.

If an arrangement is determined to be a lease, we record the resulting ROU asset on the consolidated balance sheets with offsetting liabilities at the commencement date. We recognize a lease in the financial statements when the arrangement either explicitly or implicitly involves property, plant or equipment ("PP&E"), the contract terms are dependent on the use of the PP&E, and we have the ability or right to control the PP&E or to direct others to control the PP&E and receive the majority of the economic benefits of the assets.

The following tables show the presentation of the right-of-use assets and lease liabilities within our combined and consolidated financial statements:

	As of December 31, 2021
	(in thousands)
Field and other property and equipment, at cost
Financing right-of-use asset	$	5,249
Other assets
Operating right-of-use asset	2,299
Other current liabilities
Short-term operating lease liability	(1,292)
Other liabilities
Long-term operating lease liability	(1,007)

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	Year Ended December 31, 2021
	(in thousands)
Lease cost included in combined and consolidated statement of operations
Operating lease cost	$	939
Financing lease cost - amortization of ROU assets	20
Financing lease cost - interest on lease liabilities	131
Administrative lease cost (1)	100
Short-term lease cost (2)	876
Total lease cost	$	2,066

(1)     Costs related primarily to office equipment and IT solutions with lease terms of more than one month and less than one year.

(2)     Costs related primarily to generators, compressors and vehicle agreements with lease terms of more than one month and less than one year.

Lease term and discount rate related to our leases are as follows:

	As of December 31, 2021
	Operating	Financing
Weighted-average remaining lease term (years)	2.3	3.1
Weighted-average discount rate	4.50%	4.50%

As of December 31, 2021, the maturity analysis for our lease liabilities under the scope of ASC 842 is as follows:

	As of December 31, 2021
	Operating		Financing
Year Ended December 31,	(in thousands)
2022	$	1,292	$	1,606
2023	666		1,887
2024	412		1,370
2025	18		633
2026	18		16
After 2026	24		—
Less: interest	(131)		(394)
Present value of lease liabilities	$	2,299	$	5,118

NOTE 12 – Commitments and Contingencies

From time to time, we may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of business. We are currently unaware of any proceedings that, in the opinion of management, will individually or in the aggregate have a material adverse effect on our financial position, results of operations or cash flows.

We are subject to extensive federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require us to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. We believe we are currently in compliance with all applicable federal, state and local regulations. Accordingly, no liability or loss associated with environmental remediation was recognized as of December 31, 2021 except for the following:

We were engaged with the Environmental Protection Agency (EPA) for alleged violations of the Clean Water Act between 2016 and 2018. We have settled these allegations with the EPA and have recorded $1.4 million as a liability and expense at December 31, 2020, all of which was paid during 2021.

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On February 14, 2022, the New Mexico Energy, Minerals and Natural Resources Department’s Oil Conservation Division announced a civil penalty of $913,200 to Contango for failure to file form C-115 according to required deadlines and having too many inactive wells. The parties are discussing a resolution to the matter.

Following the filing of the preliminary joint proxy statement/prospectus related to the Merger Transactions on July 26, 2021, four lawsuits have been filed in the United States District Court for the Southern District of New York, and one lawsuit has been filed in the United States District for the Eastern District of New York, each in connection with the Merger Transactions (the “Shareholder Actions”): Stein v. Contango Oil & Gas Co., et al., No. 1:21-cv-06769 (S.D.N.Y. Aug. 11, 2021) (the “Stein Action”); Prus v. Contango Oil & Gas Co., et al., No. 1:21-cv-04656 (E.D.N.Y. Aug. 18, 2021) (the “Prus Action”); Whitfield v. Contango Oil & Gas Co., et al., No. 1:21-cv-0700 (S.D.N.Y. Aug. 19, 2021) (the “Whitfield Action”); Byerly v. Contango Oil & Gas Co., et al., 1:21-cv-07327 (S.D.N.Y. Aug. 31, 2021) (the “Byerly Action”); Provost v. Contango Oil & Gas Co., et al., 1:21-cv-07874 (S.D.N.Y. Sept. 21, 2021) (the “Provost Action”). Each of the Shareholder Actions names Contango and the members of the Contango board as defendants, and the Whitfield Action names Independence Energy, LLC, OpCo, Crescent Energy Company (f/k/a IE PubCo Inc.) and other affiliates as additional defendants. Each of the Shareholder Actions alleges, among other things, that the registration statement on Form S-4 filed by IE PubCo Inc. on July 26, 2021 in connection with the Merger Transactions (the “Registration Statement”) is false and misleading and/or omits certain information allegedly material to Contango shareholders in violation of Sections 14(a) and 20(a) of the Securities and Exchange Act of 1934 (as amended, the “Exchange Act”) and Rule 14a-9 promulgated thereunder. The plaintiffs in the Shareholder Actions seek, among other relief, an injunction enjoining the Merger Transactions unless and until the defendants disclose the allegedly omitted material information, a rescission of the Contango Agreement to the extent already implemented (or an award of rescissory damages), an order directing the defendants to account for all damages resulting from the alleged wrongdoing, and an award of plaintiffs’ attorneys’ and experts’ fees and other relief. The Byerly Action also requests that the court determine that the lawsuit is a proper class action and certify Byerly as class representative and his counsel as class counsel. On September 20, 2021, the court consolidated the Stein and Whitfield Actions with the Byerly Action. On October 13, 2021, the court consolidated the Provost Action with the Byerly Action. Contango has also received a demand letter sent on behalf of Catherine Coffman, a purported Contango shareholder. The letter demanded that Contango make supplemental disclosures to investors regarding the Merger Transactions based on factual and legal arguments that are substantially similar to those in the Stein, Prus, Whitfield, Byerly, and Provost Actions.

On November 26, 2021, in order to avoid the risk of the Shareholder Actions delaying the Merger Transactions and to minimize the expense of defending the Shareholder Actions, and without admitting any liability or wrongdoing, Contango and Independence voluntarily made certain disclosures that supplement those contained in the joint proxy statement/prospectus. Thereafter, plaintiffs filed voluntary notices of dismissal dismissing the Whitfield and Prus Actions. Pursuant to a scheduling order issued in the consolidated Byerly Action, plaintiff is required to file a Consolidated Amended Complaint within 10 days of an order appointing Byerly as lead plaintiff in the consolidated action.

We believe that the Shareholder Actions are without merit and, along with the individual and other defendants intend to defend against the Shareholder Actions; however, Crescent cannot predict the amount of time and expense that will be required to resolve the Shareholder Actions nor their outcomes. Additional lawsuits arising out of or related to the Merger Transactions may also be filed in the future. At December 31, 2021, we had no amounts reserved on our consolidated balance sheet related to this matter.

Oil Gathering Agreement

In connection with the execution of an oil gathering agreement with a midstream service provider, we received ownership in a Series D class of equity in the midstream service provider. The Series D units do not give us voting or other control rights, but do provide us with an incentive distribution right if other unit classes receive distributions equal to contributed capital plus targeted rates of return. We account for the Series D units through the fair value option available under ASC 825, Financial Instruments. As of December 31, 2021 and 2020, we have concluded the fair value of our investment is not material, based on the nature of the Series D units and overall risk inherent in receiving future cash flows given the stage of development of the entity and required return hurdles.

Carbon Dioxide Purchase Agreement

We assumed one take-or-pay carbon dioxide purchase agreement as part of a prior acquisition. The agreement includes a minimum volume commitment to purchase carbon dioxide at a price stipulated in the contract. The agreement provides carbon dioxide for use in our enhanced recovery projects in certain of our properties. The daily minimum volume commitments are 140 MMcf/per day from June 2021 to May 2026, with the commitment effectively ending in May 2026. We expect to purchase more carbon dioxide through the end of the agreement in 2026 than our minimum volume commitments, and, in accordance

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with the agreement, if we do not meet our minimum volume commitments for a year (or years), we can make up the volumes in future years through 2029 as long as we pay for our minimum volumes each year. As of December 31, 2021 and 2020, we have met required minimum volumes.

Oil and Natural Gas Transportation and Gathering Agreements

We have entered into certain oil and natural gas transportation and gathering agreements with various pipeline carriers. Under these agreements, we are obligated to ship minimum daily quantities or pay for any deficiencies at a specified rate. We are also obligated under certain of these arrangements to pay a demand charge for firm capacity rights on pipeline systems regardless of the amount of pipeline capacity that we utilize. If we do not utilize the capacity, we can release it to others, thus reducing our potential liability. We recognized $5.8 million, $14.5 million and $1.9 million of transportation expense in our combined and consolidated statements of operations related to minimum volume deficiencies for the years ended December 31, 2021, 2020 and 2019, respectively.

The following table summarizes our future commitments related to these oil and natural gas transportation and gathering agreements as of December 31, 2021:

	As of December 31, 2021
	(in thousands)
2022	$	105,606
2023	80,340
2024	65,848
2025	61,346
2026	32,652
Thereafter	62,957
Total minimum future commitments	$	408,749

NOTE 13 – Incentive Compensation Arrangements

Overview

We and certain of our subsidiaries have entered into incentive compensation award agreements to grant profits interest, restricted stock, performance stock units (PSUs) and other incentive awards to our employees, our Manager, and non-employee directors. The following table summarizes compensation expense we recognized in connection with our incentive compensation awards for the years indicated:

	Year Ended December 31,
	2021		2020		2019
	(in thousands)
ASC 710 profits interest awards	$	—	$	—	$	—
ASC 718 liability-classified profits interest awards	(2,043)		(797)		(2,721)
ASC 718 equity-classified profits interest awards	1,563		—		—
ASC 718 equity-classified PSU awards	1,120		—		—
ASC 718 equity-classified Contango PSU awards	39,279		—		—
Total expense (income)	$	39,919	$	(797)	$	(2,721)

Our incentive compensation awards may contain certain service-based, performance-based, and market-based vesting conditions, which are further discussed below.

ASC 710 compensation awards

Incentive unit awards

Certain of our subsidiaries have issued incentive awards that require continuous service in order to receive distributions, and do not represent an equity interest. As these incentive awards are similar to a cash bonus plan, compensation cost is measured

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based on the present value of expected benefits that are probable of being paid and recognized over the period services are provided. Compensation cost is remeasured at each reporting period based on expected future benefits. We did not recognize any compensation cost for this type of incentive award during the years ended December 31, 2021, 2020 and 2019.

ASC 718 stock-based compensation awards

Liability-classified profits interest awards

Certain of our subsidiaries issue profits interests that are liability-classified stock-based compensation awards. These awards contain different vesting conditions ranging from performance-based conditions that vest upon the achievement of certain return thresholds to time-based service requirements ranging from one year to four years. Each of these profits interests is liability-classified because of certain features within these awards that predominantly contain characteristics of liability instruments. Compensation cost for these awards is presented within general and administrative expense on the combined and consolidated statements of operations with a corresponding credit to other long-term liabilities on the consolidated balance sheets.

The fair value of liability-classified stock-based compensation profits interest awards that vested during the years ended December 31, 2021 and 2020 was $2.9 million and $7.7 million, using the fair value measurements as of December 31, 2021 and 2020, respectively. Unrecognized compensation cost related to time-based unvested awards was $23.6 million as of December 31, 2021, and is expected to be recognized over a weighted average period of 3.9 years. Unrecognized compensation cost related to performance-based unvested awards was $2.8 million as of December 31, 2021 and is expected to be recognized as the result of a realization event. No realization events occurred during the years ended December 31, 2021 and 2020. We paid cash of $0.9 million to settle liability-classified stock-based compensation profits interest awards during the year ended December 31, 2021. There were no cash settlements of liability-classified stock based compensation profits interest awards during the year ended December 31, 2020. We carried $7.1 million and $8.0 million liabilities related to these awards as of December 31, 2021 and 2020, respectively in other long term liabilities on the consolidated balance sheets. Transactions involving all of our unvested liability-classified stock-based compensation profits interest awards is summarized below:

	Year Ended December 31,
	2021	2020	2019
	(units in thousands)
Beginning Balance	888	1,215	1,163
Granted	708	—	285
Vested	(110)	(203)	(233)
Forfeited	(778)	(125)	—
Ending Balance	708	888	1,215

We capitalized $1.8 million into Proved and Unproved Oil and natural gas properties on the consolidated balance sheets associated with services provided in exchange for liability-classified stock-based compensation profits interest during the year ended December 31, 2021.

Equity-classified profits interest awards

Certain of our subsidiaries issue equity-classified profits interests awards. These awards contain different vesting conditions ranging from performance-based conditions that vest upon the achievement of certain return thresholds to time-based service requirements ranging from one year to four years. Each of these profits interests is equity-classified because of certain features within these awards that predominantly contain characteristics of equity instruments. Compensation cost for these awards is presented within General and administrative expense on the combined and consolidated statements of operations with a corresponding credit to Additional paid-in capital on the consolidated balance sheets.

The fair value of equity-classified profits interest awards that vested during the year ended December 31, 2021 was $1.8 million. We did not have any equity-classified profits interest awards that vested during the year ended December 31, 2020. We did not have any unrecognized compensation cost related to unvested equity-classified profits interest awards as of December 31, 2021. We paid cash of $0.2 million to settle equity-classified profits interest awards during the year ended December 31, 2021. There were no cash settlements of equity-classified profits interest awards during the year ended December 31, 2020. Transactions involving all of our unvested equity-classified profits interest awards, including weighted average grant date fair values, are summarized below:

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	Units	Weighted average grant date fair value
	(in thousands)
Unvested at December 31, 2020	—	$	—
Granted	477	10.98
Vested	(25)	10.61
Forfeited	(253)	11.02
Unvested at December 31, 2021	200	—

We capitalized $1.6 million into Proved and Unproved Oil and natural gas properties on the consolidated balance sheets associated with services provided in exchange for equity-classified profits interest awards during the year ended December 31, 2021.

Equity-classified PSU Awards

In conjunction with the Merger Transactions, we granted equity-classified Manager Incentive Plan PSUs in accordance with the Manager Incentive Plan. The PSU performance periods are generally three years with the performance period end dates ranging from 2024 through December 2028. Each of these units represent the right to receive a target 2% of our issued and outstanding Class A Common Stock on each unit's performance period end date, modified by an amount ranging from 0% to 240% based on certain absolute and relative shareholder return components. Compensation cost for these awards is presented within General and administrative expense on the combined and consolidated statements of operations with a corresponding credit to Additional paid-in capital on the consolidated balance sheets.

Unrecognized compensation cost related to unvested awards was $71.6 million as of December 31, 2021 and is expected to be recognized over a weighted-average period of 5.0 years. Transactions involving all of our unvested units, including weighted average grant date fair values, are summarized below:

	Target Class A Shares	Weighted average grant date fair value
	(in thousands)
Unvested at December 31, 2020	—	$	—
Granted	4,195	17.33
Vested	—	—
Forfeited	—	—
Unvested at December 31, 2021	4,195	17.33

Equity-classified Contango PSU Awards

Prior to the Merger Transaction, Contango issued equity-classified PSU awards to its employees in exchange for their services to Contango over each award's respective performance period. As part of the Merger Transactions, Contango's equity-classified PSUs were modified to pay out 300% of the target PSU award amount at the close of the Merger Transactions. Because the PSU awards were modified as part of the Merger Transactions, we recorded compensation cost in the amount of the increase in the fair value of the Contango equity-classified PSUs as a result of the modification immediately after the close of the Merger Transactions within General and administrative expense on the combined and consolidated statements of operations with corresponding credits to Additional paid-in capital and Redeemable noncontrolling interests on the consolidated balance sheets.

NOTE 14 – Related Party Transactions

KKR Group

Management Agreement

In connection with the Merger Transactions, we entered into a management agreement (the "Management Agreement") with KKR Energy Assets Manager LLC (the "Manager"). Pursuant to the Management Agreement, the Manager provides the Company with its executive management team and certain management services. The Management Agreement has an initial term of three years and shall renew automatically at the end of the initial term for an additional three-year period unless the Company or the Manager elects not to renew the Management Agreement.

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As consideration for the services rendered pursuant to the Management Agreement and the Manager’s overhead, including compensation of the executive management team, the Manager is entitled to receive compensation ("Management Compensation") equal to $13.5 million per annum, which represents our pro rata portion (based on our relative ownership of OpCo) of $53.3 million. This amount will increase over time as our ownership percentage of OpCo increases. In addition, as our business and assets expand, Management Compensation may increase by an amount equal to 1.5% per annum of the net proceeds from all future issuances of our equity securities (including in connection with acquisitions). However, incremental Management Compensation will not apply to the issuance of our shares upon the redemption or exchange of OpCo Units. During the year ended December 31, 2021, we recorded general and administrative expense of $0.9 million, related to the Management Agreement.

Additionally, the Manager is entitled to receive incentive compensation ("Incentive Compensation") under which the Manager is targeted to receive 10% of our outstanding Class A Common Stock based on the achievement of certain performance-based measures. The Incentive Compensation consists of five tranches that settle over a five year period beginning in 2024, and each tranche relates to a target number of shares of Class A common stock equal to 2% of the outstanding Class A common stock as of the time such tranche is settled. So long as the Manager continuously provides services to us until the end of the performance period applicable to a tranche, the Manager is entitled to settlement of such tranche with respect to a number of shares of Class A common stock ranging from 0% to 240% of the initial target amount based on the level of achievement with respect to the performance goals applicable to such tranche. During the year ended December 31, 2021, we granted the Performance Stock Units associated with the Incentive Compensation. See NOTE 13 – Incentive Compensation Arrangements for more information.

KKR Funds

From time to time, we may invest in upstream oil and gas assets alongside EIGF II and/or other KKR funds ("KKR Funds") pursuant to the terms of the Management Agreement. In these instances, certain of our consolidated subsidiaries enter into Master Service Agreements ("MSA") with entities owned by KKR Funds, pursuant to which our subsidiaries provide certain services to such KKR Funds, including the allocation of the production and sale of oil, natural gas and NGLs, collection and disbursement of revenues, operating expenses and general and administrative expenses in the respective oil and natural gas properties, and the payment of all capital costs associated with the ongoing operations of the oil and natural gas assets. Our subsidiaries settle balances due to or due from KKR Funds on a monthly basis. The administrative costs associated with these MSAs are allocated by us to KKR Funds based on (i) an actual basis for direct expenses we may incur on their behalf or (ii) an allocation of such charges between the various KKR Funds based on the estimated use of such services by each party. As of December 31, 2021, we had a related party receivable of $3.3 million included within Accounts receivable – affiliates and $7.0 million included within Accounts payable – affiliates on our consolidated balance sheets associated with KKR Funds transactions.

Other Transactions

We paid $1.6 million in fees to KKR Capital Markets LLC, an affiliate of KKR, for services provided as a book-running manager in connection with the issuance of our Senior Notes in May 2021 and recorded as debt issuance costs within Long-term debt on the consolidated balance sheets. Additionally, we paid $0.1 million to KKR Capstone Americas LLC for professional fees support related to insurance and employee benefits due diligence and placement and recorded as General and administrative expense on the combined and consolidated statements of operations. In February 2022, we paid $0.4 million in fees to KKR Capital Markets LLC in connection with the issuance of the New Notes. See NOTE 16 – Subsequent Events.

FDL

On April 1, 2021, certain minority investors, including FDL Operating LLC ("FDL") management, exchanged 100% of their interests in our Barnett basin natural gas assets for 9,508 of our predecessor Class A units, representing 0.77% of our consolidated ownership. Since we already consolidate the results of these assets, this transaction was accounted for as an equity transaction and reflected as a reclassification from noncontrolling interests to members' equity with no gain or loss recognized on the exchange (the "April 2021 Exchange"). As of December 31, 2021, FDL's management owns less than 0.15% of our Class B shares and holds noncontrolling interests in certain of our consolidated subsidiaries.

Certain of our consolidated subsidiaries have entered into an Oil and Natural Gas Property Operating and Services Agreement (the “FDL Agreement”) with FDL. Pursuant to the FDL Agreement, FDL was engaged to manage the day-to-day operations of the business activities of certain of our consolidated subsidiaries, including allocating to us and other interest holders the production and sale of oil, natural gas and natural gas liquids, collection and disbursement of revenues, operating expenses and general and administrative expenses in the respective oil and natural gas properties and the payment of all capital costs associated with the ongoing operations of such properties. As part of the engagement, FDL will then allocate the revenues,

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operating expenses, general and administrative expenses and cash collected to us and others as appropriate. We settle balances due to or due from FDL on a monthly basis. As of December 31, 2021, we had a net related party receivable due from FDL totaling $16.9 million and at December 31, 2020, we had a net related party payable due to FDL totaling $7.5 million, included within Accounts receivable – affiliates and Accounts payable – affiliates, respectively, on our consolidated balance sheets. On September 20, 2021 we provided notice that we are terminating the FDL Agreement effective on March 31, 2022. During October 2021, as part of the termination principal terms, we agreed to pay up to $6.5 million in wind down costs and additional severance costs for certain qualifying, dedicated employees, of which any unused portion will be returned to us at the end of the wind down period. During the year ended December 31, 2021, we recorded $3.3 million of expense associated with the termination.

RPM

An affiliate of KKR Group has entered into a Master Management Services Agreement (the “MSA”) with a subsidiary of RPM Energy Management Partnership L.P. (“RPM”) to act as the manager of certain mineral and non-operated assets controlled by our consolidated subsidiaries. Pursuant to the MSA and under management of certain KKR affiliated entities, RPM manages the day-to-day operations of the business activities of certain of our oil and natural gas properties. We reimburse RPM for all reasonable out-of-pocket expenses incurred for fulfilling its obligations under the MSA (“Allocable Overhead Costs”). The Allocable Overhead Costs are charged to us on an actual basis without mark-up or subsidy. As such, the Allocable Overhead Costs approximate reasonable market rates and are representative of the expenses that we would have incurred had we not entered into the MSA. We settle balances due to or due from RPM on a monthly basis.

As of December 31, 2021 and 2020 we had a payable due to RPM of $1.7 million included within Accounts payable - affiliates on our consolidated balance sheets. On December 31, 2021, we terminated our relationship with RPM.

NOTE 15 – Earnings Per Share

We have two classes of common stock in the form of Class A Common Stock and Class B Common Stock. However, only shares of Class A Common Stock are entitled to dividends, and shares of Class B Common Stock do not have rights to participate in dividends or undistributed earnings. We apply the two-class method for purposes of calculating earnings per share (“EPS”). The two-class method determines earnings per share of common stock and participating securities according to dividends or dividend equivalents declared during the period and each security's respective participation rights in undistributed earnings and losses.

As described in NOTE 1 – Organization and Basis of Presentation, our financial statements have been retrospectively recast to reflect the historical accounts of Independence and the Contributed Entities on a combined basis due to the Merger Transactions and Independence Reorganization, respectively. Net income (loss) for periods prior to the Merger Transactions is allocated to our Predecessor as our Predecessor's Class A Units were exchanged for shares of Class B Common Stock in connection with the Merger Transactions. Net income (loss) attributable to Crescent Energy is allocated to Class A Common Stock and Class B Common Stock based on the participation rights of each class to share in undistributed earnings and losses after giving effect to dividends declared during the period, if any.

The following table sets forth the computation of basic and diluted net income (loss) per share:

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	Year Ended December 31,
	2021		2020		2019
	(in thousands, except unit and per unit amounts)
Numerator:
Net income (loss)	$	(432,227)	$	(216,124)	$	46,709
Less: net (income) loss attributable to Predecessor	339,168		118,649		(45,839)
Less: net (income) loss attributable to noncontrolling interests	14,922		97,475		(870)
Less: net (income) loss attributable to redeemable noncontrolling interests	58,761		—		—
Net income (loss) attributable to Crescent Energy	$	(19,376)	$	—	$	—
Denominator:
Weighted-average Class A common stock outstanding - basic and diluted (1)	41,954,385
Weighted-average Class B common stock outstanding - basic and diluted	127,536,463
Net income (loss) per share:
Class A common stock - basic and diluted (1)	$	(0.46)
Class B common stock - basic and diluted	$	—

(1)Represents weighted-average Class A common stock outstanding and net loss per share of Class A common stock for the period subsequent to the Merger Transactions.

NOTE 16 – Subsequent Events

Subsequent events have been evaluated through the date of issuance of these financial statements, and there have been no events subsequent to December 31, 2021, other than those items disclosed below, that would require additional adjustments to our disclosure in our financial statements.

$200.0 million Senior Notes Issuance

In February 2022, we issued an additional $200.0 million aggregate principal amount of our 7.250% senior notes due 2026 (the “New Notes”). The New Notes were issued as additional notes pursuant to our $500.0 million issuance in May 2021 as described in NOTE 8 – Debt. The New Notes will be treated as a single series and will vote together as a single class with the Senior Notes, and have identical terms and conditions, other than the issue date, the issue price and the first interest payment, as the Senior Notes.

Uinta Basin Acquisition

In February 2022, Javelin VentureCo, LLC (the “Purchaser”), one of our subsidiaries, and OpCo entered into a Membership Interest Purchase Agreement (the “Purchase Agreement”) with Verdun Oil Company II LLC, a Delaware limited liability company (the “Seller”), pursuant to which the Purchaser agreed to purchase from Seller all of the issued and outstanding membership interests (the “Purchased Interests”) of Uinta AssetCo, LLC, a to-be formed Texas limited liability company which will be a wholly-owned subsidiary of the Seller (“UtahCo”). UtahCo will hold all exploration and production assets of and certain obligations of EP Energy E&P Company, L.P. located in the state of Utah (the “Utah Assets”).

Seller will receive aggregate consideration of approximately $815.0 million in cash and the assumption of certain hedges, subject to certain customary purchase price adjustments set forth in the Purchase Agreement. OpCo has agreed to guarantee Purchaser’s obligation to fund the purchase price at closing, which is expected to occur in the first half of 2022.

In connection with the closing of the transaction, we anticipate entering into an amendment to our Revolving Credit Facility to, among other things, increase the elected commitment amount to $1.3 billion. However, there can be no assurances we will consummate this transaction or that we will enter into such amendment to our Revolving Credit Facility.

Chama

In February 2022, we contributed all the assets and prospects in the Gulf of Mexico formerly owned by Contango to Chama Energy LLC (“Chama”), an entity in which we retain an interest of approximately 9.4%. Such interest is valued at

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approximately $3.75 million. John Goff, the Chairman of our Board of Directors, holds an interest of approximately 17.5% in Chama, and the remaining interest is held by other investors. Pursuant to the Limited Liability Company Agreement of Chama, we may be required to fund certain workover costs and we will be required to fund plugging and abandonment costs related to producing assets held by Chama (collectively, “Crescent Contributions”). We will receive 90.0% of cash flows from the producing assets, which amount is increased for any Crescent Contributions.

Dividend

On March 9, 2022, the Board of Directors approved a quarterly cash dividend of $0.12 per share, or $0.48 per share on an annualized basis, to be paid to our shareholders with respect to the fourth quarter of 2021. The quarterly dividend is payable on March 31, 2022 to shareholders of record as of the close of business on March 18, 2022.

The payment of quarterly cash dividends is subject to management’s evaluation of our financial condition, results of operations and cash flows in connection with such payments and approval by our Board of Directors. In light of current economic conditions, management will evaluate any future increases in cash dividends on a quarterly basis.

NOTE 17 – Selected Quarterly Financial Data (Unaudited)

Quarterly financial data was as follows for the periods indicated:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(in thousands, except per share amounts)
2021
Revenues	$	317,860	$	330,130	$	365,726	$	463,261
Income (loss) from operations	88,045		100,483		133,604		161,607
Net income (loss)	(166,268)		(272,861)		(162,043)		168,945
Less: net (income) loss attributable to Predecessor	155,629		269,608		160,567		(246,636)
Less: net (income) loss attributable to noncontrolling interests	10,639		3,253		1,476		(446)
Less: net (income) loss attributable to redeemable noncontrolling interests	—		—		—		58,761
Net income (loss) attributable to Crescent Energy	—		—		—		(19,376)
Net income (loss) per share
Class A common stock - basic and diluted	$	—	$	—	$	—	$	(0.46)
Class B common stock - basic and diluted	$	—	$	—	$	—	$	—
2020
Revenues	$	207,848	$	103,509	$	190,612	$	252,252
Income (loss) from operations	3,353		(293,463)		(26,669)		(56,849)
Net income (loss)	466,790		(412,227)		(101,005)		(169,682)
Less: net (income) loss attributable to Predecessor	(320,722)		236,166		69,990		133,215
Less: net (income) loss attributable to noncontrolling interests	(146,068)		176,061		31,015		36,467
Net income (loss) attributable to Crescent Energy	—		—		—		—
Net income (loss) per share
Class A common stock - basic and diluted	$	—	$	—	$	—	$	—
Class B common stock - basic and diluted	$	—	$	—	$	—	$	—

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NOTE 18 – Supplemental Oil and Natural Gas Disclosures (Unaudited)

Geographic Area of Operation

All of the oil and natural gas properties in which we have working interests and mineral and royalty interests are located within the continental U.S., with the majority concentrated in Texas, Rockies and Oklahoma. Therefore, the following disclosures about our costs incurred and proved reserves are presented on a combined and consolidated basis. In addition, we have a 37% ownership in our equity method investment, Exaro, that operates in the Jonah Field in Wyoming.

Oil and Natural Gas Reserve Information

The following table presents our net proved reserves for the years ended December 31, 2021, 2020 and 2019 and the changes in net proved oil, natural gas and NGL reserves during such years. In addition, the net proved reserves for our equity method investment, Exaro, are presented based on our 37% ownership percentage. Because Exaro was acquired in 2021 as part of the Merger Transactions, prior periods are not presented.

Developed and Undeveloped	Oil (MBbls)	Natural Gas (MMcf)	Natural Gas Liquids (MBbls)	Total (MBoe)
Consolidated operations
Net proved reserves at December 31, 2018	202,805	1,189,962	75,780	476,913
Revisions of previous estimates	10,477	20,552	(11,321)	2,581
Extensions, discoveries, and other additions (1)	12,003	24,472	1,855	17,936
Sales of reserves in place	—	—	—	—
Purchases of reserves in place	—	—	—	—
Production	(13,752)	(73,747)	(5,188)	(31,231)
Net proved reserves at December 31, 2019	211,533	1,161,239	61,126	466,199
Revisions of previous estimates (2)	(57,708)	(478,153)	(20,279)	(157,680)
Extensions, discoveries, and other additions	4,088	21,479	603	8,271
Sales of reserves in place	—	—	—	—
Purchases of reserves in place (3)	22,409	196,840	18,952	74,168
Production	(13,132)	(78,541)	(5,078)	(31,300)
Net proved reserves at December 31, 2020	167,190	822,864	55,324	359,658
Revisions of previous estimates (4)	9,147	316,572	16,480	78,389
Extensions, discoveries, and other additions	7,007	17,247	2,093	11,975
Sales of reserves in place	(6,333)	(48,977)	(3,265)	(17,762)
Purchases of reserves in place (5)	46,386	451,702	11,960	133,630
Production	(13,237)	(89,455)	(6,099)	(34,245)
Net proved reserves at December 31, 2021	210,160	1,469,953	76,493	531,645
Equity affiliate
Net proved reserves at December 31, 2020	—	—	—	—
Revisions of previous estimates	—	—	—	—
Extensions, discoveries, and other additions	—	—	—	—
Sales of reserves in place	—	—	—	—
Purchases of reserves in place	205	20,880	—	3,685
Production	(1)	(115)	—	(20)
Net proved reserves at December 31, 2021	204	20,765	—	3,665
Total company
Net proved reserves at December 31, 2019	211,533	1,161,239	61,126	466,199
Net proved reserves at December 31, 2020	167,190	822,864	55,324	359,658
Net proved reserves at December 31, 2021	210,364	1,490,718	76,493	535,310

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(1)During the year ended December 31, 2019, we added 17.9 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Eagle Ford and Permian. Approximately 77% of the reserve additions for the year ended December 31, 2019 were crude oil and NGLs.

(2)Revisions of previous estimates include 92.0 MMBoe downward revisions of our PUD reserves. The revisions are primarily due to declining commodity prices which decreased the quantity of reserves recoverable from our proved locations, and also resulted in the removal of certain PUD locations that were uneconomic at year end prices.

(3)Purchases in place of 74.2 MMBoe were primarily related to the Permian and DJ Basins.

(4)Revisions of previous estimates include 92.7 MMBoe upward revision due to pricing and cost changes, offset by 21.1 MMBoe downward revisions of our PUD reserves due to the removal of certain locations that are no longer part of our five-year consolidated development plan following the Merger Transactions.

(5)Purchases in place included 125.6 MMBoe from our Merger Transactions, 5.6 MMBoe from our Central Basin Platform Acquisition and 2.5 MMBoe from our DJ Basin Acquisition.

The following table sets forth our net proved oil, natural gas and NGL reserves for both our consolidated operations and our investment in Exaro as of the years ended December 31, 2021 and 2020, 2019 and 2018:

Proved Developed Reserves	Oil (MBbls)	Natural Gas (MMcf)	Natural Gas Liquids (MBbls)	Total (MBoe)
Consolidated operations
December 31, 2021	158,091	1,404,570	66,402	458,588
December 31, 2020	92,024	748,496	44,307	261,079
December 31, 2019	103,728	870,491	48,997	297,808
Equity affiliate
December 31, 2021	204	20,765	—	3,665
December 31, 2020	—	—	—	—
December 31, 2019	—	—	—	—

Proved Undeveloped Reserves	Oil (MBbls)	Natural Gas (MMcf)	Natural Gas Liquids (MBbls)	Total (MBoe)
Consolidated operations
December 31, 2021	52,069	65,383	10,091	73,057
December 31, 2020	75,166	74,368	11,017	98,579
December 31, 2019	107,805	290,748	12,129	168,391
Equity affiliate
December 31, 2021	—	—	—	—
December 31, 2020	—	—	—	—
December 31, 2019	—	—	—	—

Capitalized Costs Relating to Oil and Gas Producing Activities

The following table summarizes the capitalized costs relating to our oil and natural gas producing activities for both our consolidated operations and our investment in Exaro as of December 31, 2021 and 2020:

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	As of December 31,
	2021		2020
	(in thousands)
Consolidated operations
Proved oil and natural gas properties (successful efforts method)	$	6,043,602	$	4,910,059
Unproved oil and natural gas properties	308,721		288,459
Oil and natural gas properties, at cost	6,352,323		5,198,518
Less accumulated depreciation, depletion and amortization	(1,881,933)		(1,666,620)
Net capitalized costs	$	4,470,390	$	3,531,898
Equity affiliate
Proved oil and natural gas properties (successful efforts method)	$	9,043	$	—
Unproved oil and natural gas properties	—		—
Oil and natural gas properties, at cost	9,043		—
Less accumulated depreciation, depletion and amortization	(67)		—
Net capitalized costs	$	8,976	$	—

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

Acquisition costs include costs incurred to purchase, lease or otherwise acquire property. Exploration costs include additions to exploratory wells, including those in progress, and exploration expenses. Development costs include additions to production facilities and equipment and additions to development wells, including those in progress.

The following table summarizes costs incurred related to our oil and natural gas activities for both our consolidated operations and our investment in Exaro for the years ended December 31, 2021, 2020 and 2019:

	Year Ended December 31,
	2021		2020		2019
	(in thousands)
Consolidated operations
Acquisition costs:
Proved	$	1,098,696	$	355,010	$	795
Unproved	41,355		680		7,264
Exploration costs	1,180		—		710
Development	194,828		83,013		318,157
Total costs incurred	$	1,336,059	$	438,703	$	326,926
Equity affiliate
Acquisition costs:
Proved	$	—	$	—	$	—
Unproved	—		—		—
Exploration costs	—		—		—
Development	—		—		—
Total costs incurred	$	—	$	—	$	—

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following information has been developed utilizing procedures prescribed by ASC 932 – Extractive Industries – Oil and Gas and based on crude oil, NGL and natural gas reserves and production volumes estimated by our engineering staff. The estimates were based on a 12-month average for first-day-of-the month commodity prices. The following information may be useful for certain comparative purposes, but should not be solely relied upon in evaluating our performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of our current value.

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The future cash flows presented below are based on sales prices and cost rates in existence as of the date of the projections. It is expected that material revisions to some estimates of crude oil, NGL and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.

Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable and possible reserves as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

Future net cash flows were calculated at December 31, 2021, 2020 and 2019 by applying prices, which were the simple average of the first-of-the-month commodity prices, adjusted for location and quality differentials, with consideration of known contractual price changes. The following table provides the average benchmark prices per unit, before location and quality differential adjustments, used to calculate the related reserve category:

	Year Ended December 31,
	2021		2020		2019
Average benchmark price per unit:
Crude oil (Bbl)	$	66.56	$	39.56	$	55.69
Natural gas (MMBtu)	$	3.60	$	1.99	$	2.62

The following table sets forth the standardized measure of discounted future net cash flows for both our consolidated operations and our investment in Exaro from projected production of oil and natural gas reserves, for the years ended December 31, 2021, 2020 and 2019:

	Year Ended December 31,
	2021		2020		2019
	(in thousands)
Consolidated operations
Future cash inflows	$	21,063,117	$	8,232,932	$	15,745,942
Future production costs	(10,194,648)		(4,280,563)		(6,766,410)
Future development costs (1)	(1,477,562)		(1,353,957)		(2,323,420)
Future income taxes	(352,136)		(30,155)		(63,136)
Future net cash flows	9,038,771		2,568,257		6,592,976
Annual discount of 10% for estimated timing	(4,080,471)		(1,240,397)		(3,482,128)
Standardized measure of discounted future net cash flows	$	4,958,300	$	1,327,860	$	3,110,848
Equity affiliate (2)
Future cash inflows	$	99,290	$	—	$	—
Future production costs	(55,371)		—		—
Future development costs	(2,309)		—		—
Future income taxes	(1,730)		—		—
Future net cash flows	39,880		—		—
Annual discount of 10% for estimated timing	(16,702)		—		—
Standardized measure of discounted future net cash flows	$	23,178	$	—	$	—

(1)    Future development costs include future abandonment and salvage costs.

(2)    The average benchmark prices used for the equity affiliate were $66.55 per barrel for crude oil and $3.64 per MMBtu for natural gas.

Changes in standardized measure of discounted future net cash flows

The following table sets forth the changes in the standardized measure of discounted future net cash flows for both our consolidated operations and our investment in Exaro for the years ended December 31, 2021, 2020 and 2019:

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	Year Ended December 31,
	2021		2020		2019
	(in thousands)
Consolidated operations
Balance at beginning of period	$	1,327,860	$	3,110,848	$	4,207,347
Net change in prices and production costs	3,330,299		(1,184,939)		(821,874)
Net change in future development costs	117,333		160,465		(59,359)
Sales and transfers of oil and natural gas produced, net of production expenses	(872,521)		(290,053)		(568,665)
Extensions, discoveries, additions and improved recovery, net of related costs	162,657		31,688		182,697
Purchases of reserves in place	1,236,388		176,480		—
Sales of reserves in place	(84,095)		—		—
Revisions of previous quantity estimates	(295,234)		(887,395)		(226,561)
Previously estimated development costs incurred	95,879		32,873		15,676
Net change in taxes	(184,419)		19,350		(19)
Accretion of discount	124,153		283,954		424,278
Changes in timing and other	—		(125,411)		(42,672)
Balance at end of period	$	4,958,300	$	1,327,860	$	3,110,848
Equity affiliate
Balance at beginning of period	$	—	$	—	$	—
Net change in prices and production costs	—		—		—
Net change in future development costs	—		—		—
Sales and transfers of oil and natural gas produced, net of production expenses	(1,246)		—		—
Extensions, discoveries, additions and improved recovery, net of related costs	—		—		—
Purchases of reserves in place	26,154		—		—
Sales of reserves in place	—		—		—
Revisions of previous quantity estimates	—		—		—
Previously estimated development costs incurred	—		—		—
Net change in taxes	(1,730)		—		—
Accretion of discount	—		—		—
Changes in timing and other	—		—		—
Balance at end of period	$	23,178	$	—	$	—

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SCHEDULE I

CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CRESCENT ENERGY COMPANY

PARENT COMPANY BALANCE SHEETS

	December 31, 2021		December 31, 2020
	(in thousands, except share and unit data)
ASSETS
Investment in subsidiary	$	3,103,176	$	2,893,160
TOTAL ASSETS	$	3,103,176	$	2,893,160
LIABILITIES, REDEEMABLE NONCONTROLLING INTERESTS AND EQUITY
Current liabilities:
Accounts payable – affiliates	$	914	$	—
Accrued liabilities	68		—
Total current liabilities	982		—
Deferred tax liability	82,537		—
Total liabilities	83,519		—
Contingencies (Note 3)
Redeemable noncontrolling interests	2,325,013		—
Equity:
Members’ equity – Class A units, no units and 1,220,421 units outstanding as of December 31, 2021 and 2020, respectively	—		2,716,892
Class A common stock, $0.0001 par value; 1,000,000,000 shares authorized and 43,105,376 shares issued and 41,954,385 shares outstanding as of December 31, 2021; no shares issued and outstanding as of December 31, 2020	4		—
Class B common stock, $0.0001 par value; 500,000,000 shares authorized and 127,536,463 shares issued and outstanding as of December 31, 2021; no shares issued and outstanding as of December 31, 2020	13		—
Preferred stock, $0.0001 par value; 500,000,000 shares authorized and 1,000 Series I preferred shares issued and outstanding as of December 31, 2021; no shares issued and outstanding as of December 31, 2020	—		—
Treasury stock, at cost; 1,150,991 shares of Class A common stock as of December 31, 2021 and no shares of Class A Common Stock as of December 31, 2020	(18,448)		—
Additional paid-in capital	720,016		—
Accumulated deficit	(19,376)		—
Noncontrolling interests	12,435		176,268
Total equity	694,644		2,893,160
TOTAL LIABILITIES, REDEEMABLE NONCONTROLLING INTERESTS AND EQUITY	$	3,103,176	$	2,893,160

The accompanying notes to financial statements are an integral part of these condensed financial statements.

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SCHEDULE I - CONTINUED

CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CRESCENT ENERGY COMPANY

PARENT COMPANY STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2021		2020		2019
	(in thousands, except per share amounts)
Revenues	$	—	$	—	$	—
Expenses:
General and administrative expense	914		—		—
Total expenses	914		—		—
Income (loss) before taxes and equity in income (losses) of subsidiary	(914)		—		—
Income tax benefit (expense)	867		—		—
Income (loss) before equity in income (losses) of subsidiary	(47)		—		—
Equity in income (losses) of subsidiary, net of tax	(432,180)		(216,124)		46,709
Net income (loss)	(432,227)		(216,124)		46,709
Less: net (income) loss attributable to Predecessor	339,168		118,649		(45,839)
Less: net (income) loss attributable to noncontrolling interests	14,922		97,475		(870)
Less: net loss attributable to redeemable noncontrolling interests	58,761		—		—
Net loss attributable to Crescent Energy	$	(19,376)	$	—	$	—
Net Loss per Share:
Class A common stock - basic and diluted	$	(0.46)
Class B common stock - basic and diluted	$	—
Weighted Average Shares Outstanding:
Class A common stock - basic and diluted	41,954
Class B common stock - basic and diluted	127,536

The accompanying notes to financial statements are an integral part of these condensed financial statements.

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SCHEDULE I - CONTINUED

CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CRESCENT ENERGY COMPANY

PARENT COMPANY STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2021		2020		2019
	(in thousands)
Cash flows from operating activities:
Net income (loss)	(432,227)		(216,124)		46,709
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Equity in (income) losses of subsidiary	432,180		216,124		(46,709)
Deferred income taxes (benefit)	(935)		—		—
Changes in operating assets and liabilities:
Accounts payable – affiliates	914		—		—
Accrued liabilities	68		—		—
Net cash provided by operating activities	—		—		—
Net cash provided by investing activities	—		—		—
Net cash provided by financing activities	—		—		—
Net change in cash, cash equivalents and restricted cash	—		—		—
Cash, cash equivalents and restricted cash, beginning of period	—		—		—
Cash, cash equivalents, and restricted cash, end of period	$	—	$	—	$	—

The accompanying notes to financial statements are an integral part of these condensed financial statements.

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SCHEDULE I - CONTINUED

CRESCENT ENERGY COMPANY

NOTES TO PARENT COMPANY FINANCIAL STATEMENTS

NOTE 1 – Basis of Presentation

On December 7, 2021, we completed the Merger Transactions, pursuant to which Contango Oil & Gas Company ("Contango") combined with Independence Energy LLC ("Independence") under a new publicly traded holding company named "Crescent Energy Company." Our Class A Common Stock is listed on The New York Stock Exchange under the symbol “CRGY.” The new combined company is structured as an “Up-C,” with all of our assets and operations and those of Contango held by Crescent Energy Company ("Crescent"), which is the sole managing member of Crescent Energy OpCo LLC ("OpCo"). We are a holding company that conducts substantially all of our business through our consolidated subsidiary, OpCo. Our sole material asset consists of units of OpCo ("OpCo Units"). As the sole managing member of OpCo, we are responsible for all operational, management and administrative decisions related to OpCo’s business. Because the unit holders of OpCo lack the characteristics of a controlling financial interest, OpCo was determined to be a variable interest entity. Crescent is considered the primary beneficiary of OpCo as it has both the power to direct OpCo and the right to receive benefits from OpCo. As a result, we consolidate the financial results of OpCo and its subsidiaries, including Crescent Energy Finance LLC. Former Contango shareholders now own shares of Crescent Class A Common Stock, which have both voting and economic rights with respect to Crescent. The former owners of our predecessor, Independence Energy LLC, now own economic, non-voting OpCo Units and corresponding shares of Crescent Class B Common Stock, which have voting (but no economic) rights with respect to Crescent. OpCo is owned approximately 25% by Crescent and approximately 75% by holders of our redeemable noncontrolling interests representing former owners of Independence.

The Isla Merger, whereby Independence merged with and into OpCo on December 7, 2021 in connection with the Merger Transactions, was accounted for as a reorganization of entities under common control. As required by GAAP, the contribution of Independence was accounted for as a reorganization of entities under common control, in a manner similar to a pooling of interests, with all assets and liabilities transferred to us at their carrying amounts. Because the Isla Merger resulted in a change in the reporting entity, and in order to furnish comparative financial information prior to the Merger Transactions, our financial statements have been retrospectively recast to reflect the historical accounts of Independence, our accounting predecessor (the "Predecessor").

These condensed parent company financial statements reflect the activity of Crescent as the parent company to OpCo and have been prepared in accordance with Rules 5-04 and 12-04 of Regulation S-X, as the restricted net assets of OpCo and its consolidated subsidiaries exceed 25% of the consolidated net assets of Crescent. This information should be read in conjunction with the combined and consolidated financial statements of Crescent included in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report.

NOTE 2 – Income Taxes

For details regarding income taxes, see NOTE 10 - Income Taxes, to the combined and consolidated financial statements of Crescent included in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report.

NOTE 3 – Contingencies

For details regarding contingencies related to litigation, see NOTE 12 - Commitments and Contingencies, to the combined and consolidated financial statements of Crescent included in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report.

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Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosures

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The Company's Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the design and operation of the Company's disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(b) under the Securities Exchange Act of 1934, as amended), as of December 31, 2021. Based on such evaluation, such officers have concluded that, as of December 31, 2021, the Company's disclosure controls and procedures are designed and effective to ensure that information required to be included in the Company's reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms and that information required to be disclosed in the Company's reports filed or submitted under the Exchange Act is accumulated and communicated to the Company's management including its principal executive officer and principal financial officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.

In designing and evaluating the Company's disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that the Company's controls will succeed in achieving their goals under all potential future conditions.

Changes in Internal Control over Financial Reporting

There were no changes in the Company's internal control over financial reporting (as defined by Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the quarter ended December 31, 2021, that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

Management's Assessment of Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over our financial reporting. As described in this Annual Report, on December 7, 2021, we completed the Merger Transactions, in accordance with the terms of the Transaction Agreement. As contemplated by SEC Compliance and Disclosure Interpretation 215.02, we have excluded the report by our management of its assessment of internal control over financial reporting required by Item 308(a) of Regulation S-K in this Annual Report, and in lieu of such report, we are providing the following disclosure as to why management’s assessment has not been included. Since management’s report is being excluded, the report of our independent registered public accounting firm under Item 308(b) of Regulation S-K is also being excluded.

As a result of the Merger Transactions, we believe that it would not be meaningful to include management’s report on internal control over financial reporting in this report since the internal controls of Contango prior to the Merger Transactions no longer exist. The system of internal controls in place following the Merger Transactions is that previously in place at Independence. Further, all of the material IT systems currently used by us are those previously used by Independence.

In our Annual Report on Form 10-K for our fiscal year ending December 31, 2022, we will include a report by our management of its assessment of internal control over financial reporting required by Item 308(a) of Regulation S-K. In making this assessment, management will use the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control -- Integrated Framework Scope of the Controls Evaluation. In such Annual Report on Form 10-K, we will also include the report of our registered public accounting firm under Item 308(b) of Regulation S-K.

Item 9B. Other Information

Not applicable

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Item 9C. Disclosure Regarding Foreign Jurisdiction that Prevent Inspections.

Not applicable

Part III

Item 10. Directors, Executive Officers and Corporate Governance

Board of Directors and Executive Officers

The following table sets forth information regarding the members (each, a “Director”) of our Board of Directors and officers (each, an “Executive Officer”).

Name	Age	Position
David C. Rockecharlie	49	Chief Executive Officer and Director
Brandi Kendall	37	Chief Financial Officer and Director
Todd N. Falk	41	Chief Accounting Officer
Benjamin M. Conner	36	Executive Vice President
John Clayton “Clay” Rynd	32	Executive Vice President
Bo Shi	33	General Counsel and Corporate Secretary
John C. Goff	66	Chairman and Director
Claire S. Farley	62	Director
Robert G. Gwin	58	Director
Ellis L. “Lon” McCain	73	Director
Karen J. Simon	62	Director
Erich Bobinsky	33	Director
Bevin Brown	45	Director

The following are biographical summaries of the business experience of each Director and Executive Officer.

David C. Rockecharlie has served as Crescent Energy Company’s Chief Executive Officer since March 2021, prior to which he served as Crescent Energy Company’s Manager and President beginning in June 2020. Mr. Rockecharlie has also served as our Director since June 2020. Mr. Rockecharlie joined Kohlberg Kravis Roberts & Co., L.P. (“KKR”) in 2011 and is currently a Partner and Head of KKR’s Energy Real Assets business and Chairman of KKR’s Energy Investment Committee. Prior to joining KKR, Mr. Rockecharlie was co-founder and co-CEO of RPM Energy, LLC, a privately-owned oil and gas company. Previously, Mr. Rockecharlie served as co-head of Jefferies & Company’s Energy Investment Banking Group and before that was an executive with El Paso Corp., where he led a variety of corporate activities. Mr. Rockecharlie began his career as an energy investment banker with S.G. Warburg and Donaldson, Lufkin & Jenrette. Mr. Rockecharlie received an A.B., magna cum laude, from Princeton University. We believe Mr. Rockecharlie’s extensive industry experience and longstanding

relationship with KKR make him well-suited to serve as a Director.

Brandi Kendall has served as Crescent Energy Company’s Chief Financial Officer since March 2021, prior to which she served as Crescent Energy Company’s Vice President beginning in June 2020. Ms. Kendall has also served as our Director since August 2020. Ms. Kendall joined KKR in 2013 and is responsible for a broad range of portfolio management activities for its Energy Real Assets team, including finance, planning, risk management and corporate development. Prior to joining KKR, Ms. Kendall served as director, finance and planning at Marlin Midstream and finance associate at NFR Energy. Ms. Kendall began her career in the energy investment banking industry, having held positions at JP Morgan and Tudor, Pickering, Holt & Co. Ms. Kendall earned a B.A. in Economics, Managerial Studies and Kinesiology from Rice University. We believe Ms. Kendall’s financial expertise and energy industry experience make her well-suited to serve as a Director.

Todd N. Falk has served as Crescent Energy Company’s Chief Accounting Officer since March 2021, prior to which he served as Crescent Energy Company’s Vice President, Finance beginning in June 2020. Mr. Falk joined KKR in 2018 and is a Director and Chief Accounting Officer of KKR’s Energy Real Assets business. Prior to joining KKR, Mr. Falk served as Director of Finance and Controller of Vitruvian Exploration from October 2013 to September 2018. Mr. Falk began his career at Deloitte,

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where as a senior manager he assisted clients with complex financial reporting issues, specializing in initial public offerings and other interactions with the SEC. Mr. Falk has over 18 years of finance and accounting experience in the energy industry, is a Certified Public Accountant and holds a B.S., magna cum laude, in Accounting and an M.S. in Finance from Texas A&M University.

Benjamin M. Conner has served as Crescent Energy Company’s Executive Vice President since March 2021. Mr. Conner joined KKR in 2014 and is a member of the Energy Real Assets team. During his time at KKR, he has been involved in numerous upstream oil and gas investments in North America within the Energy Income and Growth Fund. Prior to joining KKR, Mr. Conner was with Lime Rock Partners and was directly involved in numerous investments, with a particular focus in North American upstream oil & gas and oilfield equipment, manufacturing and services. Prior to joining Lime Rock, he was with the natural resources investment banking group of J.P. Morgan where he worked on numerous corporate advisory and financing transactions. He is a graduate of the McCombs School of Business at the University of Texas (M.P.A., B.B.A.).

John Clayton “Clay” Rynd has served as Crescent Energy Company’s Executive Vice President since March 2021. Mr. Rynd joined KKR in 2015 and is a member of the Energy Real Assets team. During his time at KKR, he has been involved in numerous oil and gas investments in North America within the Energy Income and Growth Funds strategy as well as KKR’s investments in FlowStream Commodities and Resource Environmental Solutions. Prior to joining KKR, Mr. Rynd was with Tudor, Pickering, Holt & Co. in the investment banking division, where he focused primarily on strategic advisory and M&A transactions for companies across the energy sector. Prior to that, he worked within the equity research division at Tudor, Pickering, Holt & Co. Mr. Rynd holds a B.A. in both Economics and History from Texas A&M University.

Bo Shi has served as Crescent Energy Company’s General Counsel and Corporate Secretary since December 2021. Mr. Shi previously served as General Counsel for Independence since October 2021. Prior to joining Independence, Mr. Shi worked as a Senior Associate at Vinson & Elkins L.L.P from October 2014 to January 2018, and from December 2018 to October 2021. While at Vinson & Elkins L.L.P., his practice focused on capital markets transactions, corporate governance and mergers and acquisitions, primarily within the oil and gas industry. From January 2018 until December 2018, Mr. Shi served as Senior Counsel at IPSCO Tubulars Inc., a producer and supplier of oil country tubular goods. He received a J.D. from Harvard Law School and a B.A. in Political Science and Policy Studies from Rice University.

John C. Goff, a private investor based in Fort Worth, Texas, has served as Chairman of the Crescent Energy Company Board of Directors since December 2021. He was elected to the board of directors of Contango in August 2018 and as Non-Executive Chairman of the board in October 2019. Mr. Goff founded his family office, Goff Capital, in 2007. Goff Capital invests in a variety of public and private industries and is presently focused on investments in real estate, aerospace, oil & gas, entertainment, and wellness. Mr. Goff co-founded Crescent Real Estate with Richard Rainwater in the early 1990’s, designing the strategy and orchestrating the acquisitions leading to its initial public offering (NYSE) in May 1994. Under his leadership as CEO, Crescent Real Estate grew from approximately $500 million at its IPO to $6.5 billion upon its sale to Morgan Stanley in August 2007. Crescent Real Estate provided its shareholders with a 15.4 percent compounded annual return and more than $2.5 billion in cash dividends during its 13 years as a public company. In November 2009, Mr. Goff reacquired Crescent Real Estate in a partnership with Barclays Capital, and in December 2017 he purchased Barclays Capital’s interest to become the principal owner of Crescent Real Estate and its subsidiaries. Crescent Real Estate currently has assets under management, development and investment capacity of more than $4 billion. Mr. Goff first joined Mr. Rainwater in 1987, investing in public securities, private equity, and distressed debt in a variety of industries, including oil and gas, health care, insurance, and banking. This background led Mr. Goff to establish his family office, Goff Capital, in 2009. Goff Capital is presently focused on investments in aerospace, energy, entertainment, real estate and wellness. Mr. Goff graduated from The University of Texas at Austin and is a member of McCombs Business School Hall of Fame. He was named EY Entrepreneur of the Year for the Southwest Region in 2014 and more recently, was inducted to the North Texas Real Estate, the Dallas Business and the Fort Worth Business Halls of Fame. Mr. Goff brings investment and financial acumen, including expertise in analyzing opportunities, risks and strategy in investments in various industries, including energy investments, and providing guidance regarding corporate governance matters, which makes him well-suited to serve as a Director.

Claire S. Farley has served as a Director since December 2021 and previously served as a Director of Independence from August 2020 until the closing of the Merger Transactions. Ms. Farley currently serves as a Senior Advisor to KKR’s Energy Real Assets team, after having joined KKR in 2011 as a Partner. Prior to joining KKR, she was co-founder and co-CEO of RPM Energy LLC. Ms. Farley previously was an advisory director of Jefferies Randall & Dewey, also serving as co-president. She was CEO of Randall & Dewey before it combined with Jefferies & Company. Prior to that, she served in various roles at Texaco, Inc., including CEO of HydroTexaco, president of the North American production division and president of worldwide exploration and new ventures. She has also served as CEO of two start-up ventures: Intelligent Diagnostics Corporation, and Trade-Ranger Inc. Ms. Farley serves on the board of directors of Technip FMC and LyondellBasell Industries, N.V. Ms. Farley

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holds a B.S. from Emory University. We believe that Ms. Farley’s leadership, investing and energy experience make her well-suited to serve as a Director.

Robert G. Gwin has served as a Director since December 2021. Mr. Gwin was previously President of Anadarko Petroleum Corporation (“Anadarko”), one of the world’s largest independent oil and natural gas exploration and production companies, until August of 2019 when the company was purchased by Occidental Petroleum Corporation. He previously was Executive Vice President, Finance and Chief Financial Officer of Anadarko from 2009 to 2018. Mr. Gwin is currently a director of Pembina Pipeline Corporation and Enable Midstream Partners, LP, where he previously served as Chairman of its board of directors. He previously served as the Chairman of the board of directors of both Western Gas Partners, LP and its general partner Western Gas Equity Partners, LP from 2010 to 2019, and as a director of both entities beginning in 2007. Mr. Gwin was also the Chairman of the board of directors of LyondellBasell Industries, N.V. from 2013 to 2018, where he served as a director beginning in 2011. He has served on numerous community and charitable organization boards throughout his career, currently including the MD Anderson Cancer Center, the Fuqua School of Business a Duke University, and Communities in Schools – Houston. He holds a Bachelor of Science degree from the University of Southern California and a Master of Business Administration degree from the Fuqua School of Business at Duke University, and is a Chartered Financial Analyst (CFA). We believe Mr. Gwin’s business and industry experience make him well-suited to serve as a Director.

Ellis L. “Lon” McCain has served as a Director since December 2021. Mr. McCain was previously a director of Contango from February 2006 through the consummation of the Merger Transactions, at which time he was serving as Chairman of Contango’s Audit Committee. Mr. McCain also served as Contango’s Lead Director from the 2014 Annual Meeting through the 2016 Annual Meeting. Mr. McCain served as Executive Vice President and Chief Financial Officer of Ellora Energy, Inc. (“Ellora”) from July 2009 through August 2010 when Ellora was merged into a subsidiary of Exxon Mobil Corporation. Prior to Ellora, Mr. McCain was Vice President, Treasurer, and Chief Financial Officer of Westport Resources Corporation (“Westport”), a publicly traded exploration and production company, from 2001 until the sale of Westport to Kerr McGee Corporation and his retirement from Westport in 2004. From 1992 until joining Westport in 2001, Mr. McCain was Senior Vice President and Principal of Petrie Parkman & Co., an investment banking firm specializing in the oil and gas industry. From 1978 until joining Petrie Parkman & Co., Mr. McCain held senior financial management positions with Presidio Oil Company, Petro-Lewis Corporation, and Ceres Capital. He was an Adjunct Professor of Finance at the University of Denver from 1982 through 2005. In addition to the board of Crescent Energy Company, Mr. McCain currently serves on the boards of Cheniere Energy Partners, GP, LLC, the general partner of Cheniere Energy Partners, L.P., a publicly traded partnership and Continental Resources, Inc. Mr. McCain received a B.A. in business administration and an M.B.A. with a major in finance from the University of Denver. Mr. McCain brings extensive business, financial and management expertise to the Company from his background as Chief Financial Officer of Ellora and Westport and from his tenure as an investment banker specializing in the oil and gas industry. Mr. McCain also brings considerable experience from his position as a director with several other energy companies. We believe Mr. McCain’s extensive business, financial, management and director expertise qualify him to serve on our Board and as Chairman of our Audit Committee.

Karen J. Simon has served as a Director since December 2021. Ms. Simon was previously a director of Contango from April 2021 through the consummation of the Merger Transactions. Ms. Simon previously served as Vice Chairman, Investment Banking, at JPMorgan before retiring in December 2019. Over her 36 year banking career, she held a number of leadership positions, including Global Co-Head of Financial Sponsor Coverage, providing M&A and capital raising investment banking services to private equity funds; Co-Head of EMEA Debt Capital Markets and Head of EMEA Oil & Gas coverage, both in London, and most recently she founded JPMorgan’s Director Advisory new client group focused on providing advice to public company Directors. Ms. Simon is currently a director of two European public companies; one of which she chairs, Energean plc in London (LON: ENOG) since March 2018 and Aker ASA in Oslo (OSL: AKER) since April 2013. Energean is an E&P company focused on natural gas resources in the eastern Mediterranean. In partnership with the CEO, she is advancing the company’s growth strategy and energy transition while building critical governance and compliance frameworks since Energean’s IPO in March of 2018. She is a member of Remuneration committee and Chairs the Nomination & Governance committee. Ms. Simon has served as a Non-Executive Director of Aker ASA since April 2013. Aker controls a number of industrial investments and is a leading Norwegian player in the energy transition space with recent entries into carbon capture, offshore and onshore wind power, and clean hydrogen production, plus a number of digital software offerings for industrial applications. During her career at JPMorgan, she was cited several times as one of the “100 Most Influential Women in Finance in Europe, Middle East and Africa” and was named the 2010 and 2011 “Female Private Equity Advisor of the Year” by Financial News. Ms. Simon received dual graduate business degrees in 1983: an M.B.A. from Southern Methodist University in Dallas and a Master of International Management from the American Graduate School of International Management (Thunderbird) in Arizona. Earlier, she graduated from the University of Colorado, earning a Bachelor of Arts cum laude in Economics. We believe Ms. Simon’s business and investment experience make her well-suited to serve as a Director.

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Erich Bobinsky has served as a Director since December 2021. Mr. Bobinsky previously served as a director of Independence from August 2020 until the consummation of the Merger Transactions.. Mr. Bobinsky is a Director at Liberty Mutual Investments (“LMI”), a position he has held since April 2019. Mr. Bobinsky joined LMI in 2010. Mr. Bobinsky holds a B.S. in Corporate Finance and Accounting from Bentley University. Mr. Bobinsky also holds a Chartered Financial Analyst designation and is a member of the Boston Security Analysts Society. We believe that Mr. Bobinsky’s investment experience and relationship with LMI make him well-suited to serve as a Director.

Bevin Brown has served as a Director since December 2021. Ms. Brown previously served as a director of Independence from August 2020 until the consummation of the Merger Transactions. Ms. Brown is the Managing Director of Portfolio Strategy & Management for Global Partnerships and Innovation at LMI, a position she has held since February 2020, prior to which she served as a Director at LMI beginning in 2013. Prior to joining LMI, Ms. Brown was a Director at a private equity firm and a Manager at PwC. Ms. Brown holds a B.S. from Stonehill College. We believe that Ms. Brown’s investment experience and relationship with LMI make her well-suited to serve as a Director.

Composition of our Board of Directors

Members of our Board of Directors are designated by the Preferred Stockholder, and, as applicable, any successor thereto. Our current Board of Directors consists of nine Directors. Pursuant to the Merger Transactions, two of our current Directors were designated by Contango, including Mr. Goff as Chairman and Mr. McCain, and seven Directors were designated by the Preferred Stockholder, including Messrs. Rockecharlie, Bobinsky and Gwin and Msses. Kendall, Brown, Simon and Farley, subject to the Specified Rights Agreement and Voting Agreement, as described below.

Specified Rights Agreement & Voting Agreement

The Specified Rights Agreement, dated as of June 7, 2021, by and among PT Independence and Independence Energy Aggregator GP LLC, a Delaware limited liability company (the “Specified Rights Agreement”) grants PT Independence the right to designate two Directors to our Board of Directors (one of whom must be an Independent Director), so long as Liberty Mutual Insurance Co. beneficially owns a number of shares of Common Stock equal to at least 33.33% of its initial ownership of shares of Class B Common Stock. For so long as PT Independence owns at least one share of Common Stock, PT Independence shall have the right to designate one Director to our Board of Directors. Presently, the PT Independence designees to our Board of Directors are Mr. Bobinsky and Ms. Brown.

Pursuant to the Voting Agreement, dated as of June 7, 2021, by and between John C. Goff, Independence and the other signatories thereto (the “Voting Agreement”), Mr. Goff was granted the right to be appointed to our Board of Directors in connection with the closing of the Merger Transactions. Mr. Goff may only be removed for cause by a majority vote of Independent Directors.

There are no arrangements or understandings between any Director and any other person pursuant to which the Director was selected as a Director, other than the provisions of the Transaction Agreement, the Voting Agreement and the Specified Rights Agreement, relating to the appointment of directors. None of the directors are a participant in any related party transaction required to be reported pursuant to Item 404(a) of Regulation S-K, other than Mr. Rockecharlie’s and Ms. Kendall’s indirect interest in the Management Agreement as employees of KKR.

Audit Committee

We have a separately-designated Audit Committee of the Board of Directors (the “Audit Committee”) in accordance with Section 3(a) (58)(A) of the Exchange Act. Our Audit Committee has three members: Messrs. McCain and Bobinsky and Ms. Simon. Mr. McCain currently serves as the chairperson of the Audit Committee. Our Board of Directors has determined that each of Messrs. McCain and Bobinsky and Ms. Simon constitute “Audit Committee Financial Experts” as defined in Section 11 of the Securities Act. Likewise, each of the members serving on our Audit Committee are “independent” under the relevant standards of the NYSE.

Code of Business Conduct and Ethics

Our Board of Directors had adopted a Code of Business Conduct and Ethics, which is available free of charge on our website, www.crescentenergyco.com. We intend to satisfy the disclosure requirement under Item 5.05 of Form 8-K regarding amendment to, or waiver from, a provision of our Code of Business Conduct and Ethics by posting such information on the website address and location specified above.

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Delinquent Section 16(a) Reports

None.

Item 11. Executive Compensation

Compensation Discussion and Analysis

We have been externally managed by our Manager since the closing of the Merger Transactions pursuant to the terms of the Management Agreement. During fiscal year 2021, all of our executive officers, including the individuals who would be deemed our named executive officers (“named executive officers”), were employed by the Manager. Because our Management Agreement provides that our Manager is responsible for managing our day-to-day affairs, our executive officers for fiscal year 2021 do not currently receive any cash compensation from us or any of our subsidiaries for serving as our executive officers. Additionally, the Management Agreement does not require our named executive officers to dedicate a specific amount of time to fulfilling our Manager’s obligations to us under the Management Agreement and does not require a specified amount or percentage of the fees paid to the Manager to be allocated to the named executive officers. Our Manager does not compensate its employees specifically for such services because these individuals also provide investment management and other services to other investment vehicles that are sponsored, managed or advised by affiliates of our Manager. As a result, our Manager has informed us that it cannot identify the portion of the compensation awarded to our named executive officers by our Manager that relates solely to their services to us. Accordingly, we are unable to provide complete compensation information for any of our named executive officers, including our Chief Executive Officer, as the total compensation of our named executive officers reflects the performance of all the investment vehicles for which these individuals provide services, including, but not limited to, us.

We do not determine the cash compensation payable by our Manager to our named executive officers. Our Manager and its affiliates determine the salaries, bonuses and other wages earned by our named executive officers from our Manager and its affiliates. Our Manager and its affiliates also determine whether and to what extent our named executive officers will be provided with employee benefit plans. We do not have employment agreements with our named executive officers, we do not provide pension or retirement benefits, perquisites or other personal benefits to our named executive officers and we do not have arrangements to make payments to our named executive officers upon their termination or in the event of a change in control of the Company.

While we may not pay our named executive officers any cash compensation, we pay our Manager the Management Compensation and Incentive Compensation described under the heading “Items 1 and 2. Business and Properties—Management Agreement.” The Management Compensation compensates our Manager for the services that it provides to the Company and the Incentive Compensation serves to further align the interests of our Manager and our named executive officers with that of the Company and mitigate the possibility of excessive risk taking. In addition, in the discretion, of the Compensation Committee we have adopted the Equity Incentive Plan under which we may grant awards to our service providers who are not employed by the Manager. Because all of our named executive officers were employees of our Manager, none of the named executive officers was eligible to receive an award under the Equity Incentive Plan.

Equity-Based Compensation

The following description summarizes the material terms of the two equity incentive plans we have adopted and pursuant to which we may grant equity-based compensation to our service providers. The Manager Incentive Plan governs the Incentive Compensation granted to our Manager, and the Equity Incentive Plan governs awards to our service providers who are not employees of the Manager.

Manager Incentive Plan

Prior to the closing of the Merger Transactions, we adopted and our stockholders approved, the Manager Incentive Plan. The purpose of the Manager Incentive Plan is to provide a means through which we may provide equity-based compensation to the Manager, as required by the Management Agreement. The description of the Manager Incentive Plan set forth below is a summary of the material features of the Manager Incentive Plan. This summary does not purport to be a complete description of all of the provisions of the Manager Incentive Plan and is qualified in its entirety by reference to the Manager Incentive Plan, the form of which is attached hereto as Exhibit 10.6.

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Manager Incentive Plan Share Limit. Subject to adjustment in the event of certain transactions or changes of capitalization in accordance with the Manager Incentive Plan, 4,306,745 were initially reserved for issuance pursuant to awards under the Manager Incentive Plan. The aggregate number of shares of Class A Common Stock reserved for delivery shall be increased on January 1 of each calendar year that occurs before the tenth anniversary of the Effective Date (as defined in the Manager Incentive Plan) by 10% of the additional Class A Common Stock issued, if any, during the immediately preceding calendar year. If an award under the Manager Incentive Plan is forfeited, settled for cash or expires without the actual delivery of shares, any shares subject to such award will again be available for new awards under the Manager Incentive Plan.

Administration. The Manager Incentive Plan is administered by the board or a committee later appointed by the board.

Awards. The Manager Incentive Plan provides for the grant of (i) stock options; (ii) stock appreciation rights; (iii) restricted or unrestricted Class A Common Stock; (iv) restricted stock units; (v) other equity-based awards; (vi) incentive awards; (vii) cash awards; (viii) performance awards; and (ix) substitute awards.

Certain Transactions. If any change is made to our capitalization, such as a stock split, stock combination, stock dividend, exchange of shares or other recapitalization, merger or otherwise, which results in an increase or decrease in the number of outstanding shares of Class A Common Stock, appropriate adjustments will be made by the committee in the shares subject to awards under the Manager Incentive Plan. The committee will also have the discretion to make certain adjustments to awards in the event of a Change in Control (as defined in the Manager Incentive Plan), such as accelerating the vesting or exercisability of awards, requiring the assumption of awards or substitution of awards for new awards or cancelling awards in exchange for payments of consideration in forms determined by the committee.

Clawback Policy. All awards under the Manager Incentive Plan will be subject to our clawback or recapture policy, as in effect from time to time.

Amendment and Termination. The board may amend or terminate the Manager Incentive Plan at any time; however, no amendment may adversely impair the rights of participants with respect to outstanding awards and shareholder approval will be required for any amendment to the extent necessary to comply with applicable law or exchange listing standards. The committee will not have the authority, without the approval of shareholders, to amend any outstanding stock option or stock appreciation right to reduce its exercise price per share. The Manager Incentive Plan will remain in effect for a period of ten years following the effective date of the Manager Incentive Plan (unless earlier terminated by the Board).

Other. As described under “The Transaction Agreement and Related Agreements—OpCo LLC Agreement”, the OpCo LLC Agreement provides that, subject to certain exceptions, at any time we issue a share of Class A Common Stock or any other equity security (including awards granted under the Manager Incentive Plan) following the Merger Transactions, the net proceeds received by us with respect to such issuance, if any, will be concurrently contributed to OpCo, which, in turn, will issue one Unit (if we issue a share of Class A Common Stock) or such other equity security (if we issue equity securities other than Class A Common Stock) corresponding to the equity securities issued by us to the Company Group.

The Incentive Compensation

Following the closing of the Merger Transactions, the Manager was granted the Incentive Compensation, which is an award of restricted stock units subject to performance-based vesting (“PSUs”) under the Manager Incentive Plan, as required by the Management Agreement. This summary does not purport to be a complete description of all of the provisions of the Incentive Compensation and is qualified in its entirety by reference to the award agreement governing the Incentive Compensation (the “Award Agreement”), the form of which is included as Exhibit 10.5 hereto.

General Description. The Incentive Compensation is a grant of five “Target PSUs,” each of which corresponds to a number of shares of Class A Common Stock equal to 2% of the total number of shares of Class A Common Stock outstanding on each Performance Period End Date (as defined in the Award Agreement). The Incentive Compensation represents the right to receive shares of Class A Common Stock in an amount ranging from 0% to 240% of each Target PSU, subject to the Company’s achievement of certain performance-based vesting conditions.

Vesting. Each Target PSU will become earned, if at all, following the determination of the Company’s level of achievement of certain performance goals during a three-year performance period. For each performance period, the performance goals for (i) 60% of the Target PSU shall be based on the Company’s absolute total stockholder return (the “Absolute TSR Portion”) during the applicable performance period and (ii) 40% of the Target PSU shall be based on the relative total stockholder return (the “Relative TSR Portion”) ranking of the Company as compared to our peer group during the applicable performance period.

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For each performance period, the Absolute TSR Portion of the Target PSU will become earned based on the committee’s determination of the Company’s Absolute TSR in accordance with the table below.

Absolute TSR (%)	Earned Amount (% of Absolute TSR Portion)*
<25%	0%
25%	100%
55%	150%
85%	200%
115%	250%
145%	300%

For each performance period, the Relative TSR Portion of the Target PSU will become earned based on the committee’s determination of the Company’s Relative TSR in accordance with the table below.

Relative TSR Percentile Ranking	Earned Amount (% of Relative TSR Portion)*
<20th Percentile	0%
20th Percentile	50%
40th Percentile	75%
60th Percentile	100%
70th Percentile	125%
≥80th Percentile	150%

Acceleration of Vesting. The Award Agreement provides that unearned Target PSUs will immediately be deemed earned with respect to 100% of such Target PSUs upon the occurrence of a Change in Control or a complete liquidation or dissolution of the Company, provided that the Management Agreement has not been terminated prior to such date.

Equity Incentive Plan

Prior to the closing of the Merger Transactions, we adopted, and our stockholders approved, the Equity Incentive Plan. The purpose of the Equity Incentive Plan is to incentivize individuals providing services to the Company or its affiliates as its employees, officers or non-employee directors through grants of equity-based incentive awards. Any individual employed by the Manager or any of its parent companies is not be eligible to participate in the Equity Incentive Plan. As such, none of our executive officers, including the named executive officers, were eligible to participate in the Equity Incentive Plan during fiscal year 2021. The description of the Equity Incentive Plan set forth below is a summary of the material features of the Equity Incentive Plan. This summary does not purport to be a complete description of all of the provisions of the Equity Incentive Plan and is qualified in its entirety by reference to the Equity Incentive Plan, the form of which is included as Exhibit 10.7 hereto.

Equity Incentive Plan Share Limits. Subject to adjustment in the event of certain transactions or changes of capitalization in accordance with the Equity Incentive Plan, 861,349 shares of Class A Common Stock were initially reserved for issuance pursuant to awards under the Equity Incentive Plan. The total number of shares reserved for issuance under the Equity Incentive Plan may be issued pursuant to incentive stock options (which generally are stock options that meet the requirements of Section 422 of the Code). If an award under the Equity Incentive Plan is forfeited, settled for cash or expires without the actual delivery of shares, any shares subject to such award will again be available for new awards under the Equity Incentive Plan.

Administration. The Equity Incentive Plan is administered by the board or a committee later appointed by the board.

Awards. The Equity Incentive Plan provides for the grant of (i) stock options; (ii) stock appreciation rights; (iii) restricted or unrestricted Class A Common Stock; (iv) restricted stock units; (v) other equity-based awards; (vi) incentive awards; (vii) cash awards; (viii) performance awards; and (ix) substitute awards.

Maximum Calendar Year Award. No non-employee director may receive, in any one calendar year, more than $1,000,000 in the aggregate in awards granted under the Equity Incentive Plan and cash compensation (including retainers and cash-based awards). Notwithstanding the foregoing, awards and cash compensation may be granted or paid to non-employee directors in excess of such limits for any calendar year in which the director first commences service on the Board of Directors, serves on a special committee of the Board of Directors, or serves as lead director or chairman of the Board of Directors.

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Certain Transactions. If any change is made to the Company’s capitalization, such as a stock split, stock combination, stock dividend, exchange of shares or other recapitalization, merger or otherwise, which results in an increase or decrease in the number of outstanding shares of Class A Common Stock, appropriate adjustments will be made by the committee in the shares subject to awards under the Equity Incentive Plan. The committee will also have the discretion to make certain adjustments to awards in the event of a Change in Control (as defined in the Equity Incentive Plan), such as accelerating the vesting or exercisability of awards, requiring the assumption of awards or substitution of awards for new awards or cancelling awards in exchange for payments of consideration in forms determined by the committee.

Clawback Policy. All awards under the Equity Incentive Plan will be subject to our clawback or recapture policy, as in effect from time to time.

Amendment and Termination. The board may amend or terminate the Equity Incentive Plan at any time; however, no amendment may adversely impair the rights of participants with respect to outstanding awards and shareholder approval will be required for any amendment to the extent necessary to comply with applicable law or exchange listing standards. The committee will not have the authority, without the approval of shareholders, to amend any outstanding stock option or stock appreciation right to reduce its exercise price per share. The Equity Incentive Plan will remain in effect for a period of ten years following the effective date (unless earlier terminated by the board).

Awards under the Equity Incentive Plan. No awards were made under the Equity Incentive Plan during fiscal year 2021.

Compensation Committee Report

Our compensation committee has furnished the following report. The information contained in this “Compensation Committee Report is not to be deemed “soliciting material” or “filed” with the SEC, nor is such information to be incorporated by reference into any future filings under the Securities Act of 1933, as amended, or the Exchange Act, except to the extent that we specifically incorporate it by reference into such filings.

The compensation committee has reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K under the Exchange Act with management. Based on such review and discussions, the compensation committee recommended to our board of directors that the Compensation Discussion and Analysis be included in this proxy statement.

Compensation Committee of the Board of Directors

Claire Farley

Bevin Brown

Brandi Kendall

2021 Executive Compensation Tables

As described in the Compensation Discussion and Analysis above, we did not pay any compensation to our named executive officers during the fiscal year ended December 31, 2021, and have never granted any equity or equity-based awards to our named executive officers. As such, the tabular disclosure that would otherwise be required by Item 402 of Regulation S-K of the Exchange Act has been omitted.

Potential Payments Upon Termination or Change in Control

Since our named executive officers are employees of our Manager or its affiliates, we do not have any obligations to make any payments to any of our named executive officers upon a termination of employment or upon a change of control. However, in the event that the Management Agreement is terminated without Cause (as defined in the Management Agreement), the Manager is entitled to a payment equal to three times the sum of (i) the average annual Management Compensation and (ii) (x) the number of shares of Class A Common Stock issued as Incentive Compensation that vest during the relevant period multiplied by (y) the trading price of such shares as of the date of such vesting (but only with respect to the fully vested portion thereof as of the termination date), in each case, earned by the Manager during the 24-month period immediately preceding the most recently completed calendar quarter prior to the termination date.

Director Compensation

In the fiscal year ended December 31, 2021, no director received cash, equity or other non-equity compensation for service on our board of directors.

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For 2022, each non-employee director is entitled to an annual $65,000 retainer and an annual grant of $125,000 (adjusted for partial periods of service) in restricted stock units, subject to a one-year vesting period. Additional annual cash retainer fees are paid to the chairperson of the Audit Committee ($15,000), the chairperson of the Compensation Committee ($10,000) and the chairperson of the Nominating Committee ($9,500). Meeting attendance fees of $1,000 are accrued for each Board of Directors and committee meeting attended in person or telephonically. We also provide for the reimbursement of expenses for all directors in the performance of their duties, including reasonable travel expenses incurred attending meetings.

Item 12. Security Ownership of Certain Beneficial Owner and Management and Related Stockholder Matters

The following table sets forth certain information known to us, based on filings made under Section 13(d) and 13(g) of the Exchange Act, regarding the beneficial ownership of our common stock as of February 28, 2022 by:

•each person, or group of affiliated persons, know to us to beneficially own more than 5% of our common stock;

•each member of the Board of Directors;

•each of our Named Executive Officers; and

•all of our directors and executive officers as a group.

Beneficial ownership is determined in accordance with the rules of the SEC. These rules generally attribute beneficial ownership of securities to persons who possess sole or shared voting power or investment power with respect to such securities. Except as otherwise indicated, all persons listed below have sole voting and investment power with respect to the shares beneficially owned by them, subject to applicable community property laws. Unless otherwise indicated, the address of each person or entity named in the table below is c/o Crescent Energy Company, 600 Travis Street, Suite 7200, Houston, Texas 77002.

As of February 28, 2022, there were 41,954,385 shares of our Class A Common Stock and 127,536,463 shares of our Class B Common Stock outstanding.

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Shares Beneficially Owned by Certain Beneficial Owners and Management
	Class A Common Stock			Class B Common Stock			Combined Voting Power (1)
	Number	% of class		Number	% of class		Number	% of class
5% Stockholders
Independence Energy Aggregator LP and its affiliates (2)	—	—	%	88,154,049	69.1	%	88,154,049	52.0	%
PT Independence Energy Holdings LLC and its affiliates (5)	—	—	%	39,382,414	30.9	%	39,382,414	23.2	%
John C. Goff 2010 Family Trust (6)	8,845,342	21.1% (7)		—	—	%	8,845,342	5.2	%
Directors and Named Executive Officers
John C. Goff (8)	9,686,668	23.1% (7)		—	—	%	9,686,668	5.7	%
David C. Rockecharlie	—	—	%	—	—	%	—	—	%
Brandi Kendall	—	—	%	—	—	%	—	—	%
John Clayton Rynd	—	—	%	—	—	%	—	—	%
Benjamin M. Conner	—	—	%	—	—	%	—	—	%
Todd N. Falk	—	—	%	—	—	%	—	—	%
Bo Shi	—	—	%	—	—	%	—	—	%
Karen J. Simon	5,424 (9)	*		—	—	%	5,424	*
Ellis L. McCain	33,065 (10)	*		—	—	%	33,065	*
Erich Bobinsky	—	—	%	—	—	%	—	—	%
Bevin Brown	—	—	%	—	—	%	—	—	%
Claire S. Farley	—	—	%	—	—	%	—	—	%
Robert G. Gwin	—	—	%	—	—	%	—	—	%
Directors and Executive Officers as a group (13 persons)	9,725,157	23.2	%	—	—	%	9,725,157	5.7	%

(1)Represents the percentage of voting power of our Class A Common Stock and Class B Common Stock voting together as a single class. OpCo unitholders hold one share of Class B Common Stock for each OpCo Unit that they own. Each share of Class B Common Stock has no economic rights, but entitles the holder thereof to one vote for each share of Class B Common Stock held by such holder. Accordingly, the holders of Class B Common Stock (which are also OpCo unitholders) collectively have the number of votes equal to the number of shares of Class B Common Stock that they hold.

(2)     Independence Energy Aggregator L.P. is the direct beneficial owner of the securities reported. Independence Energy Aggregator GP LLC (“Aggregator GP”) is the general partner of Independence Energy Aggregator L.P. KKR Upstream Associates LLC is the sole member of Aggregator GP. KKR Group Assets Holdings III L.P. and KKR Financial Holdings LLC are the controlling members of KKR Upstream Associates LLC. KKR Group Assets III GP LLC is the general partner of KKR Group Assets Holdings III L.P. KKR Group Partnership L.P. is the sole member of each of KKR Group Assets III GP LLC and KKR Financial Holdings LLC. KKR Group Holdings Corp. is the general partner of KKR Group Partnership L.P. KKR & Co. Inc. is the sole shareholder of KKR Group Holdings Corp. KKR Management LLP is the Series I preferred stockholder of KKR & Co. Inc. Henry R. Kravis and George R. Roberts are the founding partners of KKR Management LLP.

(3)     Consists of shares of Class B Common Stock and an equivalent number of units representing limited liability company interests of OpCo, which together are exchangeable for shares of Class A Common Stock on a one-for-one basis pursuant to the OpCo LLC Agreement.

(4)     Based on a combined total of 127,536,463 shares of Class B Common Stock outstanding as of February 28, 2022.

(5)     PT Independence is the direct beneficial owner of the securities reported. Liberty Energy Holdings LLC (“Holdings”), a member of PT Independence, has the sole right to vote or dispose of the shares of Class B Common Stock and OpCo LLC Units held by PT Independence. Therefore, Holdings is deemed to have beneficial ownership of the shares of Class B Common Stock and OpCo LLC Units. The sole member of Holdings is LMI, which is wholly owned by Liberty Mutual Group Inc. The sole shareholder of Liberty Mutual Group Inc. is LMHC Massachusetts Holdings Inc., whose sole shareholder is Liberty Mutual Holding Company Inc. Because Liberty Mutual Holding Company Inc. is a mutual

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holding company, its members are entitled to vote at meetings of the company. No such member is entitled to cast 5% or more of the votes.

(6)     The address of the principal office of the John C. Goff 2010 Family Trust (“Goff Family Trust”) is 500 Commerce Street, Suite 700, Fort Worth, Texas 76102. John C. Goff is the Sole Trustee of Goff Family Trust. Goff Family Trust is the record holder of 2,413,523 shares of Class A Common Stock, and as managing member of GFT Strategies, LLC and sole shareholder of Goff Capital, Inc. and JCG 2016 Management, LLC Holdings GP, may be deemed to beneficially own the shares of Class A Common Stock held of record by those entities.

(7)     Based on a combined total of 41,954,385 shares of Class A Common Stock outstanding as of February 28, 2022.

(8)     John C. Goff is the record holder of 714,357 shares of Class A Common Stock, and as a manager of Kulik GP, LLC, manager of Goff Focused Strategies, LLC, the sole board member of The Goff Family Foundation, and the sole trustee of the Goff Family Trust, which is the sole shareholder of Goff Capital, Inc. and JCG 2016 Management, LLC, he may be deemed to beneficially own the shares of Class A Common Stock held of record by those entities.

(9)     Based on a total of 27,121 shares of Contango common stock, par value $0.04 per share, outstanding immediately prior to the consummation of the Merger Transactions. These shares were converted automatically into the right to receive 0.2000 shares of Class A Common Stock.

(10)     Based on a total of 165,326 shares of Contango common stock, par value $0.04 per share, outstanding immediately prior to the consummation of the Merger Transactions. These shares were converted automatically into the right to receive 0.2000 shares of Class A Common Stock.

*     less than 1%

Equity Compensation Plan Information

The following table provides information with respect to the shares of our Class A Common Stock that may be issued under our existing equity compensation plans as of December 31, 2021.

Plan Category	Number of shares of Class A Common Stock to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights	Number of shares of Class A Common Stock remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
	(a)	(b)	(c)
Equity compensation plans approved by security holders
None	—	$—
Equity compensation plans not approved by shareholders (1)
Crescent Energy Company 2021 Equity Incentive Plan (3)	—	$—	861,349
Crescent Energy Company 2021 Manager Incentive Plan (2)	4,306,745 (4)	$— (5)	—
Total	4,306,745	$—	861,349

(1)In connection with the Merger Transactions, the Contango Incentive Plan was assumed by the Company, but no future awards will be made under the Contango Incentive Plan. In accordance with Instruction 5 to Item 201(d) of Regulation S—K, the Contango Incentive Plan is not included in the Equity Compensation Plan Information Table. Pursuant to the terms of the Transaction Agreement, all awards that were outstanding under the Contango Incentive Plan vested and were settled following the closing of the Merger Transactions and, as such, there are no awards outstanding under the Contango Incentive Plan. No shares of our Class A Common Stock remain available for issuance under the Contango Incentive Plan.

(2)The Manager Incentive Plan contains a formula for calculating the number of securities available for issuance under the Manager Incentive Plan. Pursuant to such formula, the total number of shares of our Class A Common Stock reserved for issuance under the Manager Incentive Plan is equal to the sum of (i) 4,306,745, plus (ii) on January 1 of each calendar year that occurs before the tenth anniversary of the effective date of the Manager Incentive Plan, 10% of the additional Class A Common Stock issued, if any, during the immediately preceding calendar year.

(3)As of December 31, 2021, no awards had been granted under the Equity Incentive Plan.

(4)The amount included herein represents the maximum number of shares issuable in respect of the Incentive Compensation. The exact number of shares Class A Common Stock covered by the Incentive Compensation will not be determinable until the Incentive Compensation vests and is settled. However, the number of shares issuable in respect of the Incentive Compensation is limited by the number of shares available for issuance under the Manager Incentive Plan. If the performance goals applicable to the Incentive Compensation became earned at target performance as of December 31, 2021, 4,306,745 shares of Class A Common Stock would have become earned, which represents all of the shares of

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Class A Common Stock reserved for issuance under the Manager Incentive Plan. If the performance goals applicable to each tranche of the Incentive Compensation became earned at a level higher than target performance as of December 31, 2021, any amount that became earned in excess of the Class A Common Stock reserved for issuance under the Manager Incentive Plan would have been settled in cash. For more information on the Incentive Compensation see the disclosure included elsewhere herein under the headings “Items 1 and 2. Business and Properties—Management Agreement” and “Item 11. Executive Compensation—Equity-Based Compensation.”

(5)All outstanding awards represent restricted stock units subject to performance-based vesting, which do not have an exercise price.

A description of the material terms of the Equity Incentive Plan and the Manager Incentive Plan in included herein under the heading “Item 11. Executive Compensation— Equity-Based Compensation,” which descriptions are incorporated to this Equity Compensation Plan Information disclosure by reference.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Policies and Procedures for Review of Related Party Transactions

A “Related Party Transaction” is a transaction, arrangement or relationship in which we or any of our subsidiaries was, is or will be a participant, the amount of which involved will or may be expected to exceed $120,000, and in which any Related Person had, has or will have a direct or indirect material interest. A “Related Person” means:

•a person who is or was (since the beginning of the Company’s last completed fiscal year, even if they do not presently serve in that role) a director or director nominee of the Company;

•a person who is or was (since the beginning of the Company’s last completed fiscal year, even if they do not presently serve in that role) a senior officer of the Company, which, among others, includes each vice president and officer of the Company that is subject to reporting under Section 16 of the Exchange Act;

•any holder of the Company’s Series I Preferred Stock (a “Preferred Holder”);

•a greater than 5% beneficial owner of any class of the Company’s voting stock (a “5% Stockholder”);

•a person who is an immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law, or sister-in-law of a director, director nominee, senior officer or 5% Stockholder of Preferred Holder, and any person (other than a tenant or employee) sharing the household of the director, director nominee, senior officer or 5% Stockholder or Preferred Holder; or

•an entity that is owned or controlled by someone listed above, an entity in which someone listed above has a substantial ownership interest or control of the entity, or an entity which someone listed above is an executive officer or general partner, or holds a similar position.

Our Related Party Transactions Policy (the “RPT Policy”) was adopted by our Board of Directors in December 2021. The RPT Policy required that, prior to entering into a Related Party Transaction, the Audit Committee shall review the material facts of the proposed transaction in advance. If advance Audit Committee review and approval of a Related Party Transaction is not feasible, then such Related Party Transaction will be reviewed and considered and, if the Audit Committee determines it to be appropriate and not inconsistent with the interests of the Company and its stockholders, ratified at the Audit Committee’s next regularly scheduled meeting. In determining whether to approve or ratify such a Related Party Transaction, the Audit Committee will take into account, among other factors it deems appropriate, (1) whether the Related Party Transaction is on terms no less favorable than terms generally available to an unaffiliated third-party under the same or similar circumstances, (2) the extent of the Related Person’s interest in the transaction and (3) whether the Related Party Transaction is material to the Company.

Unless otherwise stated, each of the Related Party Transactions discussed below were authorized or consummated prior to our adoption of the RPT Policy.

Agreements Related to the Merger Transactions

OpCo Limited Liability Company Agreement

On December 7, 2021, in connection with the closing of the Merger Transactions, the Company and Independence’s prior owners entered into the OpCo LLC Agreement.

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Pursuant to the OpCo LLC Agreement, each OpCo unitholder other than the Company and the Company Group will, subject to certain limitations, have the right, pursuant to a redemption right specified in the OpCo LLC Agreement, to cause OpCo to redeem all or a portion of its OpCo Units for (i) a corresponding number of shares of the Class A Common Stock, subject to conversion rate adjustments for stock splits, stock dividends, and reclassifications, or (ii) an approximately equivalent amount of cash as determined pursuant to the terms of the OpCo LLC Agreement. Alternatively, upon the exercise of the redemption right by an OpCo unitholder, the Company Group will have the right, pursuant to a call right specified in the OpCo LLC Agreement, to acquire each tendered OpCo Unit directly from such OpCo unitholder for, at the Company’s election, (i) one share of Class A Common Stock, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions, or (ii) an approximately equivalent amount of cash as determined pursuant to the terms of the OpCo LLC Agreement.

In addition, subject to certain exceptions, once the Company Group holds at least 95% of the OpCo Units, the Company Group will have the right to effect the redemption of all of the OpCo Units held by each member of OpCo (other than the members of the Company Group). In connection with any redemption of OpCo Units pursuant to the redemption right (or an acquisition of OpCo Units by the Company Group pursuant to the call right), the corresponding number of shares of Class B Common Stock will be cancelled.

Registration Rights Agreement

On December 7, 2021, in connection with the closing of the Merger Transactions, the Company entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with holders associated with Independence’s former owners and John C. Goff (collectively, the “Holders”), relating to the registered resale of Class A Common Stock owned by such parties as of that date (the “Registrable Securities”). Under the Registration Rights Agreement, the Company has agreed to use its reasonable best efforts to obtain the effectiveness of a registration statement following its receipt of written request by a Holder of Registrable Securities, provided that the Holders may not make such request until the five month anniversary of December 7, 2021, and no registration statement may be taken effective prior to the six month anniversary of the consummation of the Merger Transactions.

The Holders will also have “piggyback” registration rights exercisable at any time that allow them to include the shares of the Class A Common Stock that they own in certain registrations initiated by the Company or other holders of Class A Common Stock. Independence’s former owners also have customary rights to effect certain shelf take-downs, underwritten offering and block trades. The Registration Rights Agreement will terminate at such time as there are no Registrable Securities outstanding.

Management Agreement

In connection with the Merger Transactions, we entered into the Management Agreement with the Manager. Pursuant to the Management Agreement, the Manager provides us with our executive management team and certain management services. The Management Agreement has an initial term of three years and shall renew automatically at the end of the initial term for an additional three-year period unless we or the Manager elect not to renew the Management Agreement.

As consideration for the services rendered pursuant to the Management Agreement and the Manager’s overhead, including compensation of the executive management team, the Manager is entitled to receive compensation equal to $13.5 million per annum, which represents our pro rata portion (based on our relative ownership of OpCo) of $53.3 million. This amount will increase over time as our ownership percentage of OpCo increases. In addition, as our business and assets expand, this compensation may increase by an amount equal to 1.5% per annum of the net proceeds from all future issuances of our equity securities (including in connection with asset acquisitions). However, incremental compensation will not apply to the issuance of our shares upon the redemption or exchange of OpCo Units. During the year ended December 31, 2021, we recorded general and administrative expense of $0.9 million related to the Management Agreement.

Additionally, the Manager is entitled to receive incentive compensation under which the Manager is targeted to receive 10% of our outstanding Class A Common Stock based on the achievement of certain performance-based measures. The incentive compensation consists of five tranches that settle over a five year period, and each tranche relates to a target number of shares of Class A Common Stock equal to 2% of the outstanding Class A Common Stock as of the time such tranche is settled. So long as the Manager continuously provides services to us until the end of the performance period applicable to a tranche, the Manager is entitled to settlement of such tranche with respect to a number of shares of Class A Common Stock ranging from 0% to 240% of the initial target amount based on the level of achievement with respect to the performance goals applicable to such tranche. During the year ended December 31, 2021, we granted performance stock units associated with this incentive compensation. See NOTE 13 – Incentive Compensation Arrangements for more information.

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KKR Funds

From time to time, we may invest in upstream oil and gas assets alongside EIGF II and/or other KKR funds ("KKR Funds") pursuant to the terms of the Management Agreement. In these instances, certain of our consolidated subsidiaries enter into Master Service Agreements ("MSA") with entities owned by KKR Funds, pursuant to which our subsidiaries provide certain services to such KKR Funds, including the allocation of the production and sale of oil, natural gas and NGLs, collection and disbursement of revenues, operating expenses and general and administrative expenses in the respective oil and natural gas properties, and the payment of all capital costs associated with the ongoing operations of the oil and natural gas assets. Our subsidiaries settle balances due to or due from KKR Funds on a monthly basis. The administrative costs associated with these MSAs are allocated by us to KKR Funds based on (i) an actual basis for direct expenses we may incur on their behalf or (ii) an allocation of such charges between the various KKR Funds based on the estimated use of such services by each party. As of December 31, 2021, we had a related party receivable of $3.3 million included within accounts receivable – affiliates and $7.0 million included within accounts payable – affiliates on our consolidated balance sheets associated with KKR Funds transactions.

Chama

In February 2022, we contributed all the assets and prospects in the Gulf of Mexico formerly owned by Contango to Chama Energy LLC (“Chama”), an entity in which we retain an interest of approximately 9.4%. Such interest is valued at approximately $3.75 million. John Goff, the Chairman of our Board of Directors, holds an interest of approximately 17.5% in Chama, and the remaining interest is held by other investors. Pursuant to the Limited Liability Company Agreement of Chama, we may be required to fund certain workover costs and we will be required to fund plugging and abandonment costs related to producing assets held by Chama (collectively, “Crescent Contributions”). We will receive 90.0% of cash flows from the producing assets, which amount is increased for any Crescent Contributions.

Other Transactions

We paid $1.6 million in fees to KKR Capital Markets LLC, an affiliate of KKR, for services provided as a book-running manager in connection with the issuance of our Senior Notes in May 2021. Additionally, we paid $0.1 million to KKR Capstone Americas LLC for professional fees support related to insurance and employee benefits due diligence and placement. In February 2022, we paid $0.4 million in fees to KKR Capital Markets LLC in connection with the issuance of the New Notes. See NOTE 16 – Subsequent Events.

Item 14. Principal Accounting Fees and Services

Our independent registered public accounting firm is Deloitte & Touche LLP, Houston, Texas, Auditor Firm ID: 34.

Aggregate fees for professional services rendered for the Company by Deloitte & Touche LLP for the year ended December 31, 2021, are presented in the following table.

	2021		2020
	(in thousands)
Audit fees	$	2,360	$	2,640
Audit-related fees	275		—
Tax fees	2,103		2,025
All other fees	—		—
Total	$	4,738	$	4,665

The Audit Committee has considered whether Deloitte & Touche LLP is independent for purposes of providing external audit services to the Company, and the Audit Committee has determined that it is.

Audit Committee Policy for Pre-Approval of Audit, Audit-Related, Tax and Permissible Non-Audit Services

The Audit Committee has adopted procedures for pre-approving all audit and non-audit services provided by its independent accounting firm. These procedures include reviewing fee estimates for audit services and permitted recurring non-audit services, and authorizing the Partnership to execute letter agreements setting forth such fees. Audit Committee approval is

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required for any services to be performed by the independent accounting firm that are not specified in the letter agreements. The Audit Committee has delegated approval authority to the chairman of the Audit Committee, but any exercises of such authority are reported to the Audit Committee at the next meeting.

Part IV

Item 15. Exhibits, and Financial Statement Schedules

(a) Financial statements and financial statement schedules filed as part of this report are listed in the index included in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report. All valuation and qualifying accounts schedules have been omitted because they are either not material, not required, not applicable or the information required to be presented is included in our combined and consolidated financial statements and related notes.

(b) Exhibits. The following is a list of exhibits required to be filed as a part of this Annual Report in Item 15(b).

Exhibit No.	Description
2.1	Transaction Agreement, dated as of June 7, 2021, by and among Contango Oil & Gas Company, Independence Energy LLC, IE PubCo Inc., IE OpCo LLC, IE L Merger Sub LLC and IE C Merger Sub Inc. (incorporated by reference to Exhibit 2.1 to the Company's proxy statement/prospectus, filed with the Securities and Exchange Commission on October 8, 2021).
2.2	Membership Interest Purchase Agreement, dated as of February 15, 2022, by and between Verdun Oil Company II LLC and Javelin VentureCo, LLC, and Crescent Energy OpCo LLC, as guarantor (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on February 16, 2022).
3.1	Amended and Restated Certificate of Incorporation of Registrant (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
3.2	Amended and Restated By-Laws of Registrant (incorporated by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
4.1*	Description of Securities Registered Under Section 12 of the Securities Exchange Act of 1934, as amended.
4.2	Indenture, dated as of May 6, 2021, among Crescent Energy Finance LLC (f/k/a Independence Energy Finance LLC), the guarantors named therein, and U.S. Bank Trust Company, National Association, as successor to U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on February 10, 2022).
4.3	First Supplemental Indenture, dated as of January 14, 2022, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as successor to U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on February 10, 2022).
4.4	Second Supplemental Indenture, dated as of February 10, 2022, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on February 10, 2022).
4.5*	Voting Agreement, dated as of June 7, 2021, by and among John C. Goff, Independence Energy LLC and the signatories thereto.
10.1	Registration Rights Agreement, dated as of December 7, 2021, by and among Crescent Energy Company and each of the other parties set forth on the signature pages thereto (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.2	Amended & Restated Limited Liability Company Agreement of Crescent Energy OpCo LLC (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.3	Management Agreement, dated as of December 7, 2021, by and among Crescent Energy Company and KKR Energy Assets Manager LLC (incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.4	Specified Rights Agreement, dated as of June 7, 2021, by and among PT Independence Energy Holdings LLC and Independence Energy Aggregator GP LLC (incorporated by reference to Exhibit 10.1 to the Company’s Registration Statement on Form S-4, filed with the Securities and Exchange Commission on October 8, 2021).
10.5*†	Crescent Energy Company 2021 Manager Incentive Plan.
10.6†	Form of Manager Incentive Plan Award (incorporated by reference to Exhibit 10.5 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 7, 2021).

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Exhibit No.	Description
10.7†	Crescent Energy Company 2021 Equity Incentive Plan (incorporated by reference to Exhibit 10.6 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.8†	Form of Equity Incentive Plan RSU Agreement (incorporated by reference to Exhibit 10.7 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.9†	Form of Equity Incentive Plan PSU Agreement (incorporated by reference to Exhibit 10.8 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.10	Indemnification Agreement (David C. Rockecharlie) (incorporated by reference to Exhibit 10.10 to the Company’s Current Report on 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.11†	Indemnification Agreement (Brandi Kendall) (incorporated by reference to Exhibit 10.11 to the Company’s Current Report on 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.12†	Indemnification Agreement (Todd Falk) (incorporated by reference to Exhibit 10.12 to the Company’s Current Report on 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.13†	Indemnification Agreement (Ben Conner) (incorporated by reference to Exhibit 10.13 to the Company’s Current Report on 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.14†	Indemnification Agreement (Clay Rynd) (incorporated by reference to Exhibit 10.14 to the Company’s Current Report on 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.15†	Indemnification Agreement (Robert G. Gwin) (incorporated by reference to Exhibit 10.15 to the Company’s Current Report on 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.16†	Indemnification Agreement (Claire S. Farley) (incorporated by reference to Exhibit 10.16 to the Company’s Current Report on 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.17†	Indemnification Agreement (Erich Bobinsky) (incorporated by reference to Exhibit 10.17 to the Company’s Current Report on 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.18†	Indemnification Agreement (Bevin Brown) (incorporated by reference to Exhibit 10.18 to the Company’s Current Report on 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.19†	Indemnification Agreement (Karen J. Simon) (incorporated by reference to Exhibit 10.19 to the Company’s Current Report on 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.20†	Indemnification Agreement (Ellis L. McCain) (incorporated by reference to Exhibit 10.20 to the Company’s Current Report on 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.21†	Indemnification Agreement (John C. Goff) (incorporated by reference to Exhibit 10.21 to the Company’s Current Report on 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.22*	Credit Agreement, dated as of May 6, 2021, among Independence Energy Finance LLC, Wells Fargo, National Association, JP Morgan Chase Bank, N.A. and the lender parties thereto.
10.23*	First Amendment to Credit Agreement, dated as of September 24, 2021, among Independence Energy Finance LLC, Wells Fargo, National Association, and the lender parties thereto.
21.1*	Subsidiaries of the Company
23.1*	Consent of Deloitte & Touch LLP
23.2*	Consent of Netherland, Sewell & Associates, Inc.
23.3*	Consent of Haas Petroleum Engineering Services, Inc.
23.4*	Consent of Cawley, Gillespie & Associates, Inc.
23.5*	Consent of William M. Cobb & Associates, Inc.
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1*	Report of Netherland, Sewell & Associates, Inc. - Diversified Non-Operated and Mineral Assets, as of December 31, 2021.
99.2*	Report of Netherland, Sewell & Associates, Inc. - Brea-Olinda Field, Los Angeles and Orange Counties, California, as of December 31, 2021.
99.3*	Report of Haas Petroleum Engineering Services, Inc. - FDL Gardendale, Newark and Renee, as of December 31, 2021.
99.4*	Report of Cawley, Gillespie & Associate, Inc. - Eagle Ford, as of December 31, 2021.
99.5*	Report of William M. Cobb & Associates, Inc. - Contango and Sunrise, as of December 31, 2021.
101.INS**	XBRL Instance Document
101.SCH**	XBRL Schema Document
101.CAL**	XBRL Calculation Linkbase Document
101.LAB**	XBRL Label Linkbase Document

152

Table of Contents

Exhibit No.	Description
101.PRE**	XBRL Presentation Linkbase Document
101.DEF**	XBRL Definition Linkbase Document

*    Filed herewith

**    These files are furnished and deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Act of 1934, as amended, and otherwise are not subject to liability under those sections.

† Management contract or compensatory plan or agreement

Item 16. Form 10-K Summary

None.

153

Table of Contents

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 9, 2022.

CRESCENT ENERGY COMPANY

(Registrant)

/s/ David Rockecharlie

David Rockecharlie

Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 9, 2022.

/s/ David Rockecharlie	Chief Executive Officer and Director
David Rockecharlie	(Principal Executive Officer)
/s/ Brandi Kendall	Chief Financial Officer and Director
Brandi Kendall	(Principal Financial Officer)
/s/ Todd Falk	Chief Accounting Officer
Todd Falk	(Principal Accounting Officer)
/s/ John C. Goff	Chairman of the Board and Director
John C. Goff
/s/ Robert G. Gwin	Director
Robert G. Gwin
/s/ Claire S. Farley	Director
Claire S. Farley
/s/ Erich Bobinsky	Director
Erich Bobinsky
/s/ Ellis "Lon" McCain	Director
Ellis "Lon" McCain
/s/ Bevin Brown	Director
Bevin Brown
/s/ Karen Simon	Director
Karen Simon

154

EX-4.1

DESCRIPTION OF CAPITAL STOCK

The following summary of certain material provisions of Crescent Energy Company’s (“we,” “us” and “our”) capital stock does not purport to be complete and is subject to and qualified by reference to our amended and restated certificate of incorporation (our “Amended and Restated Charter”), and our amended and restated bylaws (our “Amended and Restated Bylaws”). The summary below is also qualified by reference to the provisions of the Delaware General Corporation Law (“DGCL”).

General

Our authorized capital stock consists of 2,000,000,000 shares, divided into the following classes:

•1,000,000,000 shares of Class A Common Stock, par value $0.0001 per share (our “Class A Common Stock”);

•500,000,000 shares of Class B Common Stock, par value $0.0001 per share (our “Class B Common Stock); and

•500,000,000 shares of preferred stock, of which (y) 1,000 shares are Non-Economic Series I Preferred Stock (our “Non-Economic Series I Preferred Stock”) and (z) the remaining 499,999,000 shares may be designated from time to time in accordance with the our Amended and Restated Charter (together, with the Non-Economic Series I Preferred Stock, our “Preferred Stock”).

Class A Common Stock

Voting Rights. Prior to the Trigger Date (as defined in the section herein titled “Non-Economic Series I Preferred Stock”), holders of our Class A Common Stock will not be entitled to elect directors to our Board of Directors. On and after the Trigger Date, the holders of our Class A Common Stock will be entitled to elect directors but will not have cumulative voting rights in the election of directors. Holders of our Class A Common Stock will otherwise be entitled to one vote per share held of record on all matters to be voted upon by the stockholders. Holders of our Class A Common Stock and our Class B Common Stock will vote together as a single class on all matters presented to stockholders for their vote or approval, except with respect to the amendment of certain provisions of the our Amended and Restated Charter that would alter or change the powers, preferences or special rights of our Non-Economic Series I Preferred Stock or our Class B Common Stock so as to affect them adversely, which amendments must be by a majority of the votes entitled to be cast by the holders of the class of stock affected by the amendment, voting as a separate class, or as otherwise required by applicable law.

Dividend Rights. Holders of our Class A Common Stock will be entitled to ratably receive dividends when and if declared by the our Board of Directors out of funds legally available for that purpose, subject to any statutory or contractual restrictions on the payment of dividends and to any prior rights and preferences that may be applicable to any outstanding preferred shares.

Liquidation Rights. Upon liquidation, dissolution, distribution of assets or other winding up, the holders of our Class A Common Stock will be entitled to receive ratably the assets available for

distribution to the stockholders after payment of liabilities and the liquidation preference of any of outstanding shares of our Preferred Stock.

Other Matters. Our Class A Common Stock will have no preemptive or conversion rights and there are no redemption or sinking fund provisions applicable to the our Class A Common Stock.

Class B Common Stock

Voting Rights. Prior to the Trigger Date, holders of our Class B Common Stock will not be entitled to elect directors to our Board of Directors. On and after the Trigger Date, the holders of our Class B Common Stock will be entitled to elect directors but will not have cumulative voting rights in the election of directors. Holders of our Class B Common Stock will otherwise be entitled to one vote per share held of record on all matters to be voted upon by the stockholders. Holders of our Class A Common Stock and our Class B Common Stock will vote together as a single class on all matters presented to stockholders for their vote or approval, except with respect to the amendment of certain provisions of our Amended and Restated Charter that would alter or change the powers, preferences or special rights of our Non-Economic Series I Preferred Stock or our Class B Common Stock so as to affect them adversely, which amendments must be by a majority of the votes entitled to be cast by the holders of the class of stock affected by the amendment, voting as a separate class, or as otherwise required by applicable law.

Dividend and Liquidation Rights. Holders of our Class B Common Stock will not have any right to receive dividends, unless the dividend consists of shares of our Class B Common Stock or of rights, options, warrants or other securities convertible or exercisable into or exchangeable for our Class B Common Stock paid proportionally with respect to each outstanding share of our Class B Common Stock and a dividend consisting of shares of our Class A Common Stock or of rights, options, warrants or other securities convertible or exercisable into or exchangeable for our Class A Common Stock on the same terms as simultaneously paid to the holders of our Class A Common Stock. Holders of our Class B Common Stock will not have any right to receive a distribution upon liquidation or winding up.

Preferred Stock

Our Board of Directors is authorized, subject to limitations prescribed by Delaware law, to issue our Preferred Stock in one or more series, to establish from time to time the number of shares to be included in each series, and to fix the designation, powers (including voting powers), preferences and rights of the shares of each series and any of its qualifications, limitations or restrictions, in each case without further vote or action by our stockholders (except as may be required by the terms of any preferred stock then outstanding). Our Board of Directors may (except where otherwise provided in the applicable preferred stock designation) increase (but not above the total number of authorized shares of the class) or decrease (but not below the number of shares outstanding) the number of shares of any series of our Preferred Stock, without any further vote or action by our stockholders. Our Board of Directors may authorize the issuance of our Preferred Stock with voting or conversion rights that could adversely affect the proportion of voting power held by, or other relative rights of, the holders of the our Class A Common Stock or our Class B Common Stock.

Non-Economic Series I Preferred Stock

Dividends and Liquidation Rights. Except for any distribution required by the DGCL to be made upon a dissolution event, the holder of our Non-Economic Series I Preferred Stock (the “Preferred Stockholder”) does not have any rights to receive dividends. Upon any voluntary or involuntary liquidation, dissolution or winding up of us, the holder of our Non-Economic Series I Preferred Stock will be entitled to a payment equal to $0.01 per share of our Non-Economic Series I Preferred Stock.

Voting Rights. The holder of our Non-Economic Series I Preferred Stock are entitled to one vote per share on any matter that is submitted to a vote of stockholders. In addition, the holder of our Non-Economic Series I Preferred Stock will have the exclusive right to elect the members of our Board of Directors prior to the date (the “Trigger Date”) following the earlier of (i) the first date on which the Preferred Stockholder and its affiliates no longer collectively beneficially own the Minimum Retained Ownership (as defined in our Amended and Restated Charter) and (ii) the date the Preferred Stockholder elects, by delivering written notice to us, to cause the Trigger Date to occur. Upon occurrence of the Trigger Date, all rights, powers, preferences and privileges associated with shares of our Non-Economic Series I Preferred Stock and associated with being the Preferred Stockholder in its capacity as the owner of the Series I Preferred Stock will automatically terminate in all respects and all shares of our Non-Economic Series I Preferred Stock will be automatically cancelled and forfeited for no consideration.

Actions Requiring Preferred Stockholder Approval. Prior to the Trigger Date, certain actions will require the prior approval of the Preferred Stockholder, including, without limitation:         

•entry into a debt financing arrangement in an amount in excess of 10% of our then existing long-term indebtedness (other than with respect to intercompany debt financing arrangements);

•issuances of securities that would (i) represent at least 5% of any class of equity securities or (ii) have designations, preferences, rights priorities or powers that are more favorable than our Class A Common Stock or Class B Common Stock;

•adoption of a shareholder rights plan;

•amendment of our Amended and Restated Charter and certain provisions of our Amended and Restated Bylaws relating to our Board of Directors, our officers, quorum, adjournment and the conduct of stockholder meetings, and provisions related to stock certificates, registrations of transfers, maintenance of books and records and amendments of our Amended and Restated Bylaws;

•the appointment or removal of our Chief Executive Officer or a Co-Chief Executive Officer, provided that, a majority of our directors that are independent for purposes of the Audit Committee of the Board of Directors under the rules and regulations of the New York Stock Exchange, the Exchange Act and the Sarbanes-Oxley Act of 2002, as amended (the “Independent Directors”) may remove a Chief Executive Officer without the prior approval of the Preferred Stockholder solely for Cause (as defined in our Amended and Restated Charter);

•the termination of the employment of any of our officers without Cause;

•the merger, sale or other dispositions of all or substantially all of the assets, taken as a whole, of us and our subsidiaries; and

•the liquidation or dissolution of us.

Transferability. The holder of our Non-Economic Series I Preferred Stock may transfer all or any part of our Non-Economic Series I Preferred Stock held by it without first obtaining approval of any other stockholder so long as (i) it obtains prior written approval of a majority of the Independent Directors of our Board of Directors and (ii) the transferee assumes the rights and duties of our Non-Economic Series I Preferred Stock under our Amended and Restated Charter and agrees to be bound by the provisions of our Amended and Restated Charter.

Corporate Opportunities

Delaware law permits corporations to adopt provisions renouncing any interest or expectancy in certain opportunities that are presented to the corporation or its officers, directors or stockholders. To the fullest extent permitted by law, each of our directors and officers will have the right to engage in businesses of every type and description and other activities for profit and to engage in and possess an interest in other business ventures of any and every type or description, including business interests and activities in direct competition with the business and activities of us, and we will waive and renounce any interest or expectancy therein. In addition, the doctrine of corporate opportunity will not apply with respect to us, any of our officers or directors, the Preferred Stockholder or any of their respective affiliates in circumstances where the application of any such doctrine would conflict with any fiduciary duties or contractual obligations they may have, and we will renounce any expectancy that such persons will offer any such corporate opportunity of which he, she or it may become aware to us. Notwithstanding the foregoing, we will not renounce our interest in any corporate opportunity offered to any of our directors or officers if such opportunity is expressly offered in writing to such person solely in his or her capacity as a director or officer of us and is one that such director or officer has no duty (contractual or fiduciary) to offer to KKR & Co., Inc. or its affiliates.

Anti-Takeover Provisions

Our Amended and Restated Charter and our Amended and Restated Bylaws and the DGCL contain provisions that are intended to enhance the likelihood of continuity and stability in the composition of our Board of Directors and to discourage certain types of transactions that may involve an actual or threatened acquisition of us. These provisions are intended to avoid costly takeover battles, reduce our vulnerability to a hostile change in control or other unsolicited acquisition proposal, and enhance the ability of our Board of Directors to maximize stockholder value in connection with any unsolicited offer to acquire us. However, these provisions may have the effect of delaying, deterring or preventing a merger or acquisition of us by means of a tender offer, a proxy contest or other takeover attempt that a stockholder might consider in its best interest, including attempts that might result in a premium over the prevailing market price for the shares of our Class A Common Stock held by stockholders. The following is a summary of certain provisions that may be deemed to have such effects:

Election and Removal of Directors

Prior to the Trigger Date, the Preferred Stockholder has the sole authority to elect directors. Prior to the Trigger Date, the Preferred Stockholder has the sole authority to remove and replace any director, with or without cause, at any time, subject to limited exceptions during the Protected Periods (as defined in the Amended and Restated Charter). In addition, our Amended and

Restated Charter also provides that, any newly created directorship on our Board of Directors that results from an increase in the number of directors and any vacancies on our Board of Directors will be filled by the Preferred Stockholder.

Actions Requiring Preferred Stockholder Approval

Prior to the Trigger Date, certain actions will require the prior approval of the Preferred Stockholder. See the section titled “Non-Economic Series I Preferred Stock” above.

Amendments to our Amended and Restated Charter

Except as otherwise expressly provided by applicable law, only the vote of the Preferred Stockholder, together with the approval of our Board of Directors, shall be required in order to amend the our Amended and Restated Charter and certain provisions of our Amended and Restated Bylaws. See the section titled “Non-Economic Series I Preferred Stock” above.

Special Stockholder Meetings

Our Amended and Restated Charter provides that special meetings of the holders of our Class A Common Stock and Class B Common Stock may be called at any time by our Board of Directors, the Preferred Stockholder or, prior to the Trigger Date, a majority of our Independent Directors.

Stockholder Action by Written Consent

Our Amended and Restated Charter provides that, if consented to by our Board of Directors and the Preferred Stockholder in writing, any action required to be taken at any annual or special meeting of the stockholders may be taken without a meeting, without prior notice and without a vote if a consent or consents in writing, setting forth the action so taken, is signed by the holders of outstanding Class A Common Stock and Class B Common Stock having not less than the minimum number of votes that would be necessary to authorize or take such action at a meeting at which all shares of our stock entitled to vote thereon were present and voted and such consent or consents are delivered in accordance with Section 228 of the DGCL.

Requirements for Advance Notification of Stockholder Proposals

Our Amended and Restated Bylaws will establish advance notice procedures with respect to stockholder proposals relating to the limited matters on which our Class A Common Stock and Class B Common Stock may be entitled to vote. Generally, to be timely, a stockholder’s notice must be received at our principal executive offices not less than 90 days or more than 120 days prior to the first anniversary date of the immediately preceding annual meeting of stockholders. Our Amended and Restated Bylaws will also specify requirements as to the form and content of a stockholder’s notice. Our Amended and Restated Bylaws will allow the chairman of the meeting at a meeting of the stockholders to adopt rules and regulations for the conduct of meetings, which may have the effect of precluding the conduct of certain business at a meeting if the rules and regulations are not followed. These provisions may deter, delay or discourage a potential acquirer from attempting to influence or obtain control of us.

Merger, Sale or Other Disposition of Assets

Our Amended and Restated Charter provides that we may not sell, exchange, lease or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, or consummate any merger, sale or other similar combination without the prior approval of the Preferred Stockholder.

Choice of Forum

Unless we consent in writing to the selection of an alternative forum, (a) the Court of Chancery of the State of Delaware (or, solely to the extent that the Court of Chancery lacks subject matter jurisdiction, the federal district court located in the State of Delaware) is the exclusive forum for resolving (i) any derivative action, suit or proceeding brought on behalf of the corporation, (ii) any action, suit or proceeding asserting a claim of breach of a fiduciary duty owed by any current or former director, officer, employee or stockholder of the corporation to the corporation or the corporation’s stockholders, (iii) any action, suit or proceeding asserting a claim arising pursuant to any provision of the DGCL, our Amended and Restated Charter or our Amended and Restated Bylaws or as to which the DGCL confers jurisdiction on the Court of Chancery of the State of Delaware or (iv) any action, suit or proceeding asserting a claim governed by the internal affairs doctrine, and (b) the federal district courts of the United States shall be the exclusive forum for the resolution of any action, suit or proceeding asserting a cause of action arising under the Securities Act, in each case except as otherwise provided in our Amended and Restated Charter for any series of our Preferred Stock.

Business Combinations

We have elected to opt out of Section 203 of the DGCL, which provides that an “interested stockholder” (a person other than the corporation or any direct or indirect majority-owned subsidiary who, together with affiliates and associates, owns, or, if such person is an affiliate or associate of the corporation, within three years did own, 15% or more of the outstanding voting stock of a corporation) may not engage in “business combinations” (which is broadly defined to include a number of transactions, such as mergers, consolidations, asset sales and other transactions in which an interested stockholder receives or could receive a financial benefit on other than a pro rata basis with other stockholders) with the corporation for a period of three years after the date on which the person became an interested stockholder without certain statutorily mandated approvals.

EX-4.5

VOTING AGREEMENT

This Voting Agreement (this “Agreement”), dated as of June 7, 2021, is entered into by and among Independence Energy LLC, a Delaware limited liability company (“Isla”), John C. Goff (“Goff”) and each other signatory hereto (each, together with Goff, a “Stockholder”). Isla and Stockholders are each sometimes referred to herein individually as a “Party” and collectively as the “Parties.”

WHEREAS, concurrently with the execution of this Agreement, the Company, Isla andcertain Subsidiaries of Isla are entering into a Transaction Agreement (as the same may be amended from time to time, the “Transaction Agreement”), providing for, among other things, the merger (the “Merger”) of IE C Merger Sub Inc., a Texas corporation, and the Company pursuant to the terms and conditions of the Transaction Agreement;

WHEREAS, in order to induce Isla to enter into the Transaction Agreement, Stockholders are willing to make certain representations, warranties, covenants, and agreements as set forth in this Agreement with respect to the 48,406,233 shares of common stock, par value $0.04 per share, of the Company (“Company Common Stock”) Beneficially Owned (as defined below) by Stockholders (the “Original Shares” and, together with any additional shares of Company Common Stock pursuant to Section 6 hereof, the “Shares”); and

WHEREAS, as a condition to their willingness to enter into the Transaction Agreement, Isla has required that Stockholders, and Stockholders have agreed to, execute and deliver this Agreement.

NOW, THEREFORE, in consideration of the foregoing and the respective representations, warranties, covenants, and agreements set forth below and for other good and valuable consideration, the receipt, sufficiency, and adequacy of which are hereby acknowledged, the Parties hereto, intending to be legally bound, do hereby agree as follows:

1.Definitions.

For purposes of this Agreement, capitalized terms used and not otherwise defined herein shall have the respective meanings ascribed to such terms in the Transaction Agreement. When used in this Agreement, the following terms in all of their tenses, cases, and correlative forms shall have the meanings assigned to them in this Section 1.

(a)“Affiliate” means with respect to any Person, any other Person directly or indirectly, controlling, controlled by, or under common control with, such Person, through one or more intermediaries or otherwise; provided, however, that solely for purposes of this Agreement, notwithstanding anything to the contrary set forth herein, neither the Company nor any of its Subsidiaries shall be deemed to be a Subsidiary or Affiliate of any Stockholder; provided, further, that, for the avoidance of doubt, any member of any Stockholder shall be deemed an Affiliate such Stockholder; and provided, further, that an Affiliate of any Stockholder shall include any investment fund, vehicle or holding company of which such Stockholder or an affiliate thereof serves as the general partner, managing member or discretionary manager or advisor.

(b)“Beneficially Own” or “Beneficial Ownership” has the meaning assigned to such term in Rule 13d-3 under the Exchange Act, and a Person’s beneficial ownership of securities shall be calculated in accordance with the provisions of such rule (in each case, irrespective of whether or not such rule is actually applicable in such circumstance). For the avoidance of doubt, “Beneficially Own” and “Beneficial Ownership” shall also include record ownership of securities.

US 7999143v.7

(c)“Beneficial Owner” shall mean the Person who Beneficially Owns the referenced securities.

2.Representations of Stockholder.

Each Stockholder represents and warrants to Isla that:

(a)Ownership of Shares. Such Stockholder (i) is the Beneficial Owner of the portion of the Original Shares set forth on Annex A free and clear of any proxy, voting restriction, adverse claim, or other Encumbrances, other than those created by this Agreement or under applicable federal or state securities laws; and (ii) has the sole voting power over such Original Shares. Except as expressly provided by this Agreement, there are no options, warrants, or other rights, agreements, arrangements, or commitments of any character to which such Stockholder is a party relating to the pledge, disposition, or voting of any of such Original Shares and there are no voting trusts or voting agreements with respect to such Original Shares.

(b)Disclosure of All Shares Owned. Neither such Stockholder nor any of its Affiliates Beneficially Owns any shares of Company Common Stock other than the Original Shares.

(c)Power and Authority; Binding Agreement. Such Stockholder has full power and authority to enter into, execute, and deliver this Agreement and to perform fully such Stockholder’s obligations hereunder (including the proxy described in Section 3(b) below). This Agreement has been duly and validly executed and delivered by such Stockholder and constitutes the legal, valid, and binding obligation of such Stockholder, enforceable against such Stockholder in accordance with its terms.

(d)No Conflict. The execution and delivery of this Agreement by such Stockholder does not, and the consummation of the transactions contemplated hereby and the compliance with the provisions hereof will not, conflict with or violate any Law applicable to such Stockholder or result in any breach of or violation of, or constitute a default (or an event that with notice or lapse of time or both would become a default) under, or give to others any rights of termination, amendment, acceleration, or cancellation of, or result in the creation of any Encumbrance on any of the Shares pursuant to, any agreement or other instrument or obligation, including organizational documents binding upon such Stockholder or any of the Shares.

(e)No Consents. No Consent, order or declaration of any Governmental Entity or any other Person on the part of such Stockholder is required in connection with the valid execution and delivery of this Agreement.

(f)No Litigation. There is no Proceeding pending against, or, to the knowledge of such Stockholder, threatened against or affecting, such Stockholder that could reasonably be expected to materially impair or materially adversely affect the ability of such Stockholder to perform such Stockholder’s obligations hereunder or to consummate the transactions contemplated by this Agreement on a timely basis.

3.Agreement to Vote Shares; Irrevocable Proxy.

(a)Agreement to Vote and Approve. Each Stockholder irrevocably and unconditionally agrees during the term of this Agreement, at any annual or special meeting of the Company called with respect to the following matters, and at every adjournment or postponement thereof, and on every action or approval by written consent of the Company stockholders with respect to any of the following matters, to appear at any such meeting or otherwise cause the applicable Shares to be counted as present thereat

2

for purpose of establishing a quorum and vote or cause the holder of record to vote the Shares at such meeting (i) in favor of (1) adoption of the Transaction Agreement and approval of any other matters necessary for consummation of the Transactions, including the Merger and (2) any proposal to adjourn or postpone such meeting of stockholders of the Company to a later date if there are not sufficient votes to approve the Transactions, including the Merger; and (ii) against (1) any Company Competing Proposal or any of the transactions contemplated thereby, (2) any action, proposal, transaction, or agreement which could reasonably be expected to result in a breach of any covenant, representation or warranty, or any other obligation or agreement of the Company under the Transaction Agreement or of such Stockholder under this Agreement, and (3) any action, proposal, transaction, or agreement that could reasonably be expected to impede, interfere with, delay, discourage, adversely affect, or inhibit the timely consummation of the Transactions, including the Merger, or the fulfillment of the Isla Parties’ conditions under the Transaction Agreement or change in any manner the voting rights of any class of shares of the Company (including any amendments to the Company’s Organizational Documents). Any attempt by any Stockholder to vote, consent or express dissent with respect to (or otherwise to utilize the voting power of), any Shares in contravention of this Section 3(a) shall be null and void ab initio.

(b)Irrevocable Proxy. Each Stockholder hereby appoints Isla and any designee of Isla, and each of them individually, until the Expiration Time (at which time this proxy shall automatically be revoked), its proxies and attorneys-in-fact, with full power of substitution and resubstitution, to vote or consent during the term of this Agreement with respect to the Shares in accordance with Section 3(a). This proxy and power of attorney is given to secure the performance of the duties of such Stockholder under this Agreement. Each Stockholder shall take such further action or execute such other instruments as may be necessary to effectuate the intent of this proxy. This proxy and power of attorney granted by each Stockholder shall be irrevocable during the term of this Agreement, shall be deemed to be coupled with an interest sufficient in law to support an irrevocable proxy and shall revoke any and all prior proxies granted by such Stockholder with respect to the applicable Shares. The proxy and power of attorney granted hereunder shall terminate upon the termination of this Agreement.

4.No Voting Trusts or Other Arrangement.

Each Stockholder agrees that during the term of this Agreement such Stockholder will not, and will not permit any Affiliate to, deposit any of the Shares in a voting trust, grant any proxies with respect to the Shares, or subject any of the Shares to any arrangement with respect to the voting of the Shares other than agreements entered into with Isla.

5.Transfer and Encumbrance.

Each Stockholder agrees that during the term of this Agreement, such Stockholder will not, directly or indirectly, transfer, sell, offer, exchange, assign, pledge, convey any legal or Beneficial Ownership interest in or otherwise dispose of (by merger (including by conversion into securities or other consideration), by tendering into any tender or exchange offer, by operation of Law or otherwise) or Encumber (“Transfer”) any of the Shares or enter into any contract, option or other agreement with respect to, or consent to, a Transfer of any of the Shares or such Stockholder’s voting or economic interest therein. This Section 5 shall not prohibit a Transfer of the Shares by any Stockholder to an Affiliate of such Stockholder; provided, that a Transfer referred to in this sentence shall be permitted only if, as a precondition to such Transfer, the transferee agrees in a writing, reasonably satisfactory in form and substance to Isla, to be bound by all of the terms of this Agreement. Any attempted Transfer of Shares or any interest therein in violation of this Section 5 shall, to the fullest extent permitted by Law, be null and void ab initio. If any involuntary Transfer of any of any Stockholder’s Shares shall occur, the transferee

3

(which term, as used herein, shall include any and all transferees and subsequent transferees of the initial transferee) shall take and hold such Shares subject to all of the restrictions, liabilities and rights under this Agreement, which shall continue in full force and effect until valid termination of this Agreement.

6.Additional Purchases; Adjustments.

Each Stockholder agrees that any shares of Company Common Stock and any other shares of capital stock or other equity of the Company that such Stockholder purchases, acquires the voting power or otherwise acquires Beneficial Ownership of after the execution of this Agreement and prior to the Expiration Time shall be subject to the terms and conditions of this Agreement to the same extent as if they constituted Shares as of the date hereof for all purposes of this Agreement, and such Stockholder shall promptly notify the Company of the existence of any such after-acquired Shares. In the event of any stock split, stock dividend, merger, reorganization, recapitalization, reclassification, combination, exchange of shares or the like of the capital stock of the Company affecting the Shares, the terms of this Agreement shall apply to the resulting securities and such resulting securities shall be subject to the terms and conditions of this Agreement to the same extent as if they constituted Shares as of the date hereof for all purposes of this Agreement.

7.Waiver of Appraisal and Dissenters’ Rights and Certain Other Actions.

(a)Waiver of Appraisal and Dissenters’ Rights. To the fullest extent permitted by Law, each Stockholder hereby irrevocably and unconditionally waives, and agrees not to assert or perfect, any rights of appraisal (including under Section 10.354 of the Texas Business Organization Code) or rights to dissent in connection with the Merger that such Stockholder may have by virtue of ownership of such Stockholder’s Shares.

(b)Waiver of Certain Other Actions. EachStockholder hereby agrees not to commence, join in, and agrees to take all actions necessary to opt out of any class in any class action with respect to, any claim, derivative or otherwise, against Isla, Merger Sub or the Company or any of their respective Affiliates and each of their successors or directors relating to the negotiation, execution or delivery of this Agreement or the Transaction Agreement or the consummation of the transactions contemplated hereby or thereby, including any claim (a) challenging the validity of, or seeking to enjoin the operation of, any provision of this Agreement or the Transaction Agreement (including any claim seeking to enjoin or delay the Closing) or (b) alleging a breach of any fiduciary duty of the Company Board in connection with the negotiation and entry into this Agreement, the Transaction Agreement or the transactions contemplated hereby or thereby, and hereby irrevocably waives any claim or rights whatsoever with respect to any of the foregoing.

8.Termination.

This Agreement shall terminate upon the earliest to occur of (the “Expiration Time”): (a) the Effective Time; (b) the date on which the Transaction Agreement is terminated in accordance with its terms; and (c) the termination of this Agreement by mutual written consent of the Parties. Nothing in this Section 8 shall relieve or otherwise limit the liability of any Party for any intentional breach of this Agreement prior to such termination.

9.No Solicitation.

Subject to Section 10, each Stockholder shall not, and shall cause its Affiliates and its and their Representatives not to, directly or indirectly, take any of the actions set forth in Section 6.3(b) of the Transaction Agreement (without giving effect to any amendment or modification of such clauses after the

4

date hereof). Each Stockholder shall, and shall cause its Affiliates and its and their Representatives to, immediately cease, and cause to be terminated, any discussions or negotiations conducted before the date of this Agreement with any Person other than Isla with respect to any inquiry, proposal or offer that constitutes, or would reasonably be expected to lead to, a Company Competing Proposal. In addition, each Stockholder agrees to be subject to Section 6.3(c) of the Transaction Agreement (without giving effect to any amendment or modification of such clauses after the date hereof) as if such Stockholder were the “Company” thereunder. Notwithstanding the foregoing, to the extent the Company complies with its obligations under Section 6.3 of the Merger Agreement and participates in discussions or negotiations with a Person regarding a Company Competing Proposal, the Holder or any of such Holder’s controlled Affiliates and/or such Holder’s and such Holder’s Affiliates’ Representatives may engage in discussions or negotiations with such Person to the extent that the Company can act under Section 6.3 of the Merger Agreement.

10.Further Assurances.

Each Stockholder agrees, from time to time, and without additional consideration, to execute and deliver such additional proxies, documents and other instruments and to take all such further action as Isla may reasonably request to consummate and make effective the transactions contemplated by this Agreement and to not take or permit any of its Affiliates to take any action that would reasonably be likely to adversely affect or delay the ability to perform such Stockholder’s covenants and agreements under this Agreement.

11.Specific Performance.

The Parties agree that irreparable damage, for which monetary damages would not be an adequate remedy, would occur in the event that any of the provisions of this Agreement were not performed in accordance with their specific terms or were otherwise breached by the Parties. Prior to the Expiration Time, it is accordingly agreed that the Parties shall be entitled to an injunction or injunctions, or any other appropriate form of specific performance or equitable relief, to prevent breaches of this Agreement and to enforce specifically the terms and provisions hereof in any court of competent jurisdiction, in each case in accordance with this Section 11, this being in addition to any other remedy to which they are entitled under the terms of this Agreement at Law or in equity. Each Party accordingly agrees not to raise any objections to the availability of the equitable remedy of specific performance to prevent or restrain breaches or threatened breaches of, or to enforce compliance with, the covenants and obligations of such party under this Agreement, all in accordance with the terms of this Section 11. Each Party further agrees that no other Party or any other Person shall be required to obtain, furnish or post any bond or similar instrument in connection with or as a condition to obtaining any remedy referred to in this Section 11, and each Party irrevocably waives any right it may have to require the obtaining, furnishing or posting of any such bond or similar instrument.

12.Entire Agreement.

This Agreement (together with the Transaction Agreement, the Confidentiality Agreement and any other documents and instruments executed pursuant hereto) supersedes all prior agreements, written or oral, between the Parties hereto with respect to the subject matter hereof and contains the entire agreement between the Parties with respect to the subject matter hereof. This Agreement may not be

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amended or supplemented, and no provisions hereof may be modified or waived, except by an instrument in writing signed by both of the Parties hereto. No waiver of any provisions hereof by either Party shall be deemed a waiver of any other provisions hereof by such Party, nor shall any such waiver be deemed a continuing waiver of any provision hereof by such Party.

13.Extension; Waiver.

At any time prior to the Effective Time, the Parties may, to the extent legally allowed:

(a)extend the time for the performance of any of the obligations or acts of the other Party hereunder;

(b)waive any inaccuracies in the representations and warranties of the other Party contained herein or in any document delivered pursuant hereto; or

(c)waive compliance with any of the agreements or conditions of the other Party contained herein;

provided, that, in each case, such waiver is made in writing and signed by the Party (or parties) against whom the waiver is to be effective.

Notwithstanding the foregoing, no failure or delay by Isla in exercising any right hereunder shall operate as a waiver thereof nor shall any single or partial exercise thereof preclude any other or further exercise of any other right hereunder. No agreement on the part of a Party to any such extension or waiver shall be valid unless set forth in an instrument in writing signed on behalf of such Party. No waiver by any of the Parties hereto of any default, misrepresentation or breach of representation, warranty, covenant or other agreement hereunder, whether intentional or not, shall be deemed to extend to any prior or subsequent default, misrepresentation or breach or affect in any way any rights arising by virtue of any prior or subsequent such occurrence.

14.Notices.

All notices, requests, consents, claims, demands, waivers and other communications hereunder shall be in writing and shall be deemed to have been given: (a) if delivered in person; (b) if transmitted by facsimile (but only upon confirmation of transmission by the transmitting equipment); (c) if transmitted by electronic mail (“e-mail”) (but only if confirmation of receipt of such e-mail is requested and received; provided, that each notice party shall use reasonable best efforts to confirm receipt of any such email correspondence promptly upon receipt of such request); or (d) if transmitted by national overnight courier. Such communications must be sent to the respective Parties at the following addresses (or at such other address for a Party as shall be specified in a notice given in accordance with this Section 15):

If to Isla, to:

Independence Energy LLC

c/o Kohlberg Kravis Roberts & Co.

600 Travis Street

Suite 7200

Houston, TX 77002

Attention: David Rockecharlie; Brandi Kendall; Todd Falk     

E-mail:     David.Rockecharlie@kkr.com; Brandi.Kendall@kkr.com;

Todd.Falk@kkr.com    

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with a required copy to (which copy shall not constitute notice):

Vinson & Elkins L.L.P.

1001 Fannin St.

Suite 2500

Houston, TX 77002

Attention: Keith Fullenweider; Douglas McWilliams

E-mail: kfullenweider@velaw.com; dmcwilliams@velaw.com

If to Stockholders, to:

Goff Capital, Inc.

500 Commerce Street, Suite 700

Fort Worth, Texas 76102

Attention: Jennifer Terrell

E-mail: jterrell@goffcp.com

15.Miscellaneous.

(a)Governing Law. THIS AGREEMENT, AND ALL CLAIMS OR CAUSES OF ACTION (WHETHER IN CONTRACT OR TORT) THAT MAY BE BASED UPON, ARISE OUT OF RELATE TO THIS AGREEMENT, OR THE NEGOTIATION, EXECUTION OR PERFORMANCE OF THIS AGREEMENT, SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF DELAWARE, WITHOUT GIVING EFFECT TO THE PRINCIPLES OF CONFLICTS OF LAW THEREOF.

(b)Submission to Jurisdiction. THE PARTIES IRREVOCABLY SUBMIT TO THE JURISDICTION OF THE COURT OF CHANCERY OF THE STATE OF DELAWARE OR, IF THE COURT OF CHANCERY OF THE STATE OF DELAWARE OR THE DELAWARE SUPREME COURT DETERMINES THAT, NOTWITHSTANDING SECTION 111 OF THE DELAWARE GENERAL CORPORATIONS LAW, THE COURT OF CHANCERY DOES NOT HAVE OR SHOULD NOT EXERCISE SUBJECT MATTER JURISDICTION OVER SUCH MATTER, THE SUPERIOR COURT OF THE STATE OF DELAWARE AND THE FEDERAL COURTS OF THE UNITED STATES OF AMERICA LOCATED IN THE STATE OF DELAWARE SOLELY IN CONNECTION WITH ANY DISPUTE THAT ARISES IN RESPECT OF THE INTERPRETATION AND ENFORCEMENT OF THE PROVISIONS OF THIS AGREEMENT AND THE DOCUMENTS REFERRED TO IN THIS AGREEMENT OR IN RESPECT OF THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT, AND HEREBY WAIVE, AND AGREE NOT TO ASSERT, AS A DEFENSE IN ANY ACTION, SUIT OR PROCEEDING FOR INTERPRETATION OR ENFORCEMENT HEREOF OR ANY SUCH DOCUMENT THAT IT IS NOT SUBJECT THERETO OR THAT SUCH ACTION, SUIT OR PROCEEDING MAY NOT BE BROUGHT OR IS NOT MAINTAINABLE IN SAID COURTS OR THAT VENUE THEREOF MAY NOT BE APPROPRIATE OR THAT THIS AGREEMENT OR ANY SUCH DOCUMENT MAY NOT BE ENFORCED IN OR BY SUCH COURTS, AND THE PARTIES IRREVOCABLY AGREE THAT ALL CLAIMS WITH RESPECT TO SUCH ACTION, SUIT OR PROCEEDING SHALL BE HEARD AND DETERMINED EXCLUSIVELY BY SUCH A DELAWARE STATE OR FEDERAL COURT. THE PARTIES HEREBY CONSENT TO AND GRANT ANY SUCH COURT JURISDICTION OVER THE PERSON OF SUCH PARTIES AND OVER THE SUBJECT MATTER OF SUCH DISPUTE AND AGREE THAT MAILING OF PROCESS OR OTHER PAPERS IN CONNECTION WITH SUCH ACTION,

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SUIT OR PROCEEDING IN THE MANNER PROVIDED IN SECTION 13 OR IN SUCH OTHER MANNER AS MAY BE PERMITTED BY LAW SHALL BE VALID AND SUFFICIENT SERVICE THEREOF.

(c)Waiver of Jury Trial. EACH PARTY ACKNOWLEDGES AND AGREES THAT ANY CONTROVERSY WHICH MAY ARISE UNDER THIS AGREEMENT IS LIKELY TO INVOLVE COMPLICATED AND DIFFICULT ISSUES, AND THEREFORE EACH SUCH PARTY HEREBY IRREVOCABLY AND UNCONDITIONALLY WAIVES ANY RIGHT SUCH PARTY MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY LITIGATION DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT. EACH PARTY CERTIFIES AND ACKNOWLEDGES THAT (I) NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER; (II) SUCH PARTY UNDERSTANDS AND HAS CONSIDERED THE IMPLICATIONS OF THE FOREGOING WAIVER; (III) SUCH PARTY MAKES THE FOREGOING WAIVER VOLUNTARILY; AND (IV) SUCH PARTY HAS BEEN INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER THINGS, THE MUTUAL WAIVER AND CERTIFICATIONS IN THIS SECTION 13(C).

(d)Expenses. All costs and expenses incurred in connection with this Agreement shall be paid by the Party incurring such cost or expense, whether or not the Merger is consummated.

(e)Severability. If any term or provision of this Agreement is invalid, illegal, or unenforceable in any jurisdiction, such invalidity, illegality, or unenforceability shall not affect any other term or provision of this Agreement or invalidate or render unenforceable such term or provision in any other jurisdiction. Upon such determination that any term or other provision is invalid, illegal, or unenforceable, the Parties shall negotiate in good faith to modify this Agreement so as to effect the original intent of the Parties as closely as possible in a mutually acceptable manner in order that the transactions contemplated hereby be consummated as originally contemplated to the greatest extent possible.

(f)Counterparts. This Agreement may be executed in one or more counterparts, including via facsimile or email in “portable document format” (“.pdf”) form transmission, each of which shall be deemed to be an original but all of which together shall constitute one and the same agreement and shall become effective when two or more counterparts have been signed by each of the Parties and delivered to the other Parties, it being understood that all Parties need not sign the same counterpart.

(g)Interpretation. The Parties have participated jointly in negotiating and drafting this Agreement. In the event that an ambiguity or a question of intent or interpretation arises, this Agreement shall be construed as if drafted jointly by the Parties, and no presumption or burden of proof shall arise favoring or disfavoring any Party by virtue of the authorship of any provision of this Agreement. When a reference is made in this Agreement to Sections, such reference shall be to n Section of this Agreement unless otherwise indicated. The headings contained in this Agreement are for reference purposes only and shall not affect in any way the meaning or interpretation of this Agreement. Whenever the words “include,” “includes” or “including” are used in this Agreement, they shall be deemed to be followed by the words “without limitation.” References to “the date hereof” shall mean the date of this Agreement. As used in this Agreement, the “knowledge” of a Stockholder means the actual knowledge of any officer of Holder after due inquiry.

(h)Assignment. Neither this Agreement nor any of the rights, interests or obligations hereunder shall be assigned by any of the parties hereto (whether by operation of law or otherwise)

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without the prior written consent of the other Parties. Any purported assignment in contravention hereof shall be null and void. Subject to the preceding sentence and except as set forth in Section 5, this Agreement will be binding upon, inure to the benefit of and be enforceable by the Parties and their respective successors and permitted assigns.

(i)No Third-Party Beneficiaries; Non-Recourse. Nothing in this Agreement, express or implied, is intended to or shall confer upon any Person other than the Parties and their respective successors and permitted assigns any legal or equitable right, benefit, or remedy of any nature under or by reason of this Agreement.

(j)No Ownership Interest. Nothing contained in this Agreement shall be deemed to vest in Isla any direct or indirect ownership or incidence of ownership of or with respect to the Shares. All rights, ownership and economic benefits of and relating to the Shares shall remain vested in and belong to Stockholders, and Isla shall not have any authority to manage, direct, restrict, regulate, govern or administer any of the policies or operations of the Company or exercise any power or authority to direct any Stockholder in the voting or disposition of any Shares, except as otherwise expressly provided herein.

(k)No Partnership, Agency or Joint Venture. This Agreement is intended to create, and creates, a contractual relationship and is not intended to create, and does not create, any agency, partnership, joint venture, any like relationship between the Parties or a presumption that the Parties are in any way acting in concert or as a group with respect to the obligations or the transactions contemplated by this Agreement.

(l)Disclosure. Each Stockholder consents to and authorizes the publication and disclosure by the Company and Isla of such Stockholder’s identity and holding of Shares, and the terms of this Agreement (including, for avoidance of doubt, the disclosure of this Agreement), in any press release, the Registration Statement, including the Joint Proxy Statement, as applicable, and any other disclosure document required in connection with the Transaction Agreement, the Merger and the transactions contemplated by the Transaction Agreement.

(m)Amendment. This Agreement may not be amended, modified or supplemented in any manner, whether by course of conduct or otherwise, except by an instrument in writing specifically designated as an amendment hereto, signed on behalf of each of the Parties.

(n)Reliance. Each Stockholder understands and acknowledges that the Isla Parties are entering into the Transaction Agreement in reliance upon such Stockholder’s execution and delivery of this Agreement.

[Signature Page Follows]

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IN WITNESS WHEREOF, the Parties hereto have executed and delivered this Agreement as of the date first written above.

Independence Energy LLC

By:     Independence Energy MM LLC, its managing

    Member

By    /s/ David Rockecharlie

    Name: David Rockecharlie

    Title: Chief Executive Officer

Signature Page to Voting Agreement

John C. Goff

/s/ John C. Goff

Goff MCF Partners, LP

By     GFS Contango GP, LLC, its General Partner

/s/ John C. Goff

    John C. Goff, Chief Executive Officer

Goff Family Investments, LP

By     Goff Capital, Inc., General Partner

/s/ John C. Goff

    John C. Goff, Chief Executive Officer

The John C. Goff 2010 Family Trust

By

/s/ John C. Goff

    John C. Goff, Trustee

JCG 2016 Holdings, LP

By     JCG 2016 Management, LLC, its General Partner

/s/ John C. Goff

    John C. Goff, Manager

Signature Page to Voting Agreement

Kulik Partners, LP

By     Kulik GP, LLC, its General Partner

/s/ John C. Goff

    John C. Goff, Manager

Goff MCEP Holdings, LLC

By     Goff Capital, Inc., its Manager

/s/ John C. Goff

    John C. Goff, Chief Executive Officer

Goff MCEP II, LP

By     GFS MCEP GP, LLC, its General Partner

/s/ John C. Goff

    John C. Goff, Chief Executive Officer

Goff Focused Energy Strategies, LP

By     GFS Energy GP, LLC, its General Partner

/s/ John C. Goff

    John C. Goff, Chief Executive Officer

Goff Family Foundation

By

/s/ John C. Goff

    John C. Goff, Sole Director

Signature Page to Voting Agreement

Annex A

Stockholder	Original Shares Owned
Goff MCF Partners, LP	10,144,020
Goff Family Investments, LP	3,026,664
JCG 2016 Holdings, LP	8,632,710
Goff MCEP Holdings, LLC	3,038,705
Goff MCEP II, LP	4,768,317
Goff Focused Energy Strategies, LP	2,445,290
The John C. Goff 2010 Family Trust	12,067,617
Kulik Partners, LP	372,890
Goff Family Foundation	261,957
John C. Goff SEP IRA	3,571,786
John C. Goff	48,406,233

EX-10.5

CRESCENT ENERGY COMPANY

2021 MANAGER INCENTIVE PLAN

ARTICLE I

DEFINITIONS

As used herein, the following terms shall have the meanings set forth below:

1.01.Affiliate

    “Affiliate” means, with respect to any entity, any other entity, whether now or hereafter existing, which controls, is controlled by, or is under common control with, the first entity (including, but not limited to, joint ventures, limited liability companies and partnerships). For this purpose, the term “control” (including the correlative meanings of the terms “controlled by” and “under common control with”) shall mean ownership, directly or indirectly, of fifty percent (50%) or more of the total combined voting power of all classes of voting securities issued by such entity, or the possession, directly or indirectly, of the power to direct the management and policies of such entity, by contract or otherwise. Notwithstanding the foregoing, (a) the Manager shall be deemed an Affiliate of the Company for purposes of the Plan for so long as the Manager serves as the external manager of the Company and (b) the Operating Company shall be deemed an Affiliate of the Company for purposes of the Plan for so long as the Company or a wholly-owned subsidiary of the Company serves as the sole managing member of the Operating Company.

1.02.Agreement

“Agreement” means a written agreement (including any amendment or supplement thereto) between the Company and a Participant specifying the terms and conditions of an Award.

1.03.Award

“Award” means any Option, SAR, Stock Award, award of Restricted Stock Units, Other Equity-Based Award, Incentive Award, Cash Award, Performance Award or Substitute Award, together with any other right or interest, granted to a Participant pursuant to the Plan.

1.04.Board

“Board” means the Board of Directors of the Company.

1.05.Cash Award

“Cash Award” means an Award denominated in cash and granted under Article XII.

1.06.Change in Control

    “Change in Control” means and includes each of the following:

(a)     The acquisition, either directly or indirectly, by any individual, entity or group (within the meaning of Sections 13(d) and 14(d)(2) of the Exchange Act) of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act), of more than fifty percent (50%) of either (i) the then outstanding Common Stock of the Company, taking into account as outstanding for this purpose such Common Stock issuable upon the exercise of

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options or warrants, the conversion of convertible shares or debt, and the exercise of any similar right to acquire such Common Stock (the “Outstanding Company Common Stock”) or (ii) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of trustees or directors (the “Outstanding Company Voting Securities”); provided, however, that the following acquisitions shall not constitute a Change in Control: (A) any acquisition by the Company, the Manager or any of their respective Affiliates, (B) any acquisition by a trustee or other fiduciary holding the Company’s securities under an employee benefit plan sponsored or maintained by the Company or any of its Affiliates, (C) any acquisition by an underwriter, initial purchaser or placement agent temporarily holding the Company’s securities pursuant to an offering of such securities or (D) any acquisition by an entity owned, directly or indirectly, by the stockholders of the Company in substantially the same proportions as their ownership of the then Outstanding Company Common Stock.

(b)     Individuals who constitute Incumbent Directors at the beginning of any two (2)-consecutive-year period, together with any new Incumbent Directors who become members of the Board during such two (2)-year period, cease to be a majority of the Board at the end of such two (2)-year period.

(c)    The consummation of a reorganization, merger, consolidation, statutory share exchange or similar form of corporate transaction involving the Company that requires the approval of the Company’s stockholders, whether for such transaction or the issuance of securities in the transaction (a “Business Combination”), in each case, unless following such Business Combination:

(i)     the individuals and entities who were the beneficial owners of the Outstanding Company Voting Securities immediately prior to such Business Combination, beneficially own, directly or indirectly, more than fifty percent (50%) of the combined voting power of the then outstanding voting securities entitled to vote generally in the election of members of the board of directors (or the analogous governing body) of the entity resulting from such Business Combination (the “Successor Entity”) (or, if applicable, the ultimate parent entity that directly or indirectly has beneficial ownership of sufficient voting securities to elect a majority of the members of the board of directors (or the analogous governing body) of the Successor Entity (the “Parent Company”));

(ii)    no Person beneficially owns (within the meaning of Rule 13d-3 promulgated under the Exchange Act), directly or indirectly, more than fifty percent (50%) of the combined voting power of the then outstanding voting securities entitled to vote generally in the election of members of the board of directors (or the analogous governing body) of the Parent Company (or, if there is no Parent Company, the Successor Entity); and

(iii)    at least a majority of the members of the board of directors (or the analogous governing body) of the Parent Company (or, if there is no Parent Company, the Successor Entity) following the consummation of the Business Combination were Incumbent Directors at the time of the Board’s approval of the execution of the initial agreement providing for such Business Combination.

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    (d)    The direct or indirect sale, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the properties or assets of the Company and its subsidiaries, taken as a whole, to any Person that is not a subsidiary of the Company, the Manager or any of their respective Affiliates.

    In addition, if a Change in Control (as defined in clauses (a) through (d) above) constitutes a payment event with respect to any Award that provides for the deferral of compensation and is subject to Section 409A, no payment will be made under that Award on account of a Change in Control unless the event described in clause (a), (b), (c) or (d) above, as applicable, constitutes a “change in control event” as defined in Section 409A.

1.07.Code

“Code” means the Internal Revenue Code of 1986, as amended.

1.08.Committee

“Committee” means the Board or a committee of two or more members of the Board designated by the Board to administer the Plan. Unless otherwise determined by the Board, the Committee shall consist solely of two or more non-employee members of the Board, each of whom is intended to qualify as a “non-employee director” as defined by Rule 16b-3 promulgated under the Exchange Act or any successor rule and an “independent director” under the rules of any exchange or automated quotation system on which the Common Stock is listed, traded or quoted;provided, however, that any action taken by the Committee shall be valid and effective, whether or not the members of the Committee at the time of such action are later determined not to have satisfied the foregoing requirements or other requirements provided in any charter of the Committee.

1.09.Common Stock

“Common Stock” means the Class A common stock, $0.0001 par value per share, of the Company.

1.10.Company

“Company” means Crescent Energy Company, a Delaware corporation.

1.11.Control Change Date

“Control Change Date” means the date on which a Change in Control occurs. If a Change in Control occurs on account of a series of transactions, the “Control Change Date” is the date determined by the Committee as the date upon which the last of such transactions occurs.

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1.12.Corresponding SAR

“Corresponding SAR” means a SAR that is granted in relation to a particular Option and that can be exercised only upon the surrender to the Company, unexercised, of that portion of the Option to which the SAR relates.

1.13.Dividend Equivalent Right

“Dividend Equivalent Right” means the right, subject to the terms and conditions prescribed by the Committee, of a Participant to receive (or have credited) cash, securities or other property in amounts equivalent to the cash, securities or other property dividends declared on Common Stock with respect to a specified Restricted Stock Unit, Other Equity-Based Award, Incentive Award or Performance Award denominated in Common Stock or other Company securities, as determined by the Committee in its sole discretion. Dividend Equivalent Rights payable on a Restricted Stock Unit award, an Other Equity-Based Award, an Incentive Award or a Performance Award that does not become non-forfeitable solely on the basis of continued service shall be accumulated and distributed, without interest, only when, and to the extent that, the underlying Award is vested and earned. The Committee may provide that Dividend Equivalent Rights (if any) shall be automatically reinvested in additional shares of Common Stock or otherwise reinvested, applied to the purchase of additional Awards under the Plan or deferred without interest to the date of vesting of the associated Award.

1.14.Effective Date

“Effective Date” means December 6, 2021.

1.15.Exchange Act

“Exchange Act” means the Securities Exchange Act of 1934, as amended.

1.16.Fair Market Value

“Fair Market Value” means, on any given date, the reported “closing” price of a share of Common Stock on the stock exchange on which the Common Stock is listed for trading for such date (or, if there is no closing price for a share of Common Stock on the date in question, the closing price for a share of Common Stock on the last preceding date for which such quotation exists) or, if the Common Stock is not listed on any exchange, the amount determined by the Committee using any reasonable method in good faith and in accordance with Section 409A.

1.17.Incentive Award

“Incentive Award” means an award granted under Article XI which, subject to the terms and conditions prescribed by the Committee, entitles the Participant to receive a payment from the Company or an Affiliate of the Company.

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1.18.Incumbent Director

“Incumbent Director” means (a) each individual serving on the Board as of the Effective Date during the period of such individual’s continuous service on the Board from and after the Effective Date or during any period such individual qualifies as an Incumbent Director pursuant to clause (b) of this Section 1.18 and (b) those individuals elected to the Board (either by a specific vote or by approval of the proxy statement of the Company in which such person is named as a nominee for director without objection to such nomination) and whose election or nomination for election to the Board was approved by a vote of at least two-thirds (2/3) of the directors serving on the Board at the time of the election or nomination, as applicable. No individual designated to serve as a director by a Person who shall have entered into an agreement with the Company to effect a transaction described in Section 1.06 and no individual initially elected or nominated as a director of the Company as a result of an actual or threatened election contest with respect to directors shall be an Incumbent Director.

1.19.Initial Value

“Initial Value” means, with respect to a Corresponding SAR, the Option price per share of the related Option and, with respect to a SAR granted independently of an Option, the price per share of Common Stock as determined by the Committee on the date of grant; provided, however, that the price shall not be less than the Fair Market Value on the date of grant. Except as provided in ArticlesXV and XVIII, without the approval of stockholders (a) the Initial Value of an outstanding SAR may not be reduced (by amendment, cancellation and new grant or otherwise) and (b) no payment shall be made in cancellation of a SAR if, on the date of amendment, cancellation, new grant or payment, the Initial Value exceeds Fair Market Value.

1.20.Manager

“Manager” means KKR Energy Asset Manager LLC, a Delaware limited liability company, the Company’s external manager, or any entity that subsequently becomes the Company’s external manager.

1.21.Operating Company

“Operating Company” means IE OpCo LLC, a Delaware limited liability company, which is the Company’s operating company as of the Effective Date, or any entity that becomes the Company’s operating company.

1.22.Option

“Option” means a stock option that entitles the holder to purchase from the Company a stated number of shares of Common Stock at the price set forth in an Agreement.

1.23.Other Equity-Based Award

“Other Equity-Based Award” means any Award other than an Incentive Award, Option, SAR, Stock Award, award of Restricted Stock Units or Performance Award, which, subject to such terms and conditions as may be prescribed by the Committee, entitles a Participant to

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receive Common Stock or rights or units valued in whole or in part by reference to, or otherwise based on, Common Stock (including securities convertible into Common Stock) or other equity interests.

1.24.Participant

“Participant” means the Manager or an Affiliate of the Manager who is selected by the Committee to receive one or more Awards.

1.25.Performance Award

“Performance Award” means an Award granted to a Participant under Article XIII that is based upon one or more performance goals or objectives specified by the Committee. The Committee may adjust any of such performance goals or objectives as it deems equitable.

1.26.Person

“Person” means any firm, corporation, partnership, or other entity. “Person” also includes any individual, firm, corporation, partnership, or other entity as defined in Sections 13(d)(3) and 14(d)(2) of the Exchange Act. Notwithstanding the preceding sentences, the term “Person” does not include (a) the Company or any of its subsidiaries, (b) any director or other fiduciary holding securities under an employee benefit plan of the Company or any of its Affiliates, (c) any underwriter temporarily holding securities pursuant to an offering of such securities or (d) any corporation owned, directly or indirectly, by the stockholders of the Company in substantially the same proportions as their ownership of the Common Stock.

1.27.Plan

“Plan” means this Crescent Energy Company 2021 Manager Incentive Plan, as amended from time to time.

1.28.Restricted Stock

“Restricted Stock” means a share of Common Stock granted to a Participant that is subject to certain restrictions and a risk of forfeiture.

1.29.Restricted Stock Unit

“Restricted Stock Unit” means a right granted to a Participant under Article IX entitling the Participant to receive a payment (in cash, shares of Common Stock or a combination thereof) on a specified settlement date equal to the value of a share of Common Stock.

1.30.SAR

“SAR” means a stock appreciation right that, in accordance with the terms of an Agreement, entitles the holder to receive, with respect to each share of Common Stock encompassed by the exercise of the SAR, the excess, if any, of the Fair Market Value at the time of exercise over the Initial Value. References to “SARs” include both Corresponding SARs and SARs granted independently of Options, unless the context requires otherwise.

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1.31.Section 409A

“Section 409A” means Section 409A of the Code, as amended from time to time, including the guidance and regulations promulgated thereunder and successor provisions, guidance and regulations thereto.

1.32.Stock Award

“Stock Award” means Restricted Stock or unrestricted Common Stock awarded to a Participant under Article VIII.

1.33.Substitute Award

“Substitute Award” means an Award granted in substitution for a similar award as a result of certain business transactions.

ARTICLE II

PURPOSES

The Plan is intended to assist the Company and its Affiliates in recruiting and retaining key personnel and to provide a means whereby the Manager and the Affiliates of the Manager can acquire and maintain equity interests in the Company or the Operating Company. The Plan is intended to permit the grant of Options that do not qualify as “incentive stock options” under Section 422 of the Code, and the grant of SARs, Stock Awards, awards of Restricted Stock Units, Other Equity-Based Awards, Incentive Awards, Cash Awards, Performance Awards and Substitute Awards in accordance with the Plan and any procedures that may be established by the Committee.

ARTICLE III
ADMINISTRATION

The Plan shall be administered by the Committee. The Committee shall have authority to grant Awards upon such terms (not inconsistent with the provisions of the Plan), as the Committee may consider appropriate. Such terms may include conditions (in addition to those contained in the Plan), on the transferability, forfeitability and exercisability of all or any part of an Award. The Committee may, in its discretion, make any amendments, modifications or adjustments to outstanding Awards and the terms thereof. In addition, the Committee shall have complete authority to interpret all provisions of the Plan; to prescribe the form of Agreements; to adopt, amend, and rescind rules and regulations pertaining to the administration of the Plan (including rules and regulations that require or allow Participants to defer the payment of benefits under the Plan); and to make all other determinations necessary or advisable for the administration of the Plan.

The Committee’s determinations under the Plan (including without limitation, determinations of the eligible Persons to receive Awards, the form, amount and timing of Awards, and the terms and provisions of Awards and the Agreements) need not be uniform and may be made by the Committee selectively among eligible Persons who receive, or are eligible to receive, Awards, whether or not such Persons are similarly situated. The express grant in the

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Plan of any specific power to the Committee with respect to the administration or interpretation of the Plan shall not be construed as limiting any power or authority of the Committee with respect to the administration or interpretation of the Plan. Any decision made, or action taken, by the Committee in connection with the administration of the Plan shall be final and conclusive. The members of the Committee shall not be liable for any act done in good faith with respect to the Plan or any Agreement or Award. All expenses of administering the Plan shall be borne by the Company.

ARTICLE IV
ELIGIBILITY

The Manager and each Affiliate of the Manager (including a trade or business that becomes an Affiliate of the Manager after the adoption of the Plan) is eligible to participate in the Plan.

ARTICLE V
COMMON STOCK SUBJECT TO PLAN

5.01.Common Stock Issued

Upon the grant, exercise or settlement of an Award, the Company may deliver to the Participant Common Stock from its authorized but unissued Common Stock, shares held in the treasury of the Company, shares purchased on the open market or by private purchase or a combination of the foregoing.

5.02.Aggregate Limit

Subject to adjustment as provided under Article XV, the maximum aggregate number of shares of Common Stock that may be delivered with respect to Awards under the Plan is equal to a number of shares of Common Stock equal to 4,306,745 (the “Aggregate Limit”); provided, however, that the Aggregate Limit shall be increased on January 1 of each calendar year that occurs before the tenth (10th) anniversary of the Effective Date by 10% of the additional Common Stock issued, if any, during the immediately preceding calendar year.

5.03.Reallocation of Shares

If any Award expires, is forfeited or is terminated without having been exercised or is paid in cash without a requirement for the delivery of shares of Common Stock, then any shares covered by such lapsed, cancelled, expired, unexercised or cash-settled portion of such Award (including (a) shares of Common Stock forfeited with respect to Restricted Stock and (b) shares of Common Stock withheld or surrendered to the Company in payment of any exercise or purchase price of an Award or taxes relating to Awards) shall be available for the grant of other Awards under the Plan. If shares of Common Stock are issued in settlement of a SAR granted under the Plan, the number of shares of Common Stock available under the Plan shall be reduced by the number of shares of Common Stock for which the SAR was exercised rather than the number of shares of Common Stock issued in settlement of the SAR. To the extent permitted by applicable law or the rules of any exchange on which the Common Stock is listed for trading, Common Stock issued in assumption of, or in substitution for, any outstanding awards of any entity acquired in any form of combination by the Company or any Affiliate of the Company shall not reduce the number of shares of Common Stock available for issuance under the Plan.

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ARTICLE VI
OPTIONS

6.01.Award

In accordance with the provisions of Articles III and IV, the Committee will designate each eligible Person to whom an Option is to be granted and will specify the number of shares of Common Stock covered by such Awards and the terms and conditions of such Awards.

6.02.Option Price

The price per share of Common Stock purchased on the exercise of an Option shall be determined by the Committee on the date of grant, but shall not be less than the Fair Market Value on the date the Option is granted. Except as provided in Articles XV and XVIII, the price per share of Common Stock of an outstanding Option may not be reduced (by amendment, cancellation and new grant or otherwise) without the approval of stockholders. In addition, no payment shall be made in cancellation of an Option without the approval of stockholders if, on the date of cancellation, the Option price exceeds Fair Market Value.

6.03.Maximum Option Period

The maximum period in which an Option may be exercised shall be determined by the Committee on the date of grant, except that no Option shall be exercisable after the expiration of ten (10) years from the date such Option was granted. The terms of any Option may provide that it is exercisable for a period less than such maximum period.

6.04.Option Status

Each Option granted under the Plan shall constitute an option that is not an “incentive stock option” under Section 422 of the Code.

6.05.Exercise

Subject to the provisions of the Plan and the applicable Agreement, an Option may be exercised in whole at any time or in part from time to time at such times and in compliance with such requirements as the Committee shall determine. An Option granted under the Plan may be exercised with respect to any number of whole shares of Common Stock less than the full number for which the Option could be exercised. A partial exercise of an Option shall not affect the right to exercise the Option from time to time in accordance with the Plan and the applicable Agreement with respect to the remaining shares of Common Stock subject to the Option. The exercise of an Option shall result in the termination of any Corresponding SAR to the extent of the number of shares of Common Stock with respect to which the Option is exercised.

6.06.Payment

Subject to rules established by the Committee and unless otherwise provided in an Agreement, payment of all or part of the Option price may be made in cash, certified check, by tendering Common Stock, by attestation of ownership of Common Stock, by a broker-assisted

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cashless exercise or in such other form or manner acceptable to the Committee. If Common Stock is used to pay all or part of the Option price, the sum of the cash and cash equivalent and the Fair Market Value (determined on the date of exercise) of the Common Stock so surrendered or other consideration paid must not be less than the Option price of the shares for which the Option is being exercised.

6.07.Stockholder Rights

No Participant shall have any rights as a stockholder with respect to shares of Common Stock subject to an Option until the date of exercise of such Option.

ARTICLE VII
SARS

7.01.Award

In accordance with the provisions of Articles III and IV, the Committee will designate each eligible Person to whom SARs are to be granted and will specify the number of shares of Common Stock covered by such Awards and the terms and conditions of such Awards.

7.02.SAR Price

The price per share of Common Stock purchased on the exercise of an SAR shall be determined by the Committee on the date of grant, but shall not be less than the Fair Market Value on the date the SAR is granted. Except as provided in Articles XV and XVIII, the price per share of Common Stock of an outstanding Option may not be reduced (by amendment, cancellation and new grant or otherwise) without the approval of stockholders. In addition, no payment shall be made in cancellation of an SAR without the approval of stockholders if, on the date of cancellation, the SAR price exceeds Fair Market Value.

7.03.Maximum SAR Period

The term of each SAR shall be determined by the Committee on the date of grant, except that no SAR shall have a term of more than ten (10) years from the date of grant. The terms of any SAR may provide that it has a term that is less than such maximum period.

7.04.Exercise

Subject to the provisions of the Plan and the applicable Agreement, a SAR may be exercised in whole at any time or in part from time to time at such times and in compliance with such requirements as the Committee shall determine. A SAR granted under the Plan may be exercised with respect to any number of whole shares less than the full number for which the SAR could be exercised. A partial exercise of a SAR shall not affect the right to exercise the SAR from time to time in accordance with the Plan and the applicable Agreement with respect to the remaining shares of Common Stock subject to the SAR. The exercise of a Corresponding SAR shall result in the termination of the related Option to the extent of the number of shares of Common Stock with respect to which the SAR is exercised.

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7.05.Settlement

At the Committee’s discretion, the amount payable as a result of the exercise of a SAR may be settled in cash, Common Stock, or a combination of cash and Common Stock.

7.06.Stockholder Rights

No Participant shall have any rights as a stockholder with respect to shares of Common Stock subject to a SAR until the date that the SAR is exercised and then only to the extent that the SAR is settled by the issuance of Common Stock.

ARTICLE VIII
STOCK AWARDS

8.01.Award

In accordance with the provisions of Articles III and IV, the Committee will designate each eligible Person to whom a Stock Award (either in the form of Restricted Stock or unrestricted Common Stock) is to be made and will specify the number of shares of Restricted Stock or Common Stock covered by such Stock Award and the terms and conditions of such Stock Award.

8.02.Vesting

The Committee, on the date of the Stock Award, may prescribe that a Participant’s rights in a Stock Award shall be forfeitable or otherwise restricted for a period of time or subject to such conditions as may be set forth in the Agreement. By way of example and not of limitation, the Committee may prescribe that a Participant’s rights in a Stock Award shall be forfeitable or otherwise restricted subject to continued service, the attainment of performance objectives, including objectives stated with reference to one or more performance goals or objectives, or both.

8.03.Stockholder Rights

Unless otherwise specified in accordance with the applicable Agreement, while the shares of Restricted Stock granted pursuant to the Stock Award may be forfeited or are non-transferable, a Participant will have all rights of a stockholder with respect to a Stock Award, including the right to receive dividends (in respect of which the Committee may allow a Participant to elect, or may require, that any cash dividends paid on a share of Restricted Stock be automatically reinvested in additional shares of Restricted Stock, applied to the purchase of additional Awards under the Plan or deferred without interest to the date of vesting of the associated Award of Restricted Stock, provided that any such election is intended to comply with Section 409A) and vote the shares of Common Stock; provided, however, that, unless otherwise specified in accordance with the applicable Agreement, dividends payable on shares of Restricted Stock subject to a Stock Award that does not become non-forfeitable solely on the basis of continued service shall be accumulated and paid, without interest, when and to the extent that the underlying Stock Award becomes non-forfeitable; and provided further, that during the period that the Stock Award may be forfeited or is non-transferable (a) a Participant may not sell, transfer, pledge, exchange, hypothecate, or otherwise dispose of shares of Restricted Stock granted pursuant to a Stock Award, (b) the Committee may postpone the distribution of dividends until and to the extent that the Stock Award becomes transferable and non-forfeitable,

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(c) the Company shall retain custody of any certificates representing shares of Restricted Stock granted pursuant to a Stock Award, and (d) the Participant will deliver to the Company a stock power, endorsed in blank, with respect to each Stock Award. The limitations set forth in the preceding sentence shall not apply after the shares of Restricted Stock granted under the Stock Award are transferable and are no longer forfeitable.

ARTICLE IX
RESTRICTED STOCK UNITS

9.01.Award

In accordance with the provisions of Articles III and IV, the Committee will designate each eligible Person to whom an award of Restricted Stock Units is to be made and specify the number of Restricted Stock Units covered by such Awards and the terms and conditions of such Awards. The Committee also will specify whether Dividend Equivalent Rights are granted in conjunction with the award of Restricted Stock Units.

9.02.Terms and Conditions

The Committee, at the time an award of Restricted Stock Units is made, shall specify the terms and conditions which govern the Award. The terms and conditions of an award of Restricted Stock Units may prescribe that a Participant’s rights in the Restricted Stock Units shall be forfeitable, non-transferable or otherwise restricted for a period of time, which may lapse at the expiration of the deferral period or at earlier specified times, or may be subject to such other conditions as may be determined by the Committee, in its discretion and set forth in the Agreement. By way of example and not of limitation, the Committee may prescribe that a Participant’s rights in an award of Restricted Stock Units shall be forfeitable or otherwise restricted subject to continued service, the attainment of performance objectives, including objectives stated with respect to one or more performance goals or objectives, or both. An award of Restricted Stock Units may be granted to Participants, either alone or in addition to other Awards granted under the Plan, and an award of Restricted Stock Units may be granted in the settlement of other Awards granted under the Plan.

9.03.Payment or Settlement

Settlement of an award of Restricted Stock Units shall occur upon expiration of the deferral period specified for each Restricted Stock Unit by the Committee (or, if permitted by the Committee, as elected by the Participant). Restricted Stock Units shall be satisfied by the delivery of (a) a number of shares of Common Stock equal to the number of Restricted Stock Units vesting on such date or (b) an amount in cash equal to the Fair Market Value of a specified number of shares of Common Stock covered by the vesting Restricted Stock Units, or (c) a combination thereof, as determined by the Committee at the date of grant or thereafter.

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9.04.Stockholder Rights

A Participant, as a result of receiving an award of Restricted Stock Units, shall not have any rights as a stockholder until, and then only to the extent that, the award of Restricted Stock Units is earned and settled in shares of Common Stock (to the extent applicable).

ARTICLE X
OTHER EQUITY–BASED AWARDS

10.01.Award

In accordance with the provisions of Articles III and IV, the Committee will designate each eligible Person to whom an Other Equity-Based Award is to be made and will specify the number of shares of Common Stock or other equity interests covered by such Awards and the terms and conditions of such Awards. The Committee also will specify whether Dividend Equivalent Rights are granted in conjunction with the Other Equity-Based Award.

10.02.Terms and Conditions

The Committee, at the time an Other Equity-Based Award is made, shall specify the terms and conditions which govern the Award. The terms and conditions of an Other Equity-Based Award may prescribe that a Participant’s rights in the Other Equity-Based Award shall be forfeitable, non-transferable or otherwise restricted for a period of time or subject to such other conditions as may be determined by the Committee, in its discretion and set forth in the Agreement. By way of example and not of limitation, the Committee may prescribe that a Participant’s rights in an Other Equity-Based Award shall be forfeitable or otherwise restricted subject to continued service, the attainment of performance objectives, including objectives stated with respect to one or more performance goals or objectives, or both. Other Equity-Based Awards may be granted to Participants, either alone or in addition to other Awards granted under the Plan, and Other Equity-Based Awards may be granted in the settlement of other Awards granted under the Plan.

10.03.Payment or Settlement

Other Equity-Based Awards valued in whole or in part by reference to, or otherwise based on, Common Stock, shall be payable or settled in shares of Common Stock, cash or a combination of shares of Common Stock and cash, as determined by the Committee in its discretion. Other Equity-Based Awards denominated as equity interests other than Common Stock may be paid or settled in shares or units of such equity interests or cash or a combination of both as determined by the Committee in its discretion.

10.04.Stockholder Rights

A Participant, as a result of receiving an Other Equity-Based Award, shall not have any rights as a stockholder until, and then only to the extent that, the Other Equity-Based Award is earned and settled in shares of Common Stock.

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ARTICLE XI
INCENTIVE AWARDS

11.01.Award

In accordance with the provisions of Articles III and IV, the Committee will designate each eligible Person to whom an Incentive Award is to be made and will specify the terms and conditions of such Award. The Committee also will specify whether Dividend Equivalent Rights are granted in conjunction with the Incentive Award.

11.02.Terms and Conditions

The Committee, at the time an Incentive Award is made, shall specify the terms and conditions that govern the Award.

11.03.Settlement

An Incentive Award that is earned shall be settled with a single lump sum payment which may be in cash, Common Stock or a combination of cash and Common Stock, as determined by the Committee.

11.04.Stockholder Rights

No Participant shall, as a result of receiving an Incentive Award, have any rights as a stockholder until the date that the Incentive Award is settled and then only to the extent that the Incentive Award is settled by the issuance of shares of Common Stock.

ARTICLE XII

CASH AWARDS

The Committee is authorized to grant Cash Awards, on a free-standing basis or as an element of, a supplement to, or in lieu of any other Award under the Plan to Participant in such amounts and subject to such other terms as the Committee in its discretion determines to be appropriate.

ARTICLE XIII
PERFORMANCE AWARDS

13.01.Award

In accordance with the provisions of Articles III and IV, the Committee will designate each eligible Person to whom a Performance Award is to be made and will specify the number of shares of Common Stock or other securities or property covered by such Award and the terms and conditions of such Award. The Committee also will specify whether Dividend Equivalent Rights are granted in conjunction with the Performance Award.

13.02.Performance Goals Generally

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The Committee, on the date of the grant of a Performance Award, shall prescribe that the Performance Award will be earned, and the Participant will be entitled to receive payment pursuant to the Performance Award, based on the satisfaction of one or more performance conditions or goals and a targeted level or levels of performance with respect to each of such conditions or goals, subject to, if applicable, continued service. The Committee may establish any such performance conditions or goals based on individual criteria or one or more business criteria for the Company, on a consolidated basis, and/or for specified Affiliates of the Company or business or geographical units of the Company, or other measures of performance, as determined to be appropriate by the Committee in its discretion, which performance conditions or goals may be determined on an absolute or relative basis or as compared to the performance of a published or special index deemed applicable by the Committee, in its discretion. Performance conditions or goals may differ for Performance Awards granted to any one Participant or to different Participants. The performance period applicable to any Performance Award shall be set by the Committee in its discretion but shall not exceed ten (10) years.

13.03.Settlement

At or following the end of the applicable performance period for a Performance Award, the Committee shall determine the amount, if any, of such Performance Award that will become vested, exercisable and/or settled. Settlement of such Performance Award shall be in shares of Common Stock or other securities or property or a combination of the foregoing, in the discretion of the Committee. The Committee may, in its discretion, reduce or increase the amount of vesting, exercisability and/or settlement otherwise to be made in connection with such Performance Award.

13.04.Stockholder Rights

No Participant shall, as a result of receiving an Performance Award, have any rights as a stockholder until the date that the Performance Award is settled and then only to the extent that the Performance Award is settled by the issuance of shares of Common Stock.

ARTICLE XIV
SUBSTITUTE AWARDS

Awards may be granted in substitution or exchange for any other Award granted under the Plan or under another plan of the Company or any other right of a Participant to receive payment from the Company. Except as provided in ArticleXV or XVIII hereof, the terms of outstanding Awards may not be amended to reduce the exercise price or grant price of outstanding Options or SARs or to cancel outstanding Options and SARs in exchange for cash, other Awards or Options or SARs with an exercise price or grant price that is less than the exercise price or grant price of the original Options or SARs without the approval of the stockholders of the Company.

ARTICLE XV
ADJUSTMENT UPON CHANGE IN COMMON STOCK

The Aggregate Limit and the terms of outstanding Awards granted under the Plan shall be adjusted as the Board determines is equitably required in the event that (a) the Company (i) effects one or more nonreciprocal transactions between the Company and its stockholders such as a stock dividend, extra-ordinary cash dividend, stock split, subdivision or consolidation of

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Common Stock that affects the number or kind of shares of Common Stock (or other securities of the Company) or the Fair Market Value (or the value of other Company securities) and causes a change in the Fair Market Value of the shares of Common Stock subject to outstanding Awards or (ii) engages in a transaction to which Section 424 of the Code applies or (b) there occurs any other event which, in the judgment of the Board necessitates such action. Any determination made under this Article XV by the Board shall be nondiscretionary, final and conclusive.

The issuance by the Company of any class of Common Stock, or securities convertible into any class of Common Stock, for cash or property, or for labor or services, either upon direct sale or upon the exercise of rights or warrants to subscribe therefor, or upon conversion of Common Stock or obligations of the Company convertible into such Common Stock or other securities, shall not affect, and no adjustment by reason thereof shall be made with respect to, the Aggregate Limit or the terms of outstanding Awards under the Plan.

ARTICLE XVI
COMPLIANCE WITH LAW AND APPROVAL OF REGULATORY BODIES

No Option or SAR shall be exercisable, no shares of Common Stock shall be issued, no certificates for shares of Common Stock shall be delivered, and no payment shall be made under the Plan except in compliance with all applicable federal, state and foreign laws and regulations (including, without limitation, withholding tax requirements), any listing agreement to which the Company is a party, and the rules of all stock exchanges on which the Common Stock may be listed. The Company shall have the right to rely on an opinion of its counsel as to such compliance. Any certificate issued to represent shares of Common Stock when an Award is granted, settled or exercised may bear such legends and statements as the Committee may deem advisable to assure compliance with federal, state and foreign laws and regulations. No Award shall be granted, settled or exercised until the Company has obtained such consent or approval as the Committee may deem advisable from regulatory bodies having jurisdiction over such matters.

ARTICLE XVII
GENERAL PROVISIONS

17.01.General

Awards granted under the Plan may, in the discretion of the Committee, be granted either alone, in addition to, or in tandem with any other Award. In addition, the Committee may impose on any Award or the exercise thereof, at the date of grant or thereafter (subject to Article XIX), such additional terms and conditions, not inconsistent with the provisions of the Plan, as the Committee shall determine. Without limiting the scope of the preceding sentence, the Committee may use such business criteria and other measures of performance as it may deem appropriate in establishing any performance goals applicable to an Award, and any such performance goals may differ among Awards granted to any one Participant or to different Participants.  Except as otherwise provided in an Agreement, the Committee may exercise its discretion to reduce or increase the amounts payable under any Award.

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17.02.Effect on Service

Neither the adoption of the Plan, its operation, the grant of any Award, nor any documents describing or referring to the Plan (or any part thereof), shall confer upon any Person any right to continue in the service of the Company or an Affiliate of the Company or in any way affect any right and power of the Company or an Affiliate of the Company to terminate the service of any Person at any time with or without assigning a reason therefor.

17.03.Unfunded Plan

The Plan, insofar as it provides for grants, shall be unfunded, and the Company shall not be required to segregate any assets that may at any time be represented by grants under the Plan. Any liability of the Company to any person with respect to any grant under the Plan shall be based solely upon any contractual obligations that may be created pursuant to the Plan. No such obligation of the Company shall be deemed to be secured by any pledge of, or other encumbrance on, any property of the Company.

17.04.Rules of Construction

Headings are given to the articles and sections of the Plan solely as a convenience to facilitate reference. The reference to any statute, regulation, or other provision of law shall be construed to refer to any amendment to or successor of such provision of law.

All Awards are intended to comply with, or otherwise be exempt from, Section 409A. The Plan and all Agreements shall be administered, interpreted and construed in a manner consistent with that intent. Nevertheless, the tax treatment of the benefits provided under the Plan or any Agreement is not warranted or guaranteed. Neither the Company, its Affiliates nor their respective directors or trustees, officers, employees or advisors (other than in its individual capacity as a Participant with respect to its individual liability for taxes, interest, penalties or other monetary amounts) shall be held liable for any taxes, interest, penalties or other monetary amounts owed by any Participant or any other taxpayer as a result of the Plan or any Agreement. If any provision of the Plan or any Agreement is found not to comply with, or otherwise not be exempt from, the provisions of Section 409A, it may be modified and given effect, in the sole discretion of the Committee and without requiring the Participant’s consent, in such manner as the Committee determines to be necessary or appropriate to comply with, or effectuate an exemption from, Section 409A. Each payment under an Award granted under the Plan shall be treated as a separate identified payment for purposes of Section 409A.

If a payment obligation under an Award or an Agreement arises on account of the Participant’s termination of service and such payment obligation constitutes “deferred compensation” (as defined under Section 409A), it shall be payable only after the Participant’s “separation from service” (as defined under Section 409A); provided, however, that if the Participant is a “specified employee” (as defined under Section 409A) then, subject to any permissible acceleration of payment by the Committee under Section 409A, any such payment that is scheduled to be paid within six (6) months after such separation from service shall accrue without interest and shall be paid on the first (1st) day of the seventh (7th) month beginning after the date of the Participant’s separation from service or, if earlier, within fifteen (15) days after

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the appointment of the personal representative or executor of the Participant’s estate following the Participant’s death.

17.05.Withholding Taxes

Each Participant shall be responsible for satisfying any federal, state, local and/or foreign tax withholding obligations attributable to participation in the Plan, to the extent required under applicable law. Unless otherwise provided by the Agreement, any such withholding tax obligations may be satisfied in cash (including from any cash payable in settlement of an Award) or a cash equivalent acceptable to the Committee. Except to the extent prohibited by Section 409A, any statutory federal, state, district, city or foreign withholding tax obligations also may be satisfied (a) by surrendering to the Company shares of Common Stock previously acquired by the Participant; (b) by authorizing the Company to withhold or reduce the number of shares of Common Stock otherwise issuable to the Participant upon the grant, vesting, settlement and/or exercise of an Award; or (c) by any other method as may be approved by the Committee. If shares of Common Stock are used to pay all or part of such withholding obligation, the Fair Market Value of the shares of Common Stock surrendered, withheld or reduced shall be determined as of the date of surrender, withholding or reduction and the maximum number of shares of Common Stock which may be withheld, surrendered or reduced shall be the number of shares of Common Stock which have a Fair Market Value on the date of surrender, withholding or reduction equal to the aggregate amount of such tax liabilities determined based on the greatest withholding rates for federal, state, foreign and/or local tax purposes, including payroll taxes, that may be utilized (and which may be limited to flat rate withholding) without creating adverse accounting, tax or other consequences to the Company or any of its Affiliates, as determined by the Committee in its sole discretion.

17.06.Fractional Shares

No fractional share of Common Stock shall be issued or delivered pursuant to the Plan or any Award, and the Committee shall determine in its sole discretion whether cash, other securities, or other property shall be paid or transferred in lieu of any fractional share of Common Stock or whether such fractional share of Common Stock or any rights thereto shall be canceled, terminated, or otherwise eliminated with or without consideration.

17.07.Governing Law

All questions arising with respect to the provisions of the Plan and Awards shall be determined by application of the laws of the State of Delaware, without giving effect to any conflict of law provisions thereof, except to the extent Delaware law is preempted by federal law. The obligation of the Company to sell and deliver shares of Common Stock hereunder is subject to applicable federal and state laws and to the approval of any governmental authority required in connection with the authorization, issuance, sale, or delivery of such shares of Common Stock.

17.08.Clawback

The Plan is subject to any written clawback policies that the Company, with the approval of the Board, may adopt. Any such policy may subject a Participant’s Awards and amounts paid or realized with respect to Awards under the Plan to reduction, cancelation, forfeiture or

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recoupment if certain specified events or wrongful conduct occur, including but not limited to an accounting restatement due to the Company’s material noncompliance with financial reporting regulations or other events or wrongful conduct specified in any such clawback policy adopted to conform to the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 and rules promulgated thereunder by the Securities and Exchange Commission and that the Company determines should apply to the Plan.

17.09.Nontransferability

Except as otherwise determined by the Committee, an Award may not be transferred by a Participant at any time prior to becoming earned, vested and settled.

ARTICLE XVIII
CHANGE IN CONTROL

18.01.Impact of Change in Control

In the event of a Change in Control, the Committee is authorized, in its discretion, to cause (a) all outstanding Options and SARs to become fully vested and exercisable immediately prior to such Change in Control and (b) all other outstanding Awards to become earned and non-forfeitable in their entirety upon such Change in Control.

18.02.Assumption Upon Change in Control

In the event of a Change in Control, the Committee, in its discretion and without the need for a Participant’s consent, may provide that an outstanding Award shall be assumed by, or a substitute award shall be granted by the surviving entity resulting from a transaction described in Section 1.06 (including, if applicable, the ultimate parent entity that directly or indirectly has beneficial ownership of sufficient voting securities to elect a majority of the members of the board of directors (or analogous governing body) of such entity). The assumed or substituted award shall have a value, as of the Control Change Date, that is substantially equal to the value of the original Award as of such date as the Committee determines is equitably required, and the assumed or substituted award shall have such other terms and conditions as may be prescribed by the Committee.

18.03.Cash-Out Upon Change in Control

If an Award is not assumed or replaced with a substitute award in accordance with Section 18.02, upon a Change in Control, the Committee, in its discretion and without the need of a Participant’s consent, may provide that each Award shall be cancelled in exchange for a payment. The payment may be in cash, shares of Common Stock or other securities or consideration received by stockholders in the Change in Control transaction. The amount of the payment shall be an amount that is substantially equal to (a) if the Award is denominated or to be settled in cash, the entire amount that can be paid under the Award (which, with respect to a Performance Award, unless a greater amount is otherwise provided by the Committee or an Agreement, shall be the greater of the target performance or actual performance determined at the time of the Change in Control) or (b) (i) the amount by which the price per share received by stockholders in the Change in Control for each share of Common Stock exceeds the Option price

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or Initial Value in the case of an Option and SAR, or (ii) for each share of Common Stock subject to an Award denominated in Common Stock or valued in reference to Common Stock, the price per share received by stockholders or (iii) for each other Award denominated in other securities or property, the value of such other securities or property, in each case as determined by the Committee. If the Option price or Initial Value exceeds the price per share received by stockholders in the Change in Control transaction, the Option or SAR may be cancelled under this Section 18.03 without any payment to the Participant.

ARTICLE XIX
AMENDMENT

The Board may amend or terminate the Plan at any time; provided, however, that no amendment may adversely impair the rights of Participants with respect to outstanding Awards; provided further, any adjustments made pursuant to Article XV or XVIII will not be deemed to adversely impair the rights of Participants with respect to outstanding Awards. In addition, an amendment will be contingent on approval of the Company’s stockholders if such approval is required by law or the rules of any exchange on which the shares of Common Stock are listed or if the amendment would materially increase the benefits accruing to Participants under the Plan, materially increase the aggregate number of shares of Common Stock that may be issued under the Plan (except as provided in Article XV) or materially modify the requirements as to eligibility for participation in the Plan. For the avoidance of doubt, the Board may not (except pursuant to Article XV or XVIII) without the approval of stockholders, (a) reduce the Option price per share of an outstanding Option or the Initial Value of an outstanding SAR, (b) make a payment to cancel an outstanding Option or SAR when the Option price or Initial Value, as applicable, exceeds the Fair Market Value or (c) take any other action with respect to an outstanding Option or SAR that may be treated as a repricing of the Award under the rules and regulations of the principal securities exchange on which the shares of Common Stock are listed for trading.

ARTICLE XX
EFFECTIVENESS AND DURATION OF PLAN

Awards may be granted under the Plan on and after the Effective Date. No Award may be granted under the Plan on and after the tenth (10th) anniversary of the Effective Date. Awards granted before such date shall remain valid in accordance with their terms.

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EX-10.22

Execution Version

CREDIT AGREEMENT

Dated as of May 6, 2021

among

INDEPENDENCE ENERGY FINANCE LLC

as the Borrower,

The Several Lenders

from Time to Time Parties Hereto,

WELLS FARGO BANK, NATIONAL ASSOCIATION,

as Administrative Agent, Collateral Agent

and a Letter of Credit Issuer,

and

JPMORGAN CHASE BANK, N.A.,

as Syndication Agent

WELLS FARGO SECURITIES, LLCand JPMORGAN CHASE BANK, N.A.,

as Joint Lead Arrangers and Joint Bookrunners

KE 74190199

TABLE OF CONTENTS

Page

ARTICLE I DEFINITIONS	2
Section 1.1 Defined Terms	2
Section 1.2 Other Interpretive Provisions	71
Section 1.3 Accounting Terms	72
Section 1.4 Rounding	73
Section 1.5 References to Agreements, Laws, Etc	73
Section 1.6 Times of Day	73
Section 1.7 Timing of Payment or Performance	73
Section 1.8 Currency Equivalents Generally	73
Section 1.9 Classification of Loans and Borrowings	74
Section 1.10 Pro Forma Calculations	74
Section 1.11 Rates	77
Section 1.12 Certifications	78
Section 1.13 Divisions	78
ARTICLE II AMOUNT AND TERMS OF CREDIT	78
Section 2.1 Commitments	78
Section 2.2 Minimum Amount of Each Borrowing; Maximum Number of Borrowings	78
Section 2.3 Notice of Borrowing	79
Section 2.4 Disbursement of Funds	79
Section 2.5 Repayment of Loans; Evidence of Debt	80
Section 2.6 Conversions and Continuations	81
Section 2.7 Pro Rata Borrowings	82
Section 2.8 Interest	82
Section 2.9 Interest Periods	83
Section 2.10 Increased Costs, Illegality, Etc	84
Section 2.11 Compensation	86
Section 2.12 Change of Lending Office	86
Section 2.13 Notice of Certain Costs	86
Section 2.14 Borrowing Base	86
Section 2.15 Defaulting Lenders	91
Section 2.16 Increase of Aggregate Maximum Credit Amount and/or Aggregate Elected Commitment Amount	94
Section 2.17 Extension Offers	96
Section 2.18 Benchmark Replacement Setting	98
ARTICLE III Letters of Credit	100
Section 3.1 Letters of Credit	100
Section 3.2 Letter of Credit Requests	102
Section 3.3 Letter of Credit Participations	103

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Section 3.4 Agreement to Repay Letter of Credit Drawings	105
Section 3.5 Increased Costs	106
Section 3.6 New or Successor Letter of Credit Issuer	107
Section 3.7 Role of Letter of Credit Issuer	108
Section 3.8 Cash Collateral	109
Section 3.9 Applicability of ISP and UCP	109
Section 3.10 Conflict with Issuer Documents	109
Section 3.11 Letters of Credit Issued for Restricted Subsidiaries	109
Section 3.12 Existing Letters of Credit	110
ARTICLE IV Fees; Commitments	110
Section 4.1 Fees	110
Section 4.2 Voluntary Reduction of Commitments	111
Section 4.3 Mandatory Termination of Commitments	112
ARTICLE V Payments	112
Section 5.1 Voluntary Prepayments	112
Section 5.2 Mandatory Prepayments	113
Section 5.3 Method and Place of Payment	115
Section 5.4 Net Payments	116
Section 5.5 Computations of Interest and Fees	120
Section 5.6 Limit on Rate of Interest	120
ARTICLE VI Conditions Precedent to Initial Borrowing.	121
Section 6.1 Credit Documents	121
Section 6.2 Collateral	122
Section 6.3 Legal Opinions	123
Section 6.4 Closing Certificates	123
Section 6.5 Authorization of Proceedings of Each Credit Party; Organizational Documents	123
Section 6.6 Fees	123
Section 6.7 Solvency Certificate	123
Section 6.8 Financial Statements	123
Section 6.9 Insurance Certificates	124
Section 6.10 Transactions	124
Section 6.11 Patriot Act; Beneficial Ownership	124
Section 6.12 Lien Searches	124
Section 6.13 No Indebtedness	124
Section 6.14 Title	124
Section 6.15 No Default; Representations and Warranties	125
ARTICLE VII Conditions Precedent to All Credit Events	125
Section 7.1 No Default; Representations and Warranties	125
Section 7.2 Excess Cash	125
Section 7.3 Notice of Borrowing	125

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ARTICLE VIII Representations, Warranties and Agreements	126
Section 8.1 Corporate Status	126
Section 8.2 Corporate Power and Authority; Enforceability	126
Section 8.3 No Violation	126
Section 8.4 Litigation	126
Section 8.5 Margin Regulations	127
Section 8.6 Governmental Approvals	127
Section 8.7 Investment Company Act	127
Section 8.8 True and Complete Disclosure	127
Section 8.9 No MAE	128
Section 8.10 Tax Matters	128
Section 8.11 Compliance with ERISA	128
Section 8.12 Subsidiaries	129
Section 8.13 Intellectual Property	129
Section 8.14 Environmental Laws	129
Section 8.15 Properties	129
Section 8.16 Solvency	130
Section 8.17 Gas Imbalances, Prepayments	130
Section 8.18 Marketing of Production	130
Section 8.19 Hedge Agreements	131
Section 8.20 Patriot Act	131
Section 8.21 Sanctions Laws and Regulations	131
Section 8.22 Affected Financial Institution	131
Section 8.23 Beneficial Ownership Certification	131
ARTICLE IX Affirmative Covenants	131
Section 9.1 Information Covenants	131
Section 9.2 Books, Records and Inspections	135
Section 9.3 Maintenance of Insurance	136
Section 9.4 Payment of Taxes	136
Section 9.5 Existence; Consolidated Corporate Franchises	136
Section 9.6 Compliance with Statutes, Regulations, Etc	136
Section 9.7 ERISA	137
Section 9.8 Maintenance of Properties	137
Section 9.9 Transactions with Affiliates	138
Section 9.10 Environmental Matters	140
Section 9.11 Additional Guarantors, Grantors and Collateral	141
Section 9.12 Use of Proceeds	142
Section 9.13 Further Assurances	143
Section 9.14 Reserve Reports	144
Section 9.15 Title Information	146
Section 9.16 Sanctions Laws and Regulations	146

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Section 9.17 Change in Business	147
Section 9.18 Control Agreements	147
Section 9.19 Post-Closing Title Covenant	147
ARTICLE X Negative Covenants.	148
Section 10.1 Limitation on Indebtedness	148
Section 10.2 Limitation on Liens	152
Section 10.3 Limitation on Fundamental Changes	156
Section 10.4 Limitation on Sale of Assets	159
Section 10.5 Limitation on Investments	161
Section 10.6 Limitation on Dividends	166
Section 10.7 Limitations on Junior Debt Payments and Amendments	172
Section 10.8 Negative Pledge Agreements	173
Section 10.9 Limitation on Subsidiary Distributions	174
Section 10.10 Hedge Agreements	175
Section 10.11 Financial Performance Covenants	177
ARTICLE XI Events of Default	178
Section 11.1 Payments	178
Section 11.2 Representations, Etc	178
Section 11.3 Covenants	178
Section 11.4 Default Under Other Agreements	178
Section 11.5 Bankruptcy, Etc	179
Section 11.6 ERISA	179
Section 11.7 Guarantee	180
Section 11.8 Security Documents	180
Section 11.9 Judgments	180
Section 11.10 Change of Control	180
Section 11.11 Intercreditor Agreement	180
Section 11.12 Application of Proceeds	181
Section 11.13 Equity Cure	182
Section 11.14 Action by Secured Parties	184
ARTICLE XII The Agents	185
Section 12.1 Appointment	185
Section 12.2 Delegation of Duties	185
Section 12.3 Exculpatory Provisions	186
Section 12.4 Reliance by Agents	186
Section 12.5 Notice of Default	187
Section 12.6 Non-Reliance on Administrative Agent, Collateral Agent and Other Lenders	187
Section 12.7 Indemnification	188
Section 12.8 Agents in Its Individual Capacities	189
Section 12.9 Successor Agents	189

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Section 12.10 Withholding Tax	190
Section 12.11 Security Documents and Collateral Agent under Security Documents and Guarantee	190
Section 12.12 Right to Realize on Collateral and Enforce Guarantee	190
Section 12.13 Credit Bidding	191
Section 12.14 Administrative Agent May File Proofs of Claim	192
Section 12.15 Intercreditor Agreement	193
Section 12.16 Erroneous Payments	193
ARTICLE XIII Miscellaneous	194
Section 13.1 Amendments, Waivers and Releases	194
Section 13.2 Notices	199
Section 13.3 No Waiver; Cumulative Remedies	200
Section 13.4 Survival of Representations and Warranties	200
Section 13.5 Payment of Expenses; Indemnification	200
Section 13.6 Successors and Assigns; Participations and Assignments	202
Section 13.7 Replacements of Lenders under Certain Circumstances	206
Section 13.8 Adjustments; Set-off	207
Section 13.9 Counterparts	208
Section 13.10 Severability	209
Section 13.11 Integration	209
Section 13.12 GOVERNING LAW	209
Section 13.13 Submission to Jurisdiction; Waivers	209
Section 13.14 Acknowledgments	210
Section 13.15 WAIVERS OF JURY TRIAL	211
Section 13.16 Confidentiality	211
Section 13.17 Release of Collateral and Guarantee Obligations	212
Section 13.18 USA PATRIOT Act	213
Section 13.19 Payments Set Aside	213
Section 13.20 Reinstatement	214
Section 13.21 Disposition of Proceeds	214
Section 13.22 Collateral Matters; Hedge Agreements	214
Section 13.23 Flood Insurance Provisions	214
Section 13.24 Headings	214
Section 13.25 No Third Party Beneficiaries	215
Section 13.26 Keepwell	215
Section 13.27 Certain ERISA Matters	215
Section 13.28 Acknowledgement Regarding Any Supported QFCs	216

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Schedules and Exhibits

Schedule 1.1(a) Schedule 1.1(b) Schedule 1.1(c) Schedule 1.1(d) Schedule 1.1(e) Schedule 1.1(f) Schedule 6.3 Schedule 8.4 Schedule 8.11 Schedule 8.12 Schedule 8.17 Schedule 8.18 Schedule 8.19 Schedule 9.9 Schedule 10.1 Schedule 10.2 Schedule 10.4 Schedule 10.5 Schedule 10.6 Schedule 10.8 Schedule 13.2

Elected Commitment Amounts and Maximum Credit Amount Excluded Stock Excluded Subsidiaries Closing Date Existing Letters of Credit Closing Date Subsidiary Guarantors Closing Date Non-Lender Secured Hedge Agreements Local Counsel Jurisdictions Litigation Compliance With ERISA Subsidiaries Closing Date Gas Imbalances Closing Date Marketing Agreements Closing Date Hedge Agreements Closing Date Affiliate Transactions Closing Date Indebtedness Closing Date Liens Scheduled Dispositions Closing Date Investments Closing Date Dividends Closing Date Negative Pledge Agreements Notice Addresses

Exhibit A Exhibit B Exhibit C Exhibit D Exhibit E Exhibit F Exhibit G Exhibit H Exhibit I Exhibit J Exhibit K Exhibit L Exhibit M Exhibit N-1 Exhibit N-2 Exhibit N-3 Exhibit N-4 Exhibit O

Form of Assignment and Acceptance Form of Compliance Certificate Form of Customary Intercreditor Agreement Form of Guarantee Form of Intercompany Note Form of Mortgage/Deed of Trust Form of Notice of Borrowing Form of Pledge Agreement Form of Reserve Report Certificate Form of Security Agreement Form of Letter Credit Requests Form of Credit Party Closing Certificate Form of Solvency Certificate Form of Non-Bank Tax Certificate Form of Non-Bank Tax Certificate Form of Non-Bank Tax Certificate Form of Non-Bank Tax Certificate Form of Promissory Note

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CREDIT AGREEMENT, dated as of May 6, 2021, among INDEPENDENCE ENERGY FINANCE LLC, a Delaware limited liability company (the “Borrower”), (such terms and each other capitalized term used but not defined in this preamble having the meaning provided in Section 1), the banks, financial institutions and other lending institutions from time to time parties as lenders hereto (each a “Lender” and, collectively, the “Lenders”), WELLS FARGO BANK NATIONAL ASSOCIATION, as Administrative Agent, Collateral Agent, and a Letter of Credit Issuer, and each other Letter of Credit Issuer from time to time party hereto.

RECITALS

WHEREAS, (a) the Borrower has requested that the Lenders extend credit in the form of Loans made available to the Borrower on the Closing Date and at any time and from time to time after the Closing Date subject to the Available Commitment and (b) the Borrower has requested that the Letter of Credit Issuers issue Letters of Credit (subject to the Available Commitment) at any time and from time to time prior to the L/C Maturity Date, in an aggregate Stated Amount at any time outstanding not in excess of the Letter of Credit Commitment;

WHEREAS, in connection with, and prior to the completion of, an offering of $500.0 million aggregate principal amount of 7.250% Senior Notes (the “Closing Date Unsecured Notes”) due 2026, certain restructuring transactions shall be undertaken, as more fully described in that certain Yanchang Reorganization Agreement, dated as of May 6, 2021, by and among Independence Energy Finance LLC, a Delaware limited liability company, Independence Energy MM LLC, a Delaware limited liability company, the Borrower and certain of the other Credit Parties party thereto (the “Reorganization”);

WHEREAS, in furtherance of the Transactions (as defined below), the Existing Borrowers, each of which is a direct or indirect Subsidiary of the Borrower, wish to repay in full all principal, interest, and other amounts outstanding under the Existing Credit Facilities (the “Closing Date Refinancing”);

WHEREAS, in connection with the foregoing, (i) the Borrower has requested that on the Closing Date the Lenders provide Loans to the Borrower in order to fund a portion of the Closing Date Refinancing, (ii) at any time and from time to time upon the Closing Date and prior to the Maturity Date, the proceeds of the Loans will be used by the Borrower for the Transactions, for the acquisition, development and exploration of Oil and Gas Properties and for working capital and other general corporate purposes of the Borrower and its Subsidiaries (including Permitted Acquisitions) and (iii) the Letters of Credit will be used by the Borrower and its Subsidiaries for general corporate purposes and to provide or support deposits required under purchase agreements pursuant to which the Borrower or its Subsidiaries may acquire Oil and Gas Properties and other assets;

WHEREAS, the Lenders and Letter of Credit Issuers are willing to make available to the Borrower such revolving credit and letter of credit facilities upon the terms and subject to the conditions set forth herein; and

NOW, THEREFORE, in consideration of the premises and the covenants and agreements contained herein, the parties hereto hereby agree as follows:

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ARTICLE I
DEFINITIONS

Section 1.1Defined Terms. As used herein, the following terms shall have the meanings specified in this Section 1.1 unless the context otherwise requires (it being understood that defined terms in this Agreement shall include in the singular number the plural and in the plural the singular):

“ABR” shall mean for any day a fluctuating rate per annum equal to the highest of (a) the Federal Funds Effective Rate plus ½ of 1%, (b) the rate of interest in effect for such day as publicly announced from time to time by the Administrative Agent as its “prime rate” and (c) the Adjusted LIBOR Rate for a one-month Interest Period on such day (or if such day is not a Business Day, the immediately preceding Business Day) plus 1.0%; provided that, for the avoidance of doubt, for purposes of calculating the Adjusted LIBOR Rate pursuant to clause (c) above, the LIBOR Rate for any day shall be based on the rate per annum determined by the Administrative Agent at approximately 11:00 a.m. (London time) on such day by reference to the rate appearing on the Reuters Screen LIBOR01 Page (or any successor page or any successor service, or any substitute page or substitute for such service, providing rate quotations comparable to the Reuters Screen LIBOR01 Page, as determined by the Administrative Agent from time to time for purposes of providing quotations of interest rates applicable to dollar deposits in the London interbank market) for a period equal to one-month. The “prime rate” is a rate set by the Administrative Agent based upon various factors, including the Administrative Agent’s costs and desired return, general economic conditions and other factors, and is used as a reference point for pricing some loans, which may be priced at, above, or below such announced rate. Any change in the ABR due to a change in such rate announced by the Administrative Agent, in the Federal Funds Effective Rate or in the one-month LIBOR Rate shall take effect at the opening of business on the day specified in the publication or public announcement of such change. If the ABR is being used as an alternate rate of interest pursuant to Section 2.10(b) hereof, then the ABR shall be the greater of clause (a) and (b) above and shall be determined without reference to clause (c) above. For the avoidance of doubt, if the ABR shall be less than zero, such rate shall be deemed to be zero for purposes of this Agreement.

“ABR Loan” shall mean each Loan bearing interest based on the ABR.

“Account Control Agreement” shall mean a control agreement, in form and substance reasonably satisfactory to the Administrative Agent, which grants the Administrative Agent “control” as defined in the UCC over any deposit account or securities account maintained by any Credit Party (in each case, other than an Excluded Account), in each case, among the Administrative Agent, the applicable Credit Party and the applicable financial institution at which such deposit account or securities account is maintained.

“Acquired EBITDAX” shall mean, with respect to any Acquired Entity or Business or any Converted Restricted Subsidiary (any of the foregoing, a “Pro Forma Entity”) for any period, the amount (or, at the election of the Borrower, if the annualized portion of Acquired EBITDAX for the most recent portion of such period is a more appropriate indicator of future performance than Acquired EBITDAX for such period (as determined by the Borrower in good faith), the annualized portion) for such period of Consolidated EBITDAX of such Pro Forma Entity

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(determined using such definitions as if references to the Borrower and its Restricted Subsidiaries therein were to such Pro Forma Entity and its Restricted Subsidiaries), all as determined on a consolidated basis for such Pro Forma Entity in a manner not inconsistent with GAAP.

“Acquired Entity or Business” shall have the meaning provided in the definition of the term “Consolidated EBITDAX.”

“Acquisition Hedges” shall have the meaning assigned to such term in Section 10.10(b).

“Additional Lender” shall have the meaning provided in Section 2.16(a).

“Adjusted LIBOR Rate” shall mean, with respect to any LIBOR Borrowing for any Interest Period or for any ABR Borrowing, an interest rate per annum (rounded upwards, if necessary, to the next 1/16 of 1%) equal to (a) the LIBOR Rate for such Interest Period multiplied by (b) the Statutory Reserve Rate.

“Adjusted Total Commitment” shall mean, at any time, the Total Commitment less the aggregate amount of Commitments of all Defaulting Lenders.

“Administrative Agent” shall mean Wells Fargo Bank, National Association, as the administrative agent for the Lenders under this Agreement and the other Credit Documents, or any successor administrative agent appointed in accordance with the provisions of Section 12.9.

“Administrative Agent’s Office” shall mean the Administrative Agent’s address and, as appropriate, account as set forth on Schedule 13.2, or such other address or account as the Administrative Agent may from time to time notify in writing to the Borrower and the Lenders.

“Administrative Questionnaire” shall mean, for each Lender, an administrative questionnaire in a form approved by the Administrative Agent.

“Affected Financial Institution” shall mean (a) any EEA Financial Institution or (b) any UK Financial Institution.

“Affiliate” shall mean, with respect to any Person, any other Person directly or indirectly controlling, controlled by, or under direct or indirect common control with such Person. A Person shall be deemed to control another Person if such Person possesses, directly or indirectly, the power to direct or cause the direction of the management and policies of such other Person, whether through the ownership of voting securities, by contract or otherwise; provided that in no event will any portfolio company of KKR or its Affiliates be considered as an Affiliate of the Borrower or any Restricted Subsidiaries (except with respect to Section 9.9).

“Agents” shall mean the Administrative Agent and the Collateral Agent.

“Aggregate Elected Commitment Amount” means the sum of the Elected Commitment Amounts of all of the Lenders. The Aggregate Elected Commitment Amount as of the Closing Date is $500,000,000.

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“Aggregate Maximum Credit Amount” at any time shall equal the sum of the Maximum Credit Amounts, as the same may be increased, reduced or terminated from time to time in connection with an optional increase of the Aggregate Maximum Credit Amount pursuant to Section 2.16(a) or a termination or reduction of the Aggregate Maximum Credit Amount pursuant to Section 4.2. The Aggregate Maximum Credit Amount as of the Closing Date is $1,500,000,000.

“Agreement” shall mean this Credit Agreement, as the same may from time to time be amended, restated, amended and restated, supplemented or otherwise modified.

“All-In Yield” shall mean, as to any Indebtedness, the yield thereof, whether in the form of interest rate, margin, original issue discount, upfront fees, or any LIBOR Rate or ABR floor, in each case, incurred or payable by the Credit Parties generally to all the lenders of such Indebtedness; provided that (a) original issue discount and upfront fees shall be equated to interest rate assuming a 4-year life to maturity (or, if less, the stated life to maturity at the time of its incurrence of the applicable Indebtedness), and (b) “All-In Yield” shall not include amendment fees, arrangement fees, structuring fees, commitment fees, underwriting fees and similar fees (regardless of whether shared with, or paid to, in whole or in part, any or all lenders), success fees, consent fees paid to consenting lenders, ticking fees on undrawn commitments or any other fees not paid ratably to all lenders in the primary syndication of such Indebtedness.

“Announcements” has the meaning assigned thereto in Section 1.11.

“Anti-Corruption Laws” shall mean all laws, rules, and regulations of any jurisdiction applicable to the Borrower or any of its Subsidiaries from time to time concerning or relating to bribery or corruption.

“Applicable Equity Amount” shall mean, at any time (the “Applicable Equity Amount Reference Time”), an amount equal to, without duplication,

(a)    the amount of any capital contributions made in cash to, or any proceeds of an equity issuance received by, the Borrower during the period from and including the Business Day immediately following the Closing Date, through and including the Applicable Equity Amount Reference Time, including proceeds from the issuance of Stock or Stock Equivalents of any direct or indirect parent of the Borrower, but excluding all proceeds from the issuance of Disqualified Stock; minus

(b)    the sum, without duplication, of:

(i)    the aggregate amount of any Investments made by the Borrower or any Restricted Subsidiary pursuant to Section 10.5(g)(iii)(B), Section 10.5(h)(ii) and Section 10.5(i)(B) after the Closing Date, and prior to the Applicable Equity Amount Reference Time;

(ii)    the aggregate amount of any Dividends made by the Borrower pursuant to Section 10.6(k) after the Closing Date, and prior to the Applicable Equity Amount Reference Time; and

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(iii)    the aggregate amount of prepayments, repurchases, redemptions and defeasances made by the Borrower or any Restricted Subsidiary pursuant to Section 10.7(c)(iii) after the Closing Date and prior to the Applicable Equity Amount Reference Time.

“Applicable Margin” shall mean, for any day, with respect to any ABR Loan or LIBOR Loan, as the case may be, the rate per annum set forth in the grid below based upon the Borrowing Base Utilization Percentage in effect on such day:

Borrowing Base Utilization Grid

Borrowing Base Utilization Percentage	< 30%	≥ 30% but <60%	≥ 60% but <80%	≥ 80% but <90%	≥ 90%
LIBOR Loans	2.75%	3.00%	3.25%	3.50%	3.75%
ABR Loans	1.75%	2.00%	2.25%	2.50%	2.75%
Commitment Fee Rate	0.50%	0.50%	0.50%	0.50%	0.50%

Each change in the Commitment Fee Rate or Applicable Margin shall apply during the period commencing on the effective date of such change and ending on the date immediately preceding the effective date of the next such change.

“Approved Fund” shall mean any Fund that is administered or managed by (a) a Lender, (b) an Affiliate of a Lender or (c) an entity or an Affiliate of an entity that administers or manages a Lender.

“Approved Petroleum Engineers” shall mean (a) Netherland, Sewell & Associates, Inc., (b) Ryder Scott Company Petroleum Consultants, L.P., (c) W. D. Van Gonten & Co. Petroleum Engineering, (d) DeGolyer and MacNaughton, (e) LaRoche Petroleum Consultants, Ltd., (f) Cawley, Gillespie & Associates, (g) Haas Engineering and (h) at the Borrower’s option, any other independent petroleum engineers selected by the Borrower and reasonably acceptable to the Administrative Agent.

“Assignment and Acceptance” shall mean an assignment and acceptance substantially in the form of Exhibit A or such other form as may be approved by the Administrative Agent.

“Authorized Officer” shall mean as to any Person, (a) the President, any Vice President, the Chief Executive Officer, the Chief Financial Officer, the Chief Operating Officer, the Chief Accounting Officer, the Executive Vice President, the Treasurer, the Assistant or Vice Treasurer, the Vice President-Finance, the Vice President-Acquisition Activities, the Vice President-Investments, the General Counsel and any manager, managing member or general partner, in each case, of such Person, and (b) any other individual designated as such in writing to the Administrative Agent by a Person described in clause (a). Any document delivered hereunder that is signed by an Authorized Officer shall be conclusively presumed to have been authorized by all necessary corporate, limited liability company, partnership and/or other action on the part

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of the Borrower or any other Credit Party and such Authorized Officer shall be conclusively presumed to have acted on behalf of such Person.

“Auto-Extension Letter of Credit” shall have the meaning provided in Section 3.2(b).

“Available Commitment” shall mean, at any time, (a) the Loan Limit at such time minus (b) the aggregate Total Exposures of all Lenders at such time.

“Available Distributable Consolidated EBITDAX” means, as of any time of calculation thereof, the amount equal to: (a) (i) if the Consolidated Total Debt to Consolidated EBITDAX Ratio is less than or equal to 2.00 to 1.00 (on a Pro Forma Basis after giving effect to the applicable Dividend or prepayment of Indebtedness), 10% of Consolidated EBITDAX for the most recently ended Test Period or (ii) if the Consolidated Total Debt to Consolidated EBITDAX Ratio is greater than 2.00 to 1.00 but less than or equal to 2.50 to 1.00 (on a Pro Forma Basis after giving effect to the applicable Dividend or prepayment of Indebtedness), 5% of Consolidated EBITDAX for the most recently ended Test Period, minus (b) the sum of (i) the aggregate amount of Dividends made under Section 10.6(j) and (ii) the aggregate amount of payments made on Permitted Additional Debt or Permitted Junior Lien Debt under Section 10.7(a)(v), in the case of each of clauses (i) and (ii) of this clause (b), that has occurred during the period commencing with the first day of the most recently ended Test Period, through and including the time of calculation.

“Available Free Cash Flow” means, as of any time of calculation thereof, the amount equal to: (a) Free Cash Flow as of the last day of the most recently ended Test Period, minus (b) the sum of (i) the aggregate amount of Dividends made under Section 10.6(j) and (ii) the aggregate amount of payments made on Permitted Additional Debt or Permitted Junior Lien Debt under Section 10.7(a)(v) in the case of this clause (b) that, in each case, has occurred during the period commencing with the first day of the most recently ended Test Period, through and including the time of calculation.

“Available Tenor” means, as of any date of determination and with respect to the then-current Benchmark, as applicable, (a) if the then-current Benchmark is a term rate, any tenor for such Benchmark or (b) otherwise, any payment period for interest calculated with reference to such Benchmark, as applicable, that is or may be used for determining the length of an Interest Period pursuant to this Agreement as of such date and not including, for the avoidance of doubt, any tenor for such Benchmark that is then-removed from the definition of “Interest Period” pursuant to Section 2.18(d).

“Bail-In Action” shall mean the exercise of any Write-Down and Conversion Powers by the applicable Resolution Authority in respect of any liability of an Affected Financial Institution.

“Bail-In Legislation” shall mean (a) with respect to any EEA Member Country implementing Article 55 of Directive 2014/59/EU of the European Parliament and of the Council of the European Union, the implementing law, regulation, rule or requirement for such EEA Member Country from time to time which is described in the EU Bail-In Legislation Schedule and (b) with respect to the United Kingdom, Part I of the United Kingdom Banking Act 2009 (as amended from time to time) and any other law, regulation or rule applicable in the United Kingdom relating to the resolution of unsound or failing banks, investment firms or other

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financial institutions or their affiliates (other than through liquidation, administration or other insolvency proceedings).

“Bank Price Deck” shall mean the Administrative Agent’s most recent internal price deck on a forward curve basis for each of oil, natural gas and other Hydrocarbons, as applicable, furnished to the Borrower by the Administrative Agent from time to time in accordance with the terms of this Agreement.

“Bankruptcy Code” shall have the meaning provided in Section 11.5.

“Benchmark” means, initially, LIBOR; provided that if a Benchmark Transition Event, a Term SOFR Transition Event, or an Early Opt-in Election, as applicable, and its related Benchmark Replacement Date have occurred with respect to LIBOR or the then-current Benchmark, then “Benchmark” means the applicable Benchmark Replacement to the extent that such Benchmark Replacement has replaced such prior benchmark rate pursuant to Section 2.18(a).

“Benchmark Replacement” means, for any Available Tenor, (a) with respect to any Benchmark Transition Event or Early Opt-in Election, the first alternative set forth in the order below that can be determined by the Administrative Agent for the applicable Benchmark Replacement Date:

(1)    the sum of: (A) Term SOFR and (B) the related Benchmark Replacement Adjustment;

(2)    the sum of: (A) Daily Simple SOFR and (B) the related Benchmark Replacement Adjustment;

(3)    the sum of: (A) the alternate benchmark rate that has been selected by the Administrative Agent and the Borrower as the replacement for the then-current Benchmark for the applicable Corresponding Tenor giving due consideration to (i) any selection or recommendation of a replacement benchmark rate or the mechanism for determining such a rate by the Relevant Governmental Body or (ii) any evolving or then-prevailing market convention for determining a benchmark rate as a replacement for the then-current Benchmark for Dollar-denominated syndicated credit facilities at such time and (B) the related Benchmark Replacement Adjustment; or

(b) with respect to any Term SOFR Transition Event, the sum of (i) Term SOFR and (ii) the related Benchmark Replacement Adjustment;

provided that, (i) in the case of clause (a)(1), if the Administrative Agent decides that Term SOFR is not administratively feasible for the Administrative Agent, then Term SOFR will be deemed unable to be determined for purposes of this definition and (ii) in the case of clause (a)(1) or clause (b) of this definition, the applicable Unadjusted Benchmark Replacement is displayed on a screen or other information service that publishes such rate from time to time as selected by the Administrative Agent in its reasonable discretion. If the Benchmark Replacement as determined pursuant to clause (a)(1), (a)(2) or (a)(3) or clause (b) of this definition would be less than the Floor, the Benchmark Replacement will be deemed to be the Floor for the purposes of this Agreement and the other Credit Documents.

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“Benchmark Replacement Adjustment” means, with respect to any replacement of the then-current Benchmark with an Unadjusted Benchmark Replacement for any applicable Interest Period and Available Tenor for any setting of such Unadjusted Benchmark Replacement:

(1)    for purposes of clauses (a)(1) and (a)(2) of the definition of “Benchmark Replacement,” the first alternative set forth in the order below that can be determined by the Administrative Agent:

(a)    the spread adjustment, or method for calculating or determining such spread adjustment, (which may be a positive or negative value or zero) as of the Reference Time such Benchmark Replacement is first set for such Interest Period that has been selected or recommended by the Relevant Governmental Body for the replacement of such Available Tenor of such Benchmark with the applicable Unadjusted Benchmark Replacement;

(b)    the spread adjustment (which may be a positive or negative value or zero) as of the Reference Time such Benchmark Replacement is first set for such Interest Period that would apply to the fallback rate for a derivative transaction referencing the ISDA Definitions to be effective upon an index cessation event with respect to such Available Tenor of such Benchmark;

(2)    for purposes of clause (a)(3) of the definition of “Benchmark Replacement,” the spread adjustment, or method for calculating or determining such spread adjustment, (which may be a positive or negative value or zero) that has been selected by the Administrative Agent and the Borrower giving due consideration to (i) any selection or recommendation of a spread adjustment, or method for calculating or determining such spread adjustment, for the replacement of such Available Tenor of such Benchmark with the applicable Unadjusted Benchmark Replacement by the Relevant Governmental Body on the applicable Benchmark Replacement Date or (ii) any evolving or then-prevailing market convention for determining a spread adjustment, or method for calculating or determining such spread adjustment, for the replacement of such Available Tenor of such Benchmark with the applicable Unadjusted Benchmark Replacement for Dollar-denominated syndicated credit facilities; and

(3)    for purposes of clause (b) of the definition of “Benchmark Replacement,” the spread adjustment, or method for calculating or determining such spread adjustment, (which may be a positive or negative value or zero) as of the Reference Time such Benchmark Replacement is first set for such Interest Period that has been selected or recommended by the Relevant Governmental Body for the replacement of such Available Tenor of LIBOR with a SOFR-based rate;

provided that, (x) in the case of clause (1) above, such adjustment is displayed on a screen or other information service that publishes such Benchmark Replacement Adjustment from time to time as selected by the Administrative Agent in its reasonable discretion and (y) if the then-current Benchmark is a term rate, more than one tenor of such Benchmark is available as of the applicable Benchmark Replacement Date and the applicable Unadjusted Benchmark Replacement that will replace such Benchmark in accordance with Section 2.18(a) will not be a term rate, the Available Tenor of such Benchmark for purposes of this definition of “Benchmark Replacement Adjustment” shall be deemed to be, with respect to each Unadjusted Benchmark Replacement having a payment period for interest calculated with reference thereto, the

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Available Tenor that has approximately the same length (disregarding business day adjustments) as such payment period.

“Benchmark Replacement Conforming Changes” means, with respect to any Benchmark Replacement, any technical, administrative or operational changes (including changes to the definition of “ABR,” the definition of “Business Day,” the definition of “Interest Period,” timing and frequency of determining rates and making payments of interest, timing of borrowing requests or prepayment, conversion or continuation notices, length of lookback periods, the applicability of breakage provisions, and other technical, administrative or operational matters) that the Administrative Agent (in consultation with the Borrower) decides may be appropriate to reflect the adoption and implementation of such Benchmark Replacement and to permit the administration thereof by the Administrative Agent in a manner substantially consistent with market practice (or, if the Administrative Agent decides that adoption of any portion of such market practice is not administratively feasible or if the Administrative Agent determines that no market practice for the administration of such Benchmark Replacement exists, in such other manner of administration as the Administrative Agent decides is reasonably necessary in connection with the administration of this Agreement and the other Credit Documents).

“Benchmark Replacement Date” means the earliest to occur of the following events with respect to the then-current Benchmark:

(a)    in the case of clause (a) or (b) of the definition of “Benchmark Transition Event,” the later of (a) the date of the public statement or publication of information referenced therein and (b) the date on which the administrator of such Benchmark (or the published component used in the calculation thereof) permanently or indefinitely ceases to provide all Available Tenors of such Benchmark (or such component thereof);

(b)    in the case of clause (c) of the definition of “Benchmark Transition Event,” the date of the public statement or publication of information referenced therein;

(c)    in the case of a Term SOFR Transition Event, the date that is thirty (30) days after the Administrative Agent has provided the Term SOFR Notice to the Lenders and the Borrower pursuant to Section 2.18(A)(i); or

(d)    in the case of an Early Opt-in Election, the sixth (6th) Business Day after the date notice of such Early Opt-in Election is provided to the Lenders, so long as the Administrative Agent has not received, by 5:00 p.m. (New York City time) on the fifth (5th) Business Day after the date notice of such Early Opt-in Election is provided to the Lenders, written notice of objection to such Early Opt-in Election from Lenders comprising the Majority Lenders.

For the avoidance of doubt, (i) if the event giving rise to the Benchmark Replacement Date occurs on the same day as, but earlier than, the Reference Time in respect of any determination, the Benchmark Replacement Date will be deemed to have occurred prior to the Reference Time for such determination and (ii) the “Benchmark Replacement Date” will be deemed to have occurred in the case of clause (1) or (2) with respect to any Benchmark upon the occurrence of the applicable event or events set forth therein with respect to all then-current Available Tenors of such Benchmark (or the published component used in the calculation thereof).

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“Benchmark Transition Event” means the occurrence of one or more of the following events with respect to the then-current Benchmark:

(a)    a public statement or publication of information by or on behalf of the administrator of such Benchmark (or the published component used in the calculation thereof) announcing that such administrator has ceased or will cease to provide all Available Tenors of such Benchmark (or such component thereof), permanently or indefinitely, provided that, at the time of such statement or publication, there is no successor administrator that will continue to provide any Available Tenor of such Benchmark (or such component thereof);

(b)    a public statement or publication of information by the regulatory supervisor for the administrator of such Benchmark (or the published component used in the calculation thereof), the Board, the Federal Reserve Bank of New York, an insolvency official with jurisdiction over the administrator for such Benchmark (or such component), a resolution authority with jurisdiction over the administrator for such Benchmark (or such component) or a court or an entity with similar insolvency or resolution authority over the administrator for such Benchmark (or such component), which states that the administrator of such Benchmark (or such component) has ceased or will cease to provide all Available Tenors of such Benchmark (or such component thereof) permanently or indefinitely, provided that, at the time of such statement or publication, there is no successor administrator that will continue to provide any Available Tenor of such Benchmark (or such component thereof); or

(c)    a public statement or publication of information by the regulatory supervisor for the administrator of such Benchmark (or the published component used in the calculation thereof) announcing that all Available Tenors of such Benchmark (or such component thereof) are no longer representative.

For the avoidance of doubt, a “Benchmark Transition Event” will be deemed to have occurred with respect to any Benchmark if a public statement or publication of information set forth above has occurred with respect to each then-current Available Tenor of such Benchmark (or the published component used in the calculation thereof).

“Benchmark Unavailability Period” means the period (if any) (x) beginning at the time that a Benchmark Replacement Date pursuant to clauses (a) or (b) of that definition has occurred if, at such time, no Benchmark Replacement has replaced the then-current Benchmark for all purposes hereunder and under any Credit Document in accordance with Section 2.18 and (y) ending at the time that a Benchmark Replacement has replaced the then-current Benchmark for all purposes hereunder and under any Credit Document in accordance with Section 2.18.

“Beneficial Ownership Certification” shall mean a certification regarding beneficial ownership as required by the Beneficial Ownership Regulation.

“Beneficial Ownership Regulation” means 31 CFR § 1010.230.

“Benefited Lender” shall have the meaning provided in Section 13.8(a).

“Benefit Plan” shall mean any of (a) an “employee benefit plan” (as defined in ERISA) that is subject to Title I of ERISA, (b) a “plan” as defined in Section 4975 of the Code or (c) any

10

Person whose assets include (for purposes of ERISA Section 3(42) or otherwise for purposes of Title I of ERISA or Section 4975 of the Code) the assets of any such “employee benefit plan” or “plan”.

“BHC Act Affiliate” of a party means an “affiliate” (as such term is defined under, and interpreted in accordance with, 12 U.S.C. 1841(k)) of such party.

“Board” shall mean the Board of Governors of the Federal Reserve System of the United States (or any successor).

“Borrower” shall have the meaning provided in the introductory paragraph hereto.

“Borrowing” shall mean the incurrence of one Type of Loan on a given date (or resulting from conversions on a given date) having, in the case of LIBOR Loans, the same Interest Period (provided that ABR Loans incurred pursuant to Section 2.10(b) shall be considered part of any related Borrowing of LIBOR Loans).

“Borrowing Base” shall mean, at any time, an amount equal to the amount determined in accordance with Section 2.14, as the same may be adjusted from time to time pursuant to the Borrowing Base Adjustment Provisions.

“Borrowing Base Adjustment Provisions” shall mean Section 2.14(e), Section 2.14(f), and Section 2.14(g).

“Borrowing Base Deficiency” occurs if, at any time, the aggregate Total Exposures of all Lenders exceeds the Total Commitment. The amount of the Borrowing Base Deficiency is the amount by which Total Exposures of all Lenders exceeds the Total Commitment.

“Borrowing Base Properties” shall mean the Oil and Gas Properties of the Credit Parties included in the Initial Reserve Report and thereafter in the most recently delivered Reserve Report delivered pursuant to Section 9.14and evaluated for purposes of determining the Borrowing Base then in effect.

“Borrowing Base Required Lenders” shall mean, at any date, (a) Non-Defaulting Lenders having or holding at least 100% of the Adjusted Total Commitment at such date or (b) if the Total Commitment has been terminated, Lenders having or holding at least 100% of the outstanding principal amount of the Loans and Letter of Credit Exposure (excluding the Loans and Letter of Credit Exposure of Defaulting Lenders) in the aggregate at such date.

“Borrowing Base Utilization Percentage” shall mean, as of any day, the fraction expressed as a percentage, the numerator of which is the sum of the aggregate Total Exposures of all Lenders on such day, and the denominator of which is the Borrowing Base in effect on such day.

“Business Day” shall mean any day excluding Saturday, Sunday and any other day on which banking institutions in New York City are authorized by law or other governmental actions to close, and, if such day relates to (a) any interest rate settings as to a LIBOR Loan, (b) any fundings, disbursements, settlements and payments in respect of any such LIBOR Loan, or (c) any other dealings pursuant to this Agreement in respect of any such LIBOR Loan, such day

11

shall be a day on which dealings in deposits in Dollars are conducted by and between banks in the London interbank eurodollar market.

“Capital Expenditures” shall mean, for any period, the aggregate of all expenditures (whether paid in cash or accrued as liabilities and including in all events all amounts expended or capitalized under Capital Leases) by the Borrower and the Restricted Subsidiaries during such period that, in conformity with GAAP, are or are required to be included as capital expenditures on a consolidated statement of cash flows of the Borrower and its Restricted Subsidiaries.

“Capital Lease” shall mean, as applied to any Person, any lease of any property (whether real, personal or mixed) by that Person as lessee that, in conformity with GAAP, is, or is required to be, accounted for as a capital lease on the balance sheet of that Person; provided, any lease that would have been characterized as an operating lease pursuant to GAAP prior to the date of the Borrower’s adoption of ASC 842 (whether or not such operating lease was in effect on such date) shall continue to be accounted for as an operating lease (and not as a Capital Lease) for purposes of this Agreement.

“Capitalized Lease Obligations” shall mean, as applied to any Person, all obligations under Capital Leases of such Person or any of its Subsidiaries, in each case taken at the amount thereof accounted for as liabilities on the balance sheet (excluding the footnotes thereto) in accordance with GAAP; provided that obligations that are recharacterized as Capitalized Lease Obligations due to the Borrower’s adoption of ASC 842 shall not be treated as Capitalized Lease Obligations for any purpose under this Agreement but shall instead be treated as they would have been in accordance with GAAP prior to the date of the Borrower’s adoption of ASC 842.

“Capitalized Software Expenditures” shall mean, for any period, the aggregate of all expenditures (whether paid in cash or accrued as liabilities) by a Person and its Restricted Subsidiaries during such period in respect of licensed or purchased software or internally developed software and software enhancements that, in conformity with GAAP, are or are required to be reflected as capitalized costs on the consolidated balance sheet of such Person and its Restricted Subsidiaries.

“Captive Insurance Subsidiary” shall mean any Subsidiary of the Borrower that is subject to regulation as an insurance company (or any Subsidiary thereof).

“Cash Collateralize” shall have the meaning provided in Section 3.8(c). “Cash Collateralization” and “Cash Collateralized” shall have meanings correlative thereto.

“Cash Management Agreement” shall mean any agreement entered into from time to time by the Borrower or any of the Borrower’s Restricted Subsidiaries in connection with cash management services for collections, other Cash Management Services and for operating, payroll and trust accounts of such Person, including automatic clearing house services, controlled disbursement services, electronic funds transfer services, lockbox services, stop payment services and wire transfer services.

“Cash Management Bank” shall mean any Person that either (a) at the time it provides Cash Management Services, (b) on the Closing Date or (c) at any time after it has provided any Cash Management Services, is a Lender or an Agent or an Affiliate of a Lender or an Agent.

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“Cash Management Obligations” shall mean obligations owed by the Borrower or any Restricted Subsidiary to any Cash Management Bank in connection with, or in respect of, any Cash Management Services.

“Cash Management Services” shall mean (a) commercial credit cards, merchant card services, purchase or debit cards, including non-card e-payables services, (b) treasury management services (including controlled disbursement, overdraft, automated clearing house fund transfer services, return items and interstate depository network services) and (c) any other demand deposit or operating account relationships or other cash management services, including any Cash Management Agreement.

“Casualty Event” shall mean, with respect to any Collateral, (a) any damage to, destruction of, or other casualty or loss involving, any property or asset or (b) any seizure, condemnation, confiscation or taking under the power of eminent domain of, or any requisition of title or use of, or relating to, or any similar event in respect of, any property or asset.

“Change in Law” shall mean the occurrence after the date of this Agreement or, with respect to any Lender, such later date on which such Lender becomes a party to this Agreement, (a) the adoption of any law, treaty, order, policy, rule or regulation after the Closing Date, (b) any change in any law, treaty, order, policy, rule or regulation or in the interpretation, implementation or application thereof by any Governmental Authority after the Closing Date or (c) compliance by any Lender or a Letter of Credit Issuer (or, for purposes of Section 2.10(c), by any lending office of such Lender or by such Lender’s or the Letter of Credit Issuer’s holding company, if any) with any guideline, request, directive or order enacted or promulgated after the Closing Date by any central bank or other Governmental Authority or quasi-Governmental Authority (whether or not having the force of law); provided that notwithstanding anything herein to the contrary, (x) the Dodd-Frank Wall Street Reform and Consumer Protection Act, and all requests, rules, guidelines or directives thereunder or issued in connection therewith and (y) all requests, rules, guidelines or directives promulgated by the Bank for International Settlements, the Basel Committee on Banking Regulations and Supervisory Practices (or any successor or similar authority) or the United States or foreign regulatory authorities, in each case, pursuant to Basel III, and all guidelines, requests, directives, orders, rules and regulations adopted, enacted or promulgated in connection therewith shall be deemed to have gone into effect after the Closing Date regardless of the date adopted, enacted or promulgated and shall be included as a Change in Law only to the extent a Lender is imposing applicable increased costs or costs in connection with capital adequacy and liquidity requirements similar to those described in Section 2.10(a)(ii) and Section 2.10(c) generally on other borrowers of loans under United States reserve-based credit facilities.

“Change of Control” shall mean and be deemed to have occurred if:

(a) at any time prior to a Qualified IPO, (x) the Permitted Holders shall at any time cease, directly or indirectly, to have the power to vote or direct the voting of at least 35% of the Voting Stock of the Borrower or (y) any Person, entity or “group” (within the meaning of Section 13(d) or 14(d) of the Exchange Act, but excluding any employee benefit plan of such Person, entity or “group” and its Subsidiaries and any Person or entity acting in its capacity as trustee, agent or other fiduciary or administrator of any such plan), other than the Permitted Holders, shall at any time have acquired direct or

13

indirect beneficial ownership (as defined in Rules 13(d)-3 and 13(d)-5 under the Exchange Act) of a percentage of the voting power of the outstanding Voting Stock of the Borrower that is greater than the percentage of such voting power of such Voting Stock in the aggregate, directly or indirectly, beneficially owned by the Permitted Holders, or

(b) at any time on and after a Qualified IPO, any Person, entity or “group” (within the meaning of Section 13(d) or 14(d) of the Exchange Act, but excluding any employee benefit plan of such Person, entity or “group” and their respective Subsidiaries and any Person or entity acting in its capacity as trustee, agent or other fiduciary or administrator of any such plan), other than the Permitted Holders, shall at any time have acquired direct or indirect beneficial ownership (as defined in Rules 13(d)-3 and 13(d)-5 under the Exchange Act) of voting power of the outstanding Voting Stock of the Borrower having more than the greater of (i) 35% of the ordinary voting power for the election of directors of the Borrower and (ii) the percentage of the ordinary voting power for the election of directors of the Borrower owned in the aggregate, directly or indirectly, beneficially, by the Permitted Holders, unless in the case of either clause (a) or (b) above, the Permitted Holders have, at such time, the right or the ability by voting power, contract or otherwise to elect or designate for election at least a majority of the members of the Board of Directors of the Borrower, or

(c) a “change of control” (or similar event) shall occur under any Indebtedness for borrowed money permitted under Section 10.1 with an outstanding principal amount in excess of $75,000,000 or any Permitted Refinancing Indebtedness in respect of any of the foregoing with an outstanding principal amount in excess of $75,000,000.

Notwithstanding the foregoing, for the avoidance of doubt, a Change of Control shall not occur as a result of the IPOCo Transactions, the Qualified IPO and any transactions relating thereto, including, without limitation, (i) the contribution of the Stock and/or Stock Equivalents of the Borrower to IPOCo or (ii) any transaction in which the Borrower remains a subsidiary of IPOCo but one or more intermediate holding companies between the Borrower and IPOCo are added, liquidated, merged or consolidated out of existence (except, after giving effect to a Qualified IPO, as a result of the circumstances described in clause (b) above).

Notwithstanding the preceding or any provision of Section 13d-3 of the Exchange Act, (i) a Person or group shall not be deemed to beneficially own Stock or Stock Equivalents subject to a stock or asset purchase agreement, merger agreement, option agreement, warrant agreement or similar agreement (or voting or option or similar agreement related thereto) until the consummation of the acquisition of the Stock or Stock Equivalents in connection with the transactions contemplated by such agreement, (ii) if any group includes one or more Permitted Holders, the issued and outstanding Stock or Stock Equivalents of the Borrower owned, directly or indirectly, by any Permitted Holders that are part of such group shall not be treated as being beneficially owned by such group or any other member of such group for purposes of determining whether a Change of Control has occurred and (iii) a Person or group will not be deemed to beneficially own the Stock or Stock Equivalents of another Person as a result of its ownership of the Stock or Stock Equivalents or other securities of such other Person’s parent entity (or related contractual rights) unless it owns 50% or more of the total voting power of the Stock or Stock Equivalents entitled to vote for the election of directors of such parent entity having a majority of the aggregate votes on the board of directors (or similar body) of such

14

parent entity. No Change of Control will be deemed to have occurred unless and until such Change of Control has actually been consummated.

“Class” shall mean (i) with respect to Commitments or Loans, those of such Commitments or Loans that have the same terms and conditions (without regard to differences in the Type of Loan, Interest Period, original issue discount, upfront fees or similar fees paid or payable in connection with such Commitments or Loans, or differences in tax treatment (e.g., “fungibility”)); provided that such Commitments or Loans may be designated in writing by the Administrative Agent, the Borrower and Lenders holding such Commitments or Loans as a separate Class from other Commitments or Loans that have the same terms and conditions and (ii) with respect to Lenders, those of such Lenders that have Commitments or Loans of a particular Class.

“Closing Date” shall mean May 6, 2021.

“Closing Date Refinancing” shall have the meaning provided in the recitals to this Agreement.

“Closing Date Unsecured Notes” has the meaning provided in the recitals to this Agreement.

“Code” shall mean the Internal Revenue Code of 1986, as amended from time to time.

“Collateral” shall have the meaning provided for such term in each of the Security Documents; provided that with respect to any Mortgages, “Collateral”, as defined herein, shall include “Mortgaged Property” as defined therein.

“Collateral Agent” shall mean Wells Fargo Bank, National Association, as collateral agent under the Security Documents, or any successor collateral agent appointed in accordance with the provisions of Section 12.9.

“Collateral Coverage Minimum” shall mean that the Mortgaged Properties represent at least 85% of the PV-9 of the Credit Parties’ total Proved Reserves, included, as of the Closing Date, in the Initial Reserve Report, and, thereafter, in the most recent Reserve Report delivered pursuant to Section 9.14.

“Commitment” shall mean, with respect to each Lender, the commitment of such Lender to make Loans and to acquire participations in Letters of Credit hereunder, as such commitment may be modified from time to time under this Agreement, including pursuant to assignments by or to such Lender pursuant to Section 13.6(b). The amount of each Lender’s Commitment shall at any time be the least of (a) such Lender’s Maximum Credit Amount, (b) such Lender’s Commitment Percentage of the then effective Borrowing Base, and (c) such Lender’s Elected Commitment Amount.

“Commitment Fee” shall have the meaning provided in Section 4.1(a).

“Commitment Fee Rate” shall mean, for any day, with respect to the Available Commitment on any day, the applicable rate per annum set forth next to the row heading

15

“Commitment Fee Rate” in the definition of “Applicable Margin” and based upon the Borrowing Base Utilization Percentage in effect on such day.

“Commitment Percentage” shall mean, at any time, for each Lender, the percentage obtained by dividing (a) such Lender’s Commitment at such time by (b) the amount of the Total Commitment at such time; provided that at any time when the Total Commitment shall have been terminated, each Lender’s Commitment Percentage shall be the percentage obtained by dividing (i) such Lender’s Total Exposure at such time by (ii) the aggregate Total Exposures of all Lenders at such time.

“Commodity Exchange Act” shall mean the Commodity Exchange Act (7 U.S.C. § 1 etseq.), as amended from time to time, and any successor statute.

“Compliance Certificate” shall mean the Compliance Certificate substantially in the form of Exhibit B.

“Confidential Information” shall have the meaning provided in Section 13.16.

“Consolidated EBITDAX” shall mean, for any period, Consolidated Net Income for such period, plus:

(a)    without duplication and to the extent already deducted (and not added back) in arriving at such Consolidated Net Income, the sum of the following amounts for the Borrower and the Restricted Subsidiaries for such period:

(i)    total interest expense and, to the extent not reflected in such total interest expense, any losses on Hedging Obligations or other derivative instruments entered into for the purpose of hedging interest rate risk (net of interest income and gains on such Hedging Obligations), bank fees, deferred financing fees, costs of surety bonds in connection with financing activities, commissions, discounts, yield and other fees and charges related to financing activities (including letters of credit),

(ii)    provision for taxes based on income, profits (including any margin tax related thereto) or capital, including U.S. federal, state, non-U.S., franchise, excise, property and similar taxes and foreign withholding taxes (including (i) any future taxes or other levies which replace or are intended to be in lieu of such taxes and any penalties and interest related to such taxes or arising from tax examinations and (ii) the amount of distributions actually made in accordance with Section 10.6(f)(ix)) paid or accrued during such period, including any penalties and interest relating to any tax examinations, and the net tax expense associated with any adjustments made pursuant to the definition of Consolidated Net Income,

(iii)    depreciation, depletion and amortization, including the amortization of intangible assets established through purchase accounting and the amortization of deferred financing fees or costs, and commissions, fees and expenses and amortization of Capitalized Software Expenditures and amortization of unrecognized prior service costs and actuarial gains and losses to pensions and other post-employment benefits of such Person and its Restricted Subsidiaries for

16

such period on a consolidated basis and otherwise determined in accordance with GAAP,

(iv)    Non-Cash Charges,

(v)    the amount of any reductions in arriving at Consolidated Net Income resulting from the application of Accounting Standards Codification Topic No. 810, Consolidation,

(v)    restructuring charges, accruals or reserves or related charges (including restructuring costs related to acquisitions after the Closing Date), equity-based or non-cash compensation charges or expenses including any such charges or expenses arising from grants of stock appreciation or similar rights, stock options, restricted stock or other rights, retention charges (including charges or expenses in respect of incentive plans), severance costs, costs relating to initiatives aimed at profitability improvement, costs or reserves associated with improvements to accounting functions and integration and facilities opening costs or any one-time costs incurred in connection with acquisitions and investments,

(vi)    the amount of management, monitoring, consulting, advisory and similar fees and indemnities and related expenses (it being understood that this clause (vi) is not intended to address ordinary course general and administrative expenses) paid or accrued in such period to (or on behalf of) the Sponsor to the extent otherwise permitted by Section 9.9,

(vii)    exploration expenses or costs and accretion of asset retirement obligations,

(viii)    any costs or expenses incurred pursuant to any management equity plan or stock option plan or any other management or employee benefit plan or agreement or any equity subscription or equity holder agreement, to the extent that such costs or expenses are funded with cash proceeds contributed to the capital of the Borrower or net cash proceeds of an issuance of Stock or Stock Equivalents of the Borrower (other than Disqualified Stock),

(ix)    to the extent covered by insurance and directly or indirectly reimbursed, or, so long as the Borrower has made a determination that there exists reasonable evidence that such amount will in fact be reimbursed by the insurer and only to the extent that such amount is (A) not denied by the applicable carrier in writing within 180 days and (B) in fact reimbursed within 365 days of the date of such evidence (with a deduction for any amount so added back to the extent not so reimbursed within such 365 days) reimbursable by a third party, expenses with respect to liability or casualty events or business interruption,

(x)    losses on asset Dispositions, disposals or abandonments (other than asset Dispositions, disposals or abandonments in the ordinary course of business),

17

(xi)    cash receipts (or any netting arrangements resulting in reduced cash expenditures) not representing Consolidated EBITDAX in any period to the extent non-cash gains relating to such income were deducted in the calculation of Consolidated EBITDAX pursuant to paragraph (b) below for any previous period and not added back,

(xii)    the amount of “run rate” revenue enhancements, cost savings, operating expense reductions and savings from synergies (x) related to the Transactions projected by the Borrower in good faith to result from actions that have been taken, or with respect to which substantial steps have been taken or are expected to be taken (in the good faith determination of the Borrower), within 36 months after the Closing Date or (y) related to mergers and other business combinations, acquisitions, investments, dispositions, divestitures, restructurings, operating improvements, cost savings initiatives and other similar transactions or initiatives (including the modification and renegotiation of contracts and other arrangements) consummated after the Closing Date and projected by the Borrower in good faith to result from actions that have been taken or with respect to which substantial steps have been taken, or are expected to be taken (in the good faith determination of the Borrower) within 36 months after consummation of such merger or other business combination, acquisition, divestiture, restructuring, operating improvement or cost savings initiative or other similar initiative that have been taken or with respect to which substantial steps have been taken or are expected to be taken (in the good faith determination of the Borrower), and projected by the Borrower in good faith to result within 36 months after such actions are taken, in each case, calculated on a pro forma basis as though such revenue enhancements, cost savings, operating expense reductions, and savings from synergies had been realized on the first day of such period, as if such revenue enhancements, cost savings, operating expense reductions and savings from synergies were realized during the entirety of such period, net of the amount of actual benefits realized during such period from such actions; provided that (A) such “run rate” revenue enhancements, cost savings, operating expense reductions and savings from synergies are reasonably identifiable and factually supportable in the good faith judgment of the Borrower and certified by an Authorized Officer of the Borrower and (B) no revenue enhancements, cost savings, operating expense reductions and savings from synergies shall be added pursuant to this clause (xii) to the extent duplicative of any expenses or charges otherwise added to Consolidated EBITDAX, whether through a pro forma adjustment or otherwise, for such period,

(xiii)    [reserved],

(xiv)    the amount of any loss attributable to a new plant or facility, until the date that is 12 months after the date of commencing construction of or acquiring such plant or facility, as the case may be; provided that (A) such losses are reasonably identifiable and factually supportable and certified by an Authorized Officer of the Borrower and (B) losses attributable to such plant or facility after 12 months from the date of commencing such construction of or

18

acquiring such plant or facility, as the case may be, shall not be included in this clause (xiv), and

(xv)    costs associated with preparations for and implementation of Public Company Compliance,

less

(b)    without duplication and to the extent included in arriving at such Consolidated Net Income, the sum of the following amounts for such period:

(i)    non-cash gains (excluding any non-cash gain to the extent it represents the reversal of an accrual or reserve for a potential cash item that reduced Consolidated EBITDAX in any prior period),

(ii)    gains on asset Dispositions, disposals and abandonments,

(iii)    cash expenditures (or any netting arrangements resulting in increased cash expenditures) not deducted in arriving at Consolidated EBITDAX in any period to the extent non-cash losses relating to such income were added in the calculation of Consolidated EBITDAX pursuant to paragraph (a) above for any previous period and not deducted,

(iv)    in each case, as determined on a consolidated basis for the Borrower and the Restricted Subsidiaries in accordance with GAAP; provided that:

(A)    there shall be included in determining Consolidated EBITDAX for any period, without duplication, (x) the Acquired EBITDAX of any Person or business or attributable to any property or asset, acquired by the Borrower or any Restricted Subsidiary during such period (but not the Acquired EBITDAX of any related Person or business or any Acquired EBITDAX attributable to any assets or property, in each case to the extent not so acquired) to the extent not subsequently sold, transferred or otherwise Disposed of by the Borrower or such Restricted Subsidiary (each such Person, business, property or asset acquired and not subsequently so Disposed of, an “Acquired Entity or Business”) and the Acquired EBITDAX of any Unrestricted Subsidiary that is converted into a Restricted Subsidiary during such period (each, a “Converted Restricted Subsidiary”), based on the actual (or, at the election of the Borrower, if the annualized portion of Acquired EBITDAX for the most recent portion of such period is a more appropriate indicator of future performance than Acquired EBITDAX for such period (as determined by the Borrower in good faith), the annualized portion of) Acquired EBITDAX of such Pro Forma Entity for such period (including the portion thereof occurring prior to such acquisition or conversion) determined on a historical Pro Forma Basis, and (y) for the purposes of the definition of the term “Permitted Acquisition” and the calculation of the Consolidated Total Debt to

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Consolidated EBITDAX Ratio (including, without limitation, the calculation for purposes of Section 10.11), but without limiting the adjustments included in the definition of Consolidated EBITDAX, an adjustment equal to the amount of the Pro Forma Adjustment with respect to such Acquired Entity or Business shall be added back to Consolidated EBITDAX for such period (including the portion thereof occurring prior to such acquisition or conversion) as specified in a certificate executed by an Authorized Officer and delivered to the Administrative Agent (for further delivery to the Lenders), and

(B)    to the extent included in Consolidated Net Income, there shall be excluded in determining Consolidated EBITDAX for any period, the Disposed EBITDAX of any Person or business or attributable to any property or asset (other than an Unrestricted Subsidiary) sold, transferred, abandoned or otherwise Disposed of or closed or classified as discontinued operations (but if such operations are classified as discontinued due to the fact that they are subject to an agreement to dispose of such operations, only when and to the extent such operations are actually disposed of) by the Borrower or any Restricted Subsidiary during such period (each such Person, business, property or asset so sold or Disposed of or closed, a “Sold Entity or Business”), and the Disposed EBITDAX of any Restricted Subsidiary that is converted into an Unrestricted Subsidiary during such period (each, a “Converted Unrestricted Subsidiary”) based on the actual Disposed EBITDAX of such Sold Entity or Business for such period (including the portion thereof occurring prior to such sale, transfer, abandonment or Disposition, closure or conversion).

Notwithstanding the foregoing, the aggregate amount of add-backs made pursuant to subclause (xii) of clause (a) above in any Test Period shall not exceed 15% of Consolidated EBITDAX (prior to giving effect to such add-backs) for such Test Period and the Borrower shall deliver reasonable supporting detail regarding such add-backs in the form of an exhibit reasonably acceptable to the Administrative Agent.

Consolidated EBITDAX shall be calculated for each four-fiscal quarter period using the Consolidated EBITDAX for the four most recently ended fiscal quarters. Notwithstanding anything to the contrary contained herein, (x) for purposes of determining Consolidated EBITDAX under this Agreement for any period that includes any of the fiscal quarters ended March 31, 2020, June 30, 2020, September 30, 2020 and December 31, 2020, Consolidated EBITDAX for such fiscal quarters shall be $143,367,297, $129,544,637, $133,841,136, and $134,639,893, respectively, in each case, as may be subject to add-backs and adjustments (without duplication) for the applicable Test Period (to the extent such add-backs and adjustments are not otherwise included in the foregoing amount specified for the applicable fiscal quarter) and (y) Consolidated EBITDAX for the fiscal quarter ended March 31, 2021 shall be calculated in accordance with this definition of “Consolidated EBITDAX”.

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For the avoidance of doubt, Consolidated EBITDAX shall be calculated, including pro forma adjustments, in accordance with Section 1.10.

“Consolidated Net Income” shall mean, for any period, the net income (loss) attributable to the Borrower and the Restricted Subsidiaries for such period determined on a consolidated basis in accordance with GAAP, excluding, without duplication,

(a)    any extraordinary, unusual or non-recurring charges and gains for such period (less all fees and expenses relating thereto), including any restructuring costs, charges, accruals or reserves (including restructuring and integration costs related to acquisitions and adjustments to existing reserves, and in each case, whether or not classified as such under GAAP) and any unusual or non-recurring operating expenses directly attributable to the implementation of strategic initiatives, cost-savings initiatives or business optimization (including costs associated with the implementation or adoption of business optimization programs, new systems design, retention charges, system establishment costs and implementation costs, project start-up costs, new financial reporting, and accounting or information systems expected to result in business optimization), severance costs, relocation costs, signing costs, one-time compensation costs and expenses, consulting fees, retention or completion bonuses, executive recruiting costs, transition costs, costs related to the integration, opening, pre-opening, closure and/or consolidation of facilities and fixed assets, costs and expenses incurred in connection with non-ordinary course product and intellectual property development and costs from curtailments or modifications to pension and post-retirement employee benefit plans for such period,

(b)    (i) the cumulative effect of a change in accounting principles during such period whether effected through a cumulative effect adjustment or a retroactive application, in accordance with GAAP, (ii) any non-cash gains, losses, income and expenses resulting from fair value accounting required by the applicable standard under GAAP and related interpretations, (iii) non-cash charges for deferred tax asset valuation allowances shall be excluded (except to the extent reversing a previously recognized increase to net income); provided, that the foregoing shall exclude any adjustments resulting from (x) effects of adjustments to accruals and reserves during a prior period relating to any change in methodology calculating reserves, rebates or other chargebacks and (y) the application of Accounting Standards Codification Topic No. 460, Guarantees, or any comparable regulation,

(c)    gains (losses) on asset Dispositions, disposals or abandonments (other than asset Dispositions, disposals or abandonments in the ordinary course of business) provided that the exclusion for the discontinuance of discontinued operations held for sale shall be at the option of the Borrower pending such sale,

(d)    Transaction Expenses incurred prior to or on or about the Closing Date,

(e)    any fees and expenses incurred during such period, or any amortization thereof for such period, in connection with any acquisition, investment, recapitalization, asset Disposition, issuance, incurrence or Refinancing of debt, issuance of equity securities, refinancing transaction or amendment or other modification of any debt instrument (in each case, including any such transaction consummated prior to the

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Closing Date and any such transaction undertaken but not completed) and any charges or non-recurring acquisition costs incurred during such period as a result of any such transaction,

(f)    any net after tax effect on income (or loss) for such period attributable to the early extinguishment of Indebtedness, Hedging Obligations or other derivative instruments,

(g)    any unrealized income (or loss) for such period attributable to Hedging Obligations or other derivative instruments,

(h)    accruals and reserves established or adjusted, or other charges required as a result of, the adoption or modification of accounting policies during such period,

(i)    any non-cash liabilities recorded in connection with stock-based, partnership interest-based or similar incentive-based compensation awards or arrangements, including without limitation (i) any equity or phantom equity based or non-cash compensation charge or expense, including any charge or expense arising from grants of stock appreciation rights, equity incentive programs or similar rights, stock options, restricted stock or other rights to, and any cash charges associated with equity incentives or other long term incentive compensation plans (including under the Borrower’s deferral compensation arrangements), the rollover, acceleration, or payout of, Stock or Stock Equivalents by management, other employees or business partners of the Borrower or of a Restricted Subsidiary or any parent entity, (ii) noncash compensation expense resulting from the application of Accounting Standards Codification Topic No. 718, Compensation—Stock Compensation or Accounting Standards Codification Topic 505-50, Equity-Based Payments to Non-Employees and (iii) any income (loss) attributable to deferred compensation plans or trusts,

(j)    [reserved],

(k)    any net income (or loss) for such period of any Person that is not a Restricted Subsidiary or that is accounted for by the equity method of accounting; provided that Consolidated Net Income of the Borrower shall be increased by the amount of dividends or distributions or other payments that are actually received by the Borrower or a Restricted Subsidiary in cash or Permitted Investments (or to the extent converted into cash or Permitted Investment),

(l)    to the extent covered by insurance and directly or indirectly reimbursed or reimbursable by a third party, and any expenses, charges or losses that are covered by indemnification or other reimbursement provisions in connection with any acquisition, Investment or any sale, conveyance, transfer or other disposition of assets permitted under this Agreement,

(m)    effects of adjustments related to the application of recapitalization accounting or purchase accounting, including applying purchase accounting to inventory, property and equipment, software and other intangible assets and deferred revenue required or permitted by GAAP and related authoritative pronouncements (including the effects of such adjustments pushed down to the Borrower and its Restricted Subsidiaries),

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(n)    accruals and reserves that are established or adjusted in connection with an Investment or an acquisition that are required to be established or adjusted as a result of such Investment or such acquisition, in each case, in accordance with GAAP,

(o)    (i) Non-Cash Charges, (ii) any impairment charges or asset write-off or write-down, in each case pursuant to GAAP, and the amortization of intangibles arising pursuant to GAAP; and (iii) any impairment charges, asset writeoff or write-down, including ceiling test write-downs on Oil and Gas Properties under GAAP or SEC guidelines,

(p)    any non-cash gain (loss) attributable to the mark to market movement in the valuation of Hedging Obligations or other derivative instruments pursuant to FASB Accounting Standards Codification Topic 815—Derivatives and Hedging or mark to market movement of other financial instruments pursuant to FASB Accounting Standards Codification Topic 825—Financial Instruments,

(q)    any net unrealized gain or loss (after any offset) resulting in such period from currency transaction or translation gains or losses including those related to currency remeasurements of Indebtedness (including any net loss or gain resulting from (a) Hedging Obligations for currency exchange risk and (b) resulting from intercompany indebtedness) and any other foreign currency transaction or translation gains and losses, to the extent such gain or losses are non-cash items,

(r)    any non-cash rent expense, and

(s)    earn-out and contingent consideration obligations (including to the extent accounted for as bonuses or otherwise) and adjustments thereof and purchase price adjustments.

In addition, to the extent not already included in the Consolidated Net Income of the Borrower and its Restricted Subsidiaries, Consolidated Net Income shall include the amount of proceeds received or receivable from business interruption insurance, the amount of any expenses or charges incurred by the Borrower or its Restricted Subsidiaries during such period that are, directly or indirectly, reimbursed or reimbursable by a third party, and amounts that are covered by indemnification or other reimbursement provisions in connection with any acquisition, Investment or any sale, conveyance, transfer or other disposition of assets permitted under this Agreement.

“Consolidated Total Debt” shall mean, as of any date of determination, (a) all Indebtedness of the types described in clauses (a) and (b) (other than intercompany Indebtedness owing to the Borrower or any Restricted Subsidiary), clause (d) (but, in the case of clause (d), only to the extent of any unreimbursed drawings under any letter of credit) and clause (f) of the definition thereof, in each case actually owing by the Borrower and the Restricted Subsidiaries on such date and to the extent appearing on the balance sheet of the Borrower determined on a consolidated basis in accordance with GAAP (provided that the amount of any Capitalized Lease Obligations or any such Indebtedness issued at a discount to its face value shall be determined in accordance with GAAP) minus (b) the aggregate amount of Unrestricted Cash listed on the consolidated balance sheet of the Borrower and the Restricted Subsidiaries at such date (provided

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that, at any time the aggregate Total Exposures exceeds 5% of the Loan Limit, the amount deducted from Consolidated Total Debt pursuant to this (b) shall not exceed 10% of the Loan Limit as of such date of determination).

“Consolidated Total Debt to Consolidated EBITDAX Ratio” shall mean, as of any date of determination, the ratio of (a) Consolidated Total Debt as of the last day of the most recent Test Period ended on or prior to such date of determination to (b) Consolidated EBITDAX for such Test Period.

“Contractual Requirement” shall have the meaning provided in Section 8.3.

“Controlled Investment Affiliate” shall mean, as to any Person, any other Person, other than any Sponsor, which directly or indirectly is in Control of, is Controlled by, or is under common Control with such Person and is organized by such Person (or any Person Controlling such Person) primarily for making direct or indirect equity or debt investments in the Borrower and/or other companies.

“Control” means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of such other Person, whether through the ownership of voting securities, by contract or otherwise. “Controlling” and “Controlled” shall have meanings correlative thereto.

“Converted Restricted Subsidiary” shall have the meaning provided in the definition of the term “Consolidated EBITDAX.”

“Converted Unrestricted Subsidiary” shall have the meaning provided in the definition of the term “Consolidated EBITDAX.”

“Corresponding Tenor” with respect to any Available Tenor means, as applicable, either a tenor (including overnight) or an interest payment period having approximately the same length (disregarding business day adjustment) as such Available Tenor.

“Covered Entity” shall mean any of the following: (i) a “covered entity” as that term is defined in, and interpreted in accordance with, 12 C.F.R. § 252.82(b); (ii) a “covered bank” as that term is defined in, and interpreted in accordance with, 12 C.F.R. § 47.3(b); or (iii) a “covered FS1” as that term is defined in, and interpreted in accordance with, 12 C.F.R. § 382.2(b).

“Covered Party” shall have the meaning assigned to such term in Section 13.28(b).

“Credit Documents” shall mean this Agreement, the Guarantee, the Security Documents, each Letter of Credit, any promissory notes issued by the Borrower under this Agreement, any Extension Amendment and any Customary Intercreditor Agreement with respect to the Facility entered into after the Closing Date to which the Collateral Agent is party, and any Incremental Agreement.

“Credit Event” shall mean and include the making (but not the conversion or continuation) of a Loan and the issuance of a Letter of Credit.

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“Credit Party” shall mean each of the Borrower and the Guarantors.

“Cure Amount” shall have the meaning provided in Section 11.13(a).

“Cure Deadline” shall have the meaning provided in Section 11.13(a).

“Cure Right” shall have the meaning provided in Section 11.13(a).

“Current Assets” shall mean, at any date, without duplication, the sum of all amounts that would, in conformity with GAAP, be set forth opposite the caption “total current assets” (or any like caption) on a consolidated balance sheet of the Borrower and the Restricted Subsidiaries at such date, plus the Available Commitment, but excluding (a) all non-cash assets under ASC 815 and ASC 842 and (b) the aggregate amount of any deposits (in each case, whether in cash or otherwise) posted by the Borrower or any of its Restricted Subsidiaries to secure Hedging Obligations owing by such Persons or to cover market exposures.

“Current Liabilities” shall mean, at any date, without duplication, the sum of all amounts that would, in conformity with GAAP, be set forth opposite the caption “total current liabilities” (or any like caption) on a consolidated balance sheet of the Borrower and the Restricted Subsidiaries on such date, but excluding, without duplication, (a) the liabilities related to the return of any deposits (in each case, whether cash or otherwise) posted to the Borrower or any of its Restricted Subsidiaries to secure any counterparty’s Hedging Obligations owing to the Borrower or any of its Restricted Subsidiaries or to cover such counterparty’s market exposure, (b) the current portion of any Funded Debt, (c) all Indebtedness (including Letters of Credit Outstanding) under this Agreement, or under any Permitted Refinancing Indebtedness in respect of either thereof, in each case, to the extent otherwise included therein, (d) the current portion of interest, (e) the current portion of current and deferred income taxes or any amounts payable as tax distributions, (f) any non-cash liabilities recorded in connection with stock-based, partnership interest-based or similar incentive-based compensation awards or arrangements, (g) any other liabilities that are not Indebtedness and will not be settled in cash or Permitted Investments during the next succeeding twelve month period after such date, (h) the effects from applying purchase accounting, (i) non-cash obligations under ASC 815 and ASC 842, (j) Indebtedness of a Credit Party incurred for the purpose of funding any deposit paid in the ordinary course of business to a seller of Oil and Gas Properties (or its designee) in advance of the acquisition thereof by any Credit Party while such Credit Party is awaiting the receipt of the proceeds of a capital call, provided that such Indebtedness is repaid in full within 20 Business Days of being incurred, and (k) Indebtedness of a Credit Party for the purpose of funding working capital while such Credit Party is awaiting the receipt of a capital call, provided that such Indebtedness is repaid in full within 45 Business Days of being incurred.

“Current Ratio” shall mean, as of any date of determination, the ratio of (a) Current Assets as of the last day of the most recent Test Period ended on or prior to such date of determination to (b) Current Liabilities as of the last day of such Test Period.

“Customary Intercreditor Agreement” shall mean an intercreditor agreement substantially in the form of Exhibit C (which agreement in such form or with immaterial changes thereto the Collateral Agent is irrevocably authorized (and each Lender hereby irrevocably directs the

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Collateral Agent) to enter into) or otherwise reasonably acceptable to the Administrative Agent and the Borrower), the subsidiaries of the Borrower from time to time party thereto, the Collateral Agent and one or more collateral agents or representatives for the holders of Indebtedness that is permitted under Section 10.2(w) to be, and intended to be, secured on a junior basis to the Obligations.

“Daily Simple SOFR” means, for any day, SOFR, with the conventions for this rate (which will include a lookback) being established by the Administrative Agent in accordance with the conventions for this rate selected or recommended by the Relevant Governmental Body for determining “Daily Simple SOFR” for syndicated business loans; provided that, if the Administrative Agent decides that any such convention is not administratively feasible for the Administrative Agent, then the Administrative Agent may establish another convention in its reasonable discretion.

“Debt Fund Affiliate” shall mean any Affiliate of the Sponsor that is a bona fide diversified debt fund and is not either (a) a natural person or (b) the Borrower, a Subsidiary of the Borrower.

“Default” shall mean any event, act or condition that with notice or lapse of time, or both, would constitute an Event of Default.

“Default Rate” shall have the meaning provided in Section 2.8(c).

“Default Right” has the meaning assigned to that term in, and shall be interpreted in accordance with, 12 C.F.R. §§ 252.81, 47.2 or 382.1, as applicable.

“Defaulting Lender” shall mean any Lender whose acts or failure to act, whether directly or indirectly, cause it to meet any part of the definition of “Lender Default”.

“Designated Persons” shall mean any Person:

(i)    named as a “Specially Designated National and Blocked Person” (“SDN”) on the most current list (the “SDN List”) published by OFAC at its official website or any replacement website or other replacement official publication of such list; or is otherwise the subject of any Sanctions Laws and Regulations; or

(ii)    in which any Person on the SDN List has 50% or greater ownership interest or that is otherwise controlled by an SDN.

“Disposed EBITDAX” shall mean, with respect to any Sold Entity or Business or any Converted Unrestricted Subsidiary for any period, the amount for such period of Consolidated EBITDAX of such Sold Entity or Business or Converted Unrestricted Subsidiary (determined as if references to the Borrower and the Restricted Subsidiaries in the definition of Consolidated EBITDAX were references to such Sold Entity or Business or Converted Unrestricted Subsidiary and its respective Subsidiaries), all as determined on a consolidated basis for such Sold Entity or Business or Converted Unrestricted Subsidiary, as the case may be.

“Disposition” shall have the meaning provided in Section 10.4. “Dispose” and “Disposed” shall have a correlative meaning.

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“Disqualified Institution” shall mean (i) those Persons that have been specified in writing by the Borrower to the Administrative Agent prior to the Closing Date and (ii) any competitor of the Borrower and its Subsidiaries and any Affiliates of such competitor that are operating companies (or Affiliates of operating companies) subsequently identified in writing by the Borrower, other than their respective financial investors that are not operating companies and other than any Debt Fund Affiliate. The list of Disqualified Institutions shall be specified on a schedule that is held with the Administrative Agent, which shall be made available to any Lender upon request to the Administrative Agent, subject to customary confidentiality requirements. Notwithstanding the foregoing, “Disqualified Institution” shall not include any Person that (i) has acquired an assignment or participation interest, (ii) entered into a trade for either of the foregoing or (iii) becomes a competitor of the Borrower, in each case, before such entity is added to the list of Disqualified Institutions.

“Disqualified Stock” shall mean, with respect to any Person, any Stock or Stock Equivalents of such Person which, by its terms, or by the terms of any security into which it is convertible or for which it is putable or exchangeable, or upon the happening of any event, matures or is mandatorily redeemable (other than solely for Stock or Stock Equivalents that is not Disqualified Stock), other than as a result of a change of control or asset sale, pursuant to a sinking fund obligation or otherwise, or is redeemable at the option of the holder thereof (other than as a result of a change of control or asset sale to the extent the terms of such Stock or Stock Equivalents provide that such Stock or Stock Equivalents shall not be required to be repurchased or redeemed until the Latest Maturity Date has occurred or such repurchase or redemption is otherwise permitted by this Agreement (including as a result of a waiver hereunder)), in whole or in part, in each case prior to the date that is 91 days after the Latest Maturity Date hereunder; provided that, if such Stock or Stock Equivalents are issued pursuant to any plan for the benefit of future, present or former employees, directors, officers, members of management or consultants (or their respective Controlled Investment Affiliates or immediate family members) of the Borrower or its Subsidiaries (or any direct or indirect parent thereof) or by any such plan to such employees, directors, officers, members of management or consultants (or their respective Controlled Investment Affiliates or immediate family members), such Stock or Stock Equivalents shall not constitute Disqualified Stock solely because it may be required to be repurchased by the Borrower or its Subsidiaries (or any direct or indirect parent thereof) in order to satisfy applicable statutory or regulatory obligations; provided, further, that any Stock or Stock Equivalents held by any future, present or former employee, director, officer, manager or consultant of the Borrower, any of its Subsidiaries or any of its direct or indirect parent companies or any other entity in which the Borrower or a Restricted Subsidiary has an Investment and is designated in good faith as an “affiliate” by the board of directors or managers of the Borrower, in each case pursuant to any equity holders’ agreement, management equity plan or stock incentive plan or any other management or employee benefit plan or agreement shall not constitute Disqualified Stock solely because it may be required to be repurchased by the Borrower or its Subsidiaries.

“Dividends” shall have the meaning provided in Section 10.6.

“Dollars” and “$” shall mean dollars in lawful currency of the United States of America.

“Domestic Subsidiary” shall mean each Subsidiary of the Borrower that is organized under the laws of the United States or any state thereof, or the District of Columbia.

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“Drawing” shall have the meaning provided in Section 3.4(b).

“Early Opt-in Election” means, if the then-current Benchmark is LIBOR, the occurrence of:

(a)    a notification by the Administrative Agent to (or the request by the Borrower to the Administrative Agent to notify) each of the other parties hereto that at least five currently outstanding Dollar-denominated syndicated credit facilities at such time contain (as a result of amendment or as originally executed) a SOFR-based rate (including SOFR, a term SOFR or any other rate based upon SOFR) as a benchmark rate (and such syndicated credit facilities are identified in such notice and are publicly available for review), and

(b)    the joint election by the Administrative Agent and the Borrower to trigger a fallback from LIBOR and the provision by the Administrative Agent of written notice of such election to the Lenders.

“EEA Financial Institution” shall mean (a) any credit institution or investment firm established in any EEA Member Country which is subject to the supervision of an EEA Resolution Authority, (b) any entity established in an EEA Member Country which is a parent of an institution described in clause (a) of this definition, or (c) any financial institution established in an EEA Member Country which is a subsidiary of an institution described in clauses (a) or (b) of this definition and is subject to consolidated supervision with its parent.

“EEA Member Country” shall mean any of the member states of the European Union, Iceland, Liechtenstein, and Norway.

“EEA Resolution Authority” shall mean any public administrative authority or any person entrusted with public administrative authority of any EEA Member Country (including any delegee) having responsibility for the resolution of any EEA Financial Institution.

“Elected Commitment Amount” shall mean, (a) with respect to each Lender that is a Lender on the Closing Date, the amount set forth opposite such Lender’s name on Schedule 1.1(a) as such Lender’s “Elected Commitment Amount” and (b) in the case of any Lender that becomes a Lender after the Closing Date, the amount specified as such Lender’s “Elected Commitment Amount” in the Assignment and Acceptance or in the Incremental Agreement pursuant to which such Lender assumed a portion of the Total Commitment, in each case as the same may be changed from time to time pursuant to the terms of this Agreement.

“Electronic Record” has the meaning assigned to that term in, and shall be interpreted in accordance with, 15 U.S.C. 7006.

“Electronic Signature” has the meaning assigned to that term in, and shall be interpreted in accordance with, 15 U.S.C. 7006.

“Engineering Reports” shall have the meaning provided in Section 2.14(c).

“Environmental Claims” shall mean any and all actions, suits, orders, decrees, demands, demand letters, claims, liens, notices of noncompliance, violations or potential responsibility or

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investigation (other than internal reports prepared by or on behalf of the Borrower or any of the Subsidiaries (a) in the ordinary course of such Person’s business or (b) as required in connection with a financing transaction or an acquisition or disposition of real estate) or proceedings arising under or based upon any Environmental Law or any permit required under any such Environmental Law, including, without limitation, (i) any by Governmental Authorities for enforcement, cleanup, removal, response, remedial or other actions or damages pursuant to any applicable Environmental Law and (ii) any by any third party seeking damages, contribution, indemnification, cost recovery, compensation or injunctive relief relating to the presence, release or threatened release of Hazardous Materials or arising from alleged injury to any Person (to the extent relating to human exposure to Hazardous Materials), or the environment including, without limitation, ambient air, surface water, groundwater, land surface and subsurface strata and natural resources such as wetlands.

“Environmental Law” shall mean any applicable federal, state, foreign or local statute, law, rule, regulation, ordinance, code and rule of common law now or hereafter in effect and in each case as amended, and any legally binding judicial or administrative interpretation thereof, including any legally binding judicial or administrative order, consent decree or judgment, relating to the protection of the environment, including, without limitation, ambient air, surface water, groundwater, land surface and subsurface strata and natural resources such as wetlands, or human health or safety (to the extent relating to human exposure to Hazardous Materials), or Hazardous Materials.

“ERISA” shall mean the Employee Retirement Income Security Act of 1974, as amended from time to time. Section references to ERISA are to ERISA as in effect on the Closing Date and any subsequent provisions of ERISA amendatory thereof, supplemental thereto or substituted therefor.

“ERISA Affiliate” shall mean each person (as defined in Section 3(9) of ERISA) that together with the Borrower would be deemed to be a “single employer” within the meaning of Section 414(b) or (c) of the Code or, solely for purposes of Section 302 of ERISA and Section 412 of the Code, is treated as a single employer under Section 414 of the Code.

“Erroneous Payment” shall have the meaning provided in Section 12.16.

“EU Bail-In Legislation Schedule” shall mean the EU Bail-In Legislation Schedule published by the Loan Market Association (or any successor Person), as in effect from time to time.

“Event of Default” shall have the meaning provided in Section 11.

“Excess Cash” means, at any time, the aggregate amount of cash or Permitted Investments of the Borrower and its Restricted Subsidiaries (other than Excluded Cash) in excess of an amount equal to (i) for purposes of Section 5.2(f), 15% of the then effective Borrowing Base or (ii) for purposes of Section 7.2, 10% of the then effective Borrowing Base.

“Exchange Act” shall mean the Securities Exchange Act of 1934, as amended, and the rules and regulations promulgated thereunder.

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“Exchange Rate” shall mean on any day with respect to any currency (other than Dollars), the rate at which such currency may be exchanged into any other currency (including Dollars), as set forth at approximately 11:00 a.m. (London time) on such day on the Reuters World Currency Page for such currency. In the event that such rate does not appear on any Reuters World Currency Page, the Exchange Rate shall be determined by reference to such other publicly available service for displaying exchange rates as may be agreed by the Administrative Agent and the Borrower, or, in the absence of such agreement, such Exchange Rate shall instead be the arithmetic average of the spot rates of exchange of the Administrative Agent in the market where its foreign currency exchange operations in respect of such currency are then being conducted, at or about 11:00 a.m., local time, on such date for the purchase of the relevant currency for delivery two Business Days later.

“Excluded Accounts” shall mean (a) each account all or substantially all of the deposits in which consist of amounts utilized to fund payroll, employee benefit or tax obligations of the Borrower and its Restricted Subsidiaries, (b) fiduciary accounts, trust accounts and suspense accounts of the Borrower and any Restricted Subsidiary holding royalty obligations, (c) escrow accounts or other similar accounts used solely for escrow funds or other deposits in connection with acquisitions or dispositions that are subject to an executed purchase and sale agreement, (d) “zero balance” accounts, (e) accounts of the Borrower and any Restricted Subsidiary constituting cash collateral accounts permitted under Section 10.2(b) (provided that any such account subject to control agreements in favor of the Collateral Agent, for the benefit of the Secured Parties, or otherwise constituting cash collateral in favor of the Collateral Agent, for the benefit of the Secured Parties shall not be an Excluded Account) and (f) other accounts selected by the Borrower and its Restricted Subsidiaries so long as the average daily maximum balance in any such other account over a 30-day period does not at any time exceed $3,500,000; provided that the aggregate daily maximum balance for all such bank accounts excluded pursuant to this clause (f) on any day shall not exceed $17,500,000.

“Excluded Cash” shall mean, as of any date of determination, without duplication, (a) any cash or Permitted Investments to be used (i) to pay obligations of the Borrower or any Restricted Subsidiary then due and owing or to make Dividends, debt prepayments, Investments or other acquisitions not prohibited by this Agreement or (ii) to pay bona fide royalty obligations, working interest obligations, production payments, vendor payments and suspense payments due and owing in each case of clauses (i) and (ii), for which the Borrower or such Restricted Subsidiary (x) has issued checks or has initiated wires or ACH transfers (but which amounts have not, as of such time, been subtracted from the balance in the relevant account of the Borrower or such Restricted Subsidiary) or (y) reasonably anticipates in good faith that it will issue checks or initiate wires or ACH transfers within ten (10) Business Days thereafter, (b) any cash or Permitted Investments held in Excluded Accounts or in other accounts, in each case designated and used solely for one or more of the following purposes: (i) payroll or employee wage and benefit payments, (ii) the payment of taxes, including severance and ad valorem taxes, payroll taxes and other taxes of the Borrower or any Restricted Subsidiary that are due and payable within the existing fiscal quarter, or (iii) to pay trust and fiduciary obligations of the Borrower or any Restricted Subsidiary, (c) any cash or Permitted Investments held for the Cash Collateralization of Letters of Credit, (d) while and to the extent refundable, any cash or Permitted Investments held by the Borrower or any Restricted Subsidiary constituting purchase price deposits pursuant to a binding and enforceable purchase and sale agreement containing

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customary provisions regarding the payment and refunding of such deposits, (e) any cash or Permitted Investments (including any proceeds of a Borrowing) held by the Borrower or any Restricted Subsidiary in good faith to fund any customary deposit in the nature of earnest money with respect to, or the purchase price of, any future acquisition permitted under this Agreement, provided that the Borrower shall have provided written notice of its intention to make such acquisition to the Administrative Agent at or prior to such time and (f) any proceeds of a Borrowing used to make Dividends, debt prepayments, Investments or other acquisitions not prohibited under this Agreement, in each case to the extent the Borrower has provided notice to the Administrative Agent of such purpose on or prior to the date of such Borrowing; provided that, in the case of clauses (e) and (f), such proceeds of a Borrowing shall only constitute Excluded Cash from the date of such Borrowing through and including the tenth Business Day after such Borrowing.

“Excluded Stock” shall mean (a) any Stock or Stock Equivalents with respect to which, in the reasonable judgment of the Administrative Agent (confirmed in writing by notice to the Borrower and the Collateral Agent), the cost or other consequences of pledging such Stock or Stock Equivalents in favor of the Secured Parties under the Security Documents shall be excessive in view of the benefits to be obtained by the Secured Parties therefrom, (b) solely in the case of any pledge of Stock or Stock Equivalents of any Foreign Corporate Subsidiary or FSHCO to secure the Obligations, any Stock or Stock Equivalents that is Voting Stock of such Foreign Corporate Subsidiary or FSHCO in excess of 65% of the Voting Stock of such Subsidiary, (c) any Stock or Stock Equivalents to the extent the pledge thereof would be prohibited by any Requirement of Law, (d) in the case of (i) any Stock or Stock Equivalents of any Subsidiary to the extent the pledge of such Stock or Stock Equivalents is prohibited by Contractual Requirements or (ii) any Stock or Stock Equivalents of any Subsidiary that is not wholly owned by the Borrower and its Restricted Subsidiaries at the time such Subsidiary becomes a Subsidiary, any Stock or Stock Equivalents of each such Subsidiary described in clause (d)(i) or (d)(ii) to the extent (A) that a pledge thereof to secure the Obligations is prohibited by any applicable Contractual Requirement (other than customary non-assignment provisions which are ineffective under the Uniform Commercial Code or other applicable Requirements of Law), (B) any Contractual Requirement prohibits such a pledge without the consent of any other party; provided that this clause (B) shall not apply if (1) such other party is a Credit Party or a wholly owned Restricted Subsidiary or (2) consent has been obtained to consummate such pledge (it being understood that the foregoing shall not be deemed to obligate the Borrower or any Subsidiary to obtain any such consent)) and only for so long as such Contractual Requirement or replacement or renewal thereof is in effect, or (C) a pledge thereof to secure the Obligations would give any other party (other than a Credit Party or a wholly owned Restricted Subsidiary) to any Contractual Requirement governing such Stock or Stock Equivalents the right to terminate its obligations thereunder (other than customary non-assignment provisions that are ineffective under the Uniform Commercial Code or other applicable Requirement of Law), (e) the Stock or Stock Equivalents of any Immaterial Subsidiary (unless a security interest in the Stock or Stock Equivalents of such Subsidiary may be perfected by filing an “all assets” UCC financing statement) and any Unrestricted Subsidiary, (f) the Stock or Stock Equivalents of any Subsidiary of a Foreign Corporate Subsidiary or FSHCO, (g) any Stock or Stock Equivalents of any Subsidiary to the extent that the pledge of such Stock or Stock Equivalents would result in material adverse tax consequences to the Borrower or any Subsidiary as reasonably determined by the Borrower in consultation with the Administrative Agent and (h) any Stock or Stock Equivalents set forth on Schedule 1.1(b) which have been identified on or prior to the Closing Date in writing to the Administrative Agent by an

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Authorized Officer of the Borrower and agreed to by the Administrative Agent; provided, further, that, notwithstanding anything herein to the contrary, the Stock and Stock Equivalents of any Restricted Subsidiary owning Borrowing Base Properties shall not be Excluded Stock.

“Excluded Subsidiary” shall mean (a) each Domestic Subsidiary listed on Schedule 1.1(c) and each future Domestic Subsidiary, in each case, for so long as any such Subsidiary does not constitute a Material Subsidiary, (b) each Domestic Subsidiary that is not a wholly owned Subsidiary on any date such Subsidiary would otherwise be required to become a Guarantor pursuant to the requirements of Section 9.11 (for so long as such Subsidiary remains a non-wholly owned Restricted Subsidiary), (c) [reserved], (d) each Domestic Subsidiary that is prohibited by any applicable Contractual Requirement or Requirement of Law from guaranteeing or granting Liens to secure the Obligations at the time such Subsidiary becomes a Restricted Subsidiary (and for so long as such restriction or any replacement or renewal thereof is in effect) or that would require consent, approval, license or authorization of a Governmental Authority to guarantee or grant Liens to secure the Obligations at the time such Subsidiary becomes a Restricted Subsidiary (unless such consent, approval, license or authorization has been received), (e) each Domestic Subsidiary that is a Subsidiary of a Foreign Corporate Subsidiary, (f) each FSHCO, (g) each other Domestic Subsidiary acquired pursuant to a Permitted Acquisition or other Investment permitted by Section 10.5 financed with secured Indebtedness incurred pursuant to Section 10.1(j) and permitted by the proviso in Section 10.1(j)(iii) and each Restricted Subsidiary thereof that guarantees such Indebtedness to the extent and so long as the financing documentation relating to such Permitted Acquisition or other Investment permitted by Section 10.5 to which such Restricted Subsidiary is a party prohibits such Restricted Subsidiary from guaranteeing or granting a Lien on any of its assets to secure the Obligations, (h) each not-for-profit Subsidiary, (i) each Captive Insurance Subsidiary, (j) [reserved], (k) any other Domestic Subsidiary with respect to which, (x) in the reasonable judgment of the Administrative Agent and the Borrower, the cost or other consequences of providing a Guarantee of the Obligations shall be excessive in view of the benefits to be obtained by the Lenders therefrom or (y) providing such a Guarantee would result in material adverse tax consequences as reasonably determined by the Borrower, and (l) each Unrestricted Subsidiary; provided that, notwithstanding anything herein to the contrary, no Restricted Subsidiary owning Borrowing Base Properties shall be an Excluded Subsidiary.

“Excluded Swap Obligation” shall mean, with respect to any Credit Party, (a) any Swap Obligation if, and to the extent that, all or a portion of the guarantee of such Credit Party pursuant to the Guarantee of, or the grant by such Guarantor of a security interest to secure, such Swap Obligation (or any guarantee pursuant to the Guarantee thereof) is or becomes illegal under the Commodity Exchange Act or any rule, regulation, or order of the Commodity Futures Trading Commission (or the application or official interpretation of any thereof) or (b) any other Swap Obligation designated as an “Excluded Swap Obligation” of such Credit Party as specified in any agreement between the relevant Credit Parties and Hedge Bank applicable to such Swap Obligations. If a Swap Obligation arises under a Master Agreement governing more than one Swap, such exclusion shall apply only to the portion of such Swap Obligation that is attributable to the Swap for which such guarantee or security interest is or becomes excluded in accordance with the first sentence of this definition.

“Excluded Taxes” shall mean, with respect to the Administrative Agent, any Lender or any other recipient of any payment to be made by or on account of any obligation of any Credit

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Party hereunder or under any other Credit Document (each, a “Recipient”), (i) Taxes imposed on or measured by its net income or branch profits (however denominated), and franchise (and similar) Taxes imposed on it, in each case by a jurisdiction (including any political subdivision thereof) as a result of such Recipient being organized in, having its principal office in, or in the case of any Lender, having its applicable lending office in, such jurisdiction, or as a result of any other present or former connection with such jurisdiction (other than any such connection arising solely from this Agreement or any other Credit Documents or any transactions contemplated thereunder), (ii) except in the case of a Lender that is an assignee pursuant to a request by the Borrower under Section 13.7, any U.S. federal withholding Tax imposed on any payment by or on account of any obligation of any Credit Party with respect to an interest in an applicable Loan or Commitment that is required to be imposed on amounts payable to such Lender pursuant to laws in force at the time such Lender acquires such interest in the Loan or Commitment (or designates a new lending office), except to the extent that such Lender (or its assignor, if any) was entitled, immediately prior to the designation of a new lending office (or assignment), to receive additional amounts or indemnification payments from any Credit Party with respect to such withholding Tax pursuant to Section 5.4, (iii) Taxes attributable to such Recipient’s failure to comply with Section 5.4(e) or (iv) any Tax imposed under FATCA.

“Existing Borrowers” shall mean each of the “Borrowers” under and as defined in the Existing Credit Facilities.

“Existing Class” shall have the meaning provided in Section 2.17.

“Existing Commitment” shall have the meaning provided in Section 2.17.

“Existing Credit Facilities” shall mean (i) that certain Amended and Restated Credit Agreement, among Renee Acquisition LLC, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent, dated as of January 31, 2020, as amended by that First Amendment to Amended and Restated Credit Agreement and Borrowing Base Determination Agreement, dated as of July 7, 2020, (ii) that certain Credit Agreement, among Independence Minerals L.P. (f/k/a KFH Royalties L.P.), the guarantors party thereto, the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent, dated as of October 25, 2019, as amended by (A) the First Amendment to Credit Agreement, dated as of July 30, 2020, (B) the Second Amendment to Credit Agreement, dated as of October 15, 2020 and (C) the Third Amendment to Credit Agreement, dated as of March 5, 2021, (iii) that certain Credit Agreement, among Venado EF L.P., the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent, dated as of March 10, 2017, as amended by (A) the First Amendment and Borrowing Base Redetermination Agreement, dated as of May 7, 2018, (B) the Second Amendment and Borrowing Base Redetermination Agreement, dated as of October 29, 2018, (C) the Third Amendment and Borrowing Base Redetermination Agreement, dated as of May 9, 2019, (D) the Fourth Amendment and Borrowing Base Redetermination Agreement, dated as of May 26, 2020 and (E) the Fifth Amendment and Borrowing Base Redetermination Agreement, dated as of December 23, 2020, (iv) that certain Credit Agreement among Bridge Energy LLC, the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent, dated as of July 21, 2017, as amended by (A) the First Amendment to Credit Agreement dated May 23, 2018, (B) the Second Amendment to Credit Agreement dated November 2, 2018, (C) the Third Amendment to Credit Agreement dated as of June 4, 2019 and (D) the Fourth Amendment to Credit Agreement dated as of July 3, 2020, (v) that certain Amended and

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Restated Credit Agreement, among Independence Upstream Holdings L.P. (f/k/a Colt Real Asset Holdings L.P.), as borrower, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent, dated as of June 7, 2019 as amended by (A) the First Amendment to Amended and Restated Credit Agreement and Borrowing Base Redetermination Agreement dated as of July 14, 2020 and (B) the Second Amendment to Amended and Restated Credit Agreement and Borrowing Base Redetermination Agreement dated as of October 15, 2020, (vi) that certain Amended and Restated Credit Agreement, among KNR Resource Investors L.P., as borrower, the lenders party and JPMorgan Chase Bank, N.A., as administrative agent, dated as of June 7, 2019 as amended by the First Amendment to Amended and Restated Credit Agreement and Borrowing Base Redetermination, dated as of July 28, 2020, (vii) that certain Credit Agreement among Newark Acquisition I L.P., as borrower, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent, dated as of May 31, 2018 as amended by (A) the First Amendment to Credit Agreement dated as of July 11, 2018, (B) the Second Amendment to Credit Agreement and Borrowing Base Redetermination Agreement dated as of May 30, 2019 and (C) the Third Amendment to Credit Agreement and Borrowing Base Redetermination Agreement dated as of July 7, 2020 and (viii) that certain Credit Agreement among VOG Palo Verde LP, as borrower, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent, dated as of February 28, 2018 as amended by (A) the First Amendment and Borrowing Base Redetermination Agreement, dated as of October 29, 2018, (B) Second Amendment and Borrowing Base Redetermination Agreement, dated as of May 9, 2019 and (C) the Third Amendment and Borrowing Base Redetermination Agreement, dated as of May 26, 2020.

“Existing Letters of Credit” shall mean each letter of credit existing on the Closing Date and identified on Schedule 1.1(d) and any amendments, extensions and renewals thereof.

“Existing Loans” shall have the meaning provided in Section 2.17.

“Extended Commitments” shall have the meaning provided in Section 2.17.

“Extended Loans” shall have the meaning provided in Section 2.17.

“Extending Lender” shall have the meaning provided in Section 2.17.

“Extension Amendment” shall have the meaning provided in Section 2.17.

“Extension Date” shall have the meaning provided in Section 2.17.

“Extension Election” shall have the meaning provided in Section 2.17.

“Extension Request” shall have the meaning provided in Section 2.17.

“Extension Series” shall mean all Extended Commitments that are established pursuant to the same Extension Amendment (or any subsequent Extension Amendment to the extent such Extension Amendment expressly provides that the Extended Commitments provided for therein are intended to be a part of any previously established Extension Series) and that provide for the same interest margins, extension fees, maturity and other terms.

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“Facility” shall mean this Agreement and the Commitments and the extensions of credit made hereunder.

“Fair Market Value” shall mean, with respect to any asset or group of assets on any date of determination, the value of the consideration obtainable in a Disposition of such asset at such date of determination assuming a Disposition by a willing seller to a willing purchaser dealing at arm’s length and arranged in an orderly manner over a reasonable period of time having regard to the nature and characteristics of such asset, as reasonably determined by the Borrower.

“Fair Value” shall mean the amount at which the assets (both tangible and intangible), in their entirety, of the Borrower and its Subsidiaries taken as a whole would change hands between a willing buyer and a willing seller, within a commercially reasonable period of time, each having reasonable knowledge of the relevant facts, with neither being under any compulsion to act.

“FATCA” shall mean Sections 1471 through 1474 of the Code, as of the date of this Agreement (or any amended or successor version that is substantively comparable and not materially more onerous to comply with), any current or future Treasury Regulations promulgated thereunder or official administrative interpretations thereof, any agreement entered into pursuant to Section 1471(b)(1) of the Code, any intergovernmental agreement implementing any of the foregoing, and any law, regulation, rule, promulgation or official agreement implementing any of the foregoing.

“FCA” has the meaning assigned thereto in Section 1.11.

“Federal Funds Effective Rate” shall mean, for any day, the weighted average of the per annum rates on overnight federal funds transactions with members of the Federal Reserve System arranged by federal funds brokers on such day, as published on the next succeeding Business Day by the Federal Reserve Bank of New York or, if such rate is not so published for any date that is a Business Day, the Federal Funds Effective Rate for such day shall be the average rate (rounded upward, if necessary, to a whole multiple of 1/100 of 1%) of the quotations for such day for such transactions received by the Administrative Agent from three federal funds brokers of recognized standing selected by it; provided that such rate shall not, in any event, be less than zero.

“Financial Performance Covenants” shall mean the covenants of the Borrower set forth in Section 10.11.

“Fitch” means Fitch Ratings Inc. or any successor by merger or consolidation to its business.

“Flood Insurance Laws” shall mean the National Flood Insurance Act of 1968 and the Flood Disaster Protection Act of 1973, the National Flood Insurance Reform Act of 1994, the Biggert-Waters Flood Insurance Reform Act of 2012 and the regulations issued in connection therewith by the Office of the Comptroller of the Currency, the Federal Reserve Board and other Governmental Authorities, each as it may be amended, reformed or otherwise modified from time to time.

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“Floor” means the benchmark rate floor, if any, provided in this Agreement initially (as of the execution of this Agreement, the modification, amendment or renewal of this Agreement or otherwise) with respect to the LIBOR Rate.

“Foreign Corporate Subsidiary” shall mean a Foreign Subsidiary that is treated as a “controlled foreign corporation” within the meaning of Section 957 of the Code any shares of which are treated as owned directly or indirectly by a United States Shareholder (within the meaning of Section 951(b) of the Code) as measured for purposes of Section 958(a) of the Code.

“Foreign Plan” shall mean any employee benefit plan, program, policy, arrangement or agreement maintained or contributed to by the Borrower or any of its Subsidiaries with respect to employees employed outside the United States.

“Foreign Subsidiary” shall mean each Subsidiary of the Borrower that is not a Domestic Subsidiary.

“Free Cash Flow” means, as of any time of calculation thereof, the sum of the following for the most recently ended Test Period: (a) Consolidated EBITDAX for such four fiscal quarter period, minus (b) the increase (or plus the decrease) in non-cash working capital for such four fiscal quarter period, minus (c) the sum, without duplication, of the amounts for such four fiscal quarter period of (i) voluntary and scheduled cash repayments of Indebtedness (other than the Loans) which cannot be reborrowed pursuant to the terms of such Indebtedness, (ii) capital expenditures paid in cash (other than to the extent such capital expenditures were themselves (or were incurred in connection with) an acquisition), (iii) consolidated interest expense paid in cash, (iv) taxes paid in cash, (v) exploration expenses paid in cash, and (vi) to the extent not included in the foregoing, all cash amounts that otherwise served to increase EBITDAX for such Test Period, except, in the case of each of clauses (c)(i)-(c)(vi) in this definition, to the extent financed with Free Equity Proceeds.

“Free Equity Proceeds” means proceeds of issuances of any Stock or Stock Equivalents of the Borrower or capital contributions to the Borrower from its equity holders to the extent such issuance or contribution would not result in an Event of Default; provided that, neither (a) proceeds from Disqualified Stock nor (b) amounts applied to increase EBITDAX pursuant to the terms of Section 11.13 shall be included in Free Equity Proceeds.

“Fronting Fee” shall have the meaning provided in Section 4.1(c).

“FSHCO” shall mean any direct or indirect Subsidiary substantially all of the assets of which consist of Stock, Stock Equivalents or Stock, Stock Equivalents and Indebtedness of one or more direct or indirect Foreign Corporate Subsidiaries.

“Fund” shall mean any Person (other than a natural person) that is (or will be) engaged in making, purchasing, holding or otherwise investing in commercial loans and similar extensions of credit in the ordinary course.

“Funded Debt” shall mean all indebtedness of the Borrower and the Restricted Subsidiaries for borrowed money that matures more than one year from the date of its creation or matures within one year from such date that is renewable or extendable, at the option of the

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Borrower or any Restricted Subsidiary, to a date more than one year from such date or arises under a revolving credit or similar agreement that obligates the lender or lenders to extend credit during a period of more than one year from such date, including all amounts of Funded Debt required to be paid or prepaid within one year from the date of its creation and, in the case of the Borrower, Indebtedness in respect of the Loans.

“GAAP” shall mean generally accepted accounting principles in the United States of America, as in effect from time to time.

“Governmental Authority” shall mean any nation, sovereign or government, any state, province, territory or other political subdivision thereof, and any entity or authority exercising executive, legislative, judicial, regulatory or administrative functions of or pertaining to government, including a central bank or stock exchange.

“Guarantee” shall mean the Guarantee made by any Guarantor in favor of the Collateral Agent for the benefit of the Secured Parties, substantially in the form of Exhibit D.

“Guarantee Obligations” shall mean, as to any Person, any obligation of such Person guaranteeing or intended to guarantee any Indebtedness of any other Person (the “primary obligor”) in any manner, whether directly or indirectly, including any obligation of such Person, whether or not contingent, (a) to purchase any such Indebtedness or any property constituting direct or indirect security therefor, (b) to advance or supply funds (i) for the purchase or payment of any such Indebtedness or (ii) to maintain working capital or equity capital of the primary obligor or otherwise to maintain the net worth or solvency of the primary obligor, (c) to purchase property, securities or services primarily for the purpose of assuring the owner of any such Indebtedness of the ability of the primary obligor to make payment of such Indebtedness or (d) otherwise to assure or hold harmless the owner of such Indebtedness against loss in respect thereof; provided, however, that the term “Guarantee Obligations” shall not include endorsements of instruments for deposit or collection in the ordinary course of business or customary and reasonable indemnity obligations in effect on the Closing Date or entered into in connection with any acquisition or Disposition of assets permitted under this Agreement (other than such obligations with respect to Indebtedness). The amount of any Guarantee Obligation shall be deemed to be an amount equal to the stated or determinable amount of the Indebtedness in respect of which such Guarantee Obligation is made or, if not stated or determinable, the maximum reasonably anticipated liability in respect thereof (assuming such Person is required to perform thereunder) as determined by such Person in good faith.

“Guarantors” shall mean each Domestic Subsidiary listed on Schedule 1.1(e) and each other Domestic Subsidiary (other than an Excluded Subsidiary) that becomes a party to the Guarantee after the Closing Date pursuant to Section 9.11 or otherwise; provided that, for the avoidance of doubt, the Borrower in its sole discretion may cause any Restricted Subsidiary that is not required to be a Guarantor hereunder or pursuant to the Security Documents to provide a Guarantee by causing such Restricted Subsidiary to execute a Guarantee and such Restricted Subsidiary shall be a Guarantor and a Credit Party for all purposes hereunder except to the extent released from such Guarantee in accordance with the terms hereof.

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“Hazardous Materials” shall mean (a) any petroleum or petroleum products, radioactive materials, friable asbestos, urea formaldehyde foam insulation, transformers or other equipment that contain dielectric fluid containing regulated levels of polychlorinated biphenyls, and radon gas, (b) any chemicals, materials or substances defined as or included in the definition of “hazardous substances”, “hazardous waste”, “hazardous materials”, “extremely hazardous waste”, “restricted hazardous waste”, “toxic substances”, “toxic pollutants”, “contaminants”, or “pollutants”, or words of similar import, under any applicable Environmental Law and (c) any other chemical, material or substance, which is prohibited, limited or regulated by any Environmental Law due to its hazardous or dangerous properties or characteristics.

“Hedge Agreements” shall mean (a) any and all rate swap transactions, basis swaps, credit derivative transactions, forward rate transactions, commodity swaps, commodity options, forward commodity contracts, equity or equity index swaps or options, bond or bond price or bond index swaps or options or forward bond or forward bond price or forward bond index transactions, interest rate options, forward foreign exchange transactions, cap transactions, floor transactions, collar transactions, currency swap transactions, cross-currency rate swap transactions, currency options, spot contracts and fixed-price physical delivery contracts, whether or not exchange traded, or any other similar transactions or any combination of any of the foregoing (including any options to enter into any of the foregoing), whether or not any such transaction is governed by or subject to any master agreement, and (b) any and all transactions of any kind, and the related confirmations, which are subject to the terms and conditions of, or governed by, any form of master agreement published by the International Swaps and Derivatives Association, Inc., any International Foreign Exchange Master Agreement or any other master agreement (any such master agreement, together with any related schedules, a “Master Agreement”), including any such obligations or liabilities under any Master Agreement. Notwithstanding the foregoing, (x) agreements or obligations to physically sell any commodity at any index-based price shall not be considered Hedge Agreements, except for the Newark Basis Contract, which shall constitute a Hedge Agreement and (y) any right of a Person to ‘put’ an asset to another Person that arises in connection with an acquisition, disposition or similar agreement shall not be considered a Hedge Agreement.

“Hedge Bank” shall mean (a) any Person (other than the Borrower or any of its Subsidiaries) that (i) at the time it enters into a Hedge Agreement with the Borrower or any of its Restricted Subsidiaries is a Lender or Agent or an Affiliate of a Lender or Agent, or (ii) at any time after it enters into a Hedge Agreement with the Borrower or any of its Restricted Subsidiaries it becomes a Lender or Agent or an Affiliate of a Lender or Agent, (b) with respect to any Hedge Agreement with the Borrower or any of its Restricted Subsidiaries that is in effect on the Closing Date, any Person (other than the Borrower or any of its Subsidiaries) that is a Lender or Agent or an Affiliate of a Lender or Agent on the Closing Date and (c) solely in respect of those certain hedge transactions in effect on the Closing Date and specifically set forth on Schedule 1.1(f), J. Aron & Company LLC (provided that, for the avoidance of doubt, such Person shall not constitute a Hedge Bank pursuant to this clause (c) with respect to any Hedge Agreement or transactions under any Hedge Agreement entered into on or after the Closing Date).

“Hedge PV” shall mean, with respect to any commodity Hedge Agreement, the present value, discounted at 9% per annum, of the future receipts expected to be paid to the Borrower or the Restricted Subsidiaries under such Hedge Agreement netted against the most recent Bank

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Price Deck provided to the Borrower by the Administrative Agent pursuant to Section 2.14(j); provided, however, that the “Hedge PV” shall never be less than $0.00.

“Hedging Obligations” shall mean, with respect to any Person, the obligations of such Person under Hedge Agreements.

“Highest Lawful Rate” shall mean, with respect to each Lender, the maximum nonusurious interest rate, if any, that at any time or from time to time may be contracted for, taken, reserved, charged or received on the Loans under laws applicable to such Lender which are presently in effect or, to the extent allowed by law, under such applicable laws which may hereafter be in effect and which allow a higher maximum nonusurious interest rate than applicable laws allow as of the date hereof.

“Hydrocarbon Interests” shall mean all rights, titles, interests and estates now or hereafter acquired in and to oil and gas leases, oil, gas and mineral leases, or other liquid or gaseous hydrocarbon leases, mineral fee interests, overriding royalty and royalty interests, net profit interests and production payment interests, including any reserved or residual interests of whatever nature.

“Hydrocarbons” shall mean oil, gas, casinghead gas, drip gasoline, natural gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons and all products refined, processed or separated therefrom.

“IBA” has the meaning assigned thereto in Section 1.11.

“Identified Contingent Liabilities” shall mean the maximum estimated amount of liabilities reasonably likely to result from pending litigation, asserted claims and assessments, guaranties, uninsured risks and other contingent liabilities of the Borrower and its Subsidiaries taken as a whole after giving effect to the Transactions (including all fees and expenses related thereto but exclusive of such contingent liabilities to the extent reflected in Stated Liabilities), as identified and explained in terms of their nature and estimated magnitude by an Authorized Officer of the Borrower.

“Immaterial Subsidiary” shall mean any Subsidiary that is not a Material Subsidiary.

“Impacted Interest Period” shall have the meaning provided in the definition of “LIBOR Rate”.

“Increasing Lender” shall have the meaning provided in Section 2.16(a).

“Incremental Agreement” shall have the meaning provided in Section 2.16(c).

“Incremental Increase” shall have the meaning provided in Section 2.16(a).

“Indebtedness” of any Person shall mean, without duplication, (a) all indebtedness of such Person for borrowed money, (b) all obligations of such Person evidenced by bonds, debentures, notes, loan agreements or other similar instruments, (c) the deferred purchase price of assets or services that in accordance with GAAP would be included as a liability on the

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balance sheet of such Person (other than (i) any earn-out obligation until such obligation becomes a liability on the balance sheet of such Person in accordance with GAAP, (ii) accruals for payroll and other liabilities incurred in the ordinary course of business and (iii) obligations resulting under firm transportation contracts or take or pay contracts or other similar agreements entered into in the ordinary course of business), (d) the face amount (after giving effect to any prior drawings or reductions which may have been reimbursed) of all letters of credit (including standby and commercial), bankers’ acceptances, bank guaranties, surety bonds, performance bonds and similar instruments issued or created by the account of such Person and, without duplication, all drafts drawn thereunder, (e) all indebtedness (excluding prepaid interest thereon) of any other Person secured by any Lien on any property owned by such Person, whether or not such Indebtedness has been assumed by such Person or is limited in recourse, (f) the principal component of all Capitalized Lease Obligations of such Person, (g) net Hedging Obligations of such Person, (h) all obligations of such Person in respect of the redemption, repayment or other repurchase of Disqualified Stock (excluding accrued dividends that have not increased the liquidation preference of such Disqualified Stock), (i) obligations to deliver Hydrocarbons, in consideration of one or more material advance payments, other than obligations relating to net oil, natural gas liquids or natural gas balancing arrangements arising in the ordinary course of business, (j) the undischarged balance of any production payment created by such Person or for the creation of which such Person directly or indirectly received payment, and (k) without duplication, all Guarantee Obligations of such Person in respect of the items described in clauses (a) through (k) above; provided that Indebtedness shall (A) include the Indebtedness of any partnership or joint venture (other than a joint venture that is itself a corporation or limited liability company) in which such Person is a general partner or a joint venturer, except to the extent such Person’s liability for such Indebtedness is otherwise expressly limited and only to the extent such Indebtedness would be included in the calculation of Consolidated Total Debt or (B) not include (i) trade and other ordinary course payables and accrued expenses, (ii) deferred or prepaid revenue, (iii) purchase price holdbacks in respect of a portion of the purchase price of an asset to satisfy warranty or other unperformed obligations of the respective seller, (iv) in the case of the Borrower and its Restricted Subsidiaries, the net amount of (A) all intercompany Indebtedness having a term not exceeding 364 days (inclusive of any roll-over or extensions of terms) and made in the ordinary course of business and (B) intercompany liabilities in connection with the cash management, tax and accounting operations of the Borrower and the Restricted Subsidiaries, (v) any obligation in respect of a farm-in agreement or similar arrangement whereby such Person agrees to pay all or a share of the drilling, completion or other expenses of an exploratory or development well (which agreement may be subject to a maximum payment obligation, after which expenses are shared in accordance with the working or participation interest therein or in accordance with the agreement of the parties) or perform the drilling, completion or other operation on such well in exchange for an ownership interest in an oil or gas property, (vi) operating leases or sale and leaseback transactions (except any resulting obligations under any Capital Lease) and (vii) commitments or obligations of such Person to make capital contributions in another Person or fund construction costs of equipment, gathering, transportation, processing, handling, pipelines and other related systems and facilities which constitute Industry Investments.

For purposes hereof, the amount of any net Hedging Obligations on any date shall be deemed to be the Swap Termination Value thereof as of such date. The amount of Indebtedness of any Person for purposes of clause (e) above shall be deemed to be equal to the lesser of (i) the

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aggregate unpaid amount of such Indebtedness, (ii) the Fair Market Value of the property encumbered thereby as determined by such Person in good faith and (iii) the maximum amount for which such Person may be liable in respect of such Indebtedness.

“Indemnified Liabilities” shall have the meaning provided in Section 13.5.

“Indemnified Taxes” shall mean all Taxes imposed on or with respect to, any payment by or on account of any obligation of any Credit Party hereunder or under any other Credit Document, other than (a) Excluded Taxes and (b) Other Taxes.

“Industry Investment” shall mean Investments and expenditures made in the ordinary course of, and of a nature that is or shall have become customary in, the Oil and Gas Business, including: (a) ownership interests (including equity or other ownership interests) in oil, natural gas, other Hydrocarbons and minerals properties, liquefied natural gas facilities, processing facilities, gathering systems, pipelines, storage facilities or related systems or ancillary real property interests; (b) Investments and expenditures in the form of or pursuant to operating agreements, processing agreements, farm-in agreements, farm-out agreements, development agreements, area of mutual interest agreements, unitization agreements, pooling arrangements, joint bidding agreements, service contracts, joint venture agreements, partnership agreements (whether general or limited), and other similar agreements (including for limited liability companies) with third parties; and (c) Investments in direct or indirect ownership interests in drilling rigs and related equipment, including, without limitation, transportation equipment.

“Initial Borrowing Base” shall have the meaning provided in Section 2.14(a).

“Initial Loans” any Loans made hereunder other than any Extended Loans.

“Initial Maturity Date” shall mean the fourth anniversary of the Closing Date, or, if such anniversary is not a Business Day, the Business Day immediately following such anniversary.

“Initial Reserve Report” shall mean, collectively, the reserve reports of the Existing Borrowers, prepared internally by the petroleum engineers of the Existing Borrowers, with respect to the Oil and Gas Properties of the Credit Parties, in each case rolled forward to an “as of” date of November 1, 2021, and delivered to the Administrative Agent prior to the Closing Date.

“Intercompany Note” shall mean the Intercompany Subordinated Note, dated as of the Closing Date, substantially in the form of Exhibit E executed by the Borrower and each Subsidiary of the Borrower.

“Interest Period” shall mean, with respect to any Loan, the interest period applicable thereto, as determined pursuant to Section 2.9.

“Interim Redetermination” shall have the meaning provided in Section 2.14(b).

“Interim Redetermination Date” shall mean the date on which a Borrowing Base that has been redetermined pursuant to an Interim Redetermination becomes effective as provided in Section 2.14(b).

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“Interpolated Rate” shall mean, at any time, for any Interest Period, the rate per annum (rounded to the same number of decimal places as the LIBO Screen Rate) determined by the Administrative Agent (which determination shall be conclusive and binding absent manifest error) to be equal to the rate that results from interpolating on a linear basis between: (a) the LIBO Screen Rate for the longest period (for which the LIBO Screen Rate is available) that is shorter than the Impacted Interest Period and (b) the LIBO Screen Rate for the shortest period (for which the LIBO Screen Rate is available) that exceeds the Impacted Interest Period, in each case, at such time.

“Investment” shall mean, for any Person: (a) the acquisition whether for cash, property, services or securities or otherwise of Stock, Stock Equivalents, evidences of Indebtedness or other ownership interests or other securities of any other Person (including any “short sale” or any sale of any securities at a time when such securities are not owned by the Person entering into such sale), (b) the making of any deposit with, or advance, loan or other extension of credit to, any other Person (including the purchase of property from another Person subject to an understanding or agreement, contingent or otherwise, to resell such property to such Person, but excluding any such advance, loan or extension of credit representing the purchase price of inventory or supplies sold by such Person in the ordinary course of business) (including any partnership or joint venture), (c) the entering into of any guarantee of, or other contingent obligation with respect to, Indebtedness of another Person or (d) the purchase or other acquisition (in one transaction or a series of transactions) of (i) all or substantially all of the property and assets or business of another Person or (ii) assets constituting a business unit, line of business or division of such Person; provided that, in the event that any Investment is made by the Borrower or any Restricted Subsidiary in any Person through substantially concurrent interim transfers of any amount through one or more other Restricted Subsidiaries, then such other substantially concurrent interim transfers shall be disregarded for purposes of Section 10.5. Except as otherwise explicitly addressed in any exception to Section 10.5, for purposes of covenant compliance, the amount of any Investment at any time shall be (1) the amount actually invested (measured at the time made), without adjustment for subsequent increases or decreases in the value of such Investment minus (2) the amount of dividends or distributions received in connection with such Investment and any return of capital and any payment of principal received in respect of such Investment that in each case is received in cash, cash equivalents or short-term marketable debt securities by the Person holding such Investment.

“IPOCo” means a Person formed to acquire, directly or indirectly, Stock and Stock Equivalents of the Borrower in order to undertake a Qualified IPO.

“IPOCo Transactions” means the transactions in connection with the formation and capitalization of IPOCo prior to and in connection with and reasonably related to the Qualified IPO, including, without limitation: (a) the legal formation of IPOCo and one or more Subsidiaries of the Permitted Holders to own interests therein, (b) the contribution, directly or indirectly, of the Stock and Stock Equivalents of the Borrower and other Subsidiaries of the Borrower to IPOCo, or the other acquisition by IPOCo thereof (so long as, in each case, no Change of Control pursuant to clause (a) of the definition thereof occurs as a result thereof), (c) the conversion of the outstanding Stock and Stock Equivalents in the Borrower into a new class of Stock and Stock Equivalents in the Borrower, (d) the issuance of Stock and Stock Equivalents of IPOCo or the Borrower to the public and the use of proceeds therefrom to pay transaction

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expenses, distribute funds as a reimbursement for capital expenditures, and other purposes approved by a Permitted Holder, (e) the execution, delivery and performance of customary documentation (and amendments to existing documentation) governing the relations between and among the Borrower, IPOCo, the Permitted Holders and their respective Subsidiaries, including, without limitation, the execution, delivery and performance of a tax receivables agreement among IPOCo, the Borrower and the Permitted Holders on customary terms for similar transactions and (f) any other transactions and documentation related to the foregoing or necessary or appropriate in the view of the Permitted Holders or the board of directors of the Borrower or any direct or indirect parent of the Borrower in connection with the Qualified IPO.

“ISDA Definitions” means the 2006 ISDA Definitions published by the International Swaps and Derivatives Association, Inc. or any successor thereto, as amended or supplemented from time to time, or any successor definitional booklet for interest rate derivatives published from time to time by the International Swaps and Derivatives Association, Inc. or such successor thereto.

“ISP” shall mean, with respect to any Letter of Credit, the “International Standby Practices 1998” published by the Institute of International Banking Law & Practice (or such later version thereof as may be in effect at the time of issuance).

“Issuer Documents” shall mean, with respect to any Letter of Credit, the Letter of Credit Request, and any other document, agreement and instrument entered into by the Letter of Credit Issuer and the Borrower (or any Restricted Subsidiary) or in favor of the Letter of Credit Issuer and relating to such Letter of Credit.

“KKR” shall mean Kohlberg Kravis Roberts & Co., L.P.

“L/C Borrowing” shall mean an extension of credit resulting from a drawing under any Letter of Credit which has not been reimbursed on the date when made or refinanced as a Borrowing. All L/C Borrowings shall be denominated in Dollars.

“L/C Issuance Limit” means, with respect to each Letter of Credit Issuer, an amount equal to the greatest of (i) $60,000,000, (ii) 7.5% of the then effective Loan Limit and (iii) such higher amount as such Letter of Credit Issuer may agree in its sole discretion.

“L/C Maturity Date” shall mean the date that is three Business Days prior to the Maturity Date.

“L/C Obligations” shall mean, as at any date of determination, the aggregate amount available to be drawn under all outstanding Letters of Credit plus the aggregate of all Unpaid Drawings, including all L/C Borrowings. For all purposes of this Agreement, if on any date of determination a Letter of Credit has expired by its terms but any amount may still be drawn thereunder by reason of the operation of Rule 3.14 of the ISP, such Letter of Credit shall be deemed to be “outstanding” in the amount so remaining available to be drawn.

“L/C Participant” shall have the meaning provided in Section 3.3(a).

“L/C Participation” shall have the meaning provided in Section 3.3(a).

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“Latest Maturity Date” shall mean at any date of determination, the latest Maturity Date applicable to any Class of Commitments or Loans that is outstanding hereunder on such date of determination, as extended in accordance with this Agreement from time to time.

“LCT Election” shall have the meaning provided in Section 1.10(f).

“LCT Test Date” shall have the meaning provided in Section 1.10(f).

“Lead Arranger” shall mean each of Wells Fargo Securities, LLC and JPMorgan Chase Bank, N.A., each in its capacity as joint lead arranger and joint bookrunner in respect of the Facility.

“Lender” shall have the meaning provided in the preamble to this Agreement. For avoidance of doubt, each Additional Lender shall be deemed a “Lender” for purposes of this Agreement and each other Credit Document.

“Lender Default” shall mean (i) the refusal or failure of any Lender to make available its portion of any incurrence of Loans or participations in Letters of Credit, which refusal or failure is not cured within one Business Day after the date of such refusal or failure; (ii) the failure of any Lender to pay over to the Administrative Agent, any Letter of Credit Issuer or any other Lender any other amount required to be paid by it hereunder within one Business Day of the date when due; (iii) a Lender has notified the Borrower or the Administrative Agent that it does not intend or expect to comply with any of its funding obligations or has made a public statement to that effect with respect to its funding obligations under the Facility, (iv) the failure, within three Business Days after request by the Administrative Agent or a Credit Party, acting in good faith, by a Lender to confirm in a manner reasonably satisfactory to the Administrative Agent that it will comply with its obligations under the Facility; provided that such Lender shall cease to be a Defaulting Lender pursuant to this clause (iv) upon receipt of such written confirmation by the Administrative Agent and the Borrower; (v) a Distressed Person has admitted in writing that it is insolvent or such Distressed Person becomes subject to a Lender-Related Distress Event or (vi) any Lender that has, or has a direct or indirect parent company that has, become the subject of a Bail-In Action; provided that a Lender shall not become a Defaulting Lender solely as a result of the acquisition or maintenance of an ownership interest in such Lender or Person Controlling such Lender or the exercise of Control over a Lender or Person Controlling such Lender by a Governmental Authority or an instrumentality thereof, so long as such ownership interest does not result in or provide such Lender with immunity from the jurisdiction of courts within the United States or from the enforcement of judgments or writs of attachment on its assets or permit such Lender (or such Governmental Authority) to reject, repudiate, disavow or disaffirm any contracts or agreements made with such Lender.

“Lender-Related Distress Event” shall mean, with respect to any Lender, that such Lender or any Person that directly or indirectly controls such Lender (each, a “Distressed Person”), as the case may be, is or becomes subject to a voluntary or involuntary case with respect to such Distressed Person under any debt relief law, or a custodian, conservator, receiver or similar official is appointed for such Distressed Person or any substantial part of such Distressed Person’s assets, or such Distressed Person or any Person that directly or indirectly controls such Distressed Person is subject to a forced liquidation, or such Distressed Person makes a general assignment for the benefit of creditors or is otherwise adjudicated as, or

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determined by any Governmental Authority having regulatory authority over such Distressed Person or its assets to be, insolvent or bankrupt; provided that a Lender-Related Distress Event shall not be deemed to have occurred solely by virtue of (i) the ownership or acquisition of any equity interests in any Lender or any Person that directly or indirectly controls such Lender by a Governmental Authority or an instrumentality thereof or (ii) an undisclosed administration pursuant to the laws of the Netherlands.

“Letter of Credit” shall have the meaning provided in Section 3.1 and shall include the Existing Letters of Credit.

“Letter of Credit Commitment” shall mean, at the time of incurrence or issuance of a Letter of Credit, the greater of $120,000,000 and 15% of the then effective Loan Limit, as such commitment may be reduced from time to time pursuant to Section 3.1.

“Letter of Credit Exposure” shall mean, with respect to any Lender, at any time, the sum of (a) the principal amount of any Unpaid Drawings in respect of which such Lender has made (or is required to have made) payments to the Letter of Credit Issuer pursuant to Section 3.4(a) at such time and (b) such Lender’s Commitment Percentage of the Letters of Credit Outstanding at such time (excluding the portion thereof consisting of Unpaid Drawings in respect of which the Lenders have made (or are required to have made) payments to the Letter of Credit Issuer pursuant to Section 3.4(a)) minus (c) such Lender’s Commitment Percentage of the amount of cash or deposit account balances held by the Administrative Agent to Cash Collateralize outstanding Letters of Credit and Unpaid Drawings under Section 3.8.

“Letter of Credit Fee” shall have the meaning provided in Section 4.1(b).

“Letter of Credit Issuer” shall mean (a) Wells Fargo Bank, National Association, (b) JPMorgan Chase Bank, N.A. and (c) any of their Affiliates or any replacement or successor appointed pursuant to Section 3.6 and (b) if requested by the Borrower (subject to the consent of the Administrative Agent, which consent shall not be unreasonably withheld, delayed or conditioned) any other Person who is at the time of such request a Lender that agrees to act as Letter of Credit Issuer (it being understood that if any such Person ceases to be a Lender hereunder, such Person will remain a Letter of Credit Issuer with respect to any Letters of Credit issued by such Person that remained outstanding as of the date such Person ceased to be a Lender). Each Letter of Credit Issuer may, in its discretion, arrange for such Letter of Credit to be issued by any Lender or any Affiliate thereof that agrees to act as Letter of Credit Issuer, and in each such case the term “Letter of Credit Issuer” shall include any such Lender or Affiliate with respect to Letters of Credit issued by such Lender or Affiliate. References herein and in the other Credit Documents to the Letter of Credit Issuer shall be deemed to refer to the Letter of Credit Issuer in respect of the applicable Letter of Credit or to all Letter of Credit Issuers, as the context requires.

“Letter of Credit Request” shall have the meaning provided in Section 3.2.

“Letters of Credit Outstanding” shall mean, at any time, the sum of, without duplication, (a) the aggregate Stated Amount of all outstanding Letters of Credit and (b) the aggregate principal amount of all Unpaid Drawings in respect of all Letters of Credit.

“LIBO Screen Rate” shall have the meaning provided in the definition of “LIBOR Rate”.

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“LIBOR” means the London interbank offered rate for Dollars.

“LIBOR Loan” shall mean any Loan bearing interest at a rate determined by reference to the LIBOR Rate (other than an ABR Loan bearing interest by reference to the LIBOR Rate by virtue of clause (c) of the definition of ABR).

“LIBOR Rate” shall mean, subject to the implementation of a Benchmark Replacement in accordance with Section 2.18, for any Interest Period with respect to any Borrowing of a LIBOR Loan, the London interbank offered rate as administered by ICE Benchmark Administration (or any other Person that takes over the administration of such rate for Dollars) for a period equal in length to such Interest Period as displayed on pages LIBOR01 or LIBOR02 of the Reuters screen that displays such rate or, in the event such rate does not appear on a Reuters page or screen, on any successor or substitute page on such screen that displays such rate, or on the appropriate page of such other information service that publishes such rate from time to time as shall be selected by the Administrative Agent in its reasonable discretion (in each case, the “LIBO Screen Rate”) at approximately 11:00 a.m., London time, two Business Days prior to the commencement of such Interest Period; provided that, (x) if the LIBO Screen Rate shall be less than zero, such rate shall be deemed to be zero for the purposes of this Agreement and (y) if the LIBO Screen Rate shall not be available at such time for a period equal in length to such Interest Period (an “Impacted Interest Period”), then the LIBOR Rate shall be the Interpolated Rate at such time, subject to Section 2.10 in the event that the Administrative Agent shall conclude that it shall not be possible to determine such Interpolated Rate (which conclusion shall be conclusive and binding absent manifest error); providedfurther, that, if any Interpolated Rate shall be less than zero, such rate shall be deemed to be zero for purposes of this Agreement. Notwithstanding the above, (x) to the extent that “LIBOR Rate” or “Adjusted LIBOR Rate” is used in connection with an ABR Borrowing, such rate shall be determined as modified by the definition of ABR, (y) unless otherwise specified in any amendment to this Agreement entered into in accordance with Section 2.18, in the event that a Benchmark Replacement with respect to the LIBOR Rate is implemented then all references herein to the LIBOR Rate shall be deemed references to such Benchmark Replacement and (z) if the LIBOR Rate or any Benchmark Replacement shall be less than zero, such rate shall be deemed to be zero for the purposes of this Agreement.

“Lien” shall mean any interest in property securing an obligation owed to, or a claim by, a Person other than the owner of the property, whether such interest is based on the common law, statute or contract, and whether such obligation or claim is fixed or contingent, and including (a) the lien or security interest arising from a mortgage, encumbrance, pledge, security agreement or a financing lease, consignment or bailment for security purposes or (b) Production Payments and the like payable out of Oil and Gas Properties; provided that in no event shall an operating lease be deemed to be a Lien.

“Limited Condition Transaction” shall mean any acquisition or Investment by one or more of the Borrower and its Restricted Subsidiaries of or in any assets, business or Person permitted by this Agreement the consummation of which is not conditioned on the availability of, or on obtaining, third party financing.

“Liquidation” and the correlative term “Liquidated” shall have the meaning provided in Section 2.14(f).

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“Liquidity” shall mean, as of any date of determination, the sum of (a) the Available Commitment on such date and (b) the aggregate amount of Unrestricted Cash of the Borrower and its Restricted Subsidiaries at such date, less the amount, if any, of the Borrowing Base Deficiency existing on such date of determination.

“Loan” shall mean any Initial Loan or Extended Loan made by any Lender hereunder.

“Loan Limit” shall mean, at any time, the least of (a) the Aggregate Maximum Credit Amount at such time, (b) the Borrowing Base at such time and (c) the Aggregate Elected Commitment Amount at such time.

“Majority Lenders” shall mean, at any date, (a) Non-Defaulting Lenders having or holding a majority of the Adjusted Total Commitment at such date, or (b) if the Total Commitment has been terminated or for the purposes of acceleration pursuant to Section 11, Non-Defaulting Lenders having or holding a majority of the outstanding principal amount of the Loans and Letter of Credit Exposure (excluding the Loans and Letter of Credit Exposure of Defaulting Lenders) in the aggregate at such date.

“Material Adverse Effect” shall mean a circumstance or condition affecting the business, assets, operations, properties or financial condition of the Borrower and the other Credit Parties, taken as a whole, that would, individually or in the aggregate, materially adversely affect (a) the ability of the Borrower and the other Credit Parties, taken as a whole, to perform their payment obligations under this Agreement or any of the other Credit Documents or (b) the rights and remedies of the Agents and the Lenders under this Agreement or under any of the other Credit Documents.

“Material Subsidiary” shall mean, at any date of determination, each Restricted Subsidiary of the Borrower (a) whose Total Assets (when combined with the assets of such Subsidiary’s Subsidiaries, after eliminating intercompany obligations) at the last day of the most recently ended Test Period were equal to or greater than 5% of the Total Assets of the Borrower and the Restricted Subsidiaries at such date or (b) whose revenues (when combined with the revenues of such Subsidiary’s Subsidiaries, after eliminating intercompany obligations) during such Test Period were equal to or greater than 5% of the consolidated revenues of the Borrower and the Restricted Subsidiaries for such period, in each case determined in accordance with GAAP; provided that if, at any time and from time to time after the Closing Date, Restricted Subsidiaries that are not Material Subsidiaries have, in the aggregate, (i) Total Assets (when combined with the assets of such Subsidiary’s Subsidiaries, after eliminating intercompany obligations) at the last day of such Test Period equal to or greater than 10% of the Total Assets of the Borrower and the Restricted Subsidiaries at such date or (ii) revenues (when combined with the revenues of such Subsidiary’s Subsidiaries, after eliminating intercompany obligations) during such Test Period equal to or greater than 10% of the consolidated revenues of the Borrower and the Restricted Subsidiaries for such period, in each case determined in accordance with GAAP, then the Borrower shall, on the date on which financial statements for such quarter are delivered pursuant to this Agreement, designate in writing to the Administrative Agent one or more of such Restricted Subsidiaries as “Material Subsidiaries”; provided, further, that, notwithstanding anything herein to the contrary, each Restricted Subsidiary that owns Borrowing Base Properties shall be a Material Subsidiary.

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“Maturity Date” shall mean, as to the applicable Loan, the Initial Maturity Date or any maturity date related to any Extension Series of Extended Commitments, as applicable.

“Maximum Credit Amount” shall mean, as to each Lender, the amount set forth opposite such Lender’s name on Schedule 1.1(a) under the caption “Maximum Credit Amounts,” as such amount may be increased, reduced or terminated under this Agreement.

“Mineral Interests” means interests in Hydrocarbons constituting royalty and leased mineral fee interests, including lessor royalties, overriding royalty interests, non-participating royalty interests, net profit interests, production payments and any other similar non-participatory interests, in each case, which do not bear a share of drilling, operating, or other costs as a participating mineral owner.

“Minerals Spin-Off” means (i) the initial registered public offering of Stock or Stock Equivalents of an Unrestricted Subsidiary of the Borrower holding, or to which has been contributed, all or any portion of the Mineral Interests of the Borrower and its Subsidiaries or (ii) the acquisition, purchase, merger, amalgamation or other combination of such an Unrestricted Subsidiary of the Borrower by, or with, a publicly traded company.

“Minimum Borrowing Amount” shall mean, with respect to any Borrowing of Loans, $500,000 (or, if less, the entire remaining Commitments at the time of such Borrowing).

“Minority Investment” shall mean any Person (other than a Subsidiary) in which the Borrower or any Restricted Subsidiary owns Stock or Stock Equivalents.

“Moody’s” shall mean Moody’s Investors Service, Inc. or any successor by merger or consolidation to its business.

“Mortgage” shall mean a mortgage or a deed of trust, deed to secure debt, trust deed, assignment of as-extracted collateral, fixture filing or other security document entered into by the owner of a Mortgaged Property and the Collateral Agent for the benefit of the Secured Parties in respect of that Mortgaged Property, substantially in the form of Exhibit F (with such changes thereto as may be necessary to account for local law matters) or otherwise in such form as agreed between the Borrower and the Collateral Agent.

“Mortgaged Property” shall mean real property and improvements thereto with respect to which a Mortgage has been granted on the Closing Date or pursuant to Section 9.11.

“Multiemployer Plan” shall mean a Plan that is a multiemployer plan as defined in Section 4001(a)(3) of ERISA.

“New Borrowing Base Notice” shall have the meaning provided in Section 2.14(d).

“Newark Basis Contract” means that certain Transaction Confirmation #N8270276, dated as of August 13, 2018, between Newark Acquisition I L.P., as seller, and Wells Fargo Commodities, LLC, as buyer.

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“Non-Cash Charges” shall mean, without duplication, (a) losses on non-ordinary course asset Dispositions, disposals or abandonments, (b) any impairment charge or asset write-off or write-down related to intangible assets (including goodwill), long-lived assets (including Oil and Gas Properties)and investments in debt and equity securities pursuant to GAAP, including ceiling test writedowns, (c) all losses from Investments recorded using the equity method, (d) stock-based, partnership interest-based or similar incentive-based awards or arrangements, compensation expense or costs, including any such charges arising from stock options, restricted stock grants or other equity incentive grants, (e) the non-cash impact of purchase accounting and the non-cash impact of accounting changes or restatements, (f) the accretion of discounted liabilities and (g) other non-cash charges (including reserve impairments) (provided that if any non-cash charges referred to in this clause (g) represent an accrual or reserve for potential cash items in any future period, the cash payment in respect thereof in such future period shall be subtracted from Consolidated EBITDAX to such extent, and excluding amortization of a prepaid cash item that was paid in a prior period).

“Non-Consenting Lender” shall have the meaning provided in Section 13.7(b).

“Non-Cost Bearing Interest” shall mean any ownership interest in Oil and Gas Properties where the owner of such interests does not incur any direct liability for its portion of the ongoing costs associated with exploration, drilling and production, including without limitation, a producing mineral royalty, overriding royalty interest, non-participating royalty interest or net profits interest.

“Non-Defaulting Lender” shall mean and include each Lender other than a Defaulting Lender.

“Non-Extension Notice Date” shall have the meaning provided in Section 3.2(b).

“Non-U.S. Lender” shall mean any Lender that is not a “United States person” as defined by Section 7701(a)(30) of the Code.

“Notice of Borrowing” shall mean a request of the Borrower in accordance with the terms of Section 2.3(a) and substantially in the form of Exhibit G or such other form as shall be approved by the Administrative Agent (acting reasonably).

“Notice of Conversion or Continuation” shall have the meaning provided in Section 2.6(a).

“November 2021 Redetermination” shall have the meaning provided in Section 2.14(a).

“Obligations” shall mean all advances to, and debts, liabilities, obligations, covenants and duties of, any Credit Party arising under any Credit Document or otherwise with respect to any Loan or Letter of Credit, or of the Borrower or any of its Restricted Subsidiaries under any Secured Cash Management Agreement or Secured Hedge Agreement, in each case, whether direct or indirect (including those acquired by assumption), absolute or contingent, due or to become due, now existing or hereafter arising and including interest and fees that accrue after the commencement by or against any Credit Party or any Affiliate thereof in any proceeding under any bankruptcy or insolvency law naming such Person as the debtor in such proceeding,

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regardless of whether such interest and fees are allowed claims in such proceeding. Without limiting the generality of the foregoing, the Obligations of the Credit Parties under the Credit Documents (and any of their Restricted Subsidiaries to the extent they have obligations under the Credit Documents or any Secured Cash Management Agreement or Secured Hedge Agreement) include the obligation (including Guarantee Obligations) to pay principal, interest, charges, expenses, fees, attorney costs, indemnities and other amounts payable by any Credit Party under any Credit Document or the Borrower or any of its Restricted Subsidiaries under any Secured Cash Management Agreement or Secured Hedge Agreement, and all renewals, extensions and/or rearrangements of any of the above. Notwithstanding the foregoing, (a) the obligations of the Borrower or any Restricted Subsidiary under any Secured Hedge Agreement and under any Secured Cash Management Agreement shall be secured and guaranteed pursuant to the Security Documents and the Guarantee only to the extent that, and for so long as, the other Obligations are so secured and guaranteed and (b) any release of Collateral or Guarantors effected in the manner permitted by this Agreement and the other Credit Documents shall not require the consent of the holders of Hedging Obligations under Secured Hedge Agreements or of the holders of Cash Management Obligations under Secured Cash Management Agreements. Notwithstanding the foregoing, the definition of “Obligations” shall not include any Excluded Swap Obligations.

“OFAC” shall mean the U.S. Department of the Treasury Office of Foreign Assets Control.

“Oil and Gas Business” means: (a) the business of acquiring, exploring, exploiting, developing, producing, operating and disposing of interests in oil, natural gas, natural gas liquids, liquefied natural gas and other Hydrocarbons and mineral properties or products produced in association with any of the foregoing; (b) the business of gathering, marketing, distributing, treating, processing (but not refining), storing, selling and transporting of any production from such interests or properties; (c) any business relating to exploration for or development, production, treatment, processing (but not refining), storage, transportation or marketing of oil, gas and other minerals and products produced in association therewith; (d) any business relating to oilfield sales and service; and (e) any business or activity relating to, arising from, or necessary, appropriate, incidental or ancillary to the activities described in the foregoing clauses (a) through (d) of this definition.

“Oil and Gas Properties” shall mean (a) Hydrocarbon Interests, (b) the properties now or hereafter pooled or unitized with Hydrocarbon Interests, (c) all presently existing or future unitization agreements, pooling agreements and declarations of pooled units and the units created thereby (including all units created under orders, regulations and rules of any Governmental Authority) which may affect all or any portion of the Hydrocarbon Interests, (d) all operating agreements, contracts and other agreements, including production sharing contracts and agreements, which relate to any of the Hydrocarbon Interests or the production, sale, purchase, exchange or processing of Hydrocarbons from or attributable to such Hydrocarbon Interests, (e) all Hydrocarbons in and under and which may be produced and saved or attributable to the Hydrocarbon Interests, including all oil in tanks, and all rents, issues, profits, proceeds, products, revenues and other incomes from or attributable to the Hydrocarbon Interests, (f) all tenements, hereditaments, appurtenances and properties in any manner appertaining, belonging, affixed or incidental to the Hydrocarbon Interests and (g) all properties, rights, titles, interests and estates described or referred to above, including any and all property, real or personal, now owned or hereafter acquired and situated upon, used, held for use or useful in connection with the

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operating, working or development of any of such Hydrocarbon Interests or property (excluding drilling rigs, automotive equipment, rental equipment or other personal property which may be on such premises for the purpose of drilling a well or for other similar temporary uses) and including any and all oil wells, gas wells, injection wells or other wells, structures, fuel separators, liquid extraction plants, plant compressors, pumps, pumping units, field gathering systems, gas processing plants and pipeline systems and any related infrastructure to any thereof, tanks and tank batteries, fixtures, valves, fittings, machinery and parts, engines, boilers, meters, apparatus, equipment, appliances, tools, implements, cables, wires, towers, casing, tubing and rods, surface leases, rights-of-way, easements and servitudes together with all additions, substitutions, replacements, accessions and attachments to any and all of the foregoing; provided that the Oil and Gas Properties shall not include any “building” or “mobile home” (each as defined in Regulation H as promulgated by the Federal Reserve Board under the Flood Insurance Laws).

“Ongoing Hedges” shall have the meaning provided in Section 10.10(a).

“Other Taxes” shall mean any and all present or future stamp, registration, documentary, intangible, recording, filing, or similar taxes arising from any payment made hereunder or made under any other Credit Document or from the execution or delivery of, registration or enforcement of, consummation or administration of, or otherwise with respect to, this Agreement or any other Credit Document; provided that such term shall not include any of the foregoing Taxes (i) that result from an assignment, grant of a participation pursuant to Section 13.6(c) or transfer or assignment to or designation of a new lending office or other office for receiving payments under any Credit Document (“Assignment Taxes”) to the extent such Assignment Taxes are imposed as a result of a connection between the assignor/participating Lender and/or the assignee/Participant and the taxing jurisdiction (other than a connection arising solely from any Credit Documents or any transactions contemplated thereunder), except to the extent that any such action described in this proviso is requested or required by the Borrower, or (ii) Excluded Taxes.

“Overnight Rate” shall mean, for any day, the greater of (a) the Federal Funds Effective Rate and (b) an overnight rate determined by the Administrative Agent or the Letter of Credit Issuer, as the case may be, in accordance with banking industry rules on interbank compensation.

“Participant” shall have the meaning provided in Section 13.6(c).

“Participant Register” shall have the meaning provided in Section 13.6(c).

“Patriot Act” shall have the meaning provided in Section 13.18.

“Payment in Full” shall mean the Total Commitment and each Letter of Credit have terminated (unless such Letters of Credit have been collateralized or backstopped on terms and conditions reasonably satisfactory to the Letter of Credit Issuer following the termination of the Total Commitment) and the Loans and Unpaid Drawings, together with interest, fees and all other Obligations incurred hereunder (other than Hedging Obligations under Secured Hedge Agreements, Cash Management Obligations under Secured Cash Management Agreements or contingent obligations not then due and payable), have been paid in full.

“Payment or Bankruptcy Event of Default” shall mean an Event of Default under Section 11.1 or Section 11.5.

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“PBGC” shall mean the Pension Benefit Guaranty Corporation established pursuant to Section 4002 of ERISA, or any successor thereto.

“Pension Act” shall mean the Pension Protection Act of 2006, as it presently exists or as it may be amended from time to time.

“Permitted Acquisition” shall mean the acquisition, by merger or otherwise, by the Borrower or any of the Restricted Subsidiaries of assets (including any assets constituting a business unit, line of business or division) or Stock or Stock Equivalents, so long as (a) such acquisition and all transactions related thereto shall be consummated in all material respects in accordance with Requirements of Law; (b) if such acquisition involves the acquisition of Stock or Stock Equivalents of a Person that upon such acquisition would become a Subsidiary, such acquisition shall result in the issuer of such Stock becoming a Restricted Subsidiary and, to the extent required by Section 9.11, a Guarantor; (c) such acquisition shall result in the Collateral Agent, for the benefit of the Secured Parties, being granted a security interest in any Stock or any assets so acquired to the extent required by Section 9.11; (d) after giving effect to such acquisition, no Event of Default shall have occurred and be continuing; (e) after giving effect to such acquisition, the Borrower and its Subsidiaries shall be in compliance with Section 9.17 and (f) the Borrower shall be in compliance, on a Pro Forma Basis after giving effect to such acquisition (including any Indebtedness assumed or permitted to exist pursuant to Section 10.1(j), and any related Pro Forma Adjustment), with the Financial Performance Covenants, as such covenants are recomputed as at the last day of the most recently ended Test Period as if such acquisition had occurred on the first day of such Test Period.

“Permitted Acquisition Consideration” shall mean in connection with any Permitted Acquisition, the aggregate amount (as valued at the Fair Market Value of such Permitted Acquisition at the time such Permitted Acquisition is made) of, without duplication: (a) the purchase consideration paid or payable in cash for such Permitted Acquisition, whether payable at or prior to the consummation of such Permitted Acquisition or deferred for payment at any future time, whether or not any such future payment is subject to the occurrence of any contingency, and including any and all payments representing the purchase price and any assumptions of Indebtedness and/or Guarantee Obligations, “earn-outs” and other agreements to make any payment the amount of which is, or the terms of payment of which are, in any respect subject to or contingent upon the revenues, income, cash flow or profits (or the like) of any Person or business and (b) the aggregate amount of Indebtedness incurred or assumed in connection with such Permitted Acquisition; provided, in each case, that any such future payment that is subject to a contingency shall be considered Permitted Acquisition Consideration only to the extent of the reserve, if any, required under GAAP (as determined at the time of the consummation of such Permitted Acquisition) to be established in respect thereof for the Borrower or its Restricted Subsidiaries.

“Permitted Additional Debt” shall mean unsecured senior, senior subordinated or subordinated Indebtedness issued by the Borrower or a Guarantor after the Closing Date, (a) the terms of which do not provide for any scheduled repayment, mandatory redemption or sinking fund obligation prior to the 91st day after the Latest Maturity Date as in effect on the date of determination (other than (i) customary offers to purchase upon a change of control, AHYDO payments, asset sale or casualty or condemnation event and customary acceleration rights after

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an event of default and (ii) unsecured Indebtedness incurred pursuant to a customary bridge facility if the Indebtedness pursuant to such customary bridge facility converts at maturity to Indebtedness which does not provide for any scheduled repayment, mandatory redemption or sinking fund obligation (except to the extent permitted pursuant to clause (i)) and has a Weighted Average Life to Maturity equal to or greater than the Weighted Average Life to Maturity of the Facility, if applicable, (b) if such Indebtedness is senior subordinated or subordinated Indebtedness, the terms of such Indebtedness provide for customary subordination of such Indebtedness to the Obligations and (c) no Restricted Subsidiary of the Borrower (other than a Guarantor or a Person who becomes a Guarantor in connection therewith) is an obligor under such Indebtedness.

“Permitted Holders” shall mean the (a) Sponsor and its co-investors as of the Closing Date, (b) officers, directors, employees and other members of management of the Borrower (or its direct or indirect parent) or any of its Restricted Subsidiaries who are or become holders of Stock or Stock Equivalents of the Borrower (or its direct or indirect parent company) (and their Controlled Investment Affiliates and immediate family members), (c) each Person to whom the Sponsor transfers Stock or Stock Equivalents of the Borrower (or any direct or indirect parent thereof) in connection with the primary equity syndication following the Closing Date, (d) any direct or indirect parent entity of the Borrower, for so long as a majority of the aggregate ordinary voting power represented by the issued and outstanding Voting Stock of such direct or indirect parent entity of the Borrower is owned (as defined in Rules 13(d)(3) and 13(d)(5) under the Exchange Act), directly or indirectly, by one or more Permitted Holders described in the foregoing clauses of this definition and (e) any group (within the meaning of Section 13(d)(3) or Section 14(d)(2) of the Exchange Act) of which any of the Permitted Holders are members; provided that in the case of such group and without giving effect to the existence of such group or any other group, the Sponsor, directly or indirectly, has beneficial ownership of more than 50% of the total voting power of the Voting Stock of the Borrower.

“Permitted Intercompany Activities” shall mean any transactions between or among the Borrower and its Subsidiaries that are entered into in the ordinary course of business of the Borrower and its Subsidiaries and, in the good faith judgment of the Borrower, are necessary or advisable in connection with the ownership or operation of the business of the Borrower and its Subsidiaries consisting of (i) payroll, cash management, purchasing, insurance and hedging arrangement, (ii) management, technology and licensing arrangements and (iii) other general and administrative expenses.

“Permitted Investments” shall mean:

(a)    Dollars;

(b)    (i) Euros, Yen, Canadian Dollars, Pound Sterling or any national currency of any Participating Member State of the EMU or (ii) in the case of any Foreign Subsidiary or any jurisdiction in which the Borrower or its Restricted Subsidiaries conducts business, such local currencies held by it from time to time in the ordinary course of business and not for speculation;

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(c)    securities issued or unconditionally guaranteed by the United States government or any agency or instrumentality thereof, in each case having maturities and/or reset dates of not more than 24 months from the date of acquisition thereof;

(d)    securities issued by any state, territory or commonwealth of the United States of America or any political subdivision of any such state, territory or commonwealth or any public instrumentality thereof or any political subdivision of any such state, territory or commonwealth or any public instrumentality thereof having maturities of not more than 24 months from the date of acquisition thereof and, at the time of acquisition, having an investment grade rating generally obtainable from either S&P or Moody’s (or, if at any time neither S&P nor Moody’s shall be rating such obligations, then from another nationally recognized rating service);

(e)    commercial paper and variable or fixed rate notes maturing no more than 36 months after the date of creation thereof and, at the time of acquisition, having a rating of at least A-2 or P-2 from either S&P or Moody’s (or, if at any time neither S&P nor Moody’s shall be rating such obligations, an equivalent rating from another nationally recognized rating service);

(f)    time deposits, certificates of deposit or eurodollar time deposits maturing no more than two years after the date of acquisition thereof or bankers’ acceptances maturing no more than three years after the date of acquisition thereof, in each case, issued by any Lender or any other bank having combined capital and surplus of not less than $500,000,000 in the case of domestic banks and $100,000,000 (or the Dollar equivalent thereof) in the case of foreign banks;

(g)    repurchase agreements for underlying securities of the type described in clauses (c), (d) and (f) above or clauses (h) and (i) below entered into with any bank meeting the qualifications specified in clause (d) above or securities dealers of recognized national standing;

(h)    marketable short-term money market and similar funds (i) either having assets in excess of $500,000,000 or (ii) having a rating of at least A-2 or P-2 from either S&P or Moody’s (or, if at any time neither S&P nor Moody’s shall be rating such obligations, an equivalent rating from another nationally recognized rating service);

(i)    readily marketable direct obligations issued or fully guaranteed by (i) any state, commonwealth or territory of the United States or any political subdivision or taxing authority thereof or (ii) any foreign government or any political subdivision or public instrumentality thereof; provided, that each such readily marketable direct obligation shall have an investment grade rating generally obtainable from either S&P or Moody’s (or, if at any time neither S&P nor Moody’s shall be rating such obligations, then from another nationally recognized rating service) with maturities of 36 months or less from the date of acquisition;

(j)    Investments with average maturities of 36 months or less from the date of acquisition in money market funds rated AAA- (or the equivalent thereof) or better by

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S&P or Aaa3 (or the equivalent thereof) or better by Moody’s (or, if at any time neither S&P nor Moody’s shall be rating such obligations, then from another nationally recognized rating service);

(k)    shares of investment companies that are registered under the Investment Company Act of 1940 and substantially all the investments of which are one or more of the types of securities described in clauses (a) through (j) above; and

(l)    in the case of Investments by any Restricted Foreign Subsidiary or Investments made in a country outside the United States of America, Permitted Investments shall include other customarily utilized high-quality Investments of the type and maturity described in clauses (a) through (h) above of foreign obligors, which Investments or obligors (or the parents of such obligors) have ratings described in such clauses or equivalent ratings from comparable foreign rating agencies and (ii) other shorter term investments utilized by Restricted Foreign Subsidiaries in accordance with normal investment practices for cash management in Investments analogous to the foregoing investments in clauses (a) through (k) above and in this clause (l).

Notwithstanding the foregoing, Permitted Investments shall include amounts denominated in currencies other than those set forth in clauses (a) and (b) above; provided that such amounts are converted into any currency listed in clause (a) or (b) above as promptly as practicable and in any event within ten Business Days following the receipt of such amounts

“Permitted Liens” shall mean:

(a)    Liens for taxes, assessments or governmental charges or claims not yet overdue for a period of more than 30 days or that are being contested in good faith and by appropriate proceedings for which appropriate reserves have been established to the extent required by and in accordance with GAAP (or in the case of any Foreign Subsidiary, the comparable accounting principles in the relevant jurisdiction), or for property taxes on property that the Borrower or one of its Subsidiaries has determined to abandon if the sole recourse for such tax, assessment, charge or claim is to such property;

(b)    Liens in respect of property or assets of the Borrower or any of the Restricted Subsidiaries imposed by law, such as landlords’, sublandlords’, vendors’, suppliers’, carriers’, warehousemen’s, repairmens’, construction contractors’, workers’ and mechanics’ Liens and other similar Liens arising in the ordinary course of business or incident to the exploration, development, operation or maintenance of Oil and Gas Properties, in each case so long as such Liens arise in the ordinary course of business and do not individually or in the aggregate have a Material Adverse Effect;

(c)    Liens arising from judgments or decrees in circumstances not constituting an Event of Default under Section 11.9;

(d)    Liens incurred or pledges or deposits made in connection with workers’ compensation, unemployment insurance and other types of social security, old age pension, public liability obligations or similar legislation and deposits securing liabilities

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to insurance carriers under insurance or self-insurance arrangements in respect of such obligations, or to secure (or secure the Liens securing) liability for reimbursement or indemnification obligations of (including obligations in respect of letters of credit or bank guarantees for the benefit of) insurance carriers providing property, casualty or liability insurance to the Borrower or any Subsidiary;

(e)    deposits and other Liens securing (or securing the bonds or similar instruments securing) the performance of tenders, statutory obligations, plugging and abandonment obligations, surety, stay, customs and appeal bonds, bids, leases, government contracts, trade contracts, performance and return-of-money bonds and other similar obligations (including letters of credit issued in lieu of such bonds or to support the issuance thereof) incurred in the ordinary course of business or in a manner consistent with past practice or industry practice including those incurred to secure health, safety and environmental obligations in the ordinary course of business or otherwise constituting Investments permitted by Section 10.5;

(f)    ground leases, subleases, licenses or sublicenses in respect of real property on which facilities owned or leased by the Borrower or any of its Restricted Subsidiaries are located;

(g)    easements, rights-of-way, restrictive covenants, licenses, restrictions (including zoning restrictions), title defects, exceptions, deficiencies or irregularities in title, encroachments, protrusions, servitudes, permits, conditions and covenants and other similar charges or encumbrances (including in any rights of way or other property of the Borrower or its Restricted Subsidiaries for the purpose of roads, pipelines, transmission lines, transportation lines, distribution lines for the removal of gas, oil or other minerals or timber, and other like purposes, or for joint or common use of real estate, rights of way, facilities and equipment) not interfering in any material respect with the business of the Borrower and its Restricted Subsidiaries, taken as a whole and, to the extent reasonably agreed by the Administrative Agent, any exception on the title reports issued in connection with any Borrowing Base Property;

(h)    (i) any interest or title of a lessor, sublessor, licensor or sublicensor under any lease, liens reserved in oil, gas or other Hydrocarbons, minerals, leases for bonus, royalty or rental payments and for compliance with the terms of such lease and (ii) any interest or title of a lessor, sublessor, licensor or sublicensor or secured by a lessor’s, sublessor’s, licensor’s or sublicensor’s interest under any lease, sublease, license or sublicense entered into by the Borrower or any Restricted Subsidiary in the ordinary course of business or otherwise permitted by this Agreement;

(i)    Liens in favor of customs and revenue authorities arising as a matter of law to secure payment of customs duties in connection with the importation of goods;

(j)    Liens on goods or inventory the purchase, shipment or storage price of which is financed by a documentary letter of credit or bankers’ acceptance issued for the account of the Borrower or any of its Restricted Subsidiaries; provided that such Lien

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secures only the obligations of the Borrower or such Restricted Subsidiaries in respect of such letter of credit or bankers’ acceptance to the extent permitted under Section 10.1;

(k)    leases, licenses, subleases or sublicenses granted to others not interfering in any material respect with the business of the Borrower and its Restricted Subsidiaries, taken as a whole;

(l)    Liens arising from precautionary Uniform Commercial Code financing statement or similar filings made in respect of operating leases entered into by the Borrower or any of its Restricted Subsidiaries;

(m)    Liens created in the ordinary course of business in favor of banks and other financial institutions over credit balances of any bank accounts, commodity trading accounts or other brokerage accounts of the Borrower and the Restricted Subsidiaries held at such banks or financial institutions, as the case may be, in the ordinary course of business;

(n)    Liens which arise in the ordinary course of business under operating agreements, joint venture agreements, oil and gas partnership agreements, oil and gas leases, farm-out agreements, farm-in agreements, division orders, contracts for the sale, gathering, transportation or exchange of oil and natural gas, unitization and pooling declarations and agreements, area of mutual interest agreements, overriding royalty agreements, marketing agreements, processing agreements, net profits agreements, development agreements, gas balancing or deferred production agreements, injection, repressuring and recycling agreements, salt water or other disposal agreements, seismic or other geophysical permits or agreements, and other agreements that are usual and customary in the oil and gas business and are for claims which are not delinquent or that are being contested in good faith and by appropriate proceedings for which appropriate reserves have been established to the extent required by and in accordance with GAAP; provided that any such Lien referred to in this clause does not materially impair the use of the property covered by such Lien for the purposes for which such property is held by the Borrower or any Restricted Subsidiary or materially impair the value of such property subject thereto;

(o)    (i) any zoning, building, entitlement and other land use regulations by Governmental Authorities with which the normal operation of the business complies and (ii) any zoning or similar law or right reserved to or vested in any Governmental Authority to control or regulate the use of any real property that does not materially interfere with the ordinary conduct of the business of the Borrower and its Restricted Subsidiaries, taken as a whole; and

(p)    Liens on pipelines, pipeline facilities and other midstream assets or facilities that arise by operation of law or other like Liens arising by operation of law, in each case in the ordinary course of business and incidental to the exploration, development, operation or maintenance of Oil and Gas Properties.

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(q)    Liens on equipment of the Borrower or any Restricted Subsidiary granted in the ordinary course of business to the Borrower’s or such Restricted Subsidiary’s client at which such equipment is located;

(r)    security given to a public utility or any municipality or governmental authority when required by such utility or authority in connection with the operations of that Person in the ordinary course of business;

(s)    Liens on Permitted Investments that are earmarked to be used to satisfy or discharge Indebtedness; provided that (x) such Permitted Investments are deposited into an account from which payment is to be made, directly or indirectly, to the Person or Persons holding the Indebtedness that is to be satisfied or discharged, (y) such Liens extend solely to the account in which such Permitted Investments are deposited and are solely in favor of the Person or Persons holding the Indebtedness (or any agent or trustee for such Person or Persons) that is to be satisfied or discharged and (z) the satisfaction or discharge of such Indebtedness is expressly permitted hereunder; and

(t)    deposits of cash with the owner or lessor of premises leased and operated by the Borrower or any of its Subsidiaries to secure the performance of the Borrower’s or such Subsidiary’s obligations under the terms of the lease for such premises.

Without limiting the ability of the Administrative Agent or Collateral Agent, as applicable, to subordinate any Lien to the extent permitted by the terms of this Agreement (including pursuant to Section 12.11), the parties acknowledge and agree that no intention to subordinate the priority afforded the Liens granted in favor of the Collateral Agent, for the benefit of the Secured Parties, under the Security Documents is to be hereby implied or expressed by the permitted existence of such Permitted Liens.

“Permitted Junior Lien Debt” shall mean secured Indebtedness which may be senior, senior subordinated or subordinated Indebtedness (provided that the holders of the obligations secured thereby (or a representative or trustee on their behalf) shall have entered into a Customary Intercreditor Agreement providing that the Liens securing such obligations shall rank junior to the Liens securing the Obligations), in each case, issued or incurred by the Borrower and guaranteed by the Guarantors (a) the terms of which do not provide for any scheduled repayment, mandatory redemption or sinking fund obligation prior to the 91st day after the Latest Maturity Date (other than nominal amortization, customary offers to purchase upon a change of control, asset sale or casualty or condemnation event and customary acceleration rights after an event of default), (b) if such Indebtedness is senior subordinated or subordinated Indebtedness, the terms of such Indebtedness provide for customary subordination of such Indebtedness to the Obligations and (c) no Restricted Subsidiary of the Borrower (other than a Guarantor or a Person who becomes a Guarantor in connection therewith) is an obligor under such Indebtedness.

“Permitted Junior Lien Debt Documents” shall mean any document or instrument (including any guarantee, security agreement or mortgage and which may include any or all of the Credit Documents) issued or executed and delivered with respect to any Permitted Junior Lien Debt by any Credit Party.

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“Permitted Parent” shall have the meaning provided in the definition of “Permitted Holder”.

“Permitted Refinancing Indebtedness” shall mean, with respect to any Indebtedness (the “Refinanced Indebtedness”), any Indebtedness issued or incurred in exchange for, or the net proceeds of which are used to modify, extend, refinance, renew, replace or refund (collectively to “Refinance” or a “Refinancing” or “Refinanced”), such Refinanced Indebtedness (or previous refinancing thereof constituting Permitted Refinancing Indebtedness); provided that (A) the principal amount (or accreted value, if applicable) of any such Permitted Refinancing Indebtedness does not exceed the principal amount (or accreted value, if applicable) of the Refinanced Indebtedness outstanding immediately prior to such Refinancing except by an amount equal to the unpaid accrued interest and premium thereon plus other amounts paid and fees and expenses incurred in connection with such Refinancing plus an amount equal to any existing commitment unutilized and letters of credit undrawn thereunder, (B) if the Indebtedness being Refinanced is Indebtedness permitted by Section 10.1(h), (j) or (o), the direct and contingent obligors with respect to such Permitted Refinancing Indebtedness are not changed as a result of such Refinancing (except that a Credit Party may be added as an additional obligor), (C) other than with respect to a Refinancing in respect of Indebtedness permitted pursuant to Section 10.1(g), such Permitted Refinancing Indebtedness shall have a final maturity date equal to or later than the final maturity date of, and has a Weighted Average Life to Maturity equal to or greater than the Weighted Average Life to Maturity of, the Refinanced Indebtedness, (D) if the Indebtedness being Refinanced is Indebtedness permitted by Section 10.1(h) or Section 10.1(o), the terms and conditions of any such Permitted Refinancing Indebtedness, taken as a whole, are not materially less favorable to the Lenders than the terms and conditions of the Refinanced Indebtedness being Refinanced (including, if applicable, as to collateral priority and subordination, but excluding as to interest rates, fees, floors, funding discounts and redemption or prepayment premiums) or are customary for similar Indebtedness in light of current market conditions; provided that a certificate of an Authorized Officer of the Borrower delivered to the Administrative Agent at least three Business Days prior to the incurrence or issuance of such Indebtedness, together with a reasonably detailed description of the material terms and conditions of such Indebtedness or drafts of the documentation relating thereto, stating that the Borrower has determined in good faith that such terms and conditions satisfy the foregoing requirement shall be conclusive evidence that such terms and conditions satisfy the foregoing requirement, (E) if such Refinanced Indebtedness is senior subordinated or subordinated Indebtedness, the terms of such Permitted Refinancing Indebtedness shall provide for customary subordination of such Indebtedness to the Obligations on terms no less favorable to the Secured Parties than the subordination terms applicable to the Indebtedness being refinanced, (F) if the Indebtedness being Refinanced is Permitted Additional Debt, then, to the extent such Permitted Refinancing Indebtedness constitutes Permitted Additional Debt, such Permitted Refinancing Indebtedness shall comply with the conditions set forth in the definition of Permitted Additional Debt and shall be deemed to be Permitted Additional Debt as such term is used in this Agreement and (G) if the Indebtedness being Refinanced is Permitted Junior Lien Debt, then, to the extent such Permitted Refinancing Indebtedness constitutes Permitted Junior Lien Debt, such Permitted Refinancing Indebtedness shall comply with the conditions set forth in the definition of Permitted Junior Lien Debt and shall be deemed to be Permitted Junior Lien Debt as such term is used in this Agreement.

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“Person” shall mean any individual, partnership, joint venture, firm, corporation, limited liability company, association, trust or other enterprise or any Governmental Authority.

“Petroleum Industry Standards” shall mean the Definitions for Oil and Gas Reserves promulgated by the Society of Petroleum Engineers (or any generally recognized successor) as in effect at the time in question.

“Plan” shall mean any multiemployer or single-employer plan, as defined in Section 4001 of ERISA and subject to Title IV of ERISA, that is or was within any of the preceding six plan years maintained or contributed to by (or to which there is or was an obligation to contribute or to make payments to) the Borrower or an ERISA Affiliate.

“Pledge Agreement” shall mean the Pledge Agreement entered into by the Borrower, the other pledgors party thereto and the Collateral Agent, for the benefit of the Secured Parties, substantially in the form of Exhibit H.

“Post Acquisition Period” shall mean, with respect to any Specified Transaction, the period beginning on the date such Specified Transaction is consummated and ending on the last day of the fourth full consecutive fiscal quarter immediately following the date on which such Specified Transaction is consummated.

“Present Fair Salable Value” shall mean the amount that could be obtained by an independent willing seller from an independent willing buyer if the assets (both tangible and intangible) of the Borrower and its Subsidiaries taken as a whole are sold on a going concern basis with reasonable promptness in an arm’s-length transaction under present conditions for the sale of comparable business enterprises insofar as such conditions can be reasonably evaluated.

“Proceeding” shall have the meaning provided in Section 13.5.

“Pro Forma Adjustment” shall mean, for any Test Period that includes all or any part of a fiscal quarter included in any Post Acquisition Period, with respect to the Acquired EBITDAX of the applicable Pro Forma Entity or the Consolidated EBITDAX of the Borrower, the pro forma increase or decrease in such Acquired EBITDAX or such Consolidated EBITDAX, as the case may be, projected by the Borrower in good faith as a result of (a) actions taken or expected to be taken prior to or during such Post Acquisition Period for the purposes of realizing reasonably identifiable and factually supportable cost savings, operating expense reductions and cost synergies or (b) any additional costs incurred prior to or during such Post Acquisition Period, in each case in connection with the combination of the operations of such Pro Forma Entity with the operations of the Borrower and the Restricted Subsidiaries; provided that (i) at the election of the Borrower, such Pro Forma Adjustment shall not be required to be determined for any Pro Forma Entity to the extent the aggregate consideration paid in connection with such acquisition was less than the greater of $25,000,000 and 5% of Consolidated EBITDAX as of the then most recently ended Test Period and (ii) so long as such actions are taken prior to or during such Post Acquisition Period or such costs are incurred during such Post Acquisition Period, as applicable, it may be assumed, for purposes of projecting such pro forma increase or decrease to such Acquired EBITDAX or such Consolidated EBITDAX, as the case may be, that the applicable amount of such cost savings, operating expense reductions and cost synergies will be realizable during the entirety of such Test Period, or the applicable amount of such additional costs, as

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applicable, will be incurred during the entirety of such Test Period; provided, further, that any such pro forma increase or decrease to such Acquired EBITDAX or such Consolidated EBITDAX, as the case may be, shall be without duplication for cost savings, operating expense reductions, cost synergies or additional costs already included in such Acquired EBITDAX or such Consolidated EBITDAX, as the case may be, for such Test Period.

“Pro Forma Basis”, “Pro Forma Compliance” and “Pro Forma Effect” shall mean, with respect to compliance with any test or covenant or calculation of any ratio hereunder, that (A) to the extent applicable, the Pro Forma Adjustment shall have been made and (B) all Specified Transactions and the following transactions in connection therewith shall be deemed to have occurred as of the first day of the applicable period of measurement in such test or covenant: (a) income statement items (whether positive or negative) attributable to the property or Person subject to such Specified Transaction, which (i) in the case of a Disposition of all or substantially all Stock or Stock Equivalents in any Subsidiary of the Borrower or any division, product line, or facility used for operations of the Borrower or any of its Subsidiaries, shall be excluded, and (ii) in the case of a Permitted Acquisition or Investment described in the definition of “Specified Transaction”, shall be included (and may be included on an annualized basis, at the election of the Borrower, if annualizing such income statement items is a more appropriate indicator of future performance than inclusion of the actual income statement items (as reasonably determined by the Borrower)), (b) any retirement, redemption, repayment, discharge, defeasance or extinguishment of Indebtedness, and (c) any Indebtedness incurred or assumed by the Borrower or any of the Restricted Subsidiaries in connection therewith (and if such Indebtedness has a floating or formula rate, such Indebtedness shall have an implied rate of interest for the applicable period for purposes of this definition determined by utilizing the rate which is or would be in effect with respect to such Indebtedness as at the relevant date of determination); provided that, without limiting the application of the Pro Forma Adjustment pursuant to (A) above, the foregoing pro forma adjustments may be applied to any such test solely to the extent that such adjustments are consistent with the definition of Consolidated EBITDAX and give effect to events (including operating expense reductions) that are (as determined by the Borrower in good faith) (i) (x) directly attributable to such transaction, (y) expected to have a continuing impact on the Borrower and the Restricted Subsidiaries and (z) factually supportable or (ii) otherwise consistent with the definition of Pro Forma Adjustment; provided, further, that, at the election of the Borrower, such test or covenant shall deemed to have been conducted on a Pro Forma Basis and shall not be required to be determined on a Pro Forma Basis to the extent the consideration paid or received in connection with acquisitions or dispositions, for which the election has been taken, is in aggregate at the time of determination less than the greater of $25,000,000 and 5% of Consolidated EBITDAX as of the then most recently ended Test Period.

“Pro Forma Entity” shall have the meaning provided in the definition of the term “Acquired EBITDAX.”

“Pro Forma Projections” shall have the meaning provided in Section 8.8(a).

“Production Forecast Update” shall have the meaning provided in Section 10.10(a).

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“Production Payment” means a production payment obligation (whether volumetric or dollar denominated) of the Borrower or any of its Restricted Subsidiaries which is payable from a specified share of proceeds received from production from specified Oil and Gas Properties, together with all undertakings and obligations in connection therewith.

“Proposed Acquisition” shall have the meaning provided in Section 10.10(b).

“Proposed Borrowing Base” shall have the meaning provided in Section 2.14(c)(i).

“Proposed Borrowing Base Notice” shall have the meaning provided in Section 2.14(c)(ii).

“Proved Reserves” shall mean oil and gas reserves that, in accordance with Petroleum Industry Standards, are classified as both “Proved Reserves” and one of the following: (a) “Developed Producing Reserves”, (b) “Developed Non-Producing Reserves” or (c) “Undeveloped Reserves”.

“PTE” means a prohibited transaction class exemption issued by the U.S. Department of Labor, as such exemption may be amended from time to time.

“Public Company Compliance” shall mean compliance with the requirements of the Sarbanes-Oxley Act of 2002, as amended, and the rules and regulations promulgated in connection therewith, the provisions of the Securities Act and the Exchange Act, and the rules of national securities exchange listed companies (in each case, as applicable to companies with equity or debt securities held by the public), including procuring directors and officers’ insurance, legal and other professional fees, and listing fees.

“PV-9” shall mean, with respect to any Borrowing Base Properties or Oil and Gas Properties becoming Borrowing Base Properties, the net present value, discounted at 9% per annum, of the future net revenues expected to accrue to the Borrower’s and the Credit Parties’ collective interests in such reserves during the remaining expected economic lives of such reserves, calculated in accordance with the most recent Bank Price Deck provided to the Borrower by the Administrative Agent pursuant to Section 2.14(j).

“QFC” has the meaning assigned to the term “qualified financial contract” in, and shall be interpreted in accordance with, 12 U.S.C. 5390(c)(8)(D).

“QFC Credit Support” shall have the meaning assigned to such term in Section 13.28(a).

“Qualified IPO” means any transaction or series of transactions, including a SPAC IPO, that results in, or following which, any common Stock or Stock Equivalents of the Borrower, IPOCo, other direct or indirect parent of the Borrower or any SPAC IPO Entity (or its successor by merger, amalgamation or other combination) being publicly traded on any United States national securities exchange or over-the-counter market, or any analogous exchange or market in Canada, the United Kingdom or the European Union.

“Qualified Professional Asset Manager” shall have the meaning provided in Section 13.27(a)(iii)(A).

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“Recipient” shall have the meaning provided in the definition of the term “Excluded Taxes”.

“Redetermination Date” shall mean, with respect to any Scheduled Redetermination or any Interim Redetermination, the date that the redetermined Borrowing Base related thereto becomes effective pursuant to Section 2.14(d).

“Reference Time” with respect to any setting of the then-current Benchmark means (1) if such Benchmark is LIBOR, 11:00 a.m. (London time) on the day that is two (2) London Banking Days preceding the date of such setting, and (2) if such Benchmark is not LIBOR, the time determined by the Administrative Agent in its reasonable discretion.

“Refinance” shall have the meaning provided in the definition of “Permitted Refinancing Indebtedness.”

“Register” shall have the meaning provided in Section 13.6(b)(iv).

“Regulation T” shall mean Regulation T of the Board as from time to time in effect and any successor to all or a portion thereof establishing margin requirements.

“Regulation U” shall mean Regulation U of the Board as from time to time in effect and any successor to all or a portion thereof establishing margin requirements.

“Regulation X” shall mean Regulation X of the Board as from time to time in effect and any successor to all or a portion thereof establishing margin requirements.

“Reimbursement Date” shall have the meaning provided in Section 3.4(a).

“Related Parties” shall mean, with respect to any specified Person, such Person’s Affiliates and the directors, officers, employees, agents and members of such Person or such Person’s Affiliates and any Person that possesses, directly or indirectly, the power to direct or cause the direction of the management or policies of such Person, whether through the ability to exercise voting power, by contract or otherwise.

“Relevant Governmental Body”means the Board or the Federal Reserve Bank of New York, or a committee officially endorsed or convened by the Board or the Federal Reserve Bank of New York or any successor thereto.

“Replaced Loans” shall have the meaning assigned to such term in Section 13.1(h).

“Replacement Loans” shall have the meaning assigned to such term in Section 13.1(h).

“Reportable Event” shall mean an event described in Section 4043 of ERISA and the regulations thereunder, other than any event as to which the 30-day notice period has been waived.

“Required Lenders” shall mean, at any date, (a) Non-Defaulting Lenders having or holding at least 66-2/3% of the Adjusted Total Commitment at such date or (b) if the Total Commitment has been terminated, Non-Defaulting Lenders having or holding at least 66-2/3% of

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the outstanding principal amount of the Loans and Letter of Credit Exposure (excluding the Loans and Letter of Credit Exposure of Defaulting Lenders) in the aggregate at such date.

“Requirement of Law” shall mean, as to any Person, any law, treaty, rule, regulation statute, order, ordinance, decree, judgment, consent decree, writ, injunction, settlement agreement or governmental requirement enacted, promulgated or imposed or entered into or agreed by any Governmental Authority, in each case applicable to or binding upon such Person or any of its property or assets or to which such Person or any of its property or assets is subject.

“Reserve Report” shall mean the Initial Reserve Report and any other subsequent report, in form and substance reasonably satisfactory to the Administrative Agent, setting forth, as of each June 30th or December 31st (or such other date in the event of certain Interim Redeterminations or such other date permitted hereunder) the Proved Reserves attributable to the Borrowing Base Properties of the Borrower and the Credit Parties, together with a projection of the rate of production and future net income, taxes, operating expenses and Capital Expenditures with respect thereto as of such date, based upon the most recent Bank Price Deck provided to the Borrower by the Administrative Agent pursuant to Section 2.14(j); provided that in connection with any Interim Redeterminations of the Borrowing Base pursuant to the last sentence of Section 2.14(b), (i.e., as a result of the Borrower having acquired Oil and Gas Properties with Proved Reserves which are to be Borrowing Base Properties having a PV-9 (calculated at the time of acquisition) in excess of 5% of the Borrowing Base in effect immediately prior to such acquisition), the Borrower shall be required, for purposes of updating the Reserve Report, to set forth only such additional Proved Reserves and related information as are the subject of such acquisition.

“Reserve Report Certificate” shall mean a certificate of an Authorized Officer in substantially the form of Exhibit I certifying as to the matters set forth in Section 9.14(c).

“Resolution Authority” shall mean an EEA Resolution Authority or, with respect to any UK Financial Institution, a UK Resolution Authority.

“Restricted Foreign Subsidiary” shall mean a Foreign Subsidiary that is a Restricted Subsidiary.

“Restricted Subsidiary” shall mean any Subsidiary of the Borrower other than an Unrestricted Subsidiary.

“S&P” shall mean Standard & Poor’s Ratings Services or any successor by merger or consolidation to its business.

“Sanctions Laws and Regulations” shall mean any sanctions, prohibitions or trade embargoes imposed by any executive order of the U.S. government or by any sanctions program administered by OFAC.

“Scheduled Dispositions” shall have the meaning provided in Section 10.4(i).

“Scheduled Redetermination” shall have the meaning provided in Section 2.14(b).

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“Scheduled Redetermination Date” shall mean the date on which a Borrowing Base that has been redetermined pursuant to a Scheduled Redetermination becomes effective as provided in Section 2.14(d).

“SDN” shall have the meaning provided in the definition of the term “Designated Persons.”

“SDN List” shall have the meaning provided in the definition of the term “Designated Persons.”

“SEC” shall mean the Securities and Exchange Commission or any successor thereto.

“Section 2.17 Additional Amendment” shall have the meaning provided in Section 2.17(c).

“Section 9.1 Financials” shall mean the financial statements delivered, or required to be delivered, pursuant to Section 9.1(a) or (b), together with the accompanying Authorized Officer’s certificate delivered, or required to be delivered, pursuant to Section 9.1(c).

“Secured Cash Management Agreement” shall mean any agreement related to Cash Management Services by and between the Borrower or any of its Restricted Subsidiaries and any Cash Management Bank.

“Secured Hedge Agreement” shall mean any Hedge Agreement by and between the Borrower or any of its Restricted Subsidiaries and any Hedge Bank.

“Secured Parties” shall mean, collectively, the Administrative Agent, the Collateral Agent, each Letter of Credit Issuer, each Lender, each Hedge Bank that is party to any Secured Hedge Agreement, each Cash Management Bank that is a party to any Secured Cash Management Agreement and each sub-agent pursuant to Section 12 appointed by the Administrative Agent with respect to matters relating to the Credit Documents or by the Collateral Agent with respect to matters relating to any Security Document.

“Securities Act” shall mean the Securities Act of 1933, as amended, and the rules and regulations promulgated thereunder.

“Security Agreement” shall mean the Security Agreement entered into by the Borrower, the other grantors party thereto and the Collateral Agent, for the benefit of the Secured Parties, substantially in the form of Exhibit J.

“Security Documents” shall mean, collectively, (a) the Security Agreement, (b) the Pledge Agreement, (c) the Mortgages, (d) the Account Control Agreements and (e) each other security agreement or other instrument or document executed and delivered pursuant to Section 9.11 or Section 9.13 or pursuant to any other such Security Documents or otherwise to secure or perfect the security interest in any or all of the Obligations.

“SOFR” means, with respect to any Business Day, a rate per annum equal to the secured overnight financing rate for such Business Day published by the SOFR Administrator on the SOFR Administrator’s Website at approximately 8:00 a.m. (New York City time) on the immediately succeeding Business Day.

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“SOFR Administrator” means the Federal Reserve Bank of New York (or a successor administrator of the secured overnight financing rate).

“SOFR Administrator’s Website” means the website of the Federal Reserve Bank of New York, currently at http://www.newyorkfed.org, or any successor source for the secured overnight financing rate identified as such by the SOFR Administrator from time to time.

“Sold Entity or Business” shall have the meaning provided in the definition of the term “Consolidated EBITDAX”.

“Solvent” shall mean, with respect to any Person, that as of the Closing Date, (i) the Fair Value of the assets of such Person exceeds its Stated Liabilities and Identified Contingent Liabilities; (ii) the Present Fair Salable Value of the assets of such Person exceeds its Stated Liabilities and Identified Contingent Liabilities; (iii) for the period from the date hereof through the Initial Maturity Date, such Person after consummation of the Transactions is a going concern and has sufficient capital to ensure that it will continue to be a going concern for such period, in light of the nature of the particular business or businesses conducted or to be conducted, and based on the needs and anticipated needs for capital of the business conducted or anticipated to be conducted by such Person as reflected in projected financial statements and in light of anticipated credit capacity; and (iv) for the period from the date hereof through the Maturity Date, such Person will have sufficient assets and cash flow to pay its Stated Liabilities and Identified Contingent Liabilities as those liabilities mature or (in the case of contingent liabilities) otherwise become payable, in light of the business conducted or anticipated to be conducted by such Person as reflected in projected financial statements and in light of anticipated credit capacity.

“SPAC IPO” means the acquisition, purchase, merger, amalgamation or other combination of the Borrower or any direct or indirect parent of the Borrower, by, or with, a publicly traded special purpose acquisition company or targeted acquisition company or any entity similar to the foregoing (a “SPAC IPO Entity”) that results in any common Stock or Stock Equivalents of the Borrower, any direct or indirect parent of the Borrower or such SPAC IPO Entity (or its successor by merger, amalgamation or other combination) being publicly traded on any United States national securities exchange or over-the-counter market, or any analogous exchange or market in Canada, the United Kingdom or the European Union.

“Specified Existing Commitment” shall mean any Existing Commitments belonging to a Specified Existing Commitment Class.

“Specified Existing Commitment Class” shall have the meaning provided in Section 2.17(a).

“Specified Subsidiary” shall mean, at any date of determination any Restricted Subsidiary (i) whose Total Assets at the last day of the Test Period ending on the last day of the most recently ended Test Period were equal to or greater than 15% of the Total Assets of the Borrower and the Restricted Subsidiaries at such date, or (ii) whose revenues during such Test Period were equal to or greater than 15% of the consolidated revenues of the Borrower and the Restricted Subsidiaries for such period, in each case determined in accordance with GAAP.

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“Specified Transaction” shall mean, with respect to any period, any Investment, any Disposition of assets, incurrence, issuance or Refinancing of Indebtedness, Dividend, Subsidiary designation, Incremental Increase or other event that by the terms of this Agreement requires “Pro Forma Compliance” with a test or covenant hereunder or requires such test or covenant to be calculated on a “Pro Forma Basis.”

“Sponsor” shall mean KKR and its Affiliates, but excluding (i) the Borrower and Subsidiaries of the Borrower and (ii) portfolio companies of KKR or its Affiliates.

“Stated Amount” of any Letter of Credit shall mean the maximum amount from time to time available to be drawn thereunder, determined without regard to whether any conditions to drawing could then be met.

“Stated Liabilities” shall mean the recorded liabilities (including contingent liabilities that would be recorded in accordance with GAAP) of the Borrower and its Subsidiaries taken as a whole, as of the date hereof after giving effect to the consummation of the Transactions, determined in accordance with GAAP consistently applied.

“Statutory Reserve Rate” shall mean a fraction (expressed as a decimal), the numerator of which is the number one and the denominator of which is the number one minus the aggregate of the maximum reserve percentages (including any marginal, special, emergency or supplemental reserves) expressed as a decimal established by the Board to which the Administrative Agent is subject with respect to the Adjusted LIBOR Rate, for eurocurrency funding (currently referred to as “Eurocurrency Liabilities” in Regulation D of the Board). Such reserve percentages shall include those imposed pursuant to such Regulation D of the Board. LIBOR Loans shall be deemed to constitute eurocurrency funding and to be subject to such reserve requirements without benefit of or credit for proration, exemptions or offsets that may be available from time to time to any Lender under such Regulation D of the Board or any comparable regulation. The Statutory Reserve Rate shall be adjusted automatically on and as of the effective date of any change in any reserve percentage.

“Stock” shall mean any and all shares of capital stock or shares in the capital, as the case may be (whether denominated as common stock or preferred stock or ordinary shares or preferred shares, as the case may be), beneficial, partnership or membership interests, participations or other equivalents (regardless of how designated) of or in a corporation, partnership, limited liability company or equivalent entity, whether voting or non-voting.

“Stock Equivalents” shall mean all securities convertible into or exchangeable for Stock and all warrants, options or other rights to purchase or subscribe for any Stock, whether or not presently convertible, exchangeable or exercisable.

“Subsidiary” of any Person shall mean and include (a) any corporation more than 50% of whose Stock of any class or classes having by the terms thereof ordinary voting power to elect a majority of the directors of such corporation (irrespective of whether or not at the time Stock of any class or classes of such corporation shall have or might have voting power by reason of the happening of any contingency) is at the time owned by such Person directly or indirectly through Subsidiaries and (b) any limited liability company, partnership, association, joint venture or other

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entity of which such Person directly or indirectly through Subsidiaries has more than a 50% equity interest at the time. Unless otherwise expressly provided, all references herein to a “Subsidiary” shall mean a Subsidiary of the Borrower.

“Subsidiary Guarantor” shall mean each Subsidiary that is a Guarantor.

“Successor Borrower” shall have the meaning provided in Section 10.3(a).

“Supported QFC” shall have the meaning assigned to such term in Section 13.28(a).

“Swap” shall mean any agreement, contract, or transaction that constitutes a “swap” within the meaning of Section 1a(47) of the Commodity Exchange Act.

“Swap Obligation” shall mean any obligation to pay or perform under any Swap.

“Swap Termination Value” shall mean, in respect of any one or more Hedge Agreements, after taking into account the effect of any legally enforceable netting agreement relating to such Hedge Agreements, (a) for any date on or after the date such Hedge Agreements have been closed out and termination value(s) determined in accordance therewith, such termination value(s), and (b) for any date prior to the date referenced in clause (a), the amount(s) determined as the mark-to-market value(s) for such Hedge Agreements, as determined based upon one or more mid-market or other readily available quotations provided by any recognized dealer in such Hedge Agreements (which may include a Lender or any Affiliate of a Lender).

“Taxes” shall mean any and all present or future taxes, duties, levies, imposts, assessments, deductions, withholdings or other similar charges imposed by any Governmental Authority whether computed on a separate, consolidated, unitary, combined or other basis and any interest, fines, penalties or additions to tax with respect to the foregoing.

“Term SOFR” means, for the applicable Corresponding Tenor as of the applicable Reference Time, the forward-looking term rate based on SOFR that has been selected or recommended by the Relevant Governmental Body.

“Term SOFR Notice” means a notification by the Administrative Agent to the Lenders and the Borrower of the occurrence of a Term SOFR Transition Event.

“Term SOFR Transition Event” means the determination by the Administrative Agent that (a) Term SOFR has been recommended for use by the Relevant Governmental Body, (b) the administration of Term SOFR is administratively feasible for the Administrative Agent and (c) a Benchmark Transition Event or an Early Opt-in Election, as applicable, has previously occurred resulting in the replacement of the then-current Benchmark for all purposes hereunder and under any Credit Document in accordance with Section 2.18 with a Benchmark Replacement the Unadjusted Benchmark Replacement component of which is not Term SOFR.

“Termination Date” shall mean the earlier to occur of (a) the Maturity Date and (b) the date on which the Total Commitment shall have terminated.

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“Test Period” shall mean, for any determination under this Agreement, the four consecutive fiscal quarters of the Borrower then last ended and for which Section 9.1 Financials have been delivered to the Administrative Agent; provided that, for the avoidance of doubt, the Section 9.1 Financials are deemed to have been delivered to the Administrative Agent for the fiscal quarters of the Borrower ending January 31, 2020, June 30, 2020, September 30, 2020 and December 31, 2020.

“Total Assets” shall mean, as of any date of determination, the amount that would, in conformity with GAAP, be set forth opposite the caption “total assets” (or any like caption) on a consolidated balance sheet of the Borrower and the Restricted Subsidiaries at such date (and, in the case of any determination relating to any incurrence of Indebtedness or any Investment or other acquisition, on a Pro Forma Basis including any property or assets being acquired in connection therewith).

“Total Commitment” shall mean the sum of the Commitments of the Lenders.

“Total Exposure” shall mean, with respect to any Lender at any time, the sum of (a) the aggregate principal amount of the Loans of such Lender then outstanding and (b) such Lender’s Letter of Credit Exposure at such time.

“Transaction Expenses” shall mean any fees or expenses incurred or paid by the Borrower or any of its Subsidiaries or any of their Affiliates in connection with the Transactions, this Agreement and the other Credit Documents and the transactions contemplated hereby and thereby.

“Transactions” shall mean, collectively, the Closing Date Refinancing, the Reorganization, the issuance of the Closing Date Unsecured Notes, and the consummation of the other transactions related to each of the foregoing, the entering into the Credit Documents and this Agreement, the payment of Transaction Expenses on the Closing Date and the other transactions contemplated by this Agreement and the Credit Documents.

“Transferee” shall have the meaning provided in Section 13.6(e).

“Treasury Regulations” shall mean the U.S. Department of Treasury regulations promulgated under the Code.

“Type” shall mean, as to any Loan, its nature as an ABR Loan or a LIBOR Loan.

“UCC” shall mean the Uniform Commercial Code of the State of New York or of any other state the laws of which are required to be applied in connection with the perfection of security interests in any Collateral.

“UK Financial Institution” shall mean any BRRD Undertaking (as such term is defined under the PRA Rulebook (as amended form time to time) promulgated by the United Kingdom Prudential Regulation Authority) or any person falling within IFPRU 11.6 of the FCA Handbook (as amended from time to time) promulgated by the United Kingdom Financial Conduct Authority, which includes certain credit institutions and investment firms, and certain affiliates of such credit institutions or investment firms.

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“UK Resolution Authority” shall mean the Bank of England or any other public administrative authority having responsibility for the resolution of any UK Financial Institution.

“Unadjusted Benchmark Replacement” means the applicable Benchmark Replacement excluding the related Benchmark Replacement Adjustment.

“Unfunded Current Liability” of any Plan shall mean the amount, if any, by which the Accumulated Benefit Obligation (as defined under Statement of Financial Accounting Standards No. 87 (“SFAS 87”)) under the Plan as of the close of its most recent plan year, determined in accordance with SFAS 87 as in effect on the date hereof, exceeds the Fair Market Value of the assets allocable thereto.

“Unpaid Drawing” shall have the meaning provided in Section 3.4(a).

“Unrestricted Cash” shall mean cash or cash equivalents (including Permitted Investments) of the Borrower or any of its Restricted Subsidiaries that would not appear as “restricted” on a consolidated balance sheet of the Borrower or any of its Restricted Subsidiaries; provided that cash or cash equivalents (including Permitted Investments) that would appear as “restricted” on a consolidated balance sheet of Borrower or any of its Restricted Subsidiaries solely because such cash or cash equivalents (including Permitted Investments) are subject to an Account Control Agreement in favor of the Collateral Agent shall constitute Unrestricted Cash hereunder.

“Unrestricted Subsidiary” shall mean (a) any Subsidiary of the Borrower that is formed or acquired after the Closing Date; provided that at such time (or promptly thereafter) the Borrower designates such Subsidiary an Unrestricted Subsidiary in a written notice to the Administrative Agent, (b) any Restricted Subsidiary subsequently designated as an Unrestricted Subsidiary by the Borrower in a written notice to the Administrative Agent; provided that in the case of clauses (a) and (b), (i) such designation shall be deemed to be an Investment (or reduction in an outstanding Investment, in the case of a designation of an Unrestricted Subsidiary as a Restricted Subsidiary) on the date of such designation in an amount equal to the Fair Market Value of the Borrower’s investment therein and such designation shall be permitted only to the extent permitted under Section 10.5 on the date of such designation, (ii) in the case of clause (b), such designation shall be deemed to be a Disposition of the assets owned by such Restricted Subsidiary on the date of such designation for the purposes of Section 2.14(f) and (g), as applicable, and (iii) no Event of Default or Borrowing Base Deficiency would result from such designation after giving Pro Forma Effect thereto and (c) each Subsidiary of an Unrestricted Subsidiary. No Subsidiary may be designated as an Unrestricted Subsidiary if, after such designation, it would be a “Restricted Subsidiary” for the purpose of any Permitted Additional Debt, Permitted Junior Lien Debt or any Permitted Refinancing Indebtedness in respect of any of the foregoing. The Borrower may, by written notice to the Administrative Agent, re-designate any Unrestricted Subsidiary as a Restricted Subsidiary, and thereafter, such Subsidiary shall no longer constitute an Unrestricted Subsidiary, but only if (A) to the extent such Subsidiary has outstanding Indebtedness on the date of such designation, immediately after giving effect to such designation, the Borrower shall be in compliance, on a Pro Forma Basis after giving effect to the incurrence of such Indebtedness, with the Financial Performance Covenants and (B) no Event of Default would result from such re-designation.

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“U.S. Lender” shall have the meaning provided in Section 5.4(h).

“U.S. Special Resolution Regimes” shall have the meaning provided in Section 13.28(a).

“Voting Stock” shall mean, with respect to any Person, such Person’s Stock or Stock Equivalents having the right to vote for the election of directors of such Person under ordinary circumstances.

“Weighted Average Life to Maturity” shall mean, when applied to any Indebtedness at any date, the number of years obtained by dividing: (a) the sum of the products obtained by multiplying (i) the amount of each then remaining installment, sinking fund, serial maturity or other required payments of principal, including payment at final maturity, in respect thereof, by (ii) the number of years (calculated to the nearest one-twelfth) that will elapse between such date and the making of such payment; by (b) the then outstanding principal amount of such Indebtedness.

“Write-Down and Conversion Powers” shall mean, (a) with respect to any EEA Resolution Authority, the write-down and conversion powers of such EEA Resolution Authority from time to time under the Bail-In Legislation for the applicable EEA Member Country, which write-down and conversion powers are described in the EU Bail-In Legislation Schedule, and (b) with respect to the United Kingdom, any powers of the applicable Resolution Authority under the Bail-In Legislation to cancel, reduce, modify or change the form of a liability of any UK Financial Institution or any contract or instrument under which that liability arises, to convert all or part of that liability into shares, securities or obligations of that person or any other person, to provide that any such contract or instrument is to have effect as if a right had been exercised under it or to suspend any obligation in respect of that liability or any of the powers under that Bail-In Legislation that are related to or ancillary to any of those powers.

Section 1.2Other Interpretive Provisions. With reference to this Agreement and each other Credit Document, unless otherwise specified herein or in such other Credit Document:

(a)The meanings of defined terms are equally applicable to the singular and plural forms of the defined terms.

(b)The words “herein”, “hereto”, “hereof” and “hereunder” and words of similar import when used in any Credit Document shall refer to such Credit Document as a whole and not to any particular provision thereof.

(c)Article, Section, Exhibit and Schedule references are to the Credit Document in which such reference appears.

(d)The term “including” is by way of example and not limitation.

(e)The term “documents” includes any and all instruments, documents, agreements, certificates, notices, reports, financial statements and other writings, however evidenced, whether in physical or electronic form.

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(f)In the computation of periods of time from a specified date to a later specified date, the word “from” means “from and including”; the words “to” and “until” each mean “to but excluding”; and the word “through” means “to and including”.

(g)Section headings herein and in the other Credit Documents are included for convenience of reference only and shall not affect the interpretation of this Agreement or any other Credit Document.

(h)Any reference to any Person shall be constructed to include such Person’s successors or assigns (subject to any restrictions on assignment set forth herein) and, in the case of any Governmental Authority, any other Governmental Authority that shall have succeeded to any or all of the functions thereof.

(i)Whenever the context may require, any pronoun shall include the corresponding masculine, feminine and neuter forms.

(j)The word “will” shall be construed to have the same meaning as the word “shall”.

(k)The words “asset” and “property” shall be construed to have the same meaning and effect and to refer to any and all tangible and intangible assets and properties, including cash, securities, accounts and contract rights.

(l)No provision of any Credit Document shall be interpreted or construed against any Person solely because such Person or its legal counsel drafted such provision.

(m)The principal amount of any non-interest bearing Indebtedness or other discount security constituting Indebtedness at any date shall be the principal amount thereof that would be shown on a balance sheet of the Borrower dated such date prepared in accordance with GAAP.

Section 1.3Accounting Terms.

(a)All accounting terms not specifically or completely defined herein shall be construed in conformity with, and all financial data (including financial ratios and other financial calculations) required to be submitted pursuant to this Agreement shall be prepared in conformity with, GAAP, applied in a manner consistent with that used in preparing the first audited financial statements delivered under Section 9.1(a) (and prior to such time in a manner consistent with the past practices of the Sponsor for its portfolio companies in the oil and gas sector as reasonably determined by the Borrower), except as otherwise specifically prescribed herein; provided, however, that if the Borrower notifies the Administrative Agent that the Borrower requests an amendment to any provision hereof to eliminate the effect of any change occurring after the Closing Date in GAAP or in the application thereof on the operation of such provision (or if the Administrative Agent notifies the Borrower that the Required Lenders request an amendment to any provision hereof for such purpose), regardless of whether any such notice is given before or after such change in GAAP or in the application thereof, then such provision shall be interpreted on the basis of GAAP as in effect and applied immediately before such

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change shall have become effective until such notice shall have been withdrawn or such provision amended in accordance herewith.

(b)Notwithstanding anything to the contrary herein, for purposes of determining compliance with any test or covenant contained in this Agreement with respect to any period during which any Specified Transaction occurs, the Consolidated Total Debt to Consolidated EBITDAX Ratio and the Current Ratio, as applicable, shall be calculated with respect to such period and such Specified Transaction on a Pro Forma Basis.

Section 1.4Rounding. Any financial ratios required to be maintained or complied with by the Borrower pursuant to this Agreement (or required to be satisfied in order for a specific action to be permitted under this Agreement) shall be calculated by dividing the appropriate component by the other component, carrying the result to one place more than the number of places by which such ratio is expressed herein and rounding the result up or down to the nearest number (with a rounding-up if there is no nearest number).

Section 1.5References to Agreements, Laws, Etc. Unless otherwise expressly provided herein, (a) references to organizational documents, agreements (including the Credit Documents) and other Contractual Requirements shall be deemed to include all subsequent amendments, restatements, amendment and restatements, extensions, supplements and other modifications thereto, but only to the extent that such amendments, restatements, amendment and restatements, extensions, supplements and other modifications are permitted by any Credit Document and (b) references to any Requirement of Law shall include all statutory and regulatory provisions consolidating, amending, replacing, supplementing or interpreting such Requirement of Law.

Section 1.6Times of Day. Unless otherwise specified, all references herein to times of day shall be references to New York City (daylight or standard, as applicable).

Section 1.7Timing of Payment or Performance. When the payment of any obligation or the performance of any covenant, duty or obligation is stated to be due or performance required on a day which is not a Business Day, the date of such payment (other than as described in Section 2.9) or performance shall extend to the immediately succeeding Business Day.

Section 1.8Currency Equivalents Generally.

(a)For purposes of any determination under Section 9, Section 10 (other than Section 10.11) or Section 11 or any determination under any other provision of this Agreement requiring the use of a current exchange rate, all amounts incurred, outstanding or proposed to be incurred or outstanding in currencies other than Dollars shall be translated into Dollars at the Exchange Rate then in effect on the date of such determination; provided, however, that (x) for purposes of determining compliance with Section 10 with respect to the amount of any Indebtedness, Investment, Disposition, Dividend or payment under Section 10.7 in a currency other than Dollars, no Default or Event of Default shall be deemed to have occurred solely as a result of changes in rates of exchange occurring after the time such Indebtedness or Investment is incurred or

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Disposition, Dividend or payment under Section 10.7 is made, (y) for purposes of determining compliance with any Dollar-denominated restriction on the incurrence of Indebtedness, if such Indebtedness is incurred to Refinance other Indebtedness denominated in a foreign currency, and such Refinancing would cause the applicable Dollar-denominated restriction to be exceeded if calculated at the relevant currency exchange rate in effect on the date of such Refinancing, such Dollar-denominated restriction shall be deemed not to have been exceeded so long as the principal amount of such Refinanced Indebtedness does not exceed the principal amount of such Indebtedness being Refinanced and (z) for the avoidance of doubt, the foregoing provisions of this Section 1.8 shall otherwise apply to such Sections, including with respect to determining whether any Indebtedness or Investment may be incurred or Disposition, Dividend or payment under Section 10.7 may be made at any time under such Sections. For purposes of Section 10.11, amounts in currencies other than Dollars shall be translated into Dollars at the applicable exchange rates used in preparing the most recently delivered financial statements pursuant to Section 9.1(a) or Section 9.1(b).

(b)Each provision of this Agreement shall be subject to such reasonable changes of construction as the Administrative Agent may from time to time specify with the Borrower’s consent (such consent not to be unreasonably withheld) to appropriately reflect a change in currency of any country and any relevant market conventions or practices relating to such change in currency.

Section 1.9Classification of Loans and Borrowings. For purposes of this Agreement, Loans may be classified and referred to by Class (e.g., an “Extended Loan”) or by Type (e.g., a “LIBOR Loan”) or by Class and Type (e.g., a “LIBOR Extended Loan”).

Section 1.10Pro Forma Calculations.

(a)Notwithstanding anything to the contrary herein, financial ratios and tests, including the Financial Performance Covenants, shall be calculated in the manner prescribed by this Section 1.10; provided that notwithstanding anything to the contrary in Section 1.10(b), (c) or (d), when calculating the Financial Performance Covenants for purposes of determining actual compliance (and not Pro Forma Compliance or compliance on a Pro Forma Basis) with the Financial Performance Covenants, the events described in this Section 1.10 that occurred subsequent to the end of the applicable Test Period shall not be given pro forma effect. In addition, whenever a covenant, test or ratio is to be calculated on a pro forma basis, the reference to the “Test Period” for purposes of calculating such financial ratio or test shall be deemed to be a reference to, and shall be based on, the most recently ended Test Period for which financial statements of the Borrower are available; provided that, the provisions of this sentence shall not apply for purposes of determining actual compliance with the Financial Performance Covenants for purposes of Section 10.11 (other than, for the avoidance of doubt, for the purpose of determining pro forma compliance with the Financial Performance Covenants), each of which shall be based on the financial statements delivered pursuant to Section 9.01(a) or (b), as applicable, for the relevant Test Period.

(b)For purposes of calculating any financial ratio or test, or basket that is based on a percentage of Consolidated EBITDAX, Specified Transactions (with any incurrence or repayment of any Indebtedness (other than Indebtedness incurred under any

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revolving credit facility or line of credit for working capital purposes in connection therewith) to be subject to Section 1.10(d)) that have been made (i) during the applicable Test Period and (ii) if applicable as described in Section 1.10(a), subsequent to such Test Period and prior to or simultaneously with the event for which the calculation of any such ratio is made shall be calculated on a pro forma basis assuming that all such Specified Transactions (and any increase or decrease in Consolidated EBITDAX and the component financial definitions used therein attributable to any Specified Transaction) had occurred on the first day of the applicable Test Period. If since the beginning of any applicable Test Period any Person that subsequently became a Restricted Subsidiary or was merged, amalgamated or consolidated with or into the Borrower or any of its Restricted Subsidiaries since the beginning of such Test Period shall have made any Specified Transaction that would have required adjustment pursuant to this Section 1.10, then such financial ratio or test shall be calculated to give pro forma effect thereto in accordance with this Section 1.10.

(c)Whenever pro forma effect is to be given to the Transactions, a Specified Transaction or the implementation of an operational initiative or operational change, the pro forma calculations shall be made in good faith by a responsible financial or accounting officer of the Borrower and may include, for the avoidance of doubt, the amount of “run-rate” cost savings, operating expense reductions and savings from other operating improvements and synergies projected by the Borrower in good faith to be realized as a result of specified actions taken, committed to be taken or expected to be taken (calculated on a pro forma basis as though such cost savings, operating expense reductions and savings from other operating improvements and synergies had been realized on the first day of such period and as if such cost savings, operating expense reductions, operating initiatives, savings from operating changes and synergies were realized during the entirety of such period) and “run-rate” means the full recurring benefit for a period that is associated with any action taken, committed to be taken or expected to be taken (including any savings expected to result from the elimination of a public target’s costs of Public Company Compliance) net of the amount of actual benefits realized during such period from such actions; provided that (A) such amounts are reasonably identifiable and factually supportable in the good faith judgment of the Borrower, (B) such cost savings, operating expense reductions, and savings from other operating improvements and synergies are reasonably identifiable and factually supportable and determined, in the good faith judgment of the Borrower, to result from actions either taken or expected to be taken within 36 months after the date of the Transactions, such Specified Transaction or determination to implement such initiative or operational change, and (C) no amounts shall be added pursuant to this Section 1.10(c) to the extent duplicative of any amounts that are otherwise added back in computing Consolidated EBITDAX, whether through a pro forma adjustment or otherwise, with respect to such period.

(d)In the event that the Borrower or any Restricted Subsidiary incurs (including by assumption or guarantees) or repays (including by redemption, repayment, retirement or extinguishment) any Indebtedness included in the calculations of any financial ratio or test (in each case, other than Indebtedness incurred under any revolving credit facility or line of credit for working capital purposes), (i) during the applicable Test Period or (ii) subject to Section 1.10(a) subsequent to the end of the applicable Test Period and prior to or simultaneously with the event for which the calculation of any such

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ratio is made, then such financial ratio or test shall be calculated giving pro forma effect to such incurrence or repayment of Indebtedness, to the extent required, as if the same had occurred on the last day of the applicable Test Period.

(e)At any time prior to the first applicable test date under Section 10.11, any provision requiring the pro forma compliance with Section 10.11 shall be made assuming that compliance with the Financial Performance Covenants is required for the most recent Test Period prior to such time.

(f)Notwithstanding anything in this Agreement or any Credit Document to the contrary, when calculating the Financial Performance Covenants testing any basket determined by reference to Consolidated EBITDAX or Total Assets or determining other compliance with this Agreement (including the determination of compliance with any provision of this Agreement which requires that no Default or Event of Default has occurred, is continuing or would result therefrom or requiring the accuracy of representations and warranties) in connection with a Specified Transaction undertaken in connection with the consummation of a Limited Condition Transaction, the date of determination of such ratio and determination for calculation of any such covenant or ratio or whether any Default or Event of Default has occurred, is continuing or would result therefrom, at the option of the Borrower (the Borrower’s election to exercise such option in connection with any Limited Condition Transaction, an “LCT Election”), be deemed to be the date the definitive agreements for such Limited Condition Transaction are entered into (the “LCT Test Date”) and if, after such ratios and other provisions are measured or determined on a Pro Forma Basis after giving effect to such Limited Condition Transaction and the other Specified Transactions to be entered into in connection therewith (including any incurrence of Indebtedness and the use of proceeds thereof) as if they occurred at the beginning of the most recent date of determination ending prior to the LCT Test Date, the Borrower could have taken such action on the relevant LCT Test Date in compliance with such ratios and provisions, such ratios and provisions shall be deemed to have been complied with on such date; provided that, if financial statements for one or more subsequent fiscal periods shall have become available, the Borrower may elect, in its sole discretion, to redetermine all such ratios, tests or baskets on the basis of such financial statements, in which case such date of redetermination shall thereafter be deemed to be the applicable LCT Test Date. For the avoidance of doubt, (x) if any of such ratios or baskets are exceeded as a result of fluctuations in such ratio or basket (including due to fluctuations in Consolidated EBITDAX or Total Assets of the Borrower or the target of any Limited Condition Transaction or any incurrence, disposition or Dividend or currency exchange rates at or prior to the consummation of the relevant Limited Condition Transaction), or any Default or Event of Default has occurred and is continuing or any such representation or warranty in any Credit Document is not correct at such time, such ratios, baskets and other provisions will not be deemed to have been exceeded or failed to have been complied with as a result of such circumstances solely for purposes of determining whether the Limited Condition Transaction and the other transactions to be entered into in connection therewith are permitted hereunder and (y) such ratios, baskets and other provisions shall not be tested at the time of consummation of such Limited Condition Transaction or related Specified Transactions. If the Borrower has made an LCT Election for any Limited Condition Transaction, then in connection with any subsequent calculation of

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any ratio (excluding, for the avoidance of doubt, the Financial Performance Covenants (other than Pro Forma Compliance)) or basket availability with respect to any other Specified Transaction on or following the relevant LCT Test Date and prior to the earlier of the date on which such Limited Condition Transaction is consummated or the date that the definitive agreement for such Limited Condition Transaction is terminated or expires without consummation of such Limited Condition Transaction or is otherwise revoked or withdrawn by the Borrower, any such ratio or basket shall be calculated (and tested) on a Pro Forma Basis assuming such Limited Condition Transaction and other transactions in connection therewith (including any incurrence of Indebtedness and the use of proceeds thereof) have been consummated.

Section 1.11Rates. The interest rate on LIBOR Loans and ABR Loans (when determined by reference to clause (c) of the definition of ABR) may be determined by reference to the LIBOR Rate, which is derived from the London interbank offered rate. The London interbank offered rate is intended to represent the rate at which contributing banks may obtain short-term borrowings from each other in the London interbank market. On March 5, 2021, ICE Benchmark Administration (“IBA”), the administrator of the London interbank offered rate, and the Financial Conduct Authority (the “FCA”), the regulatory supervisor of IBA, announced in public statements (the “Announcements”) that the final publication or representativeness date for the London interbank offered rate for Dollars for: (a) 1-week and 2-month tenor settings will be December 31, 2021 and (b) overnight, 1-month, 3-month, 6-month and 12-month tenor settings will be June 30, 2023. No successor administrator for IBA was identified in such Announcements. As a result, it is possible that commencing immediately after such dates, the London interbank offered rate for such tenors may no longer be available or may no longer be deemed a representative reference rate upon which to determine the interest rate on LIBOR Loans or ABR Loans (when determined by reference to clause (c) of the definition of ABR). There is no assurance that the dates set forth in the Announcements will not change or that IBA or the FCA will not take further action that could impact the availability, composition or characteristics of any London interbank offered rate. Public and private sector industry initiatives have been and continue, as of the date hereof, to be underway to implement new or alternative reference rates to be used in place of the London interbank offered rate. In the event that the London interbank offered rate or any other then-current Benchmark is no longer available or in certain other circumstances set forth in Section 2.18, such Section 2.18 provides a mechanism for determining an alternative rate of interest. The Administrative Agent will promptly notify the Borrower, pursuant to Section 2.18, of any change to the reference rate upon which the interest rate on LIBOR Loans and ABR Loans (when determined by reference to clause (c) of the definition of ABR) is based. However, the Administrative Agent does not warrant or accept any responsibility for, and shall not have any liability with respect to, (i) the administration of, submission of, calculation of or any other matter related to the London interbank offered rate or with respect to any alternative, comparable or successor rate thereto, or replacement rate thereof (including any then-current Benchmark or any Benchmark Replacement), including whether the composition or characteristics of any such alternative, successor or replacement reference rate (including any Benchmark Replacement), as it may or may not be adjusted pursuant to Section 2.18, will be similar to, or produce the same value or economic equivalence of, the LIBOR Rate or any other Benchmark, or have the same volume or liquidity as did the London interbank offered rate or any other Benchmark prior to its discontinuance or unavailability, or (ii) the effect, implementation or composition of any Benchmark Replacement Conforming Changes.

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Section 1.12Certifications. All certifications to be made hereunder by an officer or representative of a Credit Party shall be made by such person in his or her capacity solely as an officer or a representative of such Credit Party, on such Credit Party’s behalf and not in such Person’s individual capacity.

Section 1.13Divisions. For all purposes under the Credit Documents, in connection with any division or plan of division under Delaware law (or any comparable event under a different jurisdiction’s laws): (a) if any asset, right, obligation or liability of any Person becomes the asset, right, obligation or liability of a different Person, then it shall be deemed to have been transferred from the original Person to the subsequent Person, and (b) if any new Person comes into existence, such new Person shall be deemed to have been organized on the first date of its existence by the holders of its Equity Interests at such time.

ARTICLE II
AMOUNT AND TERMS OF CREDIT

Section 2.1Commitments.

(a)Subject to and upon the terms and conditions herein set forth, each Lender severally, but not jointly, agrees to make a loan or loans denominated in Dollars to the Borrower, which Loans (i) shall be made at any time and from time to time on and after the Closing Date and prior to the Termination Date, (ii) may, at the option of the Borrower, be incurred and maintained as, and/or converted into, ABR Loans or LIBOR Loans; provided that all Loans made by each of the Lenders pursuant to the same Borrowing shall, unless otherwise specifically provided herein, consist entirely of Loans of the same Type, (iii) may be repaid and reborrowed in accordance with the provisions hereof, (iv) shall not, for any Lender at any time, after giving effect thereto and to the application of the proceeds thereof, result in such Lender’s Total Exposure at such time exceeding such Lender’s Commitment, and (v) shall not, after giving effect thereto and to the application of the proceeds thereof, result in the aggregate amount of all Lenders’ Total Exposures at such time exceeding the Loan Limit then in effect.

(b)Each Lender may at its option make any LIBOR Loan by causing any domestic or foreign branch or Affiliate of such Lender to make such Loan, provided that (i) any exercise of such option shall not affect the obligation of the Borrower to repay such Loan and (ii) in exercising such option, such Lender shall use its reasonable efforts to minimize any increased costs to the Borrower resulting therefrom (which obligation of the Lender shall not require it to take, or refrain from taking, actions that it determines would result in increased costs for which it will not be compensated hereunder or that it determines would be otherwise disadvantageous to it and in the event of such request for costs for which compensation is provided under this Agreement, the provisions of Section 2.10 shall apply).

Section 2.2Minimum Amount of Each Borrowing; Maximum Number of Borrowings. The aggregate principal amount of each Borrowing shall be in a minimum amount of at least the Minimum Borrowing Amount for such Type of Loans and in a multiple of $100,000 in excess thereof (except Loans to reimburse the Letter of Credit Issuer with respect to

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any Unpaid Drawing shall be made in the amounts required by Section 3.3 or Section 3.4, as applicable). More than one Borrowing may be incurred on any date; provided, that at no time shall there be outstanding more than ten Borrowings of LIBOR Loans under this Agreement.

Section 2.3Notice of Borrowing.

(a)Whenever the Borrower desires to incur Loans (other than borrowings to repay Unpaid Drawings), the Borrower shall give the Administrative Agent at the Administrative Agent’s Office, (i) written notice (or telephonic notice promptly confirmed in writing) prior to 1:00 p.m. (New York City time) at least three Business Days’ prior to each Borrowing of Loans if such Loans are to be initially LIBOR Loans (or written notice (or telephonic notice promptly confirmed in writing) prior to 9:00 a.m. (New York City time) two Business Days’ prior to a Borrowing of Loans to be made on the Closing Date initially as LIBOR Loans) and (ii) written notice (or telephonic notice promptly confirmed in writing) prior to 12:00 noon (New York City time) on the date of each Borrowing of Loans that are to be ABR Loans. Each Notice of Borrowing shall specify (A) the aggregate principal amount of the Loans to be made pursuant to such Borrowing, (B) the date of the Borrowing (which shall be a Business Day), (C) whether the respective Borrowing shall consist of ABR Loans and/or LIBOR Loans and, if LIBOR Loans, the Interest Period to be initially applicable thereto (if no Interest Period is selected, the Borrower shall be deemed to have selected an Interest Period of one month’s duration) and (D) the Loan Limit, the current aggregate Total Exposures (without regard to the requested Borrowing) of all Lenders and the pro forma aggregate Total Exposures (giving effect to the requested Borrowing) of all Lenders. The Administrative Agent shall promptly give each Lender written notice (or telephonic notice promptly confirmed in writing) of each proposed Borrowing of Loans, of such Lender’s Commitment Percentage thereof and of the other matters covered by the related Notice of Borrowing.

(b)Borrowings to reimburse Unpaid Drawings shall be made upon the notice specified in Section 3.4(a).

(c)Without in any way limiting the obligation of the Borrower to confirm in writing any notice it may give hereunder by telephone, the Administrative Agent may act prior to receipt of written confirmation without liability upon the basis of such telephonic notice believed by the Administrative Agent in good faith to be from an Authorized Officer of the Borrower.

Section 2.4Disbursement of Funds.

(a)No later than 1:00 p.m. (New York City time) on the date specified in each Notice of Borrowing, each Lender will make available its pro rata portion of each Borrowing requested to be made on such date in the manner provided below.

(b)Each Lender shall make available all amounts it is to fund to the Borrower under any Borrowing in immediately available funds to the Administrative Agent at the Administrative Agent’s Office in Dollars, and the Administrative Agent will (except in the case of Borrowings to repay Unpaid Drawings) make available to the Borrower, by

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depositing or wiring to an account as designated by the Borrower in the Notice of Borrowing to the Administrative Agent the aggregate of the amounts so made available in Dollars. Unless the Administrative Agent shall have been notified by any Lender prior to the date of any such Borrowing that such Lender does not intend to make available to the Administrative Agent its portion of the Borrowing or Borrowings to be made on such date, the Administrative Agent may assume that such Lender has made such amount available to the Administrative Agent on such date of Borrowing, and the Administrative Agent, in reliance upon such assumption, may (in its sole discretion and without any obligation to do so) make available to the Borrower a corresponding amount. If such corresponding amount is not in fact made available to the Administrative Agent by such Lender and the Administrative Agent has made available such amount to the Borrower, the Administrative Agent shall be entitled to recover such corresponding amount from such Lender. If such Lender does not pay such corresponding amount forthwith upon the Administrative Agent’s demand therefor the Administrative Agent shall promptly notify the Borrower and the Borrower shall immediately pay such corresponding amount to the Administrative Agent in Dollars. The Administrative Agent shall also be entitled to recover from such Lender or the Borrower, as the case may be, interest on such corresponding amount in respect of each day from the date such corresponding amount was made available by the Administrative Agent to the Borrower to the date such corresponding amount is recovered by the Administrative Agent, at a rate per annum equal to (i) if paid by such Lender, the Overnight Rate or (ii) if paid by the Borrower, the then-applicable rate of interest or fees, calculated in accordance with Section 2.8, for the respective Loans.

(c)Nothing in this Section 2.4 shall be deemed to relieve any Lender from its obligation to fulfill its commitments hereunder or to prejudice any rights that the Borrower may have against any Lender as a result of any default by such Lender hereunder (it being understood, however, that no Lender shall be responsible for the failure of any other Lender to fulfill its commitments hereunder).

Section 2.5Repayment of Loans; Evidence of Debt.

(a)The Borrower promises and agrees to repay to the Administrative Agent, for the benefit of the applicable Lenders, (i) on the Initial Maturity Date, the then outstanding Initial Loans and (ii) on the relevant maturity date for any Extension Series of Extended Commitments, all then outstanding Extended Loans in respect of such Extension Series.

(b)Each Lender shall maintain in accordance with its usual practice an account or accounts evidencing the indebtedness of the Borrower to the appropriate lending office of such Lender resulting from each Loan made by such lending office from time to time, including the amounts of principal and interest payable and paid to such lending office from time to time under this Agreement.

(c)The Administrative Agent, acting solely for this purpose as a non-fiduciary agent of the Borrower, shall maintain the Register pursuant to Section 13.6(b), and a subaccount for each Lender, in which Register and subaccounts (taken together) shall be recorded (i) the amount of each Loan made hereunder (whether such Loan is an

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Initial Loan or an Extended Loan, as applicable), the Type of each Loan made and the Interest Period applicable thereto, (ii) the amount of any principal or interest due and payable or to become due and payable from the Borrower to each Lender hereunder and (iii) the amount of any sum received by the Administrative Agent hereunder from the Borrower and each Lender’s share thereof.

(d)The entries made in the Register and accounts and subaccounts maintained pursuant to Section 2.5(b) and Section 2.5(c) shall, to the extent permitted by applicable Requirements of Law, be prima facie evidence of the existence and amounts of the obligations of the Borrower therein recorded; provided, however, that the failure of any Lender or the Administrative Agent to maintain such account, such Register or such subaccount, as applicable, or any error therein, shall not in any manner affect the obligation of the Borrower to repay (with applicable interest) the Loans made to the Borrower by such Lender in accordance with the terms of this Agreement.

Section 2.6Conversions and Continuations.

(a)Subject to the penultimate sentence of this Section 2.6(a), (i) the Borrower shall have the option on any Business Day to convert all or a portion equal to at least the Minimum Borrowing Amount (and in multiples of $100,000 in excess thereof) of the outstanding principal amount of Loans of one Type into a Borrowing or Borrowings of another Type and (ii) the Borrower shall have the option on any Business Day to continue the outstanding principal amount of any LIBOR Loans as LIBOR Loans for an additional Interest Period; provided that (A) no partial conversion of LIBOR Loans shall reduce the outstanding principal amount of LIBOR Loans made pursuant to a single Borrowing to less than the Minimum Borrowing Amount, (B) ABR Loans may not be converted into LIBOR Loans if an Event of Default is in existence on the date of the conversion and the Administrative Agent has or the Majority Lenders have determined in its or their sole discretion not to permit such conversion, (C) LIBOR Loans may not be continued as LIBOR Loans for an additional Interest Period if an Event of Default is in existence on the date of the proposed continuation and the Administrative Agent has or the Majority Lenders have determined in its or their sole discretion not to permit such continuation, and (D) Borrowings resulting from conversions pursuant to this Section 2.6 shall be limited in number as provided in Section 2.2. Each such conversion or continuation shall be effected by the Borrower by giving the Administrative Agent at the Administrative Agent’s Office written notice (or telephonic notice promptly confirmed in writing) prior to 1:00 p.m. (New York City time) (1) at least three Business Days’ prior to the date of such conversion or continuation, in the case of a continuation of or conversion to LIBOR Loans or (2) on the date of conversion, in the case of a conversion into ABR Loans (each, a “Notice of Conversion or Continuation”) specifying the Loans to be so converted or continued, the Type of Loans to be converted into or continued and, if such Loans are to be converted into or continued as LIBOR Loans, the Interest Period to be initially applicable thereto (if no Interest Period is selected, the Borrower shall be deemed to have selected an Interest Period of one month’s duration). The Administrative Agent shall give each applicable Lender notice as promptly as practicable of any such proposed conversion or continuation affecting any of its Loans.

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(b)If any Event of Default is in existence at the time of any proposed continuation of any LIBOR Loans and the Administrative Agent has or the Majority Lenders have determined in its or their sole discretion not to permit such continuation, such LIBOR Loans shall be automatically converted on the last day of the current Interest Period into ABR Loans. If upon the expiration of any Interest Period in respect of LIBOR Loans, the Borrower has failed to elect a new Interest Period to be applicable thereto as provided in Section 2.6(a) above, the Borrower shall be deemed to have elected to convert such Borrowing of LIBOR Loans into a Borrowing of ABR Loans, effective as of the expiration date of such current Interest Period.

(c)Notwithstanding anything to the contrary herein, the Borrower may deliver a Notice of Conversion or Continuation pursuant to which the Borrower elects to irrevocably continue the outstanding principal amount of any Loans subject to an interest rate Hedge Agreement as LIBOR Loans for each Interest Period until the expiration of the term of such applicable Hedge Agreement; provided that any Notice of Conversion or Continuation delivered pursuant to this Section 2.6(c) shall include a schedule attaching the relevant interest rate Hedge Agreement or related trade confirmation.

Section 2.7Pro Rata Borrowings. Each Borrowing of Initial Loans under this Agreement shall be made by the Lenders pro rata on the basis of their then applicable Commitment Percentage with respect to the applicable Class. Each Borrowing of Extended Loans under this Agreement shall be granted by the Lenders of the relevant Extension Series thereof pro rata on the basis of their then-applicable Extended Commitments for the applicable Extension Series. It is understood that (a) no Lender shall be responsible for any default by any other Lender in its obligation to make Loans hereunder and that each Lender severally but not jointly shall be obligated to make the Loans provided to be made by it hereunder, regardless of the failure of any other Lender to fulfill its commitments hereunder and (b) failure by a Lender to perform any of its obligations under any of the Credit Documents shall not release any Person from performance of its obligation under any Credit Document.

Section 2.8Interest.

(a)The unpaid principal amount of each ABR Loan shall bear interest from the date of the Borrowing thereof until maturity (whether by acceleration or otherwise) at a rate per annum that shall at all times be the Applicable Margin plus the ABR, in each case, in effect from time to time.

(b)The unpaid principal amount of each LIBOR Loan shall bear interest from the date of the Borrowing thereof until maturity thereof (whether by acceleration or otherwise) at a rate per annum that shall at all times be the Applicable Margin plus the relevant Adjusted LIBOR Rate, in each case, in effect from time to time.

(c)If all or a portion of (i) the principal amount of any Loan or (ii) any interest payable thereon shall not be paid when due (whether at stated maturity, by acceleration or otherwise), such overdue amount shall bear interest at a rate per annum that is (the “Default Rate”) (A) in the case of overdue principal, the rate that would otherwise be applicable thereto plus 2% or (B) in the case of any overdue interest, to the

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extent permitted by applicable Requirements of Law, the rate described in Section 2.8(a)plus 2% from the date of such non-payment to the date on which such amount is paid in full (after as well as before judgment).

(d)Interest on each Loan shall accrue from and including the date of any Borrowing to but excluding the date of any repayment thereof and shall be payable in Dollars; provided that any Loan that is repaid on the same date on which it is made shall bear interest for one day. Except as provided below, interest shall be payable (i) in respect of each ABR Loan, quarterly in arrears on the last Business Day of each March, June, September and December, (ii) in respect of each LIBOR Loan, on the last day of each Interest Period applicable thereto and, in the case of an Interest Period in excess of three months, on each date occurring at three-month intervals after the first day of such Interest Period, (iii) in respect of each Loan, (A) on any prepayment (on the amount prepaid), (B) at maturity (whether by acceleration or otherwise) and (C) after such maturity, on demand.

(e)All computations of interest hereunder shall be made in accordance with Section 5.5.

(f)The Administrative Agent, upon determining the interest rate for any Borrowing of LIBOR Loans, shall promptly notify the Borrower and the relevant Lenders thereof. Each such determination shall, absent clearly demonstrable error, be final and conclusive and binding on all parties hereto.

Section 2.9Interest Periods. At the time the Borrower gives a Notice of Borrowing or Notice of Conversion or Continuation in respect of the making of, or conversion into or continuation as, a Borrowing of LIBOR Loans in accordance with Section 2.6(a), the Borrower shall give the Administrative Agent written notice (or telephonic notice promptly confirmed in writing) of the Interest Period applicable to such Borrowing, which Interest Period shall, at the option of the Borrower be a one, three or six or, in each case, if available to all the Lenders making such LIBOR Loans as determined by such Lenders in good faith based on prevailing market conditions, a 12-month period or any period shorter than one-month, in each case, if requested by the Borrower.

Notwithstanding anything to the contrary contained above:

(a)the initial Interest Period for any Borrowing of LIBOR Loans shall commence on the date of such Borrowing (including the date of any conversion from a Borrowing of ABR Loans) and each Interest Period occurring thereafter in respect of such Borrowing shall commence on the day on which the next preceding Interest Period expires;

(b)if any Interest Period relating to a Borrowing of LIBOR Loans begins on the last Business Day of a calendar month or begins on a day for which there is no numerically corresponding day in the calendar month at the end of such Interest Period, such Interest Period shall end on the last Business Day of the calendar month at the end of such Interest Period;

(c)if any Interest Period would otherwise expire on a day that is not a Business Day, such Interest Period shall expire on the next succeeding Business Day;

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provided that, if any Interest Period in respect of a LIBOR Loan would otherwise expire on a day that is not a Business Day, but is a day of the month after which no further Business Day occurs in such month, such Interest Period shall expire on the next preceding Business Day; and

(d)the Borrower shall not be entitled to elect any Interest Period in respect of any LIBOR Loan if such Interest Period would extend beyond the Maturity Date.

Section 2.10Increased Costs, Illegality, Etc.

(a)Subject to Section 2.18, in the event that (x) in the case of Section 2.10(a)(i) below, the Majority Lenders or (y) in the case of Section 2.10(a)(ii) and Section 2.10(a)(iii) below, any Lender, shall have reasonably determined (which determination shall, absent clearly demonstrable error, be final and conclusive and binding upon all parties hereto):

(i)on any date for determining the LIBOR Rate for any Interest Period that (A) deposits in the principal amounts of the Loans comprising such LIBOR Borrowing are not generally available in the relevant market or (B) by reason of any changes arising on or after the Closing Date affecting the interbank LIBOR market, adequate and fair means do not exist for ascertaining the applicable interest rate on the basis provided for in the definition of LIBOR Rate; or

(ii)that, due to a Change in Law occurring at any time or after the Closing Date, which Change in Law shall (A) impose, modify or deem applicable any reserve, special deposit, compulsory loan, insurance charge or similar requirement against assets of, deposits with or for the account of, or credit extended by, any Lender, (B) subject any Lender to any Tax with respect to any Credit Document or any LIBOR Loan made by it (other than (i) Taxes indemnifiable under Section 5.4, or (ii) Excluded Taxes), or (C) impose on any Lender or the London interbank market any other condition, cost or expense affecting this Agreement or LIBOR Loans made by such Lender, which results in the cost to such Lender of making, converting into, continuing or maintaining LIBOR Loans or participating in Letters of Credit (in each case hereunder) increasing by an amount which such Lender reasonably deems material or the amounts received or receivable by such Lender hereunder with respect to the foregoing shall be reduced; or

(iii)at any time, that the making or continuance of any LIBOR Loan has become unlawful as a result of compliance by such Lender in good faith with any Requirement of Law (or would conflict with any such Requirement of Law not having the force of law even though the failure to comply therewith would not be unlawful);

then, and in any such event, such Lenders (or the Administrative Agent, in the case of Section 2.10(a)(i) above) shall within a reasonable time thereafter give notice (if by telephone, confirmed in writing) to the Borrower and to the Administrative Agent of such determination (which notice the Administrative Agent shall promptly transmit to each of the other Lenders). Thereafter (x) in the case of Section 2.10(a)(i) above, LIBOR Loans shall no longer be available until such time as the Administrative Agent notifies the Borrower and the Lenders that the

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circumstances giving rise to such notice by the Administrative Agent no longer exist (which notice the Administrative Agent agrees to give at such time when such circumstances no longer exist), and any Notice of Borrowing or Notice of Conversion given by the Borrower with respect to LIBOR Loans that have not yet been incurred shall be deemed rescinded by the Borrower, (y) in the case of Section 2.10(a)(ii) above, the Borrower shall pay to such Lender, promptly (but no later than fifteen days) after receipt of written demand therefor such additional amounts as shall be required to compensate such Lender for such increased costs or reductions in amounts receivable hereunder (it being agreed that a written notice as to the additional amounts owed to such Lender, showing in reasonable detail the basis for the calculation thereof, submitted to the Borrower by such Lender shall, absent clearly demonstrable error, be final and conclusive and binding upon all parties hereto) and (z) in the case of Section 2.10(a)(iii) above, the Borrower shall take one of the actions specified in Section 2.10(b) as promptly as possible and, in any event, within the time period required by applicable Requirements of Law.

(b)At any time that any LIBOR Loan is affected by the circumstances described in Section 2.10(a)(ii) or Section 2.10(a)(iii), the Borrower may (and in the case of a LIBOR Loan affected pursuant to Section 2.10(a)(iii) shall) either (i) if the affected LIBOR Loan is then being made pursuant to a Borrowing, cancel such Borrowing by giving the Administrative Agent telephonic notice (confirmed promptly in writing) thereof on the same date that the Borrower was notified by a Lender pursuant to Section 2.10(a)(ii) or Section 2.10(a)(iii) or (ii) if the affected LIBOR Loan is then outstanding, upon at least three Business Days’ notice to the Administrative Agent, require the affected Lender to convert each such LIBOR Loan into an ABR Loan; provided that if more than one Lender is affected at any time, then all affected Lenders must be treated in the same manner pursuant to this Section 2.10(b).

(c)If, after the Closing Date, any Change in Law relating to capital adequacy or liquidity of any Lender or compliance by any Lender or its parent with any Change in Law relating to capital adequacy or liquidity occurring after the Closing Date, has or would have the effect of reducing the rate of return on such Lender’s or its parent’s capital or assets as a consequence of such Lender’s commitments or obligations hereunder to a level below that which such Lender or its parent could have achieved but for such Change in Law (taking into consideration such Lender’s or its parent’s policies with respect to capital adequacy or liquidity), then from time to time, promptly (but in any event no later than fifteen days) after written demand by such Lender (with a copy to the Administrative Agent), the Borrower shall pay to such Lender such additional amount or amounts as will compensate such Lender or its parent for such reduction, it being understood and agreed, however, that a Lender shall not be entitled to such compensation as a result of such Lender’s compliance with, or pursuant to any request or directive to comply with, any applicable Requirement of Law as in effect on the Closing Date (except as otherwise set forth in the definition of Change in Law). Each Lender, upon determining in good faith that any additional amounts will be payable pursuant to this Section 2.10(c), will give prompt written notice thereof to the Borrower, which notice shall set forth in reasonable detail the basis of the calculation of such additional amounts, although the failure to give any such notice shall not, subject to Section 2.13, release or diminish the Borrower’s obligations to pay additional amounts pursuant to this Section 2.10(c) upon receipt of such notice.

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Section 2.11Compensation. If (a) any payment of principal of any LIBOR Loan is made by the Borrower to or for the account of a Lender other than on the last day of the Interest Period for such LIBOR Loan as a result of a payment or conversion pursuant to Section 2.5, Section 2.6, Section 2.10, Section 5.1, Section 5.2 or Section 13.7, as a result of acceleration of the maturity of the Loans pursuant to Section 11 or for any other reason, (b) any Borrowing of LIBOR Loans is not made on the date specified in a Notice of Borrowing, (c) any ABR Loan is not converted into a LIBOR Loan on the date specified in a Notice of Conversion or Continuation, (d) any LIBOR Loan is not continued as a LIBOR Loan on the date specified in a Notice of Conversion or Continuation or (e) any prepayment of principal of any LIBOR Loan is not made as a result of a withdrawn notice of prepayment pursuant to Section 5.1 or Section 5.2, the Borrower shall after the Borrower’s receipt of a written request by such Lender (which request shall set forth in reasonable detail the basis for requesting such amount), pay to the Administrative Agent (within fifteen days after such request) for the account of such Lender any amounts required to compensate such Lender for any additional losses, costs or expenses that such Lender may reasonably incur as a result of such payment, failure to convert, failure to continue or failure to prepay, including any loss, cost or expense (excluding loss of anticipated profits) actually incurred by reason of the liquidation or reemployment of deposits or other funds acquired by any Lender to fund or maintain such LIBOR Loan.

Section 2.12Change of Lending Office. Each Lender agrees that, upon the occurrence of any event giving rise to the operation of Section 2.10(a)(ii), Section 2.10(a)(iii), Section 2.10(c), Section 3.5 or Section 5.4 with respect to such Lender, it will, if requested by the Borrower use reasonable efforts (subject to overall policy considerations of such Lender) to designate another lending office for any Loans affected by such event; provided that such designation is made on such terms that such Lender and its lending office suffer no economic, legal or regulatory disadvantage, with the object of avoiding the consequence of the event giving rise to the operation of any such Section. Nothing in this Section 2.12 shall affect or postpone any of the obligations of the Borrower or the right of any Lender provided in Section 2.10, Section 3.5 or Section 5.4.

Section 2.13Notice of Certain Costs. Notwithstanding anything in this Agreement to the contrary, to the extent any notice or demand pursuant to Section 2.10, Section 2.11, Section 3.5 or Section 5.4 is given by any Lender more than 180 days after such Lender has knowledge (or should have had knowledge) of the occurrence of the event giving rise to the additional cost, reduction in amounts, loss, tax or other additional amounts described in such Sections, such Lender shall not be entitled to compensation under Section 2.10, Section 2.11, Section 3.5 or Section 5.4, as the case may be, for any such amounts incurred or accruing prior to the 181st day prior to the giving of such notice or demand to the Borrower; provided that if the circumstance giving rise to such claim is retroactive, then such 180-day period referred to above shall be extended to include the period of retroactive effect thereof.

Section 2.14Borrowing Base.

(a)Initial Borrowing Base. For the period from and including the Closing Date to but excluding the first Redetermination Date, the amount of the Borrowing Base shall be $850,000,000 (the “Initial Borrowing Base”). Notwithstanding the foregoing, the Borrowing Base may be subject to further adjustments from time to time pursuant to the Borrowing Base Adjustment Provisions.

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(b)Scheduled and Interim Redeterminations. The Borrowing Base shall be redetermined on or about November 1, 2021 (the “November 2021 Redetermination”) and thereafter semi-annually, in each case, in accordance with this Section 2.14 (a “Scheduled Redetermination”), and, subject to Section 2.14(d), such redetermined Borrowing Base shall become effective and applicable to the Borrower, the Administrative Agent, the Letter of Credit Issuers and the Lenders on or about November 1, 2021 (in the case of the November 2021 Redetermination), and thereafter on or about April 1st and October 1st of each year, commencing April 1, 2022, subject to the terms of Section 2.14(c)(iii) and Section 2.14(d). In addition, the Borrower may at any time (including prior to the November 2021 Redetermination), by notifying the Administrative Agent thereof not more than twice during any period between consecutive Scheduled Redeterminations, and the Administrative Agent, may at any time (commencing after the November 2021 Redetermination), at the direction of the Required Lenders, by notifying the Borrower thereof, not more than one time during any period between consecutive Scheduled Redeterminations, in each case elect to cause the Borrowing Base to be redetermined between Scheduled Redeterminations (an “Interim Redetermination”) in accordance with this Section 2.14. In addition to, and not including and/or limited by the annual Interim Redetermination allowed above, the Borrower may, by notifying the Administrative Agent thereof, at any time between Scheduled Redeterminations, request additional Interim Redeterminations of the Borrowing Base in the event it acquires Oil and Gas Properties with Proved Reserves which are to be Borrowing Base Properties having a PV-9 (calculated at the time of acquisition) in excess of 5% of the Borrowing Base in effect immediately prior to such acquisition (it being understood that for purposes of the foregoing, the designation of an Unrestricted Subsidiary owning Oil and Gas Properties with Proved Reserves as a Restricted Subsidiary shall be deemed to constitute an acquisition by the Borrower of Oil and Gas Properties with Proved Reserves); provided that, in connection with an Interim Redetermination occurring in connection with such threshold being satisfied, the Borrower, may, as set forth in the definition of Reserve Report, elect only to provide a Reserve Report in respect of the acquired properties (in which case the most recent Reserve Report shall be used for the existing Borrowing Base Properties).

(c)Scheduled and Interim Redetermination Procedure.

(i)Each Scheduled Redetermination and each Interim Redetermination shall be effectuated as follows: Upon receipt by the Administrative Agent of (A) the Reserve Report and the Reserve Report Certificate, and (B) such other reports, data and supplemental information, including the information provided pursuant to Section 9.14(c), as may, from time to time, be reasonably requested by the Required Lenders (the Reserve Report, such Reserve Report Certificate and such other reports, data and supplemental information being the “Engineering Reports”), the Administrative Agent shall evaluate the information contained in the Engineering Reports and shall in good faith propose a new Borrowing Base (the “Proposed Borrowing Base”) based upon such information and such other information (including the status of title information with respect to the Borrowing Base Properties as described in the Engineering Reports and the existence of any Hedge Agreements) as the

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Administrative Agent deems appropriate in good faith in accordance with its usual and customary oil and gas lending criteria as it exists at the particular time.

(ii)The Administrative Agent shall notify the Borrower and the Lenders of the Proposed Borrowing Base (the “Proposed Borrowing Base Notice”):

(A)in the case of a Scheduled Redetermination (1) if the Administrative Agent shall have received the Engineering Reports required to be delivered by the Borrower pursuant to Section 9.14(a) and Section 9.14(c) in a timely manner, then on or before the March 15th and September 15th of such year following the date of delivery (or, in the case of the November 2021 Redetermination, on or before October 15, 2021) or (2) if the Administrative Agent shall not have received the Engineering Reports required to be delivered by the Borrower pursuant to Section 9.14(a) and Section 9.14(c) in a timely manner, then promptly after the Administrative Agent has received complete Engineering Reports from the Borrower and has had a reasonable opportunity to determine the Proposed Borrowing Base in accordance with Section 2.14(c)(i); and

(B)in the case of an Interim Redetermination, promptly, and in any event, within 15 days after the Administrative Agent has received the required Engineering Reports.

(iii)Any Proposed Borrowing Base that would increase the Borrowing Base then in effect must be approved or deemed to have been approved by Lenders constituting at least the Borrowing Base Required Lenders, which determination shall be made by each Lender in good faith and in such Lender’s sole discretion and in a manner consistent with such Lender’s usual and customary oil and gas lending criteria as it exists at the particular time as provided in this Section 2.14(c)(iii) and any Proposed Borrowing Base that would decrease or maintain the Borrowing Base then in effect must be approved or be deemed to have been approved by Lenders constituting at least the Required Lenders, which determination shall be made by each Lender in good faith and in such Lender’s sole discretion and in a manner consistent with such Lender’s usual and customary oil and gas lending criteria as it exists at the particular time as provided in this Section 2.14(c)(iii). Upon receipt of the Proposed Borrowing Base Notice, each Lender shall have 15 days to agree with the Proposed Borrowing Base or disagree with the Proposed Borrowing Base by proposing an alternate Borrowing Base. If at the end of such 15-day period, any Lender has not communicated its approval or disapproval in writing to the Administrative Agent, such silence shall be deemed to be an approval of the Proposed Borrowing Base. If, at the end of such 15-day period, the Borrowing Base Required Lenders, in the case of a Proposed Borrowing Base that would increase the Borrowing Base then in effect, or the Required Lenders, in the case of a Proposed Borrowing Base that would decrease or maintain the Borrowing Base then in effect, have approved or deemed to have approved, as aforesaid, then the Proposed Borrowing Base shall become the new Borrowing Base, effective on the date specified in Section 2.14(d). If,

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however, at the end of such 15-day period, the Borrowing Base Required Lenders or the Required Lenders, as applicable, have not approved or deemed to have approved, as aforesaid, then the Administrative Agent shall promptly thereafter poll the Lenders to ascertain the highest Borrowing Base then acceptable to the Borrowing Base Required Lenders (in the case of any increase to the Borrowing Base) or a number of Lenders sufficient to constitute the Required Lenders (in any other case) and such amount shall become the new Borrowing Base, effective on the date specified in Section 2.14(d).

(d)Effectiveness of a Redetermined Borrowing Base. Subject to Section 2.14(h), after a redetermined Borrowing Base is approved or is deemed to have been approved by the Borrowing Base Required Lenders or the Required Lenders, as applicable, pursuant to Section 2.14(c)(iii), the Administrative Agent shall promptly thereafter notify the Borrower and the Lenders of the amount of the redetermined Borrowing Base (the “New Borrowing Base Notice”), and such amount shall become the new Borrowing Base, effective and applicable to the Borrower, the Administrative Agent, the Letter of Credit Issuers and the Lenders:

(i)in the case of a Scheduled Redetermination, (A) if the Administrative Agent shall have received the Engineering Reports required to be delivered by the Borrower pursuant to Section 9.14(a) and Section 9.14(c) in a timely and complete manner, on the April 1st or October 1st, as applicable, following such notice (or, in the case of the November 2021 Redetermination, on November 1, 2021) or (B) if the Administrative Agent shall not have received the Engineering Reports required to be delivered by the Borrower pursuant to Section 9.14(a) and Section 9.14(c) in a timely and complete manner, then on the Business Day next succeeding delivery of such New Borrowing Base Notice; and

(ii)in the case of an Interim Redetermination, on the Business Day next succeeding delivery of such New Borrowing Base Notice.

Subject to Section 2.14(h), such amount shall then become the Borrowing Base until the next Scheduled Redetermination Date, the next Interim Redetermination Date or the next adjustment to the Borrowing Base under the Borrowing Base Adjustment Provisions or Section 2.14(h), whichever occurs first. Notwithstanding the foregoing, no Scheduled Redetermination or Interim Redetermination shall become effective until the New Borrowing Base Notice related thereto is received by the Borrower.

(e)Reduction of Borrowing Base Upon Incurrence of Permitted Junior Lien Debt and/or Permitted Additional Debt. Upon the issuance or incurrence of any Permitted Junior Lien Debt and/or Permitted Additional Debt in accordance with Section 10.1(o) (other than Permitted Junior Lien Debt or Permitted Additional Debt constituting Permitted Refinancing Indebtedness incurred to Refinance such Indebtedness), unless otherwise determined by the Required Lenders, the Borrowing Base then in effect shall be reduced by an amount equal to the product of 0.25 multiplied by the stated principal amount of such Permitted Additional Debt or Permitted Junior Lien Debt, as applicable, (without regard to any original issue discount), and the Borrowing Base as so reduced

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shall become the new Borrowing Base one Business Day after such issuance or incurrence, effective and applicable to the Borrower, the Administrative Agent, the Letter of Credit Issuers and the Lenders on such date until the next redetermination or modification thereof hereunder.

(f)Reduction of Borrowing Base Upon Termination of Hedge Positions. If the Borrower or any Restricted Subsidiary shall terminate or create any off-setting positions in respect of any commodity hedge positions (whether evidenced by a floor, put or Hedge Agreement) (a “Liquidation”) upon which (i) the Lenders relied in determining the Borrowing Base and (ii) the Hedge PV (as calculated at the time of any such termination or creation of off-setting positions) of such terminated and/or offsetting positions (after taking into account any other Hedge Agreement executed contemporaneously with the taking of such actions) exceeds 5% of the effective Borrowing Base, then no later than two Business Days’ after the date of such termination or creation, the Borrower shall provide notice to the Administrative Agent thereof and thereafter the Required Lenders shall have the right to adjust the Borrowing Base then in effect by an amount up to the Borrowing Base value, if any, attributable to such terminated or off-setting hedge positions in the calculation of the then-effective Borrowing Base and, if the Required Lenders in fact elect to make any such adjustment, the Administrative Agent shall promptly notify the Borrower in writing of the Borrowing Base value, if any, attributable to such hedge positions in the calculation of the then-effective Borrowing Base and the amount by which they have elected to reduce the Borrowing Base and upon receipt of such notice, the Borrowing Base shall be simultaneously reduced by such elected amount; provided that for purposes of this Section 2.14(f), a Hedge Agreement shall not be deemed to have been Liquidated if, (x) such Hedge Agreement is novated from the existing counterparty to a Hedge Bank, with the Borrower or the applicable Credit Party being the “remaining party” for purposes of such novation or (y) upon its termination, it is replaced, in a substantially contemporaneous transaction, with one or more Hedge Agreements (i) with approximately the same aggregate Swap Termination Value and (ii) each of which matures pursuant to its terms after the scheduled effective date of the next Scheduled Redetermination. For the avoidance of doubt, the parties acknowledge that the Borrowing Base value of a Hedge Agreement may be more or less than the mark-to-market or termination value of such Hedge Agreement.

(g)Reduction of Borrowing Base Upon Asset Dispositions. If (x) the Borrower or one of the other Credit Parties Disposes of Oil and Gas Properties or Disposes of any Stock or Stock Equivalents in any Restricted Subsidiary or Minority Investment owning Oil and Gas Properties, in each case, to a Person other than a Credit Party, (y) such Disposition involves Borrowing Base Properties included in the most recently delivered Reserve Report and (z) the aggregate PV-9 (calculated at the time of such Disposition) of all such Borrowing Base Properties Disposed of (after giving effect to any concurrent acquisitions of and other investments in Oil and Gas Properties by the Borrower and its Restricted Subsidiaries with respect to which the Borrower has delivered a Reserve Report in accordance with Section 9.14(b)), since the later of (A) the later of (1) the Closing Date and (2) the last Redetermination Date and (B) the last adjustment of the Borrowing Base made pursuant to this Section 2.14(g), exceeds 5% of the then-effective Borrowing Base then, no later than two Business Days after the date of consummation of any such Disposition, the Borrower shall provide notice to the

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Administrative Agent thereof, and upon the consummation of such Disposition, the Required Lenders shall have the right to adjust the Borrowing Base then in effect by an amount up to the Borrowing Base value, if any, attributable to such Disposed of Borrowing Base Properties in the calculation of the then-effective Borrowing Base and, if the Required Lenders in fact elect to make any such adjustment, the Administrative Agent shall promptly notify the Borrower in writing of the Borrowing Base value, if any, attributable to such Disposed of Borrowing Base Properties in the calculation of the then-effective Borrowing Base and the amount by which they have elected to reduce the Borrowing Base and upon receipt of such notice, the Borrowing Base shall be simultaneously reduced by such elected amount.

(h)Borrower’s Right to Elect Reduced Borrowing Base. Within three Business Days of its receipt of a New Borrowing Base Notice, the Borrower may provide written notice to the Administrative Agent and the Lenders that specifies for the period from the effective date of the New Borrowing Base Notice until the next succeeding Scheduled Redetermination Date, the Borrowing Base will be a lesser amount than the amount set forth in such New Borrowing Base Notice, whereupon such specified lesser amount will become the new Borrowing Base. The Borrower’s notice under this Section 2.14(h) shall be irrevocable, but without prejudice to its rights to initiate Interim Redeterminations. Notwithstanding the foregoing, in no event shall the Borrower be entitled to reduce the Borrowing Base pursuant to this Section 2.14(h) to an amount that is less than the Total Exposures of all Lenders.

(i)[Reserved].

(j)Administrative Agent Data. The Administrative Agent hereby agrees to provide, promptly, and in any event within 3 Business Days, following its receipt of a request by the Borrower, an updated Bank Price Deck. In addition, the Administrative Agent and the Lenders agree, upon request, to meet with the Borrower to discuss their evaluation of the reservoir engineering of the Oil and Gas Properties included in the Reserve Report and their respective methodologies for valuing such properties and the other factors considered in calculating the Borrowing Base.

Section 2.15Defaulting Lenders. Notwithstanding any provision of this Agreement to the contrary, if any Lender becomes a Defaulting Lender, then the following provisions shall apply for so long as such Lender is a Defaulting Lender:

(a)Commitment Fees shall cease to accrue on the unfunded portion of the Commitment of such Defaulting Lender pursuant to Section 4.1(a);

(b)The Commitment and Total Exposure of such Defaulting Lender shall not be included in determining whether all Lenders, the Majority Lenders or the Required Lenders or Borrowing Base Required Lenders have taken or may take any action hereunder (including any consent to any amendment or waiver pursuant to Section 13.1); provided that (i) any waiver, amendment or modification requiring the consent of all Lenders pursuant to Section 13.1 (other than Section 13.1(a)(ii)(I)) or requiring the consent of each affected Lender pursuant to Section 13.1(a)(ii)(A) shall require the consent of such Defaulting Lender (which for the avoidance of doubt would include any change to the Maturity Date applicable to such Defaulting Lender, decreasing or

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forgiving any principal or interest due to such Defaulting Lender, any decrease of any interest rate applicable to Loans made by such Defaulting Lender (other than the waiving of post-default interest rates) and any increase in such Defaulting Lender’s Commitment) and (ii) any redetermination, whether an increase, decrease or affirmation, of the Borrowing Base shall occur without the participation of a Defaulting Lender, but the Commitment of a Defaulting Lender may not be increased without the consent of such Defaulting Lender;

(c)If any Letter of Credit Exposure exists at the time a Lender becomes a Defaulting Lender, then (i) all or any part of such Letter of Credit Exposure of such Defaulting Lender will, subject to the limitation in the first proviso below, automatically be reallocated (effective on the day such Lender becomes a Defaulting Lender) among the Non-Defaulting Lenders pro rata in accordance with their respective Commitment Percentages; provided that (A) each Non-Defaulting Lender’s Total Exposure may not in any event exceed the Commitment of such Non-Defaulting Lender as in effect at the time of such reallocation and (B) subject to Section 2.15(g), neither such reallocation nor any payment by a Non-Defaulting Lender pursuant thereto will constitute a waiver or release of any claim the Borrower, the Administrative Agent, the Letter of Credit Issuers or any other Lender may have against such Defaulting Lender or cause such Defaulting Lender to be a Non-Defaulting Lender, (ii) to the extent that all or any portion (the “unreallocated portion”) of the Defaulting Lender’s Letter of Credit Exposure cannot, or can only partially, be so reallocated to Non-Defaulting Lenders, whether by reason of the first proviso in Section 2.15(c)(i) or otherwise, the Borrower shall, within two Business Days following notice by the Administrative Agent, Cash Collateralize for the benefit of the applicable Letter of Credit Issuer only the Borrower’s obligations corresponding to such Defaulting Lender’s Letter of Credit Exposure (after giving effect to any partial reallocation pursuant to Section 2.15(c)(i) above), in accordance with the procedures set forth in Section 3.8 for so long as such Letter of Credit Exposure is outstanding, (iii) if the Borrower Cash Collateralizes any portion of such Defaulting Lender’s Letter of Credit Exposure pursuant to Section 2.15(c), the Borrower shall not be required to pay any fees to such Defaulting Lender pursuant to Section 4.1(b) with respect to such Defaulting Lender’s Letter of Credit Exposure during the period such Defaulting Lender’s Letter of Credit Exposure is Cash Collateralized, (iv) if the Letter of Credit Exposure of the Non-Defaulting Lenders is reallocated pursuant to Section 2.15(c), then the Letter of Credit Fees payable for the account of the Lenders pursuant to Section 4.1(b) shall be adjusted in accordance with such Non-Defaulting Lenders’ Commitment Percentages and the Borrower shall not be required to pay any Letter of Credit Fees to the Defaulting Lender pursuant to Section 4.1(b) with respect to such Defaulting Lender’s Letter of Credit Exposure during the period that such Defaulting Lender’s Letter of Credit Exposure is reallocated, or (v) if any Defaulting Lender’s Letter of Credit Exposure is neither Cash Collateralized nor reallocated pursuant to this Section 2.15(c), then, without prejudice to any rights or remedies of the Letter of Credit Issuer or any Lender hereunder, all Letter of Credit Fees payable under Section 4.1(b) with respect to such Defaulting Lender’s Letter of Credit Exposure shall be payable to the Letter of Credit Issuer until such Letter of Credit Exposure is Cash Collateralized and/or reallocated;

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(d)So long as any Lender is a Defaulting Lender, no Letter of Credit Issuer will be required to issue any new Letter of Credit or amend any outstanding Letter of Credit to increase the Stated Amount thereof, alter the drawing terms thereunder or extend the expiry date thereof, unless the Letter of Credit Issuer is reasonably satisfied that any exposure that would result from the exposure to such Defaulting Lender is eliminated or fully covered by the Commitments of the Non-Defaulting Lenders or by Cash Collateralization or a combination thereof in accordance with Section 2.15(c) above or otherwise in a manner reasonably satisfactory to the Letter of Credit Issuer, and participating interests in any such newly issued or increased Letter of Credit shall be allocated among Non-Defaulting Lenders in a manner consistent with Section 2.15(c)(i) (and Defaulting Lenders shall not participate therein); and

(e)If the Borrower, the Administrative Agent and each Letter of Credit Issuer agree in writing in their discretion that a Lender that is a Defaulting Lender should no longer be deemed to be a Defaulting Lender, the Administrative Agent will so notify the parties hereto, whereupon, as of the effective date specified in such notice and subject to any conditions set forth therein, such Lender will cease to be a Defaulting Lender and will be a Non-Defaulting Lender and any applicable cash collateral shall be promptly returned to the Borrower and any Letter of Credit Exposure of such Lender reallocated pursuant to Section 2.15(c) shall be reallocated back to such Lender; provided that, except to the extent otherwise expressly agreed by the affected parties, no change hereunder from Defaulting Lender to Non-Defaulting Lender will constitute a waiver or release of any claim of any party hereunder arising from such Lender’s having been a Defaulting Lender.

(f)Any payment of principal, interest, fees or other amounts received by the Administrative Agent for the account of that Defaulting Lender (whether voluntary or mandatory, at maturity, pursuant to Section 11 or otherwise, and including any amounts made available to the Administrative Agent by that Defaulting Lender pursuant to Section 13.8), shall be applied at such time or times as may be determined by the Administrative Agent as follows: first, to the payment of any amounts owing by that Defaulting Lender to the Administrative Agent hereunder; second, to the payment on a pro rata basis of any amounts owing by that Defaulting Lender to each Letter of Credit Issuer hereunder; third, to Cash Collateralize the fronting exposure of the Letter of Credit Issuers with respect to such Defaulting Lender in accordance with the procedures set forth in Section 3.8; fourth, as the Borrower may request (so long as no Default or Event of Default exists), to the funding of any Loan in respect of which that Defaulting Lender has failed to fund its portion thereof as required by this Agreement, as determined by the Administrative Agent; fifth, if so determined by the Administrative Agent and the Borrower, to be held in a non-interest bearing deposit account and released pro rata in order to (A) satisfy obligations of that Defaulting Lender to fund Loans under this Agreement and (B) Cash Collateralize the Letter of Credit Issuers’ future fronting exposure with respect to such Defaulting Lender with respect to future Letters of Credit issued under this Agreement, in accordance with the procedures set forth in Section 3.8; sixth, to the payment of any amounts owing to the Lenders or the Letter of Credit Issuers as a result of any judgment of a court of competent jurisdiction obtained by any Lender or such Letter of Credit Issuer against that Defaulting Lender as a result of that Defaulting Lender’s breach of its obligations under this Agreement; seventh, so long as no Default or

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Event of Default exists, to the payment of any amounts owing to the Borrower as a result of any judgment of a court of competent jurisdiction obtained by the Borrower against that Defaulting Lender as a result of that Defaulting Lender’s breach of its obligations under this Agreement; and eighth, to that Defaulting Lender or as otherwise directed by a court of competent jurisdiction; provided that if such payment is a payment of the principal amount of any Loans or Unpaid Drawings, such payment shall be applied solely to pay the relevant Loans of, and Unpaid Drawings owed to, the relevant non-Defaulting Lenders on a pro rata basis prior to being applied in the manner set forth in this Section 2.15(f). Any payments, prepayments or other amounts paid or payable to a Defaulting Lender that are applied (or held) to pay amounts owed by a Defaulting Lender or to post cash collateral pursuant to Section 3.8 shall be deemed paid to and redirected by that Defaulting Lender, and each Lender irrevocably consents hereto.

(g)Notwithstanding anything to the contrary in any Credit Documents or in any other agreement, arrangement or understanding among any such parties, each party hereto acknowledges that any liability of any Affected Financial Institution arising under any Credit Documents, to the extent such liability is unsecured, may be subject to the Write-Down and Conversion Powers of the applicable Resolution Authority and agrees and consents to, and acknowledges and agrees to be bound by:

(i)the application of any Write-Down and Conversion Powers by the applicable Resolution Authority to any such liabilities arising hereunder which may be payable to it by any party hereto that is an Affected Financial Institution; and

(ii)the effects of any Bail-In Action on any such liability, including, if applicable:

(A)a reduction in full or in part or cancellation of any such liability;

(B)a conversion of all, or a portion of, such liability into shares or other instruments of ownership in such Affected Financial Institution, its parent entity, or a bridge institution that may be issued to it or otherwise conferred on it, and that such shares or other instruments of ownership will be accepted by it in lieu of any rights with respect to any such liability under this Agreement or any other Credit Documents; or

(C)the variation of the terms of such liability in connection with the exercise of the Write-Down and Conversion Powers of the Applicable Resolution Authority.

Section 2.16Increase of Aggregate Maximum Credit Amount and/or Aggregate Elected Commitment Amount.

(a)Subject to the conditions set forth in Section 2.16(b), the Borrower may increase the Aggregate Maximum Credit Amount and/or the Aggregate Elected Commitment Amount then in effect (any such increase an “Incremental Increase”) by increasing the Maximum Credit Amount and/or Elected Commitment Amount of a

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Lender (an “Increasing Lender”) or by causing a Person that at such time is not a Lender to become a Lender (an “Additional Lender”).

(b)Any increase in the Aggregate Maximum Credit Amount or the Aggregate Elected Commitment Amount, as applicable, shall be subject to the following additional conditions:

(i)such increase shall not be less than $5,000,000 (and increments of $1,000,000 above that minimum) unless the Administrative Agent otherwise consents (such consent not to be unreasonably withheld, conditioned or delayed), and no such increase shall be permitted if after giving effect thereto the Aggregate Elected Commitment Amount would exceed the Borrowing Base then in effect;

(ii)no Event of Default shall have occurred and be continuing after giving effect to such increase;

(iii)no Lender’s Maximum Credit Amount or Elected Commitment Amount may be increased without the consent of such Lender (to be granted or withheld in each such Lender’s sole discretion);

(iv)the maturity date of such increase shall be the same as the Maturity Date;

(v)the increase shall be on the exact same terms and pursuant to the exact same documentation applicable to this Agreement (other than with respect to any arrangement, structuring, upfront or other fees or discounts payable in connection with such Incremental Increase) (provided that, to the extent applicable, the Applicable Margin of the Facility shall be increased to be consistent with that for such Incremental Increase); and

(vi)the Borrower may seek commitments in respect of an Incremental Increase, in its sole discretion, from either existing Lenders (each of which shall be entitled to agree or decline to participate in its sole discretion) with the consent of each Letter of Credit Issuer (such consent not to be unreasonably withheld or delayed) or from additional banks, financial institutions or other institutional lenders or investors who will become Lenders hereunder with the consent of the Administrative Agent and each Letter of Credit Issuer (in each case, such consent not to be unreasonably withheld or delayed).

(c)Except as otherwise specified above, the other terms of any Incremental Increase, shall be on terms and pursuant to documentation (any such documentation, an “Incremental Agreement”) to be determined between the Borrower and the lenders providing such Incremental Increase (and for the avoidance of doubt, without requiring the consent or acknowledgment of any other Lender or the Administrative Agent (except, in the case of the Administrative Agent, to the extent affecting the rights and duties of, or any fees or other amounts payable to, the Administrative Agent)). Each of the parties hereto hereby irrevocably agrees that this Agreement and the other Credit Documents may be amended pursuant to an Incremental Agreement, without the consent of Lenders

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other than the Lenders providing such Incremental Increase, to the extent necessary to (i) reflect the existence and terms of an Incremental Increase and (ii) address technical issues relating to funding and payments, and the Required Lenders hereby expressly authorize and direct the Administrative Agent, if necessary, to enter into any such Incremental Agreement.

Section 2.17Extension Offers.

(a)The Borrower may at any time and from time to time request that all or a portion of the Commitments of any Class, existing at the time of such request (each, an “Existing Commitment” and any related revolving credit loans under any such facility, “Existing Loans”; each Existing Commitment and related Existing Loans together being referred to as an “Existing Class”) be converted to extend the termination date thereof and the scheduled maturity date(s) of any payment of principal with respect to all or a portion of any principal amount of Existing Loans related to such Existing Commitments (any such Existing Commitments which have been so extended, “Extended Commitments” and any related revolving credit loans, “Extended Loans”) and to provide for other terms consistent with this Section 2.17. Prior to entering into any Extension Amendment with respect to any Extended Commitments, the Borrower shall provide a notice to the Administrative Agent (who shall provide a copy of such notice to each of the Lenders of the applicable Class of Existing Commitments and which such request shall be offered equally to all Lenders) (an “Extension Request”) setting forth the proposed terms of the Extended Commitments to be established thereunder, which terms shall be substantially similar to those applicable to the Existing Commitments from which they are to be Extended (the “Specified Existing Commitment Class”) except that (w) all or any of the final maturity dates of such Extended Commitments may be delayed to later dates than the final maturity dates of the Existing Commitments of the Specified Existing Commitment Class, (x)(A) the interest rates, interest margins, rate floors, upfront fees, funding discounts, original issue discounts and premiums with respect to the Extended Commitments may be different from those for the Existing Commitments of the Specified Existing Commitment Class and/or (B) additional fees and/or premiums may be payable to the Lenders providing such Extended Commitments in addition to or in lieu of any of the items contemplated by the preceding clause (A), (y)(1) the undrawn revolving credit commitment fee rate with respect to the Extended Commitments may be different from such rate for Existing Commitments of the Specified Existing Commitment Class and (2) the Extension Amendment may provide for other covenants and terms that apply to any period after the Latest Maturity Date; provided that, notwithstanding anything to the contrary in this Section 2.17 or otherwise, (1) the borrowing and repayment (other than in connection with a permanent repayment and termination of commitments (which shall be governed by clause (3) below)) of the Extended Loans under any Extended Commitments shall be made on a pro rata basis with any borrowings and repayments of the Existing Loans of the Specified Existing Commitment Class (the mechanics for which may be implemented through the applicable Extension Amendment and may include technical changes related to the borrowing and replacement procedures of the Specified Existing Commitment Class), (2) assignments and participations of Extended Commitments and Extended Loans shall be governed by the assignment and participation provisions set forth in Section 13.6 and (3) subject to the applicable limitations set forth in Section 4.2, permanent repayments of Extended Loans (and corresponding permanent reduction in the related Extended Commitments) shall be

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permitted as may be agreed between the Borrower and the Lenders thereof. No Lender shall have any obligation to agree to have any of its Loans or Commitments of any Existing Class converted into Extended Loans or Extended Commitments pursuant to any Extension Request. Any Extended Commitments of any Extension Series shall constitute a separate Class of revolving credit commitments from Existing Commitments of the Specified Existing Commitment Class and from any other Existing Commitments (together with any other Extended Commitments so established on such date).

(b)The Borrower shall provide the applicable Extension Request at least five Business Days (or such shorter period as the Administrative Agent may determine in its reasonable discretion) prior to the date on which Lenders under the Existing Class are requested to respond, and shall agree to such procedures, if any, as may be established by, or acceptable to, the Administrative Agent, in each case acting reasonably, to accomplish the purpose of this Section 2.17. Any Lender (an “Extending Lender”) wishing to have all or a portion of its Commitments (or any earlier Extended Commitments) of an Existing Class subject to such Extension Request converted into Extended Commitments shall notify the Administrative Agent (an “Extension Election”) on or prior to the date specified in such Extension Request of the amount of its Commitments (and/or any earlier Extended Commitments) which it has elected to convert into Extended Commitments (subject to any minimum denomination requirements imposed by the Administrative Agent). In the event that the aggregate amount of Commitments (and any earlier Extended Commitments) subject to Extension Elections exceeds the amount of Extended Commitments requested pursuant to the Extension Request, Commitments and (and any earlier Extended Commitments) subject to Extension Elections shall be converted to Extended Commitments on a pro rata basis based on the amount of Commitments (and any earlier Extended Commitments) included in each such Extension Election or as may be otherwise agreed to in the applicable Extension Amendment. Notwithstanding the conversion of any Existing Commitment into an Extended Commitment, such Extended Commitment shall be treated identically to all Existing Commitments of the Specified Existing Commitment Class for purposes of the obligations of a Lender in respect of Letters of Credit under Section 3, except that the applicable Extension Amendment may provide that the last day for issuing Letters of Credit may be extended and the related obligations to issue Letters of Credit may be continued (pursuant to mechanics to be specified in the applicable Extension Amendment) so long as the applicable Letter of Credit Issuer, as applicable, have consented to such extensions (it being understood that no consent of any other Lender shall be required in connection with any such extension).

(c)Extended Commitments shall be established pursuant to an amendment (an “Extension Amendment”) to this Agreement (which, notwithstanding anything to the contrary set forth in Section 13.1, shall not require the consent of any Lender other than the Extending Lenders with respect to the Extended Commitments established thereby) executed by the Credit Parties, the Administrative Agent and the Extending Lenders. It is understood and agreed that each Lender hereunder has consented, and shall at the effective time thereof be deemed to consent to each amendment to this Agreement and the other Credit Documents authorized by this Section 2.17 and the arrangements described above in connection therewith. No Extension Amendment shall provide for any tranche of Extended Commitments in an aggregate principal amount that is less than

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$1,000,000. Notwithstanding anything to the contrary in this Section 2.17(c) and without limiting the generality or applicability of Section 13.1 to any Section 2.17 Additional Amendments (as defined below), any Extension Amendment may provide for additional terms and/or additional amendments other than those referred to or contemplated above (any such additional amendment, a “Section 2.17 Additional Amendment”) to this Agreement and the other Credit Documents; provided that such Section 2.17 Additional Amendments are within the requirements of Section 2.17(a) and do not become effective prior to the time that such Section 2.17 Additional Amendments have been consented to (including, without limitation, pursuant to consents applicable to holders of any Extended Loans provided for in any Extension Amendment) by such of the Lenders, Credit Parties and other parties (if any) as may be required in order for such Section 2.17 Additional Amendments to become effective in accordance with Section 13.1.

(d)Notwithstanding anything to the contrary contained in this Agreement, (A) on any date on which any Class of Existing Commitments is converted to extend the related scheduled maturity date(s) in accordance with paragraph (a) above (an “Extension Date”), in the case of the Existing Commitments of each Extending Lender under any Specified Existing Commitment Class, the aggregate principal amount of such Existing Commitments shall be deemed reduced by an amount equal to the aggregate principal amount of Extended Commitments so converted by such Lender on such date, and such Extended Commitments shall be established as a separate Class of revolving credit commitments from the Specified Existing Commitment Class and from any other Existing Commitments (together with any other Extended Commitments so established on such date) and (B) if, on any Extension Date, any Existing Loans of any Extending Lender are outstanding under the Specified Existing Commitment Class, such Existing Loans (and any related participations) shall be deemed to be allocated as Extended Loans (and related participations) in the same proportion as such Extending Lender’s Specified Existing Commitments to Extended Commitments.

(e)No exchange of Loans or Commitments pursuant to any Extension Amendment in accordance with this Section 2.17 shall constitute a voluntary or mandatory payment or prepayment for purposes of this Agreement.

Section 2.18Benchmark Replacement Setting.

(a)

(i)Benchmark Replacement. Notwithstanding anything to the contrary herein or in any other Credit Documents, if a Benchmark Transition Event or an Early Opt-in Election, as applicable, and its related Benchmark Replacement Date have occurred prior to the Reference Time in respect of any setting of the then-current Benchmark, then (x) if a Benchmark Replacement is determined in accordance with clause (a)(1) or (a)(2) of the definition of “Benchmark Replacement” for such Benchmark Replacement Date, such Benchmark Replacement will replace such Benchmark for all purposes hereunder and under any Credit Documents in respect of such Benchmark setting and subsequent Benchmark settings without any amendment to, or further action or

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consent of any other party to, this Agreement or any other Credit Documents and (y) if a Benchmark Replacement is determined in accordance with clause (a)(3) of the definition of “Benchmark Replacement” for such Benchmark Replacement Date, such Benchmark Replacement will replace such Benchmark for all purposes hereunder and under any Credit Documents in respect of any Benchmark setting at or after 5:00 p.m. (New York City time) on the fifth (5th) Business Day after the date notice of such Benchmark Replacement is provided to the Lenders without any amendment to, or further action or consent of any other party to, this Agreement or any other Credit Documents so long as the Administrative Agent has not received, by such time, written notice of objection to such Benchmark Replacement from Lenders comprising the Majority Lenders.

(ii)Notwithstanding anything to the contrary herein or in any other Credit Documents, if a Term SOFR Transition Event and its related Benchmark Replacement Date have occurred prior to the Reference Time in respect of any setting of the then-current Benchmark, then the applicable Benchmark Replacement will replace the then-current Benchmark for all purposes hereunder or under any Credit Documents in respect of such Benchmark setting and subsequent Benchmark settings, without any amendment to, or further action or consent of any other party to, this Agreement or any other Credit Documents; provided that this clause (B) shall not be effective unless the Administrative Agent has delivered to the Lenders and the Borrower a Term SOFR Notice. For the avoidance of doubt, the Administrative Agent shall not be required to deliver a Term SOFR Notice after a Term SOFR Transition Event and may elect or not elect to do so in its sole discretion.     

(b)Benchmark Replacement Conforming Changes. In connection with the implementation of a Benchmark Replacement, the Administrative Agent will have the right to make (in consultation with the Borrower) Benchmark Replacement Conforming Changes from time to time and, notwithstanding anything to the contrary herein or in any other Credit Documents, any amendments implementing such Benchmark Replacement Conforming Changes will become effective without any further action or consent of any other party to this Agreement or any other Credit Documents.

(c)Notices; Standards for Decisions and Determinations. The Administrative Agent will promptly notify the Borrower and the Lenders of (A) any occurrence of a Benchmark Transition Event, a Term SOFR Transition Event or an Early Opt-in Election, as applicable, and its related Benchmark Replacement Date, (B) the implementation of any Benchmark Replacement, (C) the effectiveness of any Benchmark Replacement Conforming Changes, (D) the removal or reinstatement of any tenor of a Benchmark pursuant to Section 2.18(d) below and (E) the commencement or conclusion of any Benchmark Unavailability Period. Any determination, decision or election that may be made by the Administrative Agent or, if applicable, any Lender (or group of Lenders) pursuant to this Section 2.18, including any determination with respect to a tenor, rate or adjustment or of the occurrence or non-occurrence of an event, circumstance or date and any decision to take or refrain from taking any action or any selection, will be conclusive and binding absent manifest error and may be made in its or their sole discretion and

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without consent from any other party to this Agreement or any other Credit Documents, except, in each case, as expressly required pursuant to this Section 2.18.

(d)Unavailability of Tenor of Benchmark. Notwithstanding anything to the contrary herein or in any other Credit Documents, at any time (including in connection with the implementation of a Benchmark Replacement), (A) if the then-current Benchmark is a term rate (including Term SOFR or LIBOR) and either (1) any tenor for such Benchmark is not displayed on a screen or other information service that publishes such rate from time to time as selected by the Administrative Agent in its reasonable discretion or (2) the regulatory supervisor for the administrator of such Benchmark has provided a public statement or publication of information announcing that any tenor for such Benchmark is or will be no longer representative, then the Administrative Agent may modify the definition of “Interest Period” for any Benchmark settings at or after such time to remove such unavailable or non-representative tenor and (B) if a tenor that was removed pursuant to clause (A) above either (1) is subsequently displayed on a screen or information service for a Benchmark (including a Benchmark Replacement) or (2) is not, or is no longer, subject to an announcement that it is or will no longer be representative for a Benchmark (including a Benchmark Replacement), then the Administrative Agent may modify the definition of “Interest Period” for all Benchmark settings at or after such time to reinstate such previously removed tenor.

(e)Benchmark Unavailability Period. Upon the Borrower’s receipt of notice of the commencement of a Benchmark Unavailability Period, the Borrower may revoke any request for a borrowing of, conversion to or continuation of LIBOR Loans to be made, converted or continued during any Benchmark Unavailability Period and, failing that, the Borrower will be deemed to have converted any such request into a request for a borrowing of or conversion to ABR Loans. During any Benchmark Unavailability Period or at any time that a tenor for the then-current Benchmark is not an Available Tenor, the component of the Base Rate based upon the then-current Benchmark or such tenor for such Benchmark, as applicable, will not be used in any determination of the ABR.

(f)London Interbank Offered Rate Benchmark Transition Event. On March 5, 2021, the IBA, the administrator of the London interbank offered rate, and the FCA, the regulatory supervisor of the IBA, made the Announcements that the final publication or representativeness date for (A) 1-week and 2-month London interbank offered rate tenor settings will be December 31, 2021 and (B) overnight, 1-month, 3-month, 6-month and 12-month London interbank offered rate tenor settings will be June 30, 2023. No successor administrator for the IBA was identified in such Announcements. The parties hereto agree and acknowledge that the Announcements resulted in the occurrence of a Benchmark Transition Event with respect to the London interbank offered rate pursuant to the terms of this Agreement and that any obligation of the Administrative Agent to notify any parties of such Benchmark Transition Event pursuant to Section 2.18(c) shall be deemed satisfied.

ARTICLE III
Letters of Credit

Section 3.1Letters of Credit.

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(a)Subject to and upon the terms and conditions herein set forth, at any time and from time to time on and after the Closing Date and prior to the L/C Maturity Date, the Letter of Credit Issuer agrees, in reliance upon the agreements of the Lenders set forth in this Section 3, to issue upon the request of the Borrower and for the direct or indirect benefit of the Borrower and the Restricted Subsidiaries, a letter of credit or letters of credit (the “Letters of Credit” and each, a “Letter of Credit”) in such form and with such Issuer Documents as may be approved by the Letter of Credit Issuer in its reasonable discretion; provided that the Borrower shall be a co-applicant of, and jointly and severally liable with respect to, each Letter of Credit issued for the account of a Restricted Subsidiary.

(b)Notwithstanding the foregoing, (i) no Letter of Credit shall be issued the Stated Amount of which, when added to the Letters of Credit Outstanding at such time, would exceed the Letter of Credit Commitment then in effect, (ii) (A) no Letter of Credit shall be issued the Stated Amount of which would cause the aggregate amount of all Lenders’ Total Exposures at such time to exceed the Loan Limit then in effect or any Lender’s Total Exposures at such time to exceed such Lender’s Commitment then in effect and (B) no Letter of Credit Issuer shall be obligated to issue any Letter of Credit, the Stated Amount of which, when added to the Letters of Credit Outstanding issued by such Letter of Credit Issuer at such time, would exceed such Letter of Credit Issuer’s L/C Issuance Limit (it being understood that, without limiting clauses (i) and (ii)(A), upon the Borrower’s request, a Letter of Credit Issuer may agree, in its sole discretion, to issue Letters of Credit in an aggregate amount exceeding such Letter of Credit Issuer’s L/C Issuance Limit), (iii) each Letter of Credit shall have an expiration date occurring no later than one year after the date of issuance (or 18 months with respect to Letters of Credit issued for the benefit of the Texas Railroad Commission) or such longer period of time as may be agreed by the applicable Letter of Credit Issuer, unless otherwise agreed upon by the Administrative Agent and the Letter of Credit Issuer or as provided under Section 3.2(b); provided that any Letter of Credit may provide for automatic renewal thereof for additional periods of up to 12 months (or 18 months with respect to Letters of Credit issued for the benefit of the Texas Railroad Commission) or such longer period of time as may be agreed by the applicable Letter of Credit Issuer, subject to the provisions of Section 3.2(b); provided, further, that in no event shall such expiration date occur later than the L/C Maturity Date unless arrangements which are reasonably satisfactory to the Letter of Credit Issuer to Cash Collateralize (or backstop) such Letter of Credit have been made, (iv) each Letter of Credit shall be denominated in Dollars, (v) no Letter of Credit shall be issued if it would be illegal under any applicable Requirement of Law for the beneficiary of the Letter of Credit to have a Letter of Credit issued in its favor and (vi) no Letter of Credit shall be issued by a Letter of Credit Issuer after it has received a written notice from any Credit Party or the Administrative Agent or the Majority Lenders stating that a Default or Event of Default has occurred and is continuing until such time as the Letter of Credit Issuer shall have received a written notice (A) of rescission of such notice from the party or parties originally delivering such notice, (B) of the waiver of such Default or Event of Default in accordance with the provisions of Section 13.1 or (C) that such Default or Event of Default is no longer continuing.

(c)Upon at least one Business Day’s prior written notice (or telephonic notice promptly confirmed in writing) to the Administrative Agent and the Letter of Credit

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Issuer (which notice the Administrative Agent shall promptly transmit to each of the applicable Lenders), the Borrower shall have the right, on any day, permanently to terminate or reduce the Letter of Credit Commitment in whole or in part; provided that, after giving effect to such termination or reduction, the Letters of Credit Outstanding shall not exceed the Letter of Credit Commitment. Any such reduction of the Letter of Credit Commitment shall be applied ratably among the Letter of Credit Issuers based upon their respective L/C Issuance Limits.

Section 3.2Letter of Credit Requests.

(a)Whenever the Borrower desires that a Letter of Credit be issued for its account, the Borrower shall give the Administrative Agent and the Letter of Credit Issuer a Letter of Credit Request by no later than 1:00 p.m. (New York City time) at least three (or such lesser number as may be agreed upon by the Administrative Agent and the Letter of Credit Issuer) Business Days prior to the proposed date of issuance. Each notice shall be executed by the Borrower and shall be in the form of Exhibit K or such other form (including by electronic or fax transmission) as reasonably agreed between the Borrower, the Administrative Agent and the Letter of Credit Issuer (each a “Letter of Credit Request”). No Letter of Credit Issuer shall issue any Letters of Credit unless such Letter of Credit Issuer shall have received notice from the Administrative Agent that the conditions to such issuance have been met, which notice shall be deemed given if the Letter of Credit Issuer has not received notice from the Administrative Agent that the conditions to such issuance have been met within two Business Days after the date of the applicable Letter of Credit Request.

(b)If the Borrower so requests in any applicable Letter of Credit Request, the Letter of Credit Issuer may, in its sole and absolute discretion, agree to issue a Letter of Credit that has automatic extension provisions (each, an “Auto-Extension Letter of Credit”); provided that any such Auto-Extension Letter of Credit must permit the Letter of Credit Issuer to prevent any such extension at least once in each 12-month period (commencing with the date of issuance of such Letter of Credit) by giving prior notice to the beneficiary thereof not later than a day (the “Non-Extension Notice Date”) in each such 12-month period to be agreed upon at the time such Letter of Credit is issued. Unless otherwise directed by the Letter of Credit Issuer, the Borrower shall not be required to make a specific request to the Letter of Credit Issuer for any such extension. Once an Auto-Extension Letter of Credit has been issued, the Lenders shall be deemed to have authorized (but may not require) the Letter of Credit Issuer to permit the extension of such Letter of Credit at any time to an expiry date not later than the L/C Maturity Date; provided, however, that the Letter of Credit Issuer shall not permit any such extension if (i) the Letter of Credit Issuer has determined that it would not be permitted, or would have no obligation, at such time to issue such Letter of Credit in its revised form (as extended) under the terms hereof (by reason of the provisions of Section 3.1(b) or otherwise), or (ii) it has received notice (which may be by telephone or in writing) on or before the day that is five Business Days before the Non-Extension Notice Date (A) from the Administrative Agent that the Majority Lenders have elected not to permit such extension or (B) from the Administrative Agent, any Lender or the Borrower that one or

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more of the applicable conditions specified in Section 7 are not then satisfied, and in each such case directing the Letter of Credit Issuer not to permit such extension.

(c)Each Letter of Credit Issuer shall, in addition to its notification obligations set forth elsewhere in this Section, report in writing to the Administrative Agent and each Lender at least two (or such lesser number as may be agreed upon by the Administrative Agent and the Letter of Credit Issuer) Business Days to the time that such Letter of Credit Issuer issues, amends, renews or extends any Letter of Credit, the date of such issuance, amendment, renewal or extension, and the stated amount of the Letters of Credit issued, amended, renewed or extended by it and outstanding after giving effect to such issuance, amendment, renewal or extension (and whether the amounts thereof shall have changed).

(d)The making of each Letter of Credit Request shall be deemed to be a representation and warranty by the Borrower that the Letter of Credit may be issued in accordance with, and will not violate the requirements of, Section 3.1(b).

Section 3.3Letter of Credit Participations.

(a)Immediately upon the issuance by the Letter of Credit Issuer of any Letter of Credit (and on the Closing Date, with respect to the Existing Letters of Credit), the Letter of Credit Issuer shall be deemed to have sold and transferred to each Lender (each such Lender, in its capacity under this Section 3.3, an “L/C Participant”), and each such L/C Participant shall be deemed irrevocably and unconditionally to have purchased and received from the Letter of Credit Issuer, without recourse or warranty, an undivided interest and participation (each an “L/C Participation”), to the extent of such L/C Participant’s Commitment Percentage, in each Letter of Credit, each substitute therefor, each drawing made thereunder and the obligations of the Borrower under this Agreement with respect thereto, and any security therefor or guaranty pertaining thereto.

(b)In determining whether to pay under any Letter of Credit, the relevant Letter of Credit Issuer shall have no obligation relative to the L/C Participants other than to confirm that (i) any documents required to be delivered under such Letter of Credit have been delivered, (ii) the Letter of Credit Issuer has examined the documents with reasonable care and (iii) the documents appear to comply on their face with the requirements of such Letter of Credit. Any action taken or omitted to be taken by the relevant Letter of Credit Issuer under or in connection with any Letter of Credit issued by it, if taken or omitted in the absence of gross negligence or willful misconduct, shall not create for the Letter of Credit Issuer any resulting liability.

(c)In the event that the Letter of Credit Issuer makes any payment under any Letter of Credit issued by it and the Borrower shall not have repaid such amount in full to the Administrative Agent for the account of the respective Letter of Credit Issuer pursuant to Section 3.4(a), the Administrative Agent shall notify each L/C Participant, and each such L/C Participant shall promptly and unconditionally pay to the Administrative Agent for the account of the Letter of Credit Issuer, the amount of such L/C Participant’s Commitment Percentage of such unreimbursed payment in Dollars and in immediately available funds. Each L/C Participant shall make available to the

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Administrative Agent for the account of the Letter of Credit Issuer such L/C Participant’s Commitment Percentage of the amount of such payment no later than 1:00 p.m. (New York City time) on the first Business Day after the date notified by the Administrative Agent in immediately available funds. If and to the extent such L/C Participant shall not have so made its Commitment Percentage of the amount of such payment available to the Administrative Agent for the account of the Letter of Credit Issuer, such L/C Participant agrees to pay to the Administrative Agent for the account of the Letter of Credit Issuer, forthwith on demand, such amount, together with interest thereon for each day from such date until the date such amount is paid to the Administrative Agent for the account of the Letter of Credit Issuer at a rate per annum equal to the Overnight Rate from time to time then in effect, plus any administrative, processing or similar fees customarily charged by the Letter of Credit Issuer in connection with the foregoing. The failure of any L/C Participant to make available to the Administrative Agent for the account of the Letter of Credit Issuer its Commitment Percentage of any payment under any Letter of Credit shall not relieve any other L/C Participant of its obligation hereunder to make available to the Administrative Agent for the account of the Letter of Credit Issuer its Commitment Percentage of any payment under such Letter of Credit on the date required, as specified above, but no L/C Participant shall be responsible for the failure of any other L/C Participant to make available to the Administrative Agent such other L/C Participant’s Commitment Percentage of any such payment.

(d)Whenever the Letter of Credit Issuer receives a payment in respect of an unpaid reimbursement obligation as to which the Administrative Agent has received for the account of the Letter of Credit Issuer any payments from the L/C Participants pursuant to Section 3.3(c) above, the Letter of Credit Issuer shall pay to the Administrative Agent and the Administrative Agent shall promptly pay to each L/C Participant that has paid its Commitment Percentage of such reimbursement obligation, in Dollars and in immediately available funds, an amount equal to such L/C Participant’s share (based upon the proportionate aggregate amount originally funded by such L/C Participant to the aggregate amount funded by all L/C Participants) of the principal amount so paid in respect of such reimbursement obligation and interest thereon accruing after the purchase of the respective L/C Participations at the Overnight Rate.

(e)The obligations of the L/C Participants to make payments to the Administrative Agent for the account of a Letter of Credit Issuer with respect to Letters of Credit shall be irrevocable and not subject to counterclaim, set-off or other defense or any other qualification or exception whatsoever and shall be made in accordance with the terms and conditions of this Agreement under all circumstances, including under any of the following circumstances:

(i)any lack of validity or enforceability of this Agreement or any of the other Credit Documents;

(ii)the existence of any claim, set-off, defense or other right that the Borrower may have at any time against a beneficiary named in a Letter of Credit, any transferee of any Letter of Credit (or any Person for whom any such transferee may be acting), the Administrative Agent, the Letter of Credit Issuer,

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any Lender or other Person, whether in connection with this Agreement, any Letter of Credit, the transactions contemplated herein or any unrelated transactions (including any underlying transaction between the Borrower and the beneficiary named in any such Letter of Credit);

(iii)any draft, certificate or any other document presented under any Letter of Credit proving to be forged, fraudulent, invalid or insufficient in any respect or any statement therein being untrue or inaccurate in any respect;

(iv)the surrender or impairment of any security for the performance or observance of any of the terms of any of the Credit Documents; or

(v)the occurrence of any Default or Event of Default.

Section 3.4Agreement to Repay Letter of Credit Drawings.

(a)The Borrower hereby agrees to reimburse the Letter of Credit Issuer by making payment in Dollars to the Administrative Agent for the account of the Letter of Credit Issuer in immediately available funds, for any payment or disbursement made by the Letter of Credit Issuer under any Letter of Credit issued by it (each such amount so paid until reimbursed, an “Unpaid Drawing”) (i) within one Business Day of the date of such payment or disbursement if the Letter of Credit Issuer provides notice to the Borrower of such payment or disbursement prior to 11:00 a.m. (New York City time) on the date of such payment or disbursement or (ii) if such notice is received after such time, on the next Business Day following the first date when such notice was received prior to 11:00 a.m. (New York City time) (such required date for reimbursement under clause (i) or (ii), as applicable, on such Business Day (the “Reimbursement Date”)), with interest on the amount so paid or disbursed by such Letter of Credit Issuer, from and including the date of such payment or disbursement to but excluding the Reimbursement Date, at the per annum rate for each day equal to the rate described in Section 2.8(a); provided that, notwithstanding anything contained in this Agreement to the contrary, with respect to any Letter of Credit, (i) unless the Borrower shall have notified the Administrative Agent and the Letter of Credit Issuer prior to 11:00 a.m. (New York City time) on the Reimbursement Date that the Borrower intends to reimburse the Letter of Credit Issuer for the amount of such drawing with funds other than the proceeds of Loans, the Borrower shall be deemed to have given a Notice of Borrowing requesting that the Lenders make Loans (which shall be ABR Loans) on the Reimbursement Date in an amount equal to the amount at such drawing, and (ii) the Administrative Agent shall promptly notify each Letter of Credit Participant of such drawing and the amount of its Loan to be made in respect thereof, and each Letter of Credit Participant shall be irrevocably obligated to make a Loan to the Borrower in the manner deemed to have been requested in the amount of its Commitment Percentage of the applicable Unpaid Drawing by 12:00 noon (New York City time) on such Reimbursement Date by making the amount of such Loan available to the Administrative Agent. Such Loans made in respect of such Unpaid Drawing on such Reimbursement Date shall be made without regard to the Minimum Borrowing Amount and without regard to the satisfaction of the conditions set forth in Section 7. The Administrative Agent shall use the proceeds of such Loans solely for purpose of reimbursing the Letter of Credit Issuer for the related Unpaid

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Drawing. In the event that the Borrower fails to Cash Collateralize any Letter of Credit that is outstanding on the Maturity Date, the full amount of the Letters of Credit Outstanding in respect of such Letter of Credit shall be deemed to be an Unpaid Drawing subject to the provisions of this Section 3.4 except that the Letter of Credit Issuer shall hold the proceeds received from the Lenders as contemplated above as cash collateral for such Letter of Credit to reimburse any Drawing under such Letter of Credit and shall use such proceeds first, to reimburse itself for any Drawings made in respect of such Letter of Credit following the L/C Maturity Date, second, to the extent such Letter of Credit expires or is returned undrawn while any such cash collateral remains, to the repayment of obligations in respect of any Loans that have not paid at such time and third, to the Borrower or as otherwise directed by a court of competent jurisdiction. Nothing in this Section 3.4(a) shall affect the Borrower’s obligation to repay all outstanding Loans when due in accordance with the terms of this Agreement.

(b)The obligations of the Borrower under this Section 3.4 to reimburse the Letter of Credit Issuer with respect to Unpaid Drawings (including, in each case, interest thereon) shall be absolute and unconditional under any and all circumstances and irrespective of any set-off, counterclaim or defense to payment that the Borrower or any other Person may have or have had against the Letter of Credit Issuer, the Administrative Agent or any Lender (including in its capacity as an L/C Participant), including any defense based upon the failure of any drawing under a Letter of Credit (each a “Drawing”) to conform to the terms of the Letter of Credit or any non-application or misapplication by the beneficiary of the proceeds of such Drawing; provided, that the Borrower shall not be obligated to reimburse the Letter of Credit Issuer for any wrongful payment made by the Letter of Credit Issuer under the Letter of Credit issued by it as a result of acts or omissions constituting willful misconduct, bad faith or gross negligence on the part of the Letter of Credit Issuer as determined by a final judgment of a court of competent jurisdiction.

Section 3.5Increased Costs. If, after the Closing Date, the adoption of any Change in Law shall either (a) impose, modify or make applicable any reserve, deposit, capital adequacy, liquidity or similar requirement against letters of credit issued by the Letter of Credit Issuer, or any L/C Participant’s L/C Participation therein, or (b) impose on the Letter of Credit Issuer or any L/C Participant any other conditions, costs or expenses affecting its obligations under this Agreement in respect of Letters of Credit or L/C Participations therein or any Letter of Credit or such L/C Participant’s L/C Participation therein, and the result of any of the foregoing is to increase the cost to the Letter of Credit Issuer or such L/C Participant of issuing, maintaining or participating in any Letter of Credit, or to reduce the amount of any sum received or receivable by the Letter of Credit Issuer or such L/C Participant hereunder (other than (i) Taxes indemnifiable under Section 5.4, or (ii) Excluded Taxes) in respect of Letters of Credit or L/C Participations therein, then, promptly (and in any event no later than 15 days) after receipt of written demand to the Borrower by the Letter of Credit Issuer or such L/C Participant, as the case may be (a copy of which notice shall be sent by the Letter of Credit Issuer or such L/C Participant to the Administrative Agent), the Borrower shall pay to the Letter of Credit Issuer or such L/C Participant such additional amount or amounts as will compensate the Letter of Credit Issuer or such L/C Participant for such increased cost or reduction, it being understood and agreed, however, that the Letter of Credit Issuer or an L/C Participant shall not be entitled to such compensation as a result of such Person’s compliance with, or pursuant to any request or directive to comply with, any such Requirement of Law as in effect on the Closing Date (except

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as otherwise set forth in the definition of Change in Law). A certificate submitted to the Borrower by the relevant Letter of Credit Issuer or an L/C Participant, as the case may be (a copy of which certificate shall be sent by the Letter of Credit Issuer or such L/C Participant to the Administrative Agent), setting forth in reasonable detail the basis for the determination of such additional amount or amounts necessary to compensate the Letter of Credit Issuer or such L/C Participant as aforesaid shall be conclusive and binding on the Borrower absent clearly demonstrable error.

Section 3.6New or Successor Letter of Credit Issuer.

(a)The Letter of Credit Issuer may resign as a Letter of Credit Issuer upon 30 days’ prior written notice to the Administrative Agent, the Lenders and the Borrower. The Borrower may replace the Letter of Credit Issuer for any reason upon written notice to the Letter of Credit Issuer and the Administrative Agent and may add Letter of Credit Issuers at any time upon notice to the Administrative Agent. If the Letter of Credit Issuer shall resign or be replaced, or if the Borrower shall decide to add a new Letter of Credit Issuer under this Agreement, then the Borrower may appoint from among the Lenders a successor issuer of Letters of Credit or a new Letter of Credit Issuer, as the case may be, or, with the consent of the Administrative Agent (such consent not to be unreasonably withheld) and such new Letter of Credit Issuer, another successor or new issuer of Letters of Credit, whereupon such successor issuer shall succeed to the rights, powers and duties of the replaced or resigning Letter of Credit Issuer under this Agreement and the other Credit Documents, or such new issuer of Letters of Credit shall be granted the rights, powers and duties of a Letter of Credit Issuer hereunder, and the term “Letter of Credit Issuer” shall mean such successor or such new issuer of Letters of Credit effective upon such appointment. The acceptance of any appointment as a Letter of Credit Issuer hereunder whether as a successor issuer or new issuer of Letters of Credit in accordance with this Agreement, shall be evidenced by an agreement entered into by such new or successor issuer of Letters of Credit, in a form reasonably satisfactory to the Borrower and the Administrative Agent and, from and after the effective date of such agreement, such new or successor issuer of Letters of Credit shall become a “Letter of Credit Issuer” hereunder. After the resignation or replacement of a Letter of Credit Issuer hereunder, the resigning or replaced Letter of Credit Issuer shall remain a party hereto and shall continue to have all the rights and obligations of a Letter of Credit Issuer under this Agreement and the other Credit Documents with respect to Letters of Credit issued by it prior to such resignation or replacement, but shall not be required to issue additional Letters of Credit. In connection with any resignation or replacement pursuant to this Section 3.6(a) (but, in case of any such resignation, only to the extent that a successor issuer of Letters of Credit shall have been appointed), either (i) the Borrower, the resigning or replaced Letter of Credit Issuer and the successor issuer of Letters of Credit shall arrange to have any outstanding Letters of Credit issued by the resigning or replaced Letter of Credit Issuer replaced with Letters of Credit issued by the successor issuer of Letters of Credit or (ii) the Borrower shall cause the successor issuer of Letters of Credit, if such successor issuer is reasonably satisfactory to the replaced or resigning Letter of Credit Issuer, to issue “back-stop” Letters of Credit naming the resigning or replaced Letter of Credit Issuer as beneficiary for each outstanding Letter of Credit issued by the resigning or replaced Letter of Credit Issuer, which new Letters of Credit shall have a Stated Amount equal to the Letters of Credit being back-stopped and the sole requirement for drawing on such new Letters of Credit shall be a drawing on the corresponding back-

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stopped Letters of Credit. After any resigning or replaced Letter of Credit Issuer’s resignation or replacement as Letter of Credit Issuer, the provisions of this Agreement relating to a Letter of Credit Issuer shall inure to its benefit as to any actions taken or omitted to be taken by it (A) while it was a Letter of Credit Issuer under this Agreement or (B) at any time with respect to Letters of Credit issued by such Letter of Credit Issuer. The definition of “L/C Issuance Limit” may be amended to add or remove a Letter of Credit Issuer, or modify the L/C Issuance Limit of any Letter of Credit Issuer with the consent solely of the Borrower, the Administrative Agent and such Letter of Credit Issuer (and the consent of the Majority Lenders shall not be required).

(b)To the extent that there are, at the time of any resignation or replacement as set forth in Section 3.6(a) above, any outstanding Letters of Credit, nothing herein shall be deemed to impact or impair any rights and obligations of any of the parties hereto with respect to such outstanding Letters of Credit (including any obligations related to the payment of fees or the reimbursement or funding of amounts drawn), except that the Borrower, the resigning or replaced Letter of Credit Issuer and the successor issuer of Letters of Credit shall have the obligations regarding outstanding Letters of Credit described in Section 3.6(a) above.

Section 3.7Role of Letter of Credit Issuer. Each Lender and the Borrower agree that, in paying any drawing under a Letter of Credit, the Letter of Credit Issuer shall not have any responsibility to obtain any document (other than any sight draft, certificates and documents expressly required by the Letter of Credit) or to ascertain or inquire as to the validity or accuracy of any such document or the authority of the Person executing or delivering any such document. None of the Letter of Credit Issuer, the Administrative Agent, any of their respective affiliates nor any correspondent, participant or assignee of the Letter of Credit Issuer shall be liable to any Lender for (a) any action taken or omitted in connection herewith at the request or with the approval of the Majority Lenders, (b) any action taken or omitted in the absence of gross negligence or willful misconduct or (c) the due execution, effectiveness, validity or enforceability of any document or instrument related to any Letter of Credit or Issuer Document. The Borrower hereby assumes all risks of the acts or omissions of any beneficiary or transferee with respect to its use of any Letter of Credit; provided that this assumption is not intended to, and shall not, preclude the Borrower’s pursuing such rights and remedies as it may have against the beneficiary or transferee at law or under any other agreement. None of the Letter of Credit Issuer, the Administrative Agent, any of their respective affiliates nor any correspondent, participant or assignee of the Letter of Credit Issuer shall be liable or responsible for any of the matters described in Section 3.3(e); provided that anything in such Section to the contrary notwithstanding, the Borrower may have a claim against the Letter of Credit Issuer, and the Letter of Credit Issuer may be liable to the Borrower, to the extent, but only to the extent, of any direct, as opposed to consequential or exemplary, damages suffered by the Borrower which the Borrower proves were caused by the Letter of Credit Issuer’s willful misconduct or gross negligence or the Letter of Credit Issuer’s willful failure to pay under any Letter of Credit after the presentation to it by the beneficiary of a sight draft and certificate(s) strictly complying with the terms and conditions of a Letter of Credit, in each case as determined in a final and non-appealable judgment by a court of competent jurisdiction. In furtherance and not in limitation of the foregoing, the Letter of Credit Issuer may accept documents that appear on their face to be in order, without responsibility for further investigation, regardless of any notice or information to

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the contrary, and the Letter of Credit Issuer shall not be responsible for the validity or sufficiency of any instrument transferring or assigning or purporting to transfer or assign a Letter of Credit or the rights or benefits thereunder or proceeds thereof, in whole or in part, which may prove to be invalid or ineffective for any reason.

Section 3.8Cash Collateral.

(a)Upon the request of the Majority Lenders if, as of the L/C Maturity Date, there are any Letters of Credit Outstanding, the Borrower shall immediately Cash Collateralize the then Letters of Credit Outstanding.

(b)If any Event of Default shall occur and be continuing, the Majority Lenders may require that the L/C Obligations be Cash Collateralized; provided that, upon the occurrence of an Event of Default referred to in Section 11.5 with respect to the Borrower, the Borrower shall immediately Cash Collateralize the Letters of Credit then outstanding and no notice or request by or consent from the Majority Lenders shall be required.

(c)For purposes of this Agreement, “Cash Collateralize” shall mean to pledge and deposit with or deliver to the Administrative Agent, for the benefit of the Letter of Credit Issuer and the Lenders, as collateral for the L/C Obligations, cash or deposit account balances in an amount equal to the amount of the Letters of Credit Outstanding required to be Cash Collateralized pursuant to documentation in form and substance reasonably satisfactory to the Administrative Agent and the Letter of Credit Issuer (which documents are hereby consented to by the Lenders). Derivatives of such term have corresponding meanings. The Borrower hereby grants to the Administrative Agent, for the benefit of the Letter of Credit Issuer and the L/C Participants, a security interest in all such cash, deposit accounts and all balances therein and all proceeds of the foregoing. Such cash Collateral shall be maintained in blocked, interest bearing deposit accounts established by and in the name of the Borrower, but under the “control” (as defined in Section 9-104 of the UCC) of the Administrative Agent.

Section 3.9Applicability of ISP and UCP. Unless otherwise expressly agreed by the Letter of Credit Issuer and the Borrower when a Letter of Credit is issued, (a) the rules of the ISP shall apply to each standby Letter of Credit and (b) the rules of the Uniform Customs and Practice for Documentary Credits, as most recently published by the International Chamber of Commerce at the time of issuance, shall apply to each commercial Letter of Credit.

Section 3.10Conflict with Issuer Documents. In the event of any conflict between the terms hereof and the terms of any Issuer Document, the terms hereof shall control.

Section 3.11Letters of Credit Issued for Restricted Subsidiaries. Notwithstanding that a Letter of Credit issued or outstanding hereunder is in support of any obligations of, or is for the account of, a Restricted Subsidiary, the Borrower shall be obligated to reimburse the Letter of Credit Issuer hereunder for any and all drawings under such Letter of Credit. The Borrower hereby acknowledges that the issuance of Letters of Credit for the account of

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Restricted Subsidiaries inures to the benefit of the Borrower, and that the Borrower’s business derives substantial benefits from the businesses of such Restricted Subsidiaries.

Section 3.12Existing Letters of Credit. Subject to the terms and conditions hereof, on the Closing Date, the Existing Letters of Credit shall, without any further action by the Borrower, be deemed to have been issued by the applicable Letter of Credit Issuer pursuant to, and shall constitute a Letter of Credit for all purposes under, this Agreement, in each case without payment of any fees otherwise due upon the issuance of a Letter of Credit, and each Existing Letter of Credit shall be subject to and governed by the terms and conditions hereof.

ARTICLE IV
Fees; Commitments

Section 4.1Fees.

(a)The Borrower agrees to pay to the Administrative Agent in Dollars, for the account of each Lender (in each case pro rata according to the respective Commitment Percentages of the Lenders), a commitment fee (the “Commitment Fee”) for each day from the Closing Date until but excluding the Termination Date. Each Commitment Fee shall be payable by the Borrower (i) quarterly in arrears on the last Business Day of each March, June, September and December (for the three-month period (or portion thereof) ended on such day for which no payment has been received) and (ii) on the Termination Date (for the period ended on such date for which no payment has been received pursuant to clause (i) above), and shall be computed for each day during such period at a rate per annum equal to the Commitment Fee Rate in effect on such day on the Available Commitment in effect on such day.

(b)The Borrower agrees to pay to the Administrative Agent in Dollars for the account of the Lenders pro rata on the basis of their respective Letter of Credit Exposure, a fee in respect of each Letter of Credit (the “Letter of Credit Fee”), for the period from the date of issuance of such Letter of Credit until the termination or expiration date of such Letter of Credit computed at the per annum rate for each day equal to the Applicable Margin for LIBOR Loans on the average daily Stated Amount of such Letter of Credit. Such Letter of Credit Fees shall be due and payable (i) quarterly in arrears on the last Business Day of each March, June, September and December and (ii) on the Termination Date (for the period for which no payment has been received pursuant to clause (i) above).

(c)The Borrower agrees to pay to each Letter of Credit Issuer a fee in respect of each Letter of Credit issued by it (the “Fronting Fee”), for the period from the date of issuance of such Letter of Credit to the termination or expiration date of such Letter of Credit, computed at the rate for each day equal to 0.125% per annum on the average daily Stated Amount of such Letter of Credit (or at such other rate per annum as agreed in writing subsequent to the date hereof between the Borrower and the applicable Letter of Credit Issuer). Such Fronting Fees shall be due and payable by the Borrower (i) quarterly in arrears on the last Business Day of each March, June, September and December and (ii) on the Termination Date (for the period for which no payment has been received pursuant to clause (i) above).

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(d)The Borrower agrees to pay directly to the Letter of Credit Issuer upon each issuance of, drawing under, and/or amendment of, a Letter of Credit issued by it such amount as the Letter of Credit Issuer and the Borrower shall have agreed upon for issuances of, drawings under or amendments of, letters of credit issued by it.

(e)The Borrower agrees to pay to the Administrative Agent the administrative agent fees in the amounts and on the dates as set forth in writing from time to time between the Administrative Agent and the Borrower.

Section 4.2Voluntary Reduction of Commitments.

(a)Upon at least two Business Days’ (or such shorter time period as the Administrative Agent may agree) prior written notice (or telephonic notice promptly confirmed in writing) to the Administrative Agent at the Administrative Agent’s Office (which notice the Administrative Agent shall promptly transmit to each of the Lenders), the Borrower shall have the right, without premium or penalty, on any day, permanently to terminate or reduce the Total Commitments (including the Aggregate Maximum Credit Amount and the Aggregate Elected Commitment Amount) of any Class, as determined by the Borrower, in whole or in part; provided that (a) with respect to the Total Commitments, any such termination or reduction shall apply proportionately and permanently to reduce the Total Commitments (including the Aggregate Maximum Credit Amount and the Aggregate Elected Commitment Amount) of each of the Lenders of such Class, except that, notwithstanding the foregoing, (1) the Borrower may allocate any termination or reduction of the Total Commitments (including the Aggregate Maximum Credit Amount and the Aggregate Elected Commitment Amount) among classes of Commitments either (A) ratably among Classes or (B) first to the Commitments with respect to any Existing Commitments and second to any Extended Commitments and (2) in connection with the establishment on any date of any Extended Commitments pursuant to Section 2.17, the Existing Commitments of any one or more Lenders providing any such Extended Commitments on such date shall be reduced in an amount equal to the amount of Specified Existing Commitments so extended on such date (provided that (x) after giving effect to any such reduction and to the repayment of any Loans made on such date, the Total Exposure of any such Lender does not exceed the Commitment thereof (such Total Exposure and Commitment being determined in each case, for the avoidance of doubt, exclusive of such Lender’s Extended Commitment and any exposure in respect thereof) and (y) for the avoidance of doubt, any such repayment of Loans contemplated by the preceding clause shall be made in compliance with the requirements of Section 5.3(a) with respect to the ratable allocation of payments hereunder, with such allocation being determined after giving effect to any conversion pursuant to Section 2.17 of Existing Commitments and Existing Loans into Extended Commitments and Extended Loans respectively, and prior to any reduction being made to the Commitment of any other Lender), (b) any partial reduction pursuant to this Section 4.2 shall be in the amount of at least $500,000 and in multiples of $100,000 in excess thereof, (c) after giving effect to such termination or reduction and to any prepayments of Loans or cancellation or Cash Collateralization of Letters of Credit made on the date thereof in accordance with this Agreement, the aggregate amount of the Lenders’ Total Exposures shall not exceed the Loan Limit and (d) any election by the Borrower to

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terminate or reduce the Total Commitments (including the Aggregate Maximum Credit Amount and the Aggregate Elected Commitment Amount) pursuant to a notice delivered by the Borrower pursuant to this Section 4.2(a) may be made to be contingent upon the consummation of a refinancing or other event and such notice may otherwise be extended or revoked, in each case, with the requirements of Section 2.11 to apply to any failure of the contingency to occur and any such extension or revocation.

(b)The Borrower may terminate the unused amount of the Commitment of a Defaulting Lender upon not less than two Business Days’ prior notice to the Administrative Agent (which will promptly notify the Lenders thereof), and in such event the provisions of Section 2.15(f) will apply to all amounts thereafter paid by the Borrower for the account of such Defaulting Lender under this Agreement (whether on account of principal, interest, fees, indemnity or other amounts), provided that such termination will not be deemed to be a waiver or release of any claim the Borrower, the Administrative Agent, any Letter of Credit Issuer or any Lender may have against such Defaulting Lender.

Section 4.3Mandatory Termination of Commitments. The Total Commitment shall terminate at 5:00 p.m. (New York City time) on the Termination Date.

ARTICLE V
Payments

Section 5.1Voluntary Prepayments. The Borrower shall have the right to prepay Loans without premium or penalty, in whole or in part from time to time on the following terms and conditions:

(a)the Borrower shall give the Administrative Agent at the Administrative Agent’s Office written notice (or telephonic notice promptly confirmed in writing) of its intent to make such prepayment, the amount of such prepayment and (in the case of LIBOR Loans) the specific Borrowing(s) being prepaid, which notice shall be given by the Borrower no later than 1:00 p.m. (New York City time) (i) in the case of LIBOR Loans, three Business Days (or such shorter time as the Administrative Agent may agree) prior to the date of such prepayment and (ii) in the case of ABR Loans on the date of such prepayment and shall promptly be transmitted by the Administrative Agent to each of the Lenders;

(b)each partial prepayment of (i) LIBOR Loans shall be in a minimum amount of $500,000 and in multiples of $100,000 in excess thereof, and (ii) any ABR Loans shall be in a minimum amount of $500,000 and in multiples of $100,000 in excess thereof; provided that no partial prepayment of LIBOR Loans made pursuant to a single Borrowing shall reduce the outstanding LIBOR Loans made pursuant to such Borrowing to an amount less than the applicable Minimum Borrowing Amount for such LIBOR Loans; and

(c)any prepayment of LIBOR Loans pursuant to this Section 5.1 on any day other than the last day of an Interest Period applicable thereto shall be subject to compliance by the Borrower with the applicable provisions of Section 2.11.

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Each such notice shall specify the date and amount of such prepayment and the Type of Loans to be prepaid. At the Borrower’s election in connection with any prepayment pursuant to this Section 5.1, such prepayment shall not be applied to any Loans of a Defaulting Lender.

Notwithstanding the foregoing (and as provided in clause (1) of the proviso to Section 2.17(a)), the Borrower may not prepay Extended Loans of any Extension Series unless such prepayment is accompanied by a pro rata repayment of Existing Loans of the Specified Existing Commitment Class of the Existing Class from which such Extended Loans and Extended Commitments were converted (or such Loans and Commitments of the Existing Class have otherwise been repaid and terminated in full). Any election by the Borrower to prepay the Loans pursuant to a notice delivered by the Borrower pursuant to this Section 5.1 may be made to be contingent upon the consummation of a refinancing or other event and such notice may otherwise be extended or revoked, in each case, with the requirements of Section 2.11 to apply to any failure of the contingency to occur and any such extension or revocation.

Section 5.2Mandatory Prepayments.

(a)Repayment following Optional Reduction of Commitments. If, after giving effect to any termination or reduction of the Commitments pursuant to Section 4.2(a), the aggregate Total Exposures of all Lenders exceeds the Loan Limit (as reduced), then the Borrower shall on the same Business Day (i) prepay the Loans on the date of such termination or reduction in an aggregate principal amount equal to such excess and (ii) if any excess remains after prepaying all of the Loans as a result of any Letter of Credit Exposure, pay to the Administrative Agent on behalf of the Letter of Credit Issuer and the L/C Participants an amount in cash equal to such excess to be held as cash collateral as provided in Section 3.8.

(b)Repayment of Loans Following Redetermination or Adjustment of Borrowing Base.

(i)Upon the effectiveness of a redetermination of the Borrowing Base in accordance with Section 2.14(b), if a Borrowing Base Deficiency exists, then the Borrower shall, within 10 Business Days after its receipt of a New Borrowing Base Notice indicating such Borrowing Base Deficiency, inform the Administrative Agent of the Borrower’s election to:

(A)within 30 days following such election prepay the Loans in an aggregate principal amount equal to such Borrowing Base Deficiency,

(B)prepay the Loans in six equal monthly installments, commencing on the 30th day following its receipt of such New Borrowing Base Notice with each payment being equal to 1/6th of the aggregate principal amount of such Borrowing Base Deficiency,

(C)within 30 days following such election, provide additional Collateral in the form of additional Oil and Gas Properties not evaluated in the most recently delivered Reserve Report or other Collateral reasonably acceptable to the Administrative Agent having a Borrowing Base value (as

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proposed by the Administrative Agent and approved by the Required Lenders) sufficient, after giving effect to any other actions taken pursuant to this Section 5.2(b)(i) to eliminate any such Borrowing Base Deficiency, or

(D)undertake a combination of clauses (A), (B) and (C); provided that if, because of Letter of Credit Exposure, a Borrowing Base Deficiency remains after prepaying all of the Loans, the Borrower shall Cash Collateralize such remaining Borrowing Base Deficiency as provided in Section 3.8; providedfurther, that (x) in the event the Borrower fails to provide such written notice to the Administrative Agent within the ten Business Day period referred to above, the Borrower shall be deemed to have irrevocably elected the option set forth in clause (B) above, (y) all payments required to be made pursuant to this Section 5.2(b)(i) must be made on or prior to the Termination Date and (z) once a Borrowing Base Deficiency is cured, the Borrower shall not be required to continue to take any such actions.

(ii)Upon any adjustment to the Borrowing Base pursuant to the Borrowing Base Adjustment Provisions, if a Borrowing Base Deficiency exists, then the Borrower shall (A) prepay the Loans in an aggregate principal amount equal to such Borrowing Base Deficiency and (B) if any Borrowing Base Deficiency remains after prepaying all of the Loans as a result of any Letter of Credit Exposure, Cash Collateralize such excess as provided in Section 3.8. The Borrower shall be obligated to make such prepayment and/or deposit of cash collateral no later than two Business Days following the date it receives written notice from the Administrative Agent of the adjustment of the Borrowing Base and the resulting Borrowing Base Deficiency; provided that all payments required to be made pursuant to this clause must be made on or prior to the Termination Date.

(c)Application to Loans. With respect to each prepayment of Loans elected under Section 5.1 or required by Section 5.2, the Borrower may designate (i) the Types of Loans that are to be prepaid and the specific Borrowing(s) being repaid and (ii) the Loans to be prepaid; provided that (A) each prepayment of any Loans made pursuant to a Borrowing shall be applied pro rata among such Loans and (B) notwithstanding the provisions of the preceding clause (A), no prepayment of Loans shall be applied to the Loans of any Defaulting Lender unless otherwise agreed in writing by the Borrower. In the absence of a designation by the Borrower as described in the preceding sentence, the Administrative Agent shall, subject to the above, make such designation in its reasonable discretion with a view, but no obligation, to minimize breakage costs owing under Section 2.11.

(d)LIBOR Interest Periods. In lieu of making any payment pursuant to this Section 5.2 in respect of any LIBOR Loan, other than on the last day of the Interest Period therefor so long as no Event of Default shall have occurred and be continuing, the Borrower at its option may deposit, on behalf of the Borrower, with the Administrative Agent an amount equal to the amount of the LIBOR Loan to be prepaid and such LIBOR Loan shall be repaid on the last day of the Interest Period therefor in the required amount.

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Such deposit shall be held by the Administrative Agent in a corporate time deposit account established on terms reasonably satisfactory to the Administrative Agent, earning interest at the then customary rate for accounts of such type. Such deposit shall constitute cash collateral for the LIBOR Loans to be so prepaid; provided that the Borrower may at any time direct that such deposit be applied to make the applicable payment required pursuant to this Section 5.2.

(e)Application of Proceeds. The application of proceeds pursuant to this Section 5.2 shall not reduce the aggregate amount of Commitments under the Facility and amounts prepaid may be reborrowed subject to the Available Commitment.

(f)Prepayment of Loans with Excess Cash. If the Borrower and its Restricted Subsidiaries have any Excess Cash outstanding as of the end of the 15th day of each month (or if such day is not a Business Day, the following Business Day), the Borrower shall, on or before the end of the third Business Day thereafter, prepay the Loans in an aggregate principal amount equal to the amount of such Excess Cash.

Section 5.3Method and Place of Payment.

(a)Except as otherwise specifically provided herein, all payments under this Agreement shall be made by the Borrower without set-off, counterclaim or deduction of any kind, to the Administrative Agent for the ratable account of the Lenders entitled thereto or the Letter of Credit Issuer entitled thereto, as the case may be, not later than 2:00 p.m. (New York City time), in each case, on the date when due and shall be made in immediately available funds at the Administrative Agent’s Office or at such other office as the Administrative Agent shall specify for such purpose by notice to the Borrower; it being understood that written or facsimile notice by the Borrower to the Administrative Agent to make a payment from the funds in the Borrower’s account at the Administrative Agent’s Office shall constitute the making of such payment to the extent of such funds held in such account. All repayments or prepayments of any Loans (whether of principal, interest or otherwise) hereunder and all other payments under each Credit Document shall be made in Dollars. The Administrative Agent will thereafter cause to be distributed on the same day (if payment was actually received by the Administrative Agent prior to 2:00 p.m. (New York City time) or, otherwise, on the next Business Day in the sole discretion of the Administrative Agent) like funds relating to the payment of principal or interest or fees ratably to the Lenders or the Letter of Credit Issuer, as applicable, entitled thereto.

(b)For purposes of computing interest or fees, any payments under this Agreement that are made later than 2:00 p.m. (New York City time) shall be deemed to have been made on the next succeeding Business Day in the sole discretion of the Administrative Agent. Whenever any payment to be made hereunder shall be stated to be due on a day that is not a Business Day, the due date thereof shall be extended to the next succeeding Business Day and, with respect to payments of principal, interest shall be payable during such extension at the applicable rate in effect immediately prior to such extension.

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Section 5.4Net Payments.

(a)Any and all payments made by or on behalf of the Borrower or any Guarantor under this Agreement or any other Credit Document shall be made free and clear of, and without deduction or withholding for or on account of, any Taxes; provided that if the applicable withholding agent shall be required by applicable Requirements of Law to deduct or withhold any Taxes from such payments, then (i) the applicable withholding agent shall make such deductions or withholdings as are reasonably determined by the applicable withholding agent to be required by any applicable Requirement of Law, (ii) the applicable withholding agent shall timely pay the full amount deducted or withheld to the relevant Governmental Authority within the time allowed and in accordance with applicable Requirements of Law, and (iii) to the extent withholding or deduction is required to be made on account of Indemnified Taxes or Other Taxes, the sum payable by the Borrower or such Guarantor shall be increased as necessary so that after making all required deductions and withholdings of Indemnified Taxes or Other Taxes (including deductions or withholdings of Indemnified Taxes or Other Taxes applicable to additional sums payable under this Section 5.4) the Recipient receives an amount equal to the sum it would have received had no such deductions or withholdings been made. Whenever any Indemnified Taxes or Other Taxes are payable by the Borrower or such Guarantor, as promptly as possible thereafter, the applicable withholding agent shall send to the Administrative Agent for its own account or for the account of such Recipient a certified copy of an official receipt (or other evidence acceptable to such Recipient acting reasonably) received by the applicable withholding agent showing payment thereof. After any payment of Taxes by any Credit Party or the Administrative Agent to a Governmental Authority as provided in this Section 5.4, the Borrower shall deliver to the Administrative Agent or the Administrative Agent shall deliver to the Borrower, as the case may be, a copy of a receipt issued by such Governmental Authority evidencing such payment, a copy of any return required by laws to report such payment or other evidence of such payment reasonably satisfactory to the Borrower or the Administrative Agent, as the case may be.

(b)The Borrower shall timely pay and shall indemnify and hold harmless the Administrative Agent, the Collateral Agent and each Lender with regard to any Other Taxes.

(c)The Borrower shall indemnify and hold harmless the Recipient within 30 Business Days after written demand therefor, for the full amount of any Indemnified Taxes or Other Taxes imposed on the Recipient (including Indemnified Taxes or Other Taxes imposed or asserted on or attributable to amounts payable under this Section 5.4), and any reasonable expenses arising therefrom or with respect thereto, whether or not such Indemnified Taxes or Other Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. A certificate setting forth in reasonable detail the basis and calculation of the amount of such payment or liability delivered to the Borrower by the Recipient on its own behalf or on behalf of a Lender shall be conclusive absent manifest error.

(d)Each Lender shall deliver to the Borrower and the Administrative Agent, at such time or times reasonably requested by the Borrower or the Administrative Agent,

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such properly completed and executed documentation prescribed by applicable law and such other reasonably requested information as will permit the Borrower or the Administrative Agent, as the case may be, to determine (A) whether or not any payments made hereunder or under any other Credit Document are subject to Taxes, (B) if applicable, the required rate of withholding or deduction, and (C) such Lender’s entitlement to any available exemption from, or reduction of, applicable Taxes in respect of any payments to be made to such Lender by any Credit Party pursuant to any Credit Document or otherwise to establish such Lender’s status for withholding tax purposes in the applicable jurisdiction. In addition, any Lender, if requested by the Borrower or the Administrative Agent, shall deliver such other documentation prescribed by applicable law or reasonably requested by the Borrower or the Administrative Agent as will enable the Borrower or the Administrative Agent to determine whether or not such Lender is subject to backup withholding or information reporting requirements. Notwithstanding anything to the contrary in the preceding two sentences, the completion, execution and submission of such documentation (other than such documentation set forth in paragraphs (e)(i)(A), (i)(B) and (i)(C) of this Section 5.4) shall not be required if in the Lender’s reasonable judgment such completion, execution or submission would subject such Lender to any material unreimbursed cost or expense or would materially prejudice the legal or commercial position of such Lender.

(e)Without limiting the generality of the foregoing, each Non-U.S. Lender with respect to any Loan made to the Borrower shall, to the extent it is legally entitled to do so:

(i)deliver to the Borrower and the Administrative Agent, prior to the date on which the first payment to the Non-U.S. Lender is due hereunder, two copies of (A) in the case of a Non-U.S. Lender claiming exemption from U.S. federal withholding tax under Section 871(h) or 881(c) of the Code with respect to payments of “portfolio interest”, U.S. Internal Revenue Service Form W-8BEN or Form W-8BEN-E (or any applicable successor form) together with a certificate (substantially in the form of Exhibit N-1 hereto) representing that such Non-U.S. Lender is not a “bank” for purposes of Section 881(c)(3)(A) of the Code, is not a 10% shareholder (within the meaning of Section 881(c)(3)(B) of the Code) of the Borrower, is not a “controlled foreign corporation” (within the meaning of Section 881(c)(3)(C) of the Code) and that the interest payments in question are not effectively connected with the U.S. trade or business conducted by such Lender (a “U.S. Tax Compliance Certificate”), (B) Internal Revenue Service Form W-8BEN, Form W-8BEN-E or Form W-8ECI (or any applicable successor form), in each case properly completed and duly executed by such Non-U.S. Lender claiming the benefits of an income tax treaty to which the United States is a party that completely exempts, or reduces the rate of, U.S. Federal withholding tax on payments by the Borrower under this Agreement, (C) to the extent a Non-U.S. Lender is not the beneficial owner, Internal Revenue Service Form W-8IMY, accompanied by the Internal Revenue Service Form W-8ECI, Form W-8BEN-E or Form W-8ECI (or any applicable successor form), a U.S. Tax Compliance Certificate substantially in the form of Exhibit N-2 or Exhibit N-3, and/or other certification documents from each beneficial owner, applicable; providedthatif the Non-U.S. Lender is a partnership and one or more direct or indirect partners of

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such Non-U.S. Lender are claiming the portfolio interest exemption, such non-U.S. Lender may provide a U.S. Tax Compliance Certificate substantially in the form of Exhibit N-4 on behalf of each such direct or indirect partner, or (D) any other form prescribed by applicable law as a basis for claiming exemption from or a reduction in U.S. federal withholding tax duly completed together with such supplementary documentation as may be prescribed by applicable law to permit the Borrower to determine the withholding or deduction required to be made; and

(ii)deliver to the Borrower and the Administrative Agent two further copies of any such form or certification (or any applicable successor form) on or before the date that any such form or certification expires or becomes obsolete or invalid, after the occurrence of any event requiring a change in the most recent form previously delivered by it to the Borrower, and from time to time thereafter if reasonably requested by the Borrower and the Administrative Agent;

unless in any such case any Change in Law has occurred prior to the date on which any such delivery would otherwise be required that renders any such form inapplicable or would prevent such Non-U.S. Lender from duly completing and delivering any such form with respect to it and such Non-U.S. Lender promptly so advises the Borrower and the Administrative Agent. Each Person that shall become a Participant pursuant to Section 13.6 or a Lender pursuant to Section 13.6 shall, upon the effectiveness of the related transfer, be required to provide all the forms and statements required pursuant to this Section 5.4(e); provided that in the case of a Participant such Participant shall furnish all such required forms and statements to the Lender from which the related participation shall have been purchased.

(f)If any Recipient, as applicable, determines, in its sole good faith discretion, that it had received and retained a refund of an Indemnified Tax or Other Tax for which a payment has been made by the Borrower or any Guarantor pursuant to this Agreement or any other Credit Document, which refund in the good faith judgment of such Recipient, as the case may be, is attributable to such payment made by the Borrower or any Guarantor, then the Recipient, as the case may be, shall reimburse the Borrower or such Guarantor for such amount (net of all out-of-pocket expenses of such Recipient, as the case may be, and without interest other than any interest received thereon from the relevant Governmental Authority with respect to such refund) as the Recipient, as the case may be, determines in its sole good faith discretion to be the proportion of the refund as will leave it, after such reimbursement, in no better or worse position (taking into account expenses or any taxes imposed on the refund) than it would have been in if the payment had not been required; provided that the Borrower or such Guarantor, upon the request of the Recipient, agrees to repay the amount paid over to the Borrower or such Guarantor (plus any penalties, interest or other charges imposed by the relevant Governmental Authority) to the Recipient in the event the Recipient is required to repay such refund to such Governmental Authority. In such event, such Recipient, as the case may be, shall, at the Borrower’s request, provide the Borrower with a copy of any notice of assessment or other evidence of the requirement to repay such refund received from the relevant Governmental Authority (provided that such Recipient may delete any information therein that it deems confidential). A Recipient shall use commercially reasonable efforts to claim any refund that it determines is available to it, unless it

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concludes in its sole good faith discretion that it would be adversely impacted by making such a claim. No Lender nor the Administrative Agent nor the Collateral Agent shall be obliged to make available its tax returns (or any other information relating to its taxes that it deems confidential) to any Credit Party in connection with this Section 5.4(f) or any other provision of Section 5.4.

(g)If the Borrower determines that a reasonable basis exists for contesting a Tax, each Recipient, as the case may be, shall use reasonable efforts to cooperate with the Borrower as the Borrower may reasonably request in challenging such Tax. The Borrower shall indemnify and hold each Recipient harmless against any out-of-pocket expenses incurred by such Person in connection with any request made by the Borrower pursuant to this Section 5.4(g). Nothing in this Section 5.4(g) shall obligate any Recipient to take any action that such Person, in its sole judgment, determines may result in a material detriment to such Person.

(h)Each Lender that is a United States person under Section 7701(a)(30) of the Code (each, a “U.S. Lender”) shall deliver to the Borrower and the Administrative Agent two Internal Revenue Service Forms W-9 (or substitute or successor form), properly completed and duly executed, certifying that such Lender or Agent is exempt from U.S. federal backup withholding (i) on or prior to the Closing Date (or on or prior to the date it becomes a party to this Agreement), (ii) on or before the date that such form expires or becomes obsolete or invalid, (iii) after the occurrence of a change in the Agent’s or Lender’s circumstances requiring a change in the most recent form previously delivered by it to the Borrower and the Administrative Agent, and (iv) from time to time thereafter if reasonably requested by the Borrower or the Administrative Agent.

(i)The Administrative Agent shall deliver to the Borrower, on or prior to the date on which the Administrative Agent becomes the Administrative Agent under this Agreement (or from time to time thereafter upon the reasonable request of the Borrower), either (i) an Internal Revenue Service Form W-9 (or substitute or successor form), properly completed and duly executed, certifying that the Administrative Agent is exempt from U.S. federal backup withholding, or (ii) (x) with respect to any amounts received on its own account, the applicable Internal Revenue Service Form W-8, properly completed and duly executed, and (y) with respect to any amounts received for or on account of any Lender, an Internal Revenue Service Form W-8IMY, properly completed and duly executed, certifying on Part I, Part II and Part VI thereof that it is a U.S. branch that has agreed to be treated as a U.S. person for U.S. federal tax purposes with respect to payments received by it from the Borrower in its capacity as Administrative Agent, as applicable. The Administrative Agent shall promptly notify the Borrower at any time it determines that it is no longer in a position to provide the certification described in the prior sentence.

(j)If a payment made to any Lender or any Agent under this Agreement or any other Credit Document would be subject to U.S. federal withholding tax imposed by FATCA if such Lender or such Agent were to fail to comply with the applicable reporting requirements of FATCA (including those contained in Section 1471(b) or 1472(b) of the Code, as applicable), such Lender or such Agent shall deliver to the Borrower and the

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Administrative Agent at the time or times prescribed by law and at such time or times reasonably requested by the Borrower or the Administrative Agent such documentation prescribed by applicable law (including as prescribed by Section 1471(b)(3)(C)(i) of the Code) and such additional documentation reasonably requested by the Borrower or the Administrative Agent as may be necessary for the Borrower and the Administrative Agent to comply with their obligations under FATCA, to determine that such Lender has or has not complied with such Lender’s obligations under FATCA or to determine the amount, if any, to deduct and withhold from such payment. Solely for purposes of this Section 5.4(j), “FATCA” shall include any amendments made to FATCA after the date of this Agreement.

(k)Each Lender shall severally indemnify the Administrative Agent, within 10 days after demand therefor, for (i) any Indemnified Taxes attributable to such Lender (but only to the extent that the Borrower has not already indemnified the Administrative Agent for such Indemnified Taxes and without limiting the obligation of the Borrower to do so), (ii) any Taxes attributable to such Lender’s failure to comply with the provisions of Section 13.6(c)(ii) relating to the maintenance of a Participant Register and (iii) any Excluded Taxes attributable to such Lender, in each case, that are payable or paid by the Administrative Agent in connection with this Agreement or any other Credit Document, and any reasonable expenses arising therefrom or with respect thereto, whether or not such Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. A certificate as to the amount of such payment or liability delivered to any Lender by the Administrative Agent shall be conclusive absent manifest error. Each Lender hereby authorizes the Administrative Agent to set off and apply any and all amounts at any time owing to such Lender under this Agreement or any other Credit Document or otherwise payable by the Administrative Agent to the Lender from any other source against any amount due to the Administrative Agent under this paragraph (i).

(l)For the avoidance of doubt, for purposes of this Section 5.4, the term “Lender” includes any Letter of Credit Issuer.

(m)The agreements in this Section 5.4 shall survive the termination of this Agreement and the payment of the Loans and all other amounts payable hereunder.

Section 5.5Computations of Interest and Fees.

(a)Except as provided in the next succeeding sentence, interest on LIBOR Loans and ABR Loans shall be calculated on the basis of a 360-day year for the actual days elapsed. Interest on ABR Loans in respect of which the rate of interest is calculated on the basis of the Administrative Agent’s prime rate and interest on overdue interest shall be calculated on the basis of a 365- (or 366-, as the case may be) day year for the actual days elapsed.

(b)Fees and the average daily Stated Amount of Letters of Credit shall be calculated on the basis of a 360-day year for the actual days elapsed.

Section 5.6Limit on Rate of Interest.

(a)No Payment Shall Exceed Lawful Rate. Notwithstanding any other term of this Agreement, the Borrower shall not be obligated to pay any interest or other

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amounts under or in connection with this Agreement or otherwise in respect to any of the Obligations in excess of the amount or rate permitted under or consistent with any applicable law, rule or regulation.

(b)Payment at Highest Lawful Rate. If the Borrower is not obliged to make a payment that it would otherwise be required to make, as a result of Section 5.6(a), the Borrower shall make such payment to the maximum extent permitted by or consistent with applicable laws, rules and regulations.

(c)Adjustment if Any Payment Exceeds Lawful Rate. If any provision of this Agreement or any of the other Credit Documents would obligate the Borrower or any other Credit Party to make any payment of interest or other amount payable to any Lender in an amount or calculated at a rate that would be prohibited by any applicable Requirement of Law, then notwithstanding such provision, such amount or rate shall be deemed to have been adjusted with retroactive effect to the maximum amount or rate of interest, as the case may be, as would not be so prohibited by applicable Requirements of Law, such adjustment to be effected, to the extent necessary, by reducing the amount or rate of interest required to be paid by the Borrower to the affected Lender under Section 2.8.

(d)Rebate of Excess Interest. Notwithstanding the foregoing, and after giving effect to all adjustments contemplated thereby, if any Lender shall have received from the Borrower an amount in excess of the maximum permitted by any applicable Requirement of Law, then the Borrower shall be entitled, by notice in writing to the Administrative Agent to obtain reimbursement from that Lender in an amount equal to such excess, and pending such reimbursement, such amount shall be deemed to be an amount payable by that Lender to the Borrower.

ARTICLE VI
Conditions Precedent to Initial Borrowing.

The initial Borrowing under this Agreement is subject to the satisfaction of the following conditions precedent, except as otherwise agreed or waived pursuant to Section 13.1.

Section 6.1Credit Documents. The Administrative Agent shall have received:

(a)this Agreement, executed and delivered by a duly Authorized Officer of each of the Borrower, the Administrative Agent, each Lender and each Letter of Credit Issuer;

(b)the Guarantee, executed and delivered by a duly Authorized Officer of each Person that is a Guarantor as of the Closing Date;

(c)the Security Agreement, executed and delivered by a duly Authorized Officer of the Borrower, the Collateral Agent and each Person that is a Guarantor as of the Closing Date;

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(d)the Pledge Agreement, executed and delivered by a duly Authorized Officer of the Borrower, the Collateral Agent and each other pledgor party thereto as of the Closing Date; and

(e)Mortgages, executed and delivered by a duly Authorized Officer of the applicable Credit Party, encumbering (i) Mortgaged Properties that constitute Borrowing Base Properties having a PV-9 sufficient to satisfy the Collateral Coverage Minimum and (ii) the Credit Parties’ ownership interests in the CO2 pipeline described in Exhibit I to that certain Purchase and Sale Agreement, dated as of November 24, 2014, among Anadarko E&P Onshore LLC, the Borrower and EIGF TE GP Resource Holdings I Agent Corp., as nominee for EIGF TE GP Resources Holdings I L.P., together with all exhibits and schedules thereto, as amended, restated, supplemented or otherwise modified from time to time, including by the Amendment to Purchase and Sale Agreement, dated as of February 24, 2015 (the “Renee Acquisition Agreement”) and the Monell CO2 Pipeline System described in Exhibit J to the Renee Acquisition Agreement.

Section 6.2Collateral.

(a)All documents and instruments, including Uniform Commercial Code or other applicable personal property and financing statements, reasonably requested by the Collateral Agent to be filed, registered or recorded to create the Liens intended to be created by any Security Document and perfect such Liens to the extent required by, and with the priority required by, such Security Document shall have been delivered to the Collateral Agent for filing, registration or recording and none of the Collateral shall be subject to any other pledges, security interests or mortgages, except for Liens permitted under Section 10.2.

(b)All Stock of each Restricted Subsidiary of the Borrower directly or indirectly owned by the Borrower or any Subsidiary Guarantor, in each case as of the Closing Date, shall have been pledged pursuant to the Pledge Agreement (except that such Credit Parties shall not be required to pledge any Excluded Stock) and the Collateral Agent shall have received all certificates, if any, representing such securities pledged under the Pledge Agreement, accompanied by instruments of transfer and/or undated powers endorsed in blank.

(c)Except with respect to intercompany Indebtedness, all evidences of Indebtedness for borrowed money in a principal amount in excess of $10,000,000 (individually) that is owing to the Borrower or any Subsidiary Guarantor shall be evidenced by a promissory note and shall have been pledged pursuant to the Pledge Agreement, and the Collateral Agent shall have received all such promissory notes, together with undated instruments of transfer with respect thereto endorsed in blank;

(d)All Indebtedness of the Borrower and each of its Restricted Subsidiaries that is owing to any Credit Party shall be evidenced by the Intercompany Note, which shall be executed and delivered by the Borrower and each of the Restricted Subsidiaries and shall have been pledged pursuant to the Pledge Agreement, and the Collateral Agent

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shall have received such Intercompany Note, together with undated instruments of transfer with respect thereto endorsed in blank.

(e)The Guarantee shall be in full force and effect.

Section 6.3Legal Opinions. The Administrative Agent shall have received the executed legal opinions of (a) Kirkland & Ellis LLP, counsel to the Borrower and (b) local counsel to the Borrower in the jurisdictions listed on Schedule 6.3 in form and substance reasonably satisfactory to the Administrative Agent. The Borrower, the other Credit Parties and the Administrative Agent hereby instruct such counsel to deliver such legal opinions.

Section 6.4Closing Certificates. The Administrative Agent shall have received a certificate of the Credit Parties, dated the Closing Date, substantially in the form of Exhibit L, with appropriate insertions, executed by an Authorized Officer of each Credit Party, and attaching the documents referred to in Section 6.5.

Section 6.5Authorization of Proceedings of Each Credit Party; Organizational Documents. The Administrative Agent shall have received (a) a copy of the resolutions, in form and substance reasonably satisfactory to the Administrative Agent, of the board of directors or managers of each Credit Party (or a duly authorized committee thereof) authorizing (i) the execution, delivery and performance of the Credit Documents (and any agreements relating thereto) to which it is a party and (ii) in the case of the Borrower, the extensions of credit contemplated hereunder, (b) true and complete copies of each of the organizational documents of each Person that is a Credit Party as of the Closing Date, (c) certifications as to the incumbency and specimen signature of each officer executing any Credit Document and (d) certificates of the appropriate State agencies (or other customary evidence) with respect to the existence, qualification and good standing (as applicable in each such jurisdiction) of each Credit Party in each jurisdiction where any such Credit Party is organized.

Section 6.6Fees. The Agents and the Lenders shall have received the fees in the amounts previously agreed to in writing by the Agents to be received on, or prior to, the Closing Date and all reasonable out-of-pocket expenses required to be paid on the Closing Date (including the reasonable fees, disbursements and other charges of counsel) payable by the Credit Parties for which invoices have been presented at least three Business Days prior to the Closing Date (except as otherwise reasonably agreed by the Borrower) shall have been, or will be substantially simultaneously, paid.

Section 6.7Solvency Certificate. On the Closing Date, the Administrative Agent shall have received a certificate from an Authorized Officer of the Borrower substantially in the form of Exhibit M.

Section 6.8Financial Statements. The Administrative Agent shall have received the audited consolidated balance sheet of Independence Energy LLC, the direct parent of the Borrower, as at December 31, 2020, and the related consolidated statements of operations, shareholders’ equity and cash flows for such fiscal year, all in reasonable detail and all prepared in accordance with GAAP, and reported on by independent certified public accountants of recognized national standing.

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Section 6.9Insurance Certificates. The Administrative Agent shall have received copies of insurance certificates, if applicable, evidencing the insurance required to be maintained by the Borrower and the Subsidiaries pursuant to Section 9.3, each of which shall name the Secured Parties, as additional insureds on any such liability insurance and, if casualty insurance is obtained, name the Collateral Agent as additional loss payee under any such casualty insurance, in each case in form and substance reasonably satisfactory to the Administrative Agent (provided that if such endorsement or amendment cannot be delivered by the Closing Date, the Administrative Agent may consent to such endorsement or amendment being delivered at such later date as it reasonably deems appropriate in the circumstances).

Section 6.10Transactions. The Transactions shall have been consummated substantially concurrently with the initial Borrowing under the Agreement.

Section 6.11Patriot Act; Beneficial Ownership. The Administrative Agent and Lenders shall have received, and be reasonably satisfied in form and substance with, (i) all documentation and other information about the Borrower and the Guarantors as shall have been reasonably requested in writing by the Administrative Agent and Lenders at least five days prior to the Closing Date in respect of applicable “know your customer” rules and anti-money laundering laws and regulations, including, without limitation, the Patriot Act, and (ii) to the extent the Borrower qualifies as a “legal entity customer” under the Beneficial Ownership Regulation, a Beneficial Ownership Certification.

Section 6.12Lien Searches. The Administrative Agent shall have received the results of a recent appropriate UCC search with respect to each Credit Party, and such search shall reveal no Liens on any of the assets of the Credit Parties except for Liens (a) permitted by Section 10.2 or (b) to be discharged on or prior to the Closing Date pursuant to documentation reasonably satisfactory to the Administrative Agent.

Section 6.13No Indebtedness. On the Closing Date, after giving effect to the Transactions, neither the Borrower nor any of its Restricted Subsidiaries shall have any Indebtedness for borrowed money other than the Facility, the Closing Date Unsecured Notes and other Indebtedness not prohibited hereunder, with all Indebtedness under the Existing Credit Facilities having been paid in full and the commitments thereunder having been terminated (other than with respect to contingent obligations not then due and payable and indemnities, expense reimbursements or other obligations under the Existing Credit Facilities which by their express terms survive the payment in full of Indebtedness under such Existing Credit Facilities and the termination of commitments thereunder) and all liens and security interests released. The Administrative Agent shall have received (i) evidence satisfactory to it that all Liens on the properties of the Borrower and its Restricted Subsidiaries (other than Permitted Liens) have been or shall be substantially concurrently released or terminated, subject only to the filing of applicable terminations, releases or assignments and (ii) duly executed recordable terminations, releases or assignments in forms reasonably acceptable to the Administrative Agent with respect thereto.

Section 6.14Title. The Administrative Agent shall have received title information reasonably satisfactory to the Administrative Agent setting forth the status of title to at least 70% of the PV-9 of the Borrowing Base Properties.

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Section 6.15No Default; Representations and Warranties. The Administrative Agent shall have received a certificate of an Authorized Officer of the Borrower with respect to the matters set forth in Section 7.1 as of the Closing Date.

The Administrative Agent shall notify the Borrower and the Lenders of the Closing Date, and such notice shall be conclusive and binding.

ARTICLE VII
Conditions Precedent to All Credit Events

The agreement of each Lender to make any Loan requested to be made by it on any date (excluding Loans required to be made by the Lenders in respect of Unpaid Drawings pursuant to Section 3.3 and Section 3.4), and the obligation of the Letter of Credit Issuer to issue Letters of Credit on any date, is subject to the satisfaction of the following conditions precedent:

Section 7.1No Default; Representations and Warranties. At the time of each Credit Event and also after giving effect thereto (a) no Default or Event of Default shall have occurred and be continuing and (b) all representations and warranties made by any Credit Party contained herein or in the other Credit Documents shall be true and correct in all material respects or in all respects if already qualified as to materiality (after giving effect to any qualification therein) with the same effect as though such representations and warranties had been made on and as of the date of such Credit Event (except where such representations and warranties expressly relate to an earlier date, in which case such representations and warranties shall have been true and correct in all material respects (or in all respects if already qualified as to materiality (after giving effect to any qualification therein)) as of such earlier date).

Section 7.2Excess Cash.After giving pro forma effect to each Borrowing, including the use of proceeds thereof, the Borrower and its Restricted Subsidiaries shall not have any Excess Cash. The delivery of any Notice of Borrowing by the Borrower shall constitute a certification that the condition set forth in this Section 7.2 shall be satisfied after giving pro forma effect to the requested Borrowing, including the use of proceeds thereof.

Section 7.3Notice of Borrowing.

(a)Prior to the making of each Loan (other than any Loan made pursuant to Section 3.4(a)), the Administrative Agent shall have received a Notice of Borrowing (whether in writing or by telephone) meeting the requirements of Section 2.3(a).

(b)Prior to the issuance of each Letter of Credit (other than the Existing Letters of Credit), the Administrative Agent and the Letter of Credit Issuer shall have received a Letter of Credit Request meeting the requirements of Section 3.2(a).

(c)The acceptance of the benefits of each Credit Event shall constitute a representation and warranty by each Credit Party to each of the Lenders that all the applicable conditions specified in Section 7 above have been satisfied as of that time.

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ARTICLE VIII
Representations, Warranties and Agreements

In order to induce the Lenders to enter into this Agreement, to make the Loans and issue or participate in Letters of Credit as provided for herein, the Borrower makes, on the Closing Date and on each other date as required or otherwise set forth in this Agreement, the following representations and warranties to, and agreements with, the Lenders, all of which shall survive the execution and delivery of this Agreement and the making of the Loans and the issuance of the Letters of Credit:

Section 8.1Corporate Status. Each of the Borrower and each Restricted Subsidiary (a) is a duly organized and validly existing corporation or other entity in good standing under the laws of the jurisdiction of its organization and has the corporate or other organizational power and authority to own its property and assets and to transact the business in which it is currently engaged and (b) has duly qualified and is authorized to do business and is in good standing (if applicable) in all jurisdictions where it is required to be so qualified, except where the failure to be so qualified or in good standing would not, individually or in the aggregate, reasonably be expected to result in a Material Adverse Effect.

Section 8.2Corporate Power and Authority; Enforceability. Each Credit Party has the corporate or other organizational power and authority to execute, deliver and carry out the terms and provisions of the Credit Documents to which it is a party and has taken all necessary corporate or other organizational action to authorize the execution, delivery and performance of the Credit Documents to which it is a party. Each Credit Party has duly executed and delivered each Credit Document to which it is a party and each such Credit Document constitutes the legal, valid and binding obligation of such Credit Party enforceable in accordance with its terms, subject to the effects of bankruptcy, insolvency, fraudulent conveyance, reorganization and other similar laws relating to or affecting creditors’ rights generally and general principles of equity (whether considered in a proceeding in equity or law).

Section 8.3No Violation. None of the execution, delivery or performance by any Credit Party of the Credit Documents to which it is a party will (a) contravene any Requirement of Law, except to the extent such contravention would not reasonably be expected to result in a Material Adverse Effect, (b) result in any breach of any of the terms, covenants, conditions or provisions of, or constitute a default under, or result in the creation or imposition of (or the obligation to create or impose) any Lien upon any of the property or assets of such Credit Party or any of the Restricted Subsidiaries (other than Liens created under the Credit Documents and the Liens permitted by Section 10.2) pursuant to the terms of any indenture, loan agreement, lease agreement, mortgage, deed of trust, agreement or other instrument to which such Credit Party or any of the Restricted Subsidiaries is a party or by which it or any of its property or assets is bound (any such term, covenant, condition or provision, a “Contractual Requirement”) except to the extent such breach, default or Lien that would not reasonably be expected to result in a Material Adverse Effect or (c) violate any provision of the certificate of incorporation, by-laws or other organizational documents of such Credit Party or any of the Restricted Subsidiaries.

Section 8.4Litigation. Except as set forth on Schedule 8.4, there are no actions, suits or proceedings pending or, to the knowledge of the Borrower, threatened in writing, at law, in

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equity, in arbitration or before any Governmental Authority by or against the Borrower or any of its Restricted Subsidiaries that would, either individually or in the aggregate, reasonably be expected to result in a Material Adverse Effect.

Section 8.5Margin Regulations. Neither the making of any Loan hereunder nor the use of the proceeds thereof will violate the provisions of Regulation T, Regulation U or Regulation X of the Board.

Section 8.6Governmental Approvals. The execution, delivery and performance of each Credit Document do not require any consent or approval of, registration or filing with, or other action by, any Governmental Authority, except for (a) such as have been obtained or made and are in full force and effect, (b) filings and recordings in respect of the Liens created pursuant to the Security Documents and (c) such consents, approvals, registrations, filings or actions the failure of which to obtain or make would not reasonably be expected to have a Material Adverse Effect.

Section 8.7Investment Company Act. No Credit Party is an “investment company” within the meaning of the Investment Company Act of 1940, as amended.

Section 8.8True and Complete Disclosure.

(a)None of the written factual information and written data (taken as a whole) heretofore or contemporaneously furnished by or on behalf of the Borrower, any of the Subsidiaries or any of their respective authorized representatives to the Administrative Agent, the Lead Arrangers and/or any Lender on or before the Closing Date (including all such information and data contained in the Credit Documents) for purposes of or in connection with this Agreement or any transaction contemplated herein contained any untrue statement of any material fact or omitted to state any material fact necessary to make such information and data (taken as a whole) not materially misleading at such time (as modified or supplemented by other information so furnished prior to such time) in light of the circumstances under which such information or data was furnished; it being understood and agreed that for purposes of this Section 8.8(a), such factual information and data shall not include pro forma financial and reserve information, projections or estimates (including financial and reserve estimates, forecasts and other forward-looking information) and information of a general economic or general industry nature (collectively, “Pro Forma Projections”).

(b)The projections (including financial and reserve estimates, forecasts and other forward-looking information) contained in the information and data referred to in Section 8.8(a) were based on good faith estimates and assumptions believed by the Borrower to be reasonable at the time made; it being recognized by the Agents and the Lenders that such projections are as to future events and are not to be viewed as facts, the projections are subject to significant uncertainties and contingencies, many of which are beyond the control of the Borrower and the Subsidiaries, that no assurance can be given that any particular projections will be realized and that actual results during the period or periods covered by any such projections may differ from the projected results and such differences may be material.

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Section 8.9No MAE. Since the Closing Date, there has been no event or circumstance, either individually or in the aggregate, that has had or would reasonably be expected to have a Material Adverse Effect.

Section 8.10Tax Matters. Except where the failure of which would not, either individually or in the aggregate, reasonably be expected to have a Material Adverse Effect, each of the Borrower and the Subsidiaries has filed all federal income tax returns and all other tax returns, domestic and foreign, required to be filed by it and has paid all taxes payable by it that have become due, other than those (i) not yet delinquent or (ii) being contested in good faith by appropriate proceedings.

Section 8.11Compliance with ERISA.

(a)Except as set forth on Schedule 8.11 or as would not, either individually or in the aggregate, reasonably be expected to result in a Material Adverse Effect, each Plan is in compliance with ERISA, the Code and any applicable Requirement of Law; no Reportable Event has occurred (or is reasonably likely to occur) with respect to any Plan; no Plan is insolvent (or is reasonably likely to be insolvent), and no written notice of any such insolvency has been given to the Borrower or any ERISA Affiliate; no Plan (other than a Multiemployer Plan) has an accumulated or waived funding deficiency (or is reasonably likely to have such a deficiency); on and after the effectiveness of the Pension Act, each Plan that is subject to Title IV of ERISA has satisfied the minimum funding standards (within the meaning of Section 412 of the Code or Section 302 of ERISA) applicable to such Plan, and there has been no determination that any such Plan is, or is expected to be, in “at risk” status (within the meaning of Section 4010(d)(2) of ERISA); none of the Borrower or any ERISA Affiliate has incurred (or is reasonably likely to incur) any liability to or on account of a Plan pursuant to Section 409, 502(i), 502(l), 515, 4062, 4063, 4064, 4069, 4201 or 4204 of ERISA or Section 4971 or 4975 of the Code or has been notified in writing that it will incur any liability under any of the foregoing Sections with respect to any Plan; no proceedings have been instituted (or are reasonably likely to be instituted) to terminate or to reorganize any Plan or to appoint a trustee to administer any Plan, and no written notice of any such proceedings has been given to the Borrower or any ERISA Affiliate; and no lien imposed under the Code or ERISA on the assets of the Borrower or any ERISA Affiliate exists (or is reasonably likely to exist) nor has the Borrower or any ERISA Affiliate been notified in writing that such a lien will be imposed on the assets of the Borrower or any ERISA Affiliate on account of any Plan. No Plan (other than a Multiemployer Plan) has an Unfunded Current Liability that would, individually or when taken together with any other liabilities referenced in this Section 8.11(a), be reasonably likely to have a Material Adverse Effect. With respect to Plans that are Multiemployer Plans, the representations and warranties in this Section 8.11(a), other than any made with respect to (i) liability under Section 4201 or 4204 of ERISA or (ii) liability for termination of such Plans under ERISA, are made to the best knowledge of the Borrower.

(b)All Foreign Plans are in compliance with, and have been established, administered and operated in accordance with, the terms of such Foreign Plans and applicable law, except for any failure to so comply, establish, administer or operate the

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Foreign Plans as would not reasonably be expected to have a Material Adverse Effect. All contributions or other payments which are due with respect to each Foreign Plan have been made in full and there are no funding deficiencies thereunder, except to the extent any such events would not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect.

Section 8.12Subsidiaries. Schedule 8.12 lists each Subsidiary of the Borrower (and the direct and indirect ownership interest of the Borrower therein), in each case existing on the Closing Date (after giving effect to the Transactions). Each Guarantor, Material Subsidiary and Unrestricted Subsidiary as of the Closing Date (after giving effect to the Transactions) has been so designated on Schedule 8.12.

Section 8.13Intellectual Property. The Borrower and each of the Restricted Subsidiaries have obtained all intellectual property, free from burdensome restrictions, that to the knowledge of the Borrower is reasonably necessary for the operation of their respective businesses as currently conducted and as proposed to be conducted, except where the failure to obtain any such rights would not reasonably be expected to have a Material Adverse Effect.

Section 8.14Environmental Laws.

(a)With respect to Oil and Gas Properties of the Borrower and each of the Subsidiaries other than Non-Cost Bearing Interests and except as would not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect: (i) the Borrower and each of the Subsidiaries and all Oil and Gas Properties are in compliance with all applicable Environmental Laws; (ii) neither the Borrower nor any Subsidiary has received written notice of any Environmental Claim against the Borrower or any Subsidiary; and (iii) neither the Borrower nor any Subsidiary is conducting any investigation, removal, remedial or other corrective action pursuant to any Environmental Law related to Hazardous Materials contamination at any location.

(b)Except as would not reasonably be expected to have a Material Adverse Effect, neither the Borrower nor any of the Subsidiaries has, to their knowledge, treated, stored, transported, released or disposed or arranged for disposal or transport for disposal of Hazardous Materials at, on, under or from any currently or formerly owned or leased Oil and Gas Properties or facility in each case in a manner that would reasonably be expected to give rise to liability of the Borrower or any Subsidiary under Environmental Law.

Section 8.15Properties.

(a)Each Credit Party has good and defensible title to the Borrowing Base Properties evaluated in the most recently delivered Reserve Report (other than those (i) disposed of since the date of such Reserve Report, (ii)  leases that have expired in accordance with their terms and (iii) with title defects disclosed in writing to the Administrative Agent), and good title to all its material personal properties, in each case, free and clear of all Liens other than Liens permitted by Section 10.2, except in each case where the failure to have such title would not reasonably be expected to have,

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individually or in the aggregate, a Material Adverse Effect. After giving full effect to the Liens permitted by Section 10.2, the Borrower or the Restricted Subsidiary specified as the owner owns the working interests and net revenue interests attributable to the Hydrocarbon Interests as reflected in the most recently delivered Reserve Report, and the ownership of such properties shall not in any material respect obligate the Borrower or such Restricted Subsidiary to bear the costs and expenses relating to the maintenance, development and operations of each such property in an amount in excess of the working interest of each property set forth in the most recently delivered Reserve Report that is not offset by a corresponding proportionate increase in the Borrower’s or such Restricted Subsidiary’s net revenue interest in such property other than as disclosed to the Administrative Agent in writing.

(b)All leases and agreements necessary for the conduct of the business of the Borrower and the Restricted Subsidiaries are valid and subsisting, in full force and effect, except to the extent that any such failure to be valid or subsisting would not reasonably be expected to have a Material Adverse Effect.

(c)The rights and properties presently owned, leased or licensed by the Credit Parties including all easements and rights of way, include all rights and properties necessary to permit the Credit Parties to conduct their respective businesses as currently conducted, except to the extent any failure to have any such rights or properties would not reasonably be expected to have a Material Adverse Effect.

(d)All of the properties of the Borrower and the Restricted Subsidiaries that are reasonably necessary for the operation of their businesses are in good working condition and are maintained in accordance with prudent business standards, except to the extent any failure to satisfy the foregoing would reasonably be expected to have a Material Adverse Effect.

Section 8.16Solvency. On the Closing Date (after giving effect to the consummation of the Transactions (including the execution and delivery of this Agreement, the making of the Loans on the Closing Date and the use of proceeds of such Loans on the Closing Date)), the Borrower on a consolidated basis with its Restricted Subsidiaries is Solvent.

Section 8.17Gas Imbalances, Prepayments. On the Closing Date, except as set forth on Schedule 8.17, on a net basis, there are no gas imbalances, take or pay or other prepayments exceeding 2.5% of the Credit Parties’ average monthly production of Hydrocarbon volumes, with respect to the Credit Parties’ Oil and Gas Properties that would require any Credit Party to deliver Hydrocarbons either generally or produced from their Oil and Gas Properties (excluding Non-Cost Bearing Interests owned by the Borrower or any of its Subsidiaries) at some future time without then or thereafter receiving full payment therefor.

Section 8.18Marketing of Production. On the Closing Date, except as set forth on Schedule 8.18, no material agreements exist (which are not cancelable on 60 days’ notice or less without penalty or detriment) for the sale of production of the Credit Parties’ Hydrocarbons (excluding production attributable to Borrowing Base Properties in which the Borrower’s or any of its Subsidiaries’ ownership interest therein is derived solely from Non-Cost Bearing Interests

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owned by the Borrower or any of its Subsidiaries) at a fixed non-index price (including calls on, or other rights to purchase, production, whether or not the same are currently being exercised) that (i) represent in respect of such agreements 2.5% or more of the Borrower’s average monthly production of Hydrocarbon volumes and (ii) have a maturity or expiry date of longer than six months from the Closing Date.

Section 8.19Hedge Agreements. Schedule 8.19 sets forth, as of the Closing Date, a true and complete list of all material commodity Hedge Agreements of each Credit Party, the material terms thereof relating to the type, term, effective date, termination date and notional amounts or volumes, the net mark to market value thereof, all credit support agreements relating thereto (including any margin required or supplied) and the counterparty to each such agreement.

Section 8.20Patriot Act. On the Closing Date, each Credit Party is in compliance in all material respects with the material provisions of the Patriot Act, and the Borrower has provided to the Administrative Agent all information related to the Credit Parties (including but not limited to names, addresses and tax identification numbers (if applicable)) reasonably requested in writing by the Administrative Agent and mutually agreed to be required by the Patriot Act to be obtained by the Administrative Agent or any Lender.

Section 8.21Sanctions Laws and Regulations. None of the Credit Parties nor, to their knowledge, any of their respective directors or officers is a Designated Person. The Borrower has implemented and maintains in effect policies and procedures reasonably designed to promote compliance by the Borrower, its Subsidiaries and their respective directors, officers, employees and agents with Anti-Corruption Laws and Sanctions Laws and Regulations applicable to the Borrower and its Subsidiaries, and the Borrower, its Subsidiaries and their respective officers and directors and, to the knowledge of the Borrower, the employees and agents of the Borrower and its Subsidiaries are in compliance with Anti-Corruption Laws and Sanctions Laws and Regulations applicable to the Borrower and its Subsidiaries in all material respects. No Borrowing or Letter of Credit, use of proceeds or other transaction contemplated by this Agreement will violate any Anti-Corruption Law or applicable Sanctions Laws and Regulations.

Section 8.22Affected Financial Institution. No Credit Party is an Affected Financial Institution.

Section 8.23Beneficial Ownership Certification. As of the Closing Date, to the knowledge of the Borrower, the information included in the Beneficial Ownership Certification is true and correct in all material respects.

ARTICLE IX
Affirmative Covenants

The Borrower hereby covenants and agrees that on the Closing Date and thereafter, until Payment in Full:

Section 9.1Information Covenants. The Borrower will furnish to the Administrative Agent (which shall promptly make such information available to the Lenders in accordance with its customary practice):

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(a)Annual Financial Statements. On or before the date that is 120 days after the end of each such fiscal year), beginning with the financial statements for the fiscal year ending December 31, 2021, the audited consolidated balance sheets of the Borrower and the Subsidiaries and, if different, the Borrower and the Restricted Subsidiaries, in each case as at the end of such fiscal year, and the related consolidated statements of operations, shareholders’ equity and cash flows for such fiscal year (or, in lieu of such audited financial statements of the Borrower and the Restricted Subsidiaries, a detailed reconciliation, reflecting such financial information for the Borrower and the Restricted Subsidiaries, on the one hand, and the Borrower and the Subsidiaries, on the other hand), all prepared in accordance with GAAP, and, except with respect to such reconciliation, reported on by independent certified public accountants of recognized national standing whose opinion shall not be materially qualified with a “going concern” or like qualification or exception (other than an emphasis of matter paragraph or a qualification or exception with respect to, or resulting from, (i) impending maturities of any Indebtedness occurring prior to the expiry of the first full four fiscal quarter period following such audit or (ii) a breach or anticipated breach of any financial covenants, including the Financial Performance Covenants). Notwithstanding the foregoing, the obligations in this Section 9.1(a) may be satisfied with respect to financial information of the Borrower and its consolidated Subsidiaries by furnishing (A) the applicable financial statements of any direct or indirect parent of the Borrower or (B) the Borrower’s (or any direct or indirect parent thereof), as applicable, Form 10-K filed with the SEC; provided that, with respect to each of clauses (A) and (B), (i) to the extent such information relates to a parent of the Borrower, such information is accompanied by consolidating information that explains in reasonable detail the differences between the information relating to such parent and its consolidated Subsidiaries, on the one hand, and the information relating to the Borrower and its consolidated Subsidiaries and the Borrower and its consolidated Restricted Subsidiaries on a standalone basis, on the other hand and (ii) to the extent such information is in lieu of information required to be provided under the first sentence of this Section 9.1(a), such materials are accompanied by an opinion of an independent registered public accounting firm of recognized national standing, which opinion shall not be materially qualified with a “going concern” or like qualification or exception (other than an emphasis of matter paragraph or a qualification or exception with respect to, or resulting from, (i) impending maturities of any Indebtedness occurring prior to the expiry of the first full four fiscal quarter period following such audit or (ii) a breach or anticipated breach of any financial covenants, including the Financial Performance Covenants).

(b)Quarterly Financial Statements. With respect to each of the first three quarterly accounting periods in each fiscal year of the Borrower, on or before the date that is 60 days after the end of each such quarterly accounting period, beginning with the financial statements for the fiscal quarter ending March 31, 2021), the consolidated balance sheets of the Borrower and the Subsidiaries and, if different, the Borrower and the Restricted Subsidiaries, in each case as at the end of such quarterly period, and the related consolidated statements of operations for such quarterly accounting period and for the elapsed portion of the fiscal year ended with the last day of such quarterly period, and the related consolidated statements of shareholders’ equity and cash flows for the elapsed portion of the fiscal year ended with the last day of such quarterly period, and setting forth, commencing with the fiscal quarter ending March 31, 2022, comparative

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consolidated figures for the related periods in the prior fiscal year or, in the case of such consolidated balance sheet, for the last day of the prior fiscal year (or, in lieu of such unaudited financial statements of the Borrower and the Restricted Subsidiaries, a detailed reconciliation reflecting such financial information for the Borrower and the Restricted Subsidiaries, on the one hand, and the Borrower and the Subsidiaries, on the other hand), all of which shall be certified by an Authorized Officer of the Borrower as fairly presenting in all material respects the financial condition, results of operations, shareholders’ equity and cash flows, of the Borrower and its consolidated Subsidiaries in accordance with GAAP, subject to changes resulting from audit and normal year-end audit adjustments and the absence of footnotes. Notwithstanding the foregoing, the obligations in this Section 9.1(b) may be satisfied with respect to financial information of the Borrower and its consolidated Subsidiaries by furnishing (A) the applicable financial statements of any direct or indirect parent of the Borrower or (B) the Borrower’s (or any direct or indirect parent of the Borrower), as applicable, Form 10 Q filed with the SEC; providedthat, with respect to each of clauses (A) and (B), to the extent such information relates to a parent of the Borrower, such information is accompanied by consolidating information that explains in reasonable detail the differences between the information relating to such parent and its consolidated Subsidiaries, on the one hand, and the information relating to the Borrower and its consolidated Subsidiaries and the Borrower and its consolidated Restricted Subsidiaries on a standalone basis, on the other hand.

(c)Officer’s Certificates - Compliance. Not later than five Business Days after the delivery of the financial statements provided for in Section 9.1(a) and (b), commencing with the fiscal quarter ending September 30, 2021, a certificate of an Authorized Officer of the Borrower substantially in the form of Exhibit B hereto (i) certifying that no Default or Event of Default exists or, if any Default or Event of Default does exist, specifying the nature and extent thereof, (ii) setting forth the calculations required to establish whether the Borrower and its Restricted Subsidiaries were in compliance with the Financial Performance Covenants as at the end of such fiscal year or period, as the case may be, (iii) attaching reasonably detailed calculations of Free Cash Flow for the four fiscal quarter period most recently ended, (iv) setting forth a specification of any change in the identity of the Restricted Subsidiaries, Material Subsidiaries, Guarantors and Unrestricted Subsidiaries as at the end of such fiscal year or period, as the case may be, from the Restricted Subsidiaries, Material Subsidiaries, Guarantors and Unrestricted Subsidiaries, respectively, provided to the Lenders on the Closing Date or in the most recently delivered Compliance Certificate, (v) the amount of any Pro Forma Adjustment to the extent not set forth in a previously delivered Compliance Certificate, or any change in the amount of a Pro Forma Adjustment set forth in a previously delivered Compliance Certificate and, in either case, in reasonable detail, the calculations and basis therefor and (vi) in each Compliance Certificate provided in respect of the annual financial statements delivered under Section 9.1(a), setting forth in reasonable detail the Applicable Equity Amount as at the end of the fiscal year for which such financial statements are applicable.

(d)Notice of Default; Litigation. Promptly after an Authorized Officer of the Borrower or any of the Restricted Subsidiaries obtains actual knowledge thereof, notice of (i) the occurrence of any event that constitutes a Default or Event of Default, which notice shall specify the nature thereof and what action the Borrower proposes to take with

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respect thereto and (ii) any litigation or governmental proceeding pending against the Borrower or any of the Subsidiaries that would reasonably be expected to be determined adversely and, if so determined, to result in a Material Adverse Effect.

(e)Environmental Matters. After obtaining actual knowledge of any one or more of the following environmental matters, unless such environmental matters would not, individually, or when aggregated with all other such matters, be reasonably expected to result in a Material Adverse Effect, notice of:

(i)any filed or threatened Environmental Claim against any Credit Party;

(ii)any condition or occurrence on any Oil and Gas Properties that (A) would reasonably be expected to result in noncompliance by any Credit Party with any applicable Environmental Law or (B) would reasonably be expected to result in an Environmental Claim against any Credit Party or any Oil and Gas Properties; and

(iii)the conduct of any investigation, or any removal, remedial or other corrective action in response to the actual or alleged presence, release or threatened release of any Hazardous Material on, at, under or from any Oil and Gas Properties.

All such notices shall describe in reasonable detail the nature of the Environmental Claim, investigation, removal or remedial action.

(f)Other Information. With reasonable promptness, but subject to the limitations set forth in the last sentences of Section 9.2(a) and Section 13.16, such other information (financial or otherwise) as the Administrative Agent on its own behalf or on behalf of any Lender (acting through the Administrative Agent) may reasonably request in writing from time to time.

(g)Projections. Within 120 days after the end of each fiscal year (beginning with the fiscal year ending on or about December 31, 2021) of the Borrower, a reasonably detailed consolidated budget for the following fiscal year as customarily prepared by management of the Borrower for its internal use (including a projected consolidated balance sheet of the Borrower and its Restricted Subsidiaries as of the end of the following fiscal year, the related consolidated statements of projected capital expenditures, projected cash flow and projected income and a summary of the material underlying assumptions applicable thereto) (collectively, the “Projections”), which Projections shall in each case be accompanied by a certificate of an Authorized Officer stating that such Projections have been prepared in good faith on the basis of the assumptions stated therein, which assumptions were believed to be reasonable at the time of preparation of such Projections, it being recognized by the Agents and the Lenders that such Projections are as to future events and are not to be viewed as facts, the Projections are subject to significant uncertainties and contingencies, many of which are beyond the control of the Borrower and the Subsidiaries, that no assurance can be given that any

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particular Projections will be realized and that actual results during the period or periods covered by any such Projections may differ from the projected results and such differences may be material.

Documents required to be delivered pursuant to Section 9.1(a) through Section 9.1(g) may be delivered electronically and if so delivered, shall be deemed to have been delivered on the date (i) on which the Borrower posts such documents, or provides a link thereto on the Borrower’s website on the Internet at the website address listed on Schedule 13.2, (ii) on which such documents are posted on the Borrower’s behalf on IntraLinks, Debtdomain or another relevant website, if any, to which the Lenders and the Administrative Agent have access (whether a commercial, third-party website or whether sponsored by the Administrative Agent) or (iii) on which such documents are transmitted by electronic mail to the Administrative Agent; provided that: the Borrower shall notify (which may be by facsimile or electronic mail) the Administrative Agent of the posting of any such documents and provide to the Administrative Agent by electronic mail electronic versions (i.e., soft copies) of such documents. Each Lender shall be solely responsible for timely accessing posted documents and maintaining its copies of such documents.

Section 9.2Books, Records and Inspections.

(a)The Borrower will, and will cause each Restricted Subsidiary to, permit designated representatives of the Administrative Agent or the Majority Lenders (as accompanied by the Administrative Agent) to visit and inspect any of the properties of the Borrower or such Restricted Subsidiary, and to examine the books and records of the Borrower and any such Restricted Subsidiary and discuss the affairs, finances and accounts of the Borrower and of any such Restricted Subsidiary with, and be advised as to the same by, its and their officers and independent accountants, upon reasonable advance notice to the Borrower, all at such reasonable times and intervals during normal business hours and to such reasonable extent as the Administrative Agent or the Majority Lenders may desire (and subject, in the case of any such meetings or advice from such independent accountants, to such accountants’ customary policies and procedures); provided that, excluding any such visits and inspections during the continuation of an Event of Default (i) only the Administrative Agent on behalf of the Majority Lenders may exercise rights of the Administrative Agent and the Lenders under this Section 9.2, and (ii) the Administrative Agent shall not exercise such rights more often than two times during any calendar year and only one such visit shall be at the Borrower’s expense; provided, further, that when an Event of Default exists, the Administrative Agent (or any of its representatives or independent contractors) or any representative of the Majority Lenders may do any of the foregoing at any time during normal business hours and upon reasonable advance notice. The Administrative Agent and the Majority Lenders shall give the Borrower the opportunity to participate in any discussions with the Borrower’s independent public accountants. Notwithstanding anything to the contrary in Section 9.1(f) or this Section 9.2, neither the Borrower nor any Restricted Subsidiary will be required to disclose, permit the inspection, examination or making copies or abstracts of, or discussion of, any document, information or other matter (i) that constitutes non-financial trade secrets or non-financial proprietary information, (ii) in respect of which disclosure to the Administrative Agent or any Lender (or their respective representatives or contractors) is prohibited by any Requirement of Law or any binding agreement or (iii) that is subject to attorney-client or similar privilege or constitutes attorney work product.

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(b)The Borrower will, and will cause each of the Restricted Subsidiaries to maintain proper books of record and account that permit the preparation of financial statements in conformity with GAAP.

Section 9.3Maintenance of Insurance. The Borrower will, and will cause each Restricted Subsidiary to, at all times maintain in full force and effect, pursuant to self-insurance arrangements or with insurance companies that the Borrower believes (in the good faith judgment of the management of the Borrower) are financially sound and responsible at the time the relevant coverage is placed or renewed, insurance in at least such amounts (after giving effect to any self-insurance which the Borrower believes (in the good faith judgment of management of the Borrower) is reasonable and prudent in light of the size and nature of its business) and against at least such risks (and with such risk retentions) as the Borrower believes (in the good faith judgment of management of the Borrower) is reasonable and prudent in light of the size and nature of its business; and will furnish to the Administrative Agent, upon written request from the Administrative Agent, information presented in reasonable detail as to the insurance so carried. The Secured Parties shall be, to the extent applicable, the additional insureds on any such liability insurance as their interests may appear and, if casualty insurance is obtained, the Collateral Agent shall be the additional loss payee under any such casualty insurance; provided that, so long as no Event of Default has occurred and is then continuing, the Secured Parties will provide any proceeds of such casualty insurance to the Borrower to the extent that the Borrower undertakes to apply such proceeds to the reconstruction, replacement or repair of the property insured thereby.

Section 9.4Payment of Taxes. The Borrower will pay and discharge, and will cause each of the Subsidiaries to pay and discharge, all taxes, assessments and governmental charges or levies imposed upon it or upon its income or profits, or upon any properties belonging to it, prior to the date on which material penalties attach thereto, and all lawful material claims in respect of any Taxes imposed, assessed or levied that, if unpaid, would reasonably be expected to become a material Lien upon any properties of the Borrower or any of the Restricted Subsidiaries; provided that neither the Borrower nor any of the Subsidiaries shall be required to pay or discharge any such tax, assessment, charge, levy or claim that is being contested in good faith and by proper proceedings if it has maintained adequate reserves (in the good faith judgment of management of the Borrower) with respect thereto to the extent required by, and in accordance with, GAAP or the failure to pay or discharge would not reasonably be expected to result in a Material Adverse Effect.

Section 9.5Existence; Consolidated Corporate Franchises. The Borrower will do, and will cause each Restricted Subsidiary to do, or cause to be done, all things necessary to preserve and keep in full force and effect its existence, corporate rights and authority, except to the extent that the failure to do so would not reasonably be expected to have a Material Adverse Effect; provided, however, that the Borrower and its Restricted Subsidiaries may consummate any transaction permitted under Section 10.3, Section 10.4 or Section 10.5.

Section 9.6Compliance with Statutes, Regulations, Etc. The Borrower will, and will cause each Restricted Subsidiary to, comply with all Requirements of Law applicable to it or its property except where the failure to do so would not reasonably be expected to have a Material Adverse Effect.

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Section 9.7ERISA.

(a)Promptly after the Borrower knows of the occurrence of any of the following events that, individually or in the aggregate (including in the aggregate such events previously disclosed or exempt from disclosure hereunder, to the extent the liability therefor remains outstanding), would be reasonably likely to have a Material Adverse Effect, the Borrower will deliver to the Administrative Agent a certificate of an Authorized Officer or any other senior officer of the Borrower setting forth details as to such occurrence and the action, if any, that the Borrower is required or proposes to take, together with any notices (required or otherwise) given to or filed with or by the Borrower, the PBGC, a Plan participant (other than notices relating to an individual participant’s benefits) or the Plan administrator with respect thereto: that a Reportable Event has occurred; that an accumulated funding deficiency has been incurred or an application is to be made to the Secretary of the Treasury for a waiver or modification of the minimum funding standard (including any required installment payments) or an extension of any amortization period under Section 412 of the Code with respect to a Plan; that a Plan having an Unfunded Current Liability has been or is to be terminated, partitioned or declared insolvent under Title IV of ERISA (including the giving of written notice thereof); that a Plan has an Unfunded Current Liability that has or will result in a lien on assets of a Credit Party under ERISA or the Code; that a proceeding has been instituted against the Borrower pursuant to Section 515 of ERISA to collect a delinquent contribution to a Plan; that the PBGC has notified the Borrower of its intention to appoint a trustee to administer any Plan; that the Borrower has failed to make a required installment or other payment pursuant to Section 412 of the Code with respect to a Plan; or that the Borrower has incurred or will incur (or has been notified in writing that it will incur) any liability (including any contingent or secondary liability) to or on account of a Plan pursuant to Section 409, 502(i), 502(l), 515, 4062, 4063, 4064, 4069, 4201 or 4204 of ERISA or Section 4971 or 4975 of the Code.

(b)Promptly following any request therefor, on and after the effectiveness of the Pension Act, the Borrower will deliver to the Administrative Agent copies of (i) any documents described in Section 101(k) of ERISA that the Borrower and any of its Subsidiaries may request with respect to any Multiemployer Plan and (ii) any notices described in Section 101(l) of ERISA that the Borrower and any of its Subsidiaries may request with respect to any Multiemployer Plan; provided that if the Borrower or any of its Subsidiaries has not requested such documents or notices from the administrator or sponsor of the applicable Multiemployer Plan, the Borrower or the applicable Subsidiary(ies) shall promptly make a request for such documents or notices from such administrator or sponsor and shall provide copies of such documents and notices promptly after receipt thereof.

Section 9.8Maintenance of Properties. The Borrower will, and will cause each of the Restricted Subsidiaries to, except in each case, where the failure to so comply would not reasonably be expected to result in a Material Adverse Effect (it being understood that this Section 9.8 shall not restrict any transaction otherwise permitted under Section 10.3, Section 10.4 or Section 10.5):

(a)operate its Oil and Gas Properties and other material properties or make commercially reasonable efforts to cause such Oil and Gas Properties and other material

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properties to be operated in compliance with all applicable Contractual Requirements and all applicable Requirements of Law, including applicable proration requirements and Environmental Laws;

(b)keep and maintain all property material to the conduct of its business in good working order and condition, ordinary wear and tear excepted, and preserve, maintain and keep in good repair, working order and efficiency (ordinary wear and tear excepted) all of its material Oil and Gas Properties and other material Properties, including all equipment, machinery and facilities; and

(c)to the extent a Credit Party is not the operator of any property, the Borrower shall use reasonable efforts to cause the operator to comply with this Section 9.8 in accordance with the customary practices of the industry.

Section 9.9Transactions with Affiliates. The Borrower will conduct, and cause each of the Restricted Subsidiaries to conduct, all transactions involving aggregate payments or consideration in excess of $10,000,000 with any of its Affiliates (other than the Borrower and the Restricted Subsidiaries or any entity that becomes a Restricted Subsidiary as a result of such transaction) on terms that are substantially as favorable to the Borrower or such Restricted Subsidiary as it would obtain at the time in a comparable arm’s-length transaction with a Person that is not an Affiliate, as determined by the board of directors or managers of the Borrower or such Restricted Subsidiary in good faith; provided that the foregoing restrictions shall not apply to:

(a)the consummation of the Transactions, including the payment of Transaction Expenses,

(b)the issuance of Stock or Stock Equivalents of the Borrower (or any direct or indirect parent thereof) to, or any capital contribution by, the Sponsor or any officer, director, employee or consultant of the Borrower (or any direct or indirect parent thereof) or any of its Subsidiaries,

(c)equity issuances, repurchases, retirements, redemptions or other acquisitions or retirements of Stock or Stock Equivalents by the Borrower (or any direct or indirect parent thereof) permitted under Section 10.6,

(d)the payment of indemnities and reasonable expenses incurred by the Sponsor and their Affiliates in connection with management or monitoring or the provision of other services rendered to the Borrower (or any direct or indirect parent entity thereof) or any of its Subsidiaries,

(e)loans, advances and other transactions between or among the Borrower, any Subsidiary or any joint venture (regardless of the form of legal entity) in which the Borrower or any Subsidiary has invested (and which Subsidiary or joint venture would not be an Affiliate of the Borrower or such Subsidiary, but for the Borrower’s or such Subsidiary’s ownership of Stock or Stock Equivalents in such joint venture or such Subsidiary) to the extent permitted under Section 10,

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(f)employment and severance arrangements and health, disability and similar insurance or benefit plans between the Borrower (or any direct or indirect parent thereof) and the Subsidiaries and their respective directors, officers, employees or consultants (including management and employee benefit plans or agreements, subscription agreements or similar agreements pertaining to the repurchase of Stock or Stock Equivalents pursuant to put/call rights or similar rights with current or former employees, officers, directors or consultants and equity option or incentive plans and other compensation arrangements) in the ordinary course of business or as otherwise approved by the board of directors or managers of the Borrower (or any direct or indirect parent thereof),

(g)the payment of customary fees and reasonable out-of-pocket costs to, and indemnities provided on behalf of, directors, managers, consultants, advisors, officers and employees of the Borrower (or any direct or indirect parent thereof), the Sponsor and the Subsidiaries in the ordinary course of business to the extent attributable to the ownership or operation of, or in connection with any services provided to, the Borrower and the Subsidiaries,

(h)transactions pursuant to agreements in existence on the Closing Date and set forth on Schedule 9.9, or any amendment thereto to the extent such an amendment is not adverse, taken as a whole, to the Lenders in any material respect (as determined by the Borrower in good faith),

(i)Dividends, redemptions, repurchases and other actions permitted under Section 10.6 and Section 10.7,

(j)customary payments (including reimbursement of fees and expenses) by the Borrower and any Subsidiaries to the Sponsor made for any financial advisory, financing, underwriting or placement services or in respect of other investment banking activities (including in connection with acquisitions or divestitures, whether or not consummated), which payments are approved by the majority of the members of the board of directors or managers or a majority of the disinterested members of the board of directors or managers of the Borrower (or any direct or indirect parent thereof), in good faith,

(k)any issuance of Stock or Stock Equivalents or other payments, awards or grants in cash, securities, Stock, Stock Equivalents or otherwise pursuant to, or the funding of, employment arrangements, equity options and equity ownership plans approved by the board of directors or board of managers of the Borrower (or any direct or indirect parent thereof),

(l)transactions with joint ventures for the purchase or sale of goods, equipment and services entered into in the ordinary course of business and in a manner consistent with prudent business practice followed by companies in the industry of the Borrower and its Subsidiaries,

(m)payments by the Borrower (or any direct or indirect parent thereof) and the Subsidiaries pursuant to tax sharing agreements among the Borrower (and any such

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parent) and the Subsidiaries on customary terms; provided that payments by Borrower and the Subsidiaries under any such tax sharing agreements shall not exceed the excess (if any) of the amount they would have paid on a standalone basis over the amount they actually pay directly to Governmental Authorities,

(n)sales or conveyances of net profits interests for cash at Fair Market Value allowed under Section 10.4;

(o)customary agreements and arrangements with oil and gas royalty trusts and master limited partnership agreements that comply with the affiliate transaction provisions of such royalty trust or master limited partnership agreement;

(p)any transaction in respect of which the Borrower delivers to the Administrative Agent a letter addressed to the board of directors or managers of the Borrower from an accounting, appraisal or investment banking firm, in each case of nationally-recognized standing that is in the good faith determination of the Borrower qualified to render such letter, which letter states that such transaction is (i) fair, from a financial point of view, to the Borrower or such Restricted Subsidiary or (ii) on terms, taken as a whole, that are no less favorable to the Borrower or such Restricted Subsidiary, as applicable, than would be obtained in a comparable arm’s length transaction with a person that is not an Affiliate;

(q)[reserved];

(r)transactions between the Borrower or any of its Restricted Subsidiaries and any Person that is an Affiliate solely because a director of such Person is also a director of the Borrower or any direct or indirect parent of the Borrower; provided, however, that such director abstains from voting as a director of the Borrower or such direct or indirect parent, as the case may be, on any matter involving such other Person;

(s)any lease entered into between the Borrower or any Restricted Subsidiary, as lessee and any Affiliate of the Borrower, as lessor, which is approved by a majority of the disinterested members of the board of directors or managers of the Borrower in good faith or, any lease entered into between the Borrower or any Restricted Subsidiary, as lessee, and any Affiliate of the Borrower, as lessor, in the ordinary course of business;

(t)transactions for the purpose of (a) reorganizing to facilitate any initial public offering of securities of the Borrower or any direct or indirect parent of the Borrower, (b) forming a holding company, (c) reincorporating the Borrower or (d) consummating the IPOCo Transactions;

(u)Permitted Intercompany Activities; and

(v)the formation and maintenance of any consolidated group or subgroup for tax, accounting or cash pooling or management purposes in the ordinary course of business.

Section 9.10Environmental Matters. The Borrower will at its sole expense: (i) comply, and make reasonable efforts to cause its Properties and operations and each Restricted

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Subsidiary and each Restricted Subsidiary’s Properties and operations to comply, with all applicable Environmental Laws, to the extent the failure to comply or cause such compliance could reasonably be expected to have a Material Adverse Effect; (ii) not Release or threaten to Release, and cause each Restricted Subsidiary not to Release or threaten to Release, any Hazardous Material on, under, about or from any of the Borrower’s or any Restricted Subsidiary’s Properties or any other property offsite such Property to the extent caused by the Borrower’s or any Restricted Subsidiary’s operations except in compliance with applicable Environmental Laws, in each case to the extent such Release or threatened Release or failure to cause could reasonably be expected to have a Material Adverse Effect; (iii) obtain or file, and cause each Restricted Subsidiary to obtain or file, all permits, if any, required under applicable Environmental Laws to be obtained or filed in connection with the operation or use of the Borrower’s or the Restricted Subsidiaries’ Properties, to the extent such failure to obtain or file or cause could reasonably be expected to have a Material Adverse Effect; and (iv) commence and prosecute to completion, and cause each Restricted Subsidiary to commence and prosecute to completion, any corrective actions to the extent any corrective actions are required under applicable Environmental Laws because of or in connection with the actual or suspected past, present or future Release or threatened Release of any Hazardous Material on, under, about or from any of the Borrower’s or the Restricted Subsidiaries’ Properties, to the extent failure to commence, prosecute or cause could reasonably be expected to have a Material Adverse Effect.

Section 9.11Additional Guarantors, Grantors and Collateral.

(a)Subject to any applicable limitations set forth in the Guarantee or the Security Documents, the Borrower will cause (i) any direct or indirect Domestic Subsidiary (other than any Excluded Subsidiary) formed or otherwise purchased or acquired after the Closing Date (including pursuant to a Permitted Acquisition) and (ii) any Subsidiary of the Borrower that ceases to be an Excluded Subsidiary, in each case within 45 days from the date of such formation, acquisition or cessation, as applicable (or such longer period as the Administrative Agent may agree in its reasonable discretion) to execute (A) a supplement to each of the Guarantee, the Security Agreement and the Pledge Agreement, substantially in the form of Annex A, Exhibit 1 or Annex A, as applicable, to the respective agreement in order to become a Guarantor under the Guarantee, a grantor under the Security Agreement, and a pledgor under the Pledge Agreement and (B) a joinder to the Intercompany Note, substantially in the form of Annex I thereto.

(b)Subject to any applicable limitations set forth in the Pledge Agreement, the Borrower will pledge, and, if applicable, will cause each other Subsidiary Guarantor (or Person required to become a Subsidiary Guarantor pursuant to Section 9.11(a)) to pledge, to the Collateral Agent, for the benefit of the Secured Parties, (i) all of the Stock (other than any Excluded Stock) of each Subsidiary owned by the Borrower or any Subsidiary Guarantor (or Person required to become a Guarantor pursuant to Section 9.11(a)), in each case, formed or otherwise purchased or acquired after the Closing Date, pursuant to a supplement to the Pledge Agreement substantially in the form of Annex A thereto and, (ii) except with respect to intercompany Indebtedness, all evidences of Indebtedness for borrowed money in a principal amount in excess of $10,000,000 (individually) that is owing to the Borrower or any Guarantor (or Person required to

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become a Guarantor pursuant to Section 9.11(a)), in each case pursuant to a supplement to the Pledge Agreement substantially in the form of Annex A thereto.

(c)In connection with each redetermination (but not any adjustment) of the Borrowing Base, the Borrower shall review the applicable Reserve Report, if any, and the list of current Mortgaged Properties (as described in Section 9.14(c)), to ascertain whether the PV-9 of the Mortgaged Properties (calculated at the time of redetermination) meets the Collateral Coverage Minimum after giving effect to exploration and production activities, acquisitions, Dispositions and production. In the event that the PV-9 of the Mortgaged Properties (calculated at the time of redetermination) does not meet the Collateral Coverage Minimum, then the Borrower shall, and shall cause its Credit Parties to, grant, within 75 days of delivery of the certificate required under Section 9.14(c) (or such longer period as the Administrative Agent may agree in its reasonable discretion), to the Collateral Agent as security for the Obligations a first-priority Lien interest (subject to Liens permitted by Section 10.2) on additional Oil and Gas Properties not already subject to a Lien of the Security Documents such that, after giving effect thereto, the PV-9 of the Mortgaged Properties (calculated at the time of redetermination) meets the Collateral Coverage Minimum. All such Liens will be created and perfected by and in accordance with the provisions of the Security Documents, including, if applicable, any additional Mortgages. In order to comply with the foregoing, if any Restricted Subsidiary places a Lien on its property and such Subsidiary is not a Guarantor, then it shall become a Guarantor and comply with the provisions of Section 9.11(a), Section 9.11(b) and Section 9.11(c).

(d)The Borrower agrees that all Indebtedness of the Borrower and each of its Restricted Subsidiaries that is owing to any Credit Party (or a Person required to become a Guarantor pursuant to Section 9.11(a)) shall be evidenced by the Intercompany Note, which promissory note shall be required to be pledged to the Collateral Agent, for the benefit of the Secured Parties, pursuant to the Pledge Agreement.

(e)Without limitation of clause (a), (b) or (c) above, substantially simultaneously with the delivery of any mortgage or deed of trust on any Oil and Gas Property for the benefit of any other secured party and securing Indebtedness that is subject to a Customary Intercreditor Agreement, the Borrower shall, or shall cause the relevant Credit Party to, grant to the Collateral Agent as security for the Obligations a Lien on such Oil and Gas Property. All such Liens will be created and perfected by and in accordance with the provisions of the Security Documents, including, if applicable, any additional Mortgages. In order to comply with the foregoing, if any Restricted Subsidiary places a Lien on its property and such Subsidiary is not a Guarantor, then it shall become a Guarantor and comply with the provisions of Sections 9.11(a) and (b).

Section 9.12Use of Proceeds.

(a)The Borrower will use the proceeds of the Loans to fund a portion of the Closing Date Refinancing, to consummate the Transactions, to conduct its Oil and Business, for the acquisition, development and exploration of Oil and Gas Properties and for working capital and other general corporate purposes of the Borrower and its Restricted Subsidiaries (including Permitted Acquisitions).

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(b)The Borrower will use Letters of Credit for general corporate purposes and to support deposits required under purchase agreements pursuant to which the Borrower or its Restricted Subsidiaries may acquire assets relevant to the Oil and Gas Business and other assets.

Section 9.13Further Assurances.

(a)Subject to the applicable limitations set forth in the Security Documents, the Borrower will, and will cause each other Credit Party to, execute any and all further documents, financing statements, agreements and instruments, and take all such further actions (including the filing and recording of financing statements, fixture, filings, assignments of as-extracted collateral, mortgages, deeds of trust and other documents) that may be required under any applicable Requirements of Law, or that the Collateral Agent or the Majority Lenders may reasonably request, in order to grant, preserve, protect and perfect the validity and priority of the security interests created or intended to be created by the applicable Security Documents, all at the expense of the Borrower and the Restricted Subsidiaries.

(b)Notwithstanding anything herein to the contrary, if the Collateral Agent and the Borrower reasonably determine in writing that the cost of creating or perfecting any Lien on any property is excessive in relation to the benefits afforded to the Lenders thereby, then such property may be excluded from the Collateral for all purposes of the Credit Documents.

(c)In addition, notwithstanding anything to the contrary in this Agreement or any other Credit Document, (i) the Administrative Agent may grant extensions of time for or waivers of the requirements of the creation or perfection of security interests in or the obtaining of title opinions or other title information, legal opinions, appraisals, insurance and surveys with respect to particular assets (including extensions beyond the Closing Date for the perfection of security interests in the assets of the Credit Parties on such date) where it reasonably determines, in consultation with the Borrower, that perfection or obtaining of such items is not required by law or cannot be accomplished without undue effort or expense by the time or times at which it would otherwise be required by this Agreement or the other Credit Documents, (ii) Liens required to be granted from time to time pursuant to this Agreement and the Security Documents shall be subject to exceptions and limitations set forth in the Security Documents and, to the extent appropriate in any applicable jurisdiction, as otherwise agreed between the Administrative Agent and the Borrower and (iii) the Administrative Agent and the Borrower may make such modifications to the Security Documents, and execute and/or consent to such easements, covenants, rights of way or similar instruments (and Administrative Agent may agree to subordinate the lien of any mortgage to any such easement, covenant, right of way or similar instrument or record or may agree to recognize any tenant pursuant to an agreement in a form and substance reasonably acceptable to the Administrative Agent), as are reasonable or necessary and otherwise permitted by this Agreement and the other Credit Documents.

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Section 9.14Reserve Reports.

(a)On or before March 1st and September 1st of each year, commencing March 1, 2022, the Borrower shall furnish to the Administrative Agent a Reserve Report evaluating, as of the immediately preceding December 31st and June 30th, the Proved Reserves of the Borrower and the Credit Parties located within the geographic boundaries of the United States of America (or the Outer Continental Shelf adjacent to the United States of America) that the Borrower desires to have included in any calculation of the Borrowing Base. Each Reserve Report as of December 31st shall be prepared, at the sole election of the Borrower (i) by one or more Approved Petroleum Engineers or (ii) by or under the supervision of the chief engineer of the Borrower or its Subsidiaries; provided that any such Reserve Report prepared in accordance with this clause (ii) shall be audited by one or more Approved Petroleum Engineers. Any other Reserve Report prepared in connection with a redetermination may be prepared, at the election of the Borrower (A) by one or more Approved Petroleum Engineers or (B) by or under the supervision of the chief engineer of the Borrower and its Subsidiaries. In connection with the November 2021 Redetermination, the Borrower shall furnish to the Administrative Agent a Reserve Report on or before October 1, 2021, evaluating, as of July 30, 2021, the Proved Reserves of the Borrower and the Credit Parties, which Reserve Report shall be prepared by or under the supervision of the chief engineer or qualified agent of the Borrower who shall certify such Reserve Report to be true and accurate in all material respects and to have been prepared in accordance with the procedures used in the Initial Reserve Report.

(b)In the event of an Interim Redetermination, the Borrower shall furnish to the Administrative Agent a Reserve Report prepared, at the election of the Borrower, (i) by one or more Approved Petroleum Engineers or (ii) by or under the supervision of the chief engineer of the Borrower or by the Borrower or its Subsidiaries. For any Interim Redetermination pursuant to Section 2.14(b), the Borrower shall provide such Reserve Report with an “as of” date as required by the Administrative Agent, as soon as possible, but in any event no later than 45 days, in the case of any Interim Redetermination requested by the Borrower or 60 days, in the case of any Interim Redetermination requested by the Administrative Agent or the Lenders, following the receipt of such request, unless otherwise agreed by the Administrative Agent.

(c)With the delivery of each Reserve Report, the Borrower shall provide to the Administrative Agent a Reserve Report Certificate from an Authorized Officer of the Borrower certifying that in all material respects:

(i)in the case of Reserve Reports prepared by or under the supervision of the chief engineer of the Borrower or by the Borrower and its Subsidiaries (other than the December 31 Reserve Reports), such Reserve Report has been prepared, except as otherwise specified therein, in accordance with the procedures used in the immediately preceding December 31 Reserve Report or the Initial Reserve Report, if no December 31 Reserve Report has been delivered;

(ii)the information contained in the Reserve Report and any other information delivered in connection therewith is true and correct in all material

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respects; provided, that, with respect to any projections included in such information, such projections were based on good faith estimates and assumptions believed by the Borrower or any Approved Petroleum Engineer, as applicable, to be reasonable at the time made; it being recognized by the Agents and the Lenders that such projections are as to future events and are not to be viewed as facts, the projections are subject to significant uncertainties and contingencies, many of which are beyond the control of the Borrower and the Subsidiaries, that no assurance can be given that any particular projections will be realized and that actual results during the period or periods covered by any such projections may differ from the projected results and such differences may be material;

(iii)except as set forth in an exhibit to such certificate, the Borrower or another Credit Party has good and defensible title to the Borrowing Base Properties evaluated in such Reserve Report (other than those (w) to be acquired in connection with an acquisition, (x) Disposed of in compliance with Section 10.4 since the date of such Reserve Report, (y) leases that have expired in accordance with their terms and (z) with title defects disclosed in writing to the Administrative Agent) and such Borrowing Base Properties are free (or will be at the time of the acquisition thereof) of all Liens except for Liens permitted by Section 10.2;

(iv)except as set forth on an exhibit to such certificate or previously disclosed to the Administrative Agent in writing, as of the date of such Reserve Report, on a net basis there are no gas imbalances, take or pay or other prepayments in excess of the volume specified in Section 8.17 with respect to the Credit Parties’ Oil and Gas Properties evaluated in such Reserve Report that would require the Borrower or any other Credit Party to deliver Hydrocarbons either generally or produced from such Oil and Gas Properties at some future time without then or thereafter receiving full payment therefor;

(v)none of the Borrowing Base Properties have been Disposed since the date of the immediately preceding Reserve Report to the date of the Reserve Report being delivered, except (A) those Borrowing Base Properties listed on such certificate as having been Disposed, (B) as previously disclosed to the Administrative Agent in writing or (C) Borrowing Base Properties Disposed in the ordinary course in connection with operating agreements, farmouts, joint exploration and development agreements, communitization agreements or orders, pooling agreements or orders and other agreements or orders customary in the oil and gas industry whose aggregate PV-9 (calculated at the time of Disposition) does not exceed 5% of the then-effective Borrowing Base;

(vi)attached as a schedule thereto, a list of, as of the last Business Day of the most recently ended fiscal year or period, as applicable, all material marketing agreements entered into subsequent to the later of the Closing Date and the most recently delivered Reserve Report for the sale of production of the Credit Parties’ Hydrocarbons at a fixed non- index price (including calls on, or other parties rights to purchase, production, whether or not the same are currently being exercised) that (1) represent in respect of such agreements 2.5% or more of the

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Credit Parties’ average monthly production of Hydrocarbon volumes and (2) have a maturity date or expiry date of longer than six months from the last day of such fiscal year or period, as applicable, and are not cancellable on 60 days’ notice or less without penalty or detriment;

(vii)attached as a schedule thereto, a true and complete list of all material commodity Hedge Agreements of the Borrower and each Credit Party, the material terms thereof (including the type, term, effective date, termination date and notional amounts or volumes), the net mark-to-market value thereof (as of the last Business Day of such fiscal year or period, as applicable and for which a mark to-market value is reasonably available), any new credit support agreements relating thereto not listed on Schedule 8.19 or on any previously delivered certificate delivered pursuant to this Section 9.14(c), any margin required or supplied under any credit support document and the counterparty to each such agreement;

(viii)attached thereto is a schedule setting forth, for each calendar month during the six or twelve month period, as applicable, ending as of the date of such Reserve Report, the volume of production of Hydrocarbons and sales attributable to production of Hydrocarbons (and the prices at which such sales were made and the revenues derived from such sales) for each such calendar month from the Borrowing Base Properties, and setting forth the related ad valorem, severance and production taxes and lease operating expenses attributable thereto and incurred for each such calendar month; and

(ix)all Borrowing Base Properties evaluated by such Reserve Report that are Collateral and demonstrating the extent to which the PV-9 of the Mortgaged Properties (calculated as of the date of such Reserve Report) meets the Collateral Coverage Minimum.

Section 9.15Title Information. On or before the date of delivery to the Administrative Agent of each Reserve Report required by Section 9.14(a), the Borrower will deliver, or will cause the applicable Restricted Subsidiaries to deliver, if requested by the Administrative Agent, title information consistent with usual and customary standards for the geographic regions in which the Borrowing Base Properties are located, taking into account the size, scope and number of leases and wells of the Borrower and its Restricted Subsidiaries (it being understood that standards reasonably acceptable to the Administrative Agent shall be deemed to meet such standard), as is required to demonstrate, to the reasonable satisfaction of the Administrative Agent, satisfactory title on at least 85% of the PV-9 value of the Borrowing Base Properties.

Section 9.16Sanctions Laws and Regulations. The Borrower shall, and shall ensure that its Subsidiaries shall, use the proceeds of the Loans or any Letter of Credit only in a manner that is permitted under this Agreement and in no event: (i) to fund any activities or business of or with any Designated Person, or in any country or territory, that at the time of such funding is the subject of any sanctions under any Sanctions Laws and Regulations, in violation of applicable Sanctions Laws and Regulations or (ii) in any other manner that would result in a violation of any Sanctions Laws and Regulations by any party to this Agreement.

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Section 9.17Change in Business. The Borrower and its Restricted Subsidiaries, taken as a whole, will not fundamentally and substantively alter the character of their business, taken as a whole, from the Oil and Gas Business or the business conducted by them on the Closing Date and other business reasonably related, complementary, incidental, synergistic or ancillary thereto (including Industry Investments) or reasonable extensions to any of the foregoing (the “Permitted Business”); provided that, for the avoidance of doubt, the Borrower and its Restricted Subsidiaries shall be permitted to make investments and expenditures otherwise permitted by this Agreement with respect to the development of technology or infrastructure relating to renewable energy generation, energy storage, advanced fuels, carbon mitigation, hydrogen technologies and fuel cells, in each case that are consistent with the Company’s environmental, social and governance strategy, in each case so long as the making of such investments and expenditures will not fundamentally and substantively alter the character of their business, taken as a whole, from the Permitted Business.

Section 9.18Control Agreements. In connection with any deposit account or securities account opened, established, held, acquired or otherwise maintained by the Borrower or any Guarantor (in each case, other than any Excluded Account for so long as it is an Excluded Account), the Borrower will, and will cause each Guarantor to, enter into and deliver to the Collateral Agent an Account Control Agreement no later than the date that any funds or assets are deposited therein or, with respect to any deposit account or securities account that ceases to be an Excluded Account, no later than the date of such cessation (or, in each case, such later date as the Collateral Agent may agree in its sole discretion); provided that the Borrower shall be deemed to have satisfied the requirements of this Section 9.18: (i) with respect to any deposit account or securities account established, held or maintained on the Closing Date, so long as the Borrower or applicable Guarantor delivers an Account Control Agreement to the Collateral Agent no later than 90 days after the Closing Date (or such later date as the Administrative Agent may agree in its sole discretion); and (ii) with respect to any deposit account or securities account that is acquired by the Borrower or any Guarantor as a result of a Permitted Acquisition or other transaction not prohibited by this Agreement, so long as, no later than 45 days after the date of such Permitted Acquisition (or such later date as the Administrative Agent may agree in its sole discretion), the Borrower or such Guarantor (x) causes such account to be subject to an Account Control Agreement or (y) closes such account and transfers any funds or assets therein to an account that otherwise meets the requirements of this Section 9.18.

Section 9.19Post-Closing Title Covenant. On or before the date that is 60 days after the Closing Date (or such later date as the Administrative Agent may agree in its sole discretion), the Borrower will deliver, or will cause the applicable Restricted Subsidiaries to deliver, title information consistent with usual and customary standards for the geographic regions in which the Borrowing Base Properties are located, taking into account the size, scope and number of leases and wells of the Borrower and its Restricted Subsidiaries (it being understood that standards reasonably acceptable to the Administrative Agent shall be deemed to meet such standard), as is required to demonstrate, to the reasonable satisfaction of the Administrative Agent, satisfactory title on at least 85% of the PV-9 value of the Borrowing Base Properties.

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ARTICLE X
Negative Covenants.

The Borrower hereby covenants and agrees that on the Closing Date and thereafter, until Payment in Full:

Section 10.1Limitation on Indebtedness. The Borrower will not, and will not permit any of the Restricted Subsidiaries to, create, incur, assume or suffer to exist any Indebtedness other than the following:

(a)Indebtedness (including Guarantee Obligations thereunder) in respect of the Closing Date Unsecured Notes in an aggregate principal amount not to exceed $500,000,000 and any Permitted Refinancing Indebtedness in respect thereof;

(b)Indebtedness arising under the Credit Documents (including pursuant to Section 2.16 and Section 2.17);

(c)Indebtedness of (i) the Borrower or any Guarantor owing to the Borrower or any Subsidiary; provided that any such Indebtedness owing by a Credit Party to a Subsidiary that is not a Guarantor shall (x) be evidenced by the Intercompany Note or (y) otherwise be outstanding on the Closing Date so long as such Indebtedness is evidenced by an intercompany note substantially in the form of Exhibit O or otherwise subject to subordination terms substantially identical to the subordination terms set forth in Exhibit O, in each case, to the extent permitted by Requirements of Law and not giving rise to material adverse tax consequences, (ii) any Subsidiary that is not a Guarantor owing to any other Subsidiary that is not a Guarantor and (iii) to the extent permitted by Section 10.5, any Subsidiary that is not a Guarantor owing to the Borrower or any Guarantor;

(d)Indebtedness in respect of any bankers’ acceptance, bank guarantees, letters of credit, warehouse receipt or similar facilities entered into in the ordinary course of business or consistent with past practice or industry practice (including in respect of workers compensation claims, health, disability or other employee benefits or property, casualty or liability insurance or self-insurance or other Indebtedness with respect to reimbursement-type obligations regarding workers compensation claims);

(e)subject to compliance with Section 10.5, Guarantee Obligations incurred by (i) Restricted Subsidiaries in respect of Indebtedness of the Borrower or other Restricted Subsidiaries that is permitted to be incurred under this Agreement (except that a Restricted Subsidiary that is not a Credit Party may not, by virtue of this Section 10.1(e) guarantee Indebtedness that such Restricted Subsidiary could not otherwise incur under this Section 10.1) and (ii) the Borrower in respect of Indebtedness of Restricted Subsidiaries that is permitted to be incurred under this Agreement; provided that (A) if the Indebtedness being guaranteed under this Section 10.1(e) is subordinated to the Obligations, such Guarantee Obligations shall be subordinated to the Guarantee of the Obligations on terms at least as favorable to the Lenders as those contained in the subordination of such Indebtedness and (B) no guarantee by any Restricted Subsidiary of any Permitted Additional Debt or Permitted Junior Lien Debt shall be permitted unless

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such Restricted Subsidiary shall have also provided a guarantee of the Obligations substantially on the terms set forth in the Guarantee;

(f)Guarantee Obligations (i) incurred in the ordinary course of business in respect of obligations of (or to) suppliers, customers, franchisees, lessors, licensees or sublicensees or (ii) otherwise constituting Investments permitted by Section 10.5(d), Section 10.5(g), Section 10.5(h), Section 10.5(i), Section 10.5(s), Section 10.5(t) and Section 10.5(u);

(g)(i) Indebtedness (including Indebtedness arising under Capital Leases) incurred within 365 days of the acquisition, construction, lease, repair, replacement, expansion or improvement of fixed or capital assets (excluding Hydrocarbon Interests) to finance the acquisition, construction, lease, repair, replacement expansion, or improvement of such fixed or capital assets; (ii) Indebtedness arising under Capital Leases, other than (A) Capital Leases in effect on the Closing Date and (B) Capital Leases entered into pursuant to subclause (i) above (provided that, in the case of each of the foregoing subclauses (i) and (ii), the Borrower shall be in compliance on a Pro Forma Basis after giving effect to the incurrence of such Indebtedness with the Financial Performance Covenants, as such covenants are recomputed as at the last day of the most recently ended Test Period as if such incurrence had occurred on the first day of such Test Period); and (iii) any Permitted Refinancing Indebtedness issued or incurred to Refinance any such Indebtedness;

(h)Indebtedness outstanding on the date hereof listed on Schedule 10.1 and any Permitted Refinancing Indebtedness issued or incurred to Refinance such Indebtedness;

(i)Indebtedness in respect of Hedge Agreements, subject to the limitations set forth in Section 10.10;

(j)Indebtedness (or any Permitted Refinancing Indebtedness thereof) of a Person or Indebtedness attaching to the assets of a Person that, in either case, becomes a Restricted Subsidiary (or is a Restricted Subsidiary that survives a merger with such Person or any of its Subsidiaries) or Indebtedness attaching to the assets that are acquired by the Borrower or any Restricted Subsidiary, in each case after the Closing Date as the result of a Permitted Acquisition; provided that:

(i)such Indebtedness existed at the time such Person became a Restricted Subsidiary or at the time such assets were acquired and, in each case, was not created in anticipation thereof,

(ii)such Indebtedness is not guaranteed in any respect by the Borrower or any Restricted Subsidiary (other than any such Person that so becomes a Restricted Subsidiary or is the survivor of a merger with such Person or any of its Subsidiaries),

(iii)(1) the Stock of such Person is pledged to the Collateral Agent to the extent required under Section 9.11(b) and (2) such Person executes a supplement to each of the Guarantee, the Security Agreement and the Pledge

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Agreement and a joinder to the Intercompany Note, in each case to the extent required under Section 9.11; provided that the assets covered by such pledges and security interests may, to the extent permitted by Section 10.2, equally and ratably secure such Indebtedness assumed with the Secured Parties subject to intercreditor arrangements in form and substance reasonably satisfactory to the Administrative Agent; provided, further, that the requirements of this Section 10.1(j)(iii) shall not apply to any Indebtedness of the type that could have been incurred under Section 10.1(g), and

(iv)after giving effect to the assumption of any such Indebtedness, to such acquisition and to any related Pro Forma Adjustment, the Borrower shall be in compliance on a Pro Forma Basis with the Financial Performance Covenants, as such covenants are recomputed as at the last day of the most recently ended Test Period as if such assumption and acquisition had occurred on the first day of such Test Period;

(k)[Reserved];

(l)Indebtedness consisting of secured financings by a Foreign Subsidiary in which no Credit Party’s assets are used to secure such Indebtedness;

(m)Indebtedness in respect of performance bonds, bid bonds, appeal bonds, surety bonds and completion guarantees and similar obligations and obligations in respect of letters of credit, bank guaranties or instruments related thereto, in each case provided in the ordinary course of business or consistent with past practice or industry practice, including those incurred to secure health, safety and environmental obligations in the ordinary course of business or consistent with past practice or industry practice;

(n)(i) other additional Indebtedness (of a type not otherwise described in this Section 10.1); provided that the aggregate principal amount of Indebtedness outstanding at any time pursuant to this Section 10.1(n) shall not at the time of incurrence thereof and after giving Pro Forma Effect thereto and the use of proceeds thereof, exceed the greater of (x) $120,000,000 and (y) 3.0% of Total Assets (measured as of the date of incurrence of such Indebtedness); and (ii) any Permitted Refinancing Indebtedness issued or incurred to Refinance such Indebtedness;

(o)Indebtedness in respect of Permitted Additional Debt, Permitted Junior Lien Debt and, in each case, any Permitted Refinancing Indebtedness issued or incurred to Refinance such Indebtedness; provided that (i) after giving effect to the incurrence or issuance thereof and the use of proceeds therefrom, the Borrower shall be in compliance on a Pro Forma Basis with the Financial Performance Covenants and (ii) the Borrowing Base shall be adjusted as set forth in Section 2.14(e);

(p)Cash Management Obligations, Cash Management Services and other Indebtedness in respect of cash and treasury management, netting services, automatic clearing house arrangements, employees’ credit or purchase cards, overdraft protections and similar arrangements;

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(q)Indebtedness incurred in the ordinary course of business in respect of obligations of the Borrower or any Restricted Subsidiary to pay the deferred purchase price of goods or services or progress payments in connection with such goods and services;

(r)Indebtedness arising from agreements of the Borrower or any Restricted Subsidiary providing for indemnification, adjustment of purchase price or similar obligations (including earn-outs), in each case assumed or entered into in connection with Permitted Acquisitions, other Investments and the Disposition of any business, assets or Stock permitted hereunder;

(s)Indebtedness of the Borrower or any Restricted Subsidiary consisting of (i) obligations to pay insurance premiums or (ii) obligations contained in firm transportation or supply agreements or other take or pay contracts, in each case arising in the ordinary course of business or consistent with past practice or industry practice;

(t)Indebtedness representing deferred compensation to employees, consultants or independent contractors of the Borrower (or, to the extent such work is done for the Borrower or its Subsidiaries, any direct or indirect parent thereof) and the Restricted Subsidiaries incurred in the ordinary course of business or consistent with past practice or industry practice;

(u)Indebtedness consisting of promissory notes issued by the Borrower or any Guarantor to current or former officers, managers, consultants, directors and employees (or their respective spouses, former spouses, successors, executors, administrators, heirs, legatees or distributees) to finance the purchase or redemption of Stock or Stock Equivalents of the Borrower (or any direct or indirect parent thereof) permitted by Section 10.6;

(v)Indebtedness consisting of obligations of the Borrower and the Restricted Subsidiaries under deferred compensation or other similar arrangements incurred by such Person in connection with the Transactions, Permitted Acquisitions or any other Investment permitted hereunder;

(w)[reserved];

(x)Indebtedness consisting of the undischarged balance of any Production Payment, subject to adjustment of the Borrowing Base as set forth in Section 2.14(g) to the extent required under Section 10.4(b);

(y)Indebtedness of the Borrower or any Restricted Subsidiary to any joint venture (regardless of the form of legal entity) that is not a Subsidiary arising in the ordinary course of business in connection with the Cash Management Services (including with respect to intercompany self-insurance arrangements) of the Borrower and its Restricted Subsidiaries;

(z)Indebtedness (i) incurred on behalf of, or Guarantee Obligations in respect of the Indebtedness of, joint ventures (regardless of the form of legal entity) that are not Subsidiaries and (ii) of Subsidiaries which are not Guarantors, in a principal amount,

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when aggregated with the outstanding principal amount of all Indebtedness incurred pursuant to this clause (z), not to exceed, at the time of incurrence thereof, the greater of (x) $120,000,000 and (y) 3.0% of Total Assets (measured as of the date of incurrence of such Indebtedness);

(aa)Indebtedness supported by a Letter of Credit, in a principal amount not to exceed the face amount of such Letter of Credit; and

(bb)all premiums (if any), interest (including post-petition interest), fees, expenses, charges, and additional or contingent interest on obligations described in clauses (a) through (bb) above.

    For purposes of determining compliance with Section 10.1, in the event that an item of Indebtedness (or any portion thereof) at any time, whether at the time of incurrence or issuance or upon the application of all or a portion of the proceeds thereof or subsequently, meets the criteria of more than one of the categories of permitted Indebtedness described in Section 10.1(a) through (bb) above, the Borrower, in its sole discretion, will classify and may subsequently reclassify such item of Indebtedness (or any portion thereof) in any one or more of the types of Indebtedness described in Section 10.1(a) through (bb) and will only be required to include the amount and type of such Indebtedness in such of the above clauses as determined by the Borrower at such time. The Borrower will be entitled to divide and classify an item of Indebtedness in more than one of the types of Indebtedness described in Section 10.1(a) through (bb) above.

    The accrual of interest or dividends, the accretion of accreted value, the accretion or amortization of original issue discount, and the payment of interest or dividends in the form of additional Indebtedness of the same class, accretion or amortization of original issue discount or liquidation preference and increases in the amount of Indebtedness outstanding solely as a result of fluctuations in the exchange rate of currencies, will, in each case, not be deemed to be an incurrence of Indebtedness for purposes of this Section 10.1. The principal amount of any Indebtedness incurred to refinance other Indebtedness, if incurred in a different currency from the Indebtedness or Disqualified Stock, as applicable, being refinanced, shall be calculated based on the currency exchange rate applicable to the currencies in which such respective Indebtedness is denominated that is in effect on the date of such refinancing. The principal amount of any non-interest bearing Indebtedness or other discount security constituting Indebtedness at any date shall be the principal amount thereof that would be shown on a balance sheet of the Borrower dated such date prepared in accordance with GAAP.

Section 10.2Limitation on Liens. The Borrower will not, and will not permit any of the Restricted Subsidiaries to, create, incur, assume or suffer to exist any Lien upon any property or assets of any kind (real or personal, tangible or intangible) of the Borrower or any Restricted Subsidiary, whether now owned or hereafter acquired, except:

(a)Liens arising under the Credit Documents to secure the Obligations (including Liens contemplated by Section 3.8) or permitted in respect of any Mortgaged Property by the terms of the applicable Mortgage;

(b)Permitted Liens;

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(c)(x) Liens (including liens arising under Capital Leases to secure Capitalized Lease Obligations) securing Indebtedness permitted pursuant to Section 10.1(g); provided that (i) such Liens attach concurrently with or within 365 days after the acquisition, lease, repair, replacement, construction, expansion or improvement (as applicable) being financed with such Indebtedness, (ii) other than the property financed by such Indebtedness, such Liens do not at any time encumber any property, except for replacements thereof and accessions and additions to such property and the proceeds and the products thereof and customary security deposits and (iii) with respect to Capital Leases, such Liens do not at any time extend to or cover any assets (except for accessions and additions to such assets, replacements and products thereof and customary security deposits) other than the assets subject to such Capital Leases; provided that individual financings provided by one lender may be cross collateralized to other financings provided by such lender (and its Affiliates), and (y) Liens on the assets of a Restricted Subsidiary that is not a Credit Party securing Indebtedness permitted pursuant to Section 10.1(n);

(d)Liens existing on the date hereof; provided that any Lien securing Indebtedness in excess of (i) $2,500,000 individually or in the aggregate (when taken together with all other Liens securing obligations outstanding in reliance on this Section 10.2(d) that are not listed on Schedule 10.2) shall only be permitted to the extent such Lien is listed on Schedule 10.2;

(e)(i) the modification, replacement, extension or renewal (or successive modifications, replacements, extensions or renewals), in whole or in part, of any Lien permitted by this Section 10.2 upon or in the same assets (plus improvements on and accessions to such property) theretofore subject to such Lien or upon or in after-acquired property that is (A) affixed or incorporated into the property covered by such Lien, (B) in the case of Liens permitted by Section 10.2(f) and Section 10.2(s), subject to a Lien securing Indebtedness permitted under Section 10.1, the terms of which Indebtedness require or include a pledge of after-acquired property (it being understood that such requirement shall not be permitted to apply to any property to which such requirement would not have applied but for such acquisition) and (C) the proceeds and products thereof or (ii) Liens securing Indebtedness incurred in replacement, extension, refinancing, refunding or renewal (without increase in the amount or additional direct or contingent obligors except to the extent otherwise permitted hereunder) of secured Indebtedness, to the extent the replacement, extension, refinancing, refunding or renewal of the Indebtedness secured thereby is permitted by Section 10.1;

(f)Liens existing on the assets of any Person that becomes a Subsidiary, or existing on assets acquired, pursuant to a Permitted Acquisition or other Investment permitted by Section 10.5 to the extent the Liens on such assets secure Indebtedness permitted by Section 10.1(j); provided that such Liens attach at all times only to the same assets that such Liens (or upon or in after-acquired property that is (i) affixed or incorporated into the property covered by such Lien, (ii) after-acquired property subject to a Lien securing Indebtedness permitted under Section 10.1(j), the terms of which Indebtedness require or include a pledge of after-acquired property (it being understood that such requirement shall not be permitted to apply to any property to which such requirement would not have applied but for such acquisition) and (iii) the proceeds and

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products thereof) attached to, and secure only, the same Indebtedness or obligations (or any Permitted Refinancing Indebtedness incurred to Refinance such Indebtedness) secured, immediately prior to such Permitted Acquisition or other Investment;

(g)Liens placed upon the Stock and Stock Equivalents of any Person that becomes a Restricted Subsidiary pursuant to a Permitted Acquisition or other Investment permitted by Section 10.5, or the assets of such a Restricted Subsidiary, in each case, to secure Indebtedness incurred pursuant to Section 10.1(j); provided that such Liens attach at all times only to the Stock and Stock Equivalents or assets so acquired;

(h)Liens securing Indebtedness or other obligations (i) of the Borrower or a Restricted Subsidiary in favor of a Credit Party and (ii) of any Restricted Subsidiary that is not a Credit Party in favor of any Restricted Subsidiary that is not a Credit Party;

(i)Liens (i) of a collecting bank arising under Section 4-210 of the Uniform Commercial Code on items in the course of collection, (ii) attaching to commodity trading accounts or other commodity brokerage accounts incurred in the ordinary course of business and (iii) in favor of a banking institution arising as a matter of law encumbering deposits (including the right of set-off) or other funds maintained with a financial institution (including the right of setoff) and that are within the general parameters customary in the banking industry or arising pursuant to such banking institution’s general terms and conditions;

(j)Liens (i) on cash advances in favor of the seller of any property to be acquired in an Investment permitted pursuant to Section 10.5 to be applied against the purchase price for such Investment and (ii) consisting of an agreement to Dispose of any property in a transaction permitted under Section 10.4, in each case, solely to the extent such Investment or Disposition, as the case may be, would have been permitted on the date of the creation of such Lien;

(k)Liens arising out of conditional sale, title retention, consignment or similar arrangements for sale or purchase of goods entered into by the Borrower or any of the Restricted Subsidiaries in the ordinary course of business permitted by this Agreement;

(l)Liens deemed to exist in connection with Investments in repurchase agreements permitted under Section 10.5;

(m)Liens encumbering reasonable customary initial deposits and margin deposits and similar Liens attaching to brokerage accounts incurred in the ordinary course of business and not for speculative purposes;

(n)Liens that are contractual rights of set-off (i) relating to the establishment of depository relations with banks not given in connection with the issuance or incurrence of Indebtedness, (ii) relating to pooled deposit or sweep accounts of the Borrower or any Restricted Subsidiary to permit satisfaction of overdraft or similar obligations incurred in the ordinary course of business of the Borrower and the Restricted Subsidiaries or (iii) relating to purchase orders and other agreements entered into with customers of the Borrower or any Restricted Subsidiary in the ordinary course of business;

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(o)Liens solely on any cash earnest money deposits made by the Borrower or any of the Restricted Subsidiaries in connection with any letter of intent or purchase agreement permitted hereunder;

(p)Liens on insurance policies and the proceeds thereof securing the financing of the premiums with respect thereto;

(q)Liens in respect of Production Payments, subject to adjustment of the Borrowing Base as set forth in Section 2.14(g) to the extent required under Section 10.4(b)provided that such Liens attach at all times only to the Oil and Gas Properties from which the Production Payments have been conveyed (including produced and unproduced reserves in respect thereof), it being understood that individual financings or Productions Payments provided by one lender or group of lenders may be cross-collateralized to other financings or Production Payments provided by such lender or group of lenders;

(r)the prior right of consignees and their lenders under consignment arrangements entered into in the ordinary course of business;

(s)agreements to subordinate any interest of the Borrower or any Restricted Subsidiary in any accounts receivable or other proceeds arising from inventory consigned by the Borrower or any Restricted Subsidiary pursuant to an agreement entered into in the ordinary course of business;

(t)Liens on Stock or Stock Equivalents (i) in a joint venture securing obligations of such joint venture so long as the assets of such joint venture do not constitute Collateral and (ii) of an Unrestricted Subsidiary;

(u)Liens securing any Indebtedness permitted by Sections 10.1(e) (solely and to the same extent that the Indebtedness guaranteed by such Guarantee Obligations is permitted to be subject to a Lien hereunder), (l) (as long as such Liens attach only to assets of Foreign Subsidiaries and Domestic Subsidiaries that are not Guarantors) and (p) (as long as such Liens attach only to cash and securities and securities held by the relevant Cash Management Bank);

(v)Liens arising pursuant to Section 107(l) of the Comprehensive Environmental Response, Compensation and Liability Act, 42 U.S.C. § 9607(l), or other Environmental Law, unless such Lien (i) by action of the lienholder, or by operation of law, takes priority over any Liens arising under the Credit Documents on the property upon which it is a Lien, and (ii) materially impairs the use of the property covered by such Lien for the purposes for which such property is held;

(w)Liens on Collateral securing any Permitted Junior Lien Debt and any Permitted Refinancing Indebtedness permitted by Section 10.1(o); provided that the applicable holders of such Indebtedness (or a representative or trustee thereof on their behalf) shall have entered into a Customary Intercreditor Agreement providing that the Liens securing such obligations shall rank junior to the Liens securing the Obligations; and

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(x)additional Liens on property not constituting Borrowing Base Properties, so long as the aggregate principal amount of the obligations secured thereby at the time of the incurrence thereof and after giving Pro Forma Effect thereto and the use of proceeds thereof, does not exceed the greater of (x) $80,000,000 and (y) 2.0% of Total Assets (measured as of the date on which such Lien or the Indebtedness secured is incurred), provided that Liens on such property not securing Permitted Refinancing Indebtedness of such obligations shall be permitted.

    For purposes of determining compliance with this Section 10.2, (A) Liens need not be incurred solely by reference to one category of Liens permitted by this Section 10.2 but are permitted to be incurred in part under any combination thereof and of any other available exemption, (B) in the event that a Lien (or any portion thereof) meets the criteria of one or more of the categories of Liens permitted by this Section 10.2, the Borrower may, in its sole discretion, classify or reclassify such Lien (or any portion thereof) in any manner that complies with this provision and (C) with respect to any Lien securing Indebtedness that was permitted to secure such Indebtedness at the time of the incurrence of such Indebtedness, such Lien shall also be permitted to secure any amount permitted under Section 10.1(cc) in respect of such Indebtedness.

Section 10.3Limitation on Fundamental Changes. Except as permitted by Section 10.4 or Section 10.5 (other than Section 10.5(x)) the Borrower will not, and will not permit any of the Restricted Subsidiaries to, consummate any merger, consolidation or amalgamation, or liquidate, wind up or dissolve itself (or suffer any liquidation or dissolution), or Dispose of, all or substantially all its business units, assets or other properties, except that:

(a)any Subsidiary of the Borrower or any other Person may be merged, amalgamated or consolidated with or into the Borrower; provided that (i) the Borrower shall be the continuing or surviving Person or, in the case of a merger, amalgamation or consolidation with or into the Borrower, the Person formed by or surviving any such merger, amalgamation or consolidation (if other than the Borrower) shall be an entity organized or existing under the laws of the United States, any state thereof, the District of Columbia or any territory thereof (the Borrower or such Person, as the case may be, being herein referred to as the “Successor Borrower”), (ii) the Successor Borrower (if other than the Borrower) shall expressly assume all the obligations of the Borrower under this Agreement and the other Credit Documents pursuant to a supplement hereto or thereto in form reasonably satisfactory to the Administrative Agent, (iii) no Borrowing Base Deficiency or Event of Default has occurred and is continuing at the date of such merger, amalgamation or consolidation or would result from such consummation of such merger, amalgamation or consolidation, (iv) if such merger, amalgamation or consolidation involves the Borrower and a Person that, prior to the consummation of such merger, amalgamation or consolidation, is not a Subsidiary of the Borrower (A) the Successor Borrower shall be in compliance, on a Pro Forma Basis after giving effect to such merger, amalgamation or consolidation, with the Financial Performance Covenants, as such covenants are recomputed as at the last day of the most recently ended Test Period under such Section as if such merger, amalgamation or consolidation had occurred on the first day of such Test Period, (B) each Subsidiary grantor and each Subsidiary pledgor, unless it is the other party to such merger, amalgamation or consolidation or unless the Successor Borrower is the Borrower, shall have by a supplement to the Credit Documents confirmed that its obligations thereunder shall apply to the Successor Borrower’s

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obligations under this Agreement, (C) if requested by the Administrative Agent, each mortgagor of a Mortgaged Property, unless it is the other party to such merger or consolidation or unless the Successor Borrower is the Borrower, shall have by an amendment to or restatement of the applicable Mortgage confirmed that its obligations thereunder shall apply to the Successor Borrower’s obligations under this Agreement, (D) the Borrower shall have delivered to the Administrative Agent an officer’s certificate stating that such merger, amalgamation or consolidation and any supplements to the Credit Documents preserve the enforceability of the Guarantee and the perfection and priority of the Liens under the Security Documents, (E) if reasonably requested by the Administrative Agent, an opinion of counsel shall be required to be provided to the effect that such merger, amalgamation or consolidation does not violate this Agreement or any other Credit Document, and as to such other matters regarding the Successor Borrower and the Credit Documents as the Administrative Agent or its counsel may reasonably request, (F) the Administrative Agent and Lenders shall have received all documentation and other information about the Successor Borrower (if other than the Borrower) as shall have been reasonably requested in writing by the Administrative Agent and Lenders at least five days prior to the creation of the such Successor Borrower in respect of applicable “know your customer” and anti-money laundering rules and regulations, including, without limitation, the Patriot Act; provided, further, that if the foregoing are satisfied, the Successor Borrower (if other than the Borrower) will succeed to, and be substituted for, the Borrower under this Agreement and (G) such merger, amalgamation or consolidation shall comply with all the conditions set forth in the definition of the term “Permitted Acquisition” or is otherwise permitted under Section 10.5.

(b)any Subsidiary of the Borrower or any other Person may be merged, amalgamated or consolidated with or into any one or more Subsidiaries of the Borrower; provided that (i) in the case of any merger, amalgamation or consolidation involving one or more Restricted Subsidiaries, (A) a Restricted Subsidiary shall be the continuing or surviving Person or (B) the Borrower shall take all steps necessary to cause the Person formed by or surviving any such merger, amalgamation or consolidation (if other than a Restricted Subsidiary) to become a Restricted Subsidiary, (ii) in the case of any merger, amalgamation or consolidation involving one or more Guarantors, unless otherwise permitted by Section 10.5, a Guarantor shall be the continuing or surviving Person or the Person formed by or surviving any such merger, amalgamation or consolidation (if other than a Guarantor) shall execute a supplement to the Guarantee, the Security Agreement, the Pledge Agreement and any applicable Mortgage, and a joinder to the Intercompany Note, each in form and substance reasonably satisfactory to the Collateral Agent in order for the surviving Person to become a Guarantor and pledgor, mortgagor and grantor of Collateral for the benefit of the Secured Parties and to acknowledge and agree to the terms of the Intercompany Note, (iii) no Borrowing Base Deficiency, Default or Event of Default has occurred and is continuing on the date of such merger, amalgamation or consolidation or would result from the consummation of such merger, amalgamation or consolidation and (iv) if such merger, amalgamation or consolidation involves a Subsidiary and a Person that, prior to the consummation of such merger, amalgamation or consolidation, is not a Restricted Subsidiary of the Borrower, (A) the Borrower shall be in compliance, on a Pro Forma Basis after giving effect to such merger, amalgamation or

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consolidation, with the Financial Performance Covenants, (B) the Borrower shall have delivered to the Administrative Agent an officer’s certificate stating that such merger, amalgamation or consolidation and such supplements to any Credit Document preserve the enforceability of the Guarantee and the perfection and priority of the Liens under the Security Agreement and (C) such merger, amalgamation or consolidation shall comply with all the conditions set forth in the definition of the term “Permitted Acquisition” or is otherwise permitted under Section 10.5;

(c)any Restricted Subsidiary that is not a Guarantor may (i) merge, amalgamate or consolidate with or into any other Restricted Subsidiary and (ii) Dispose of any or all of its assets (upon voluntary liquidation or otherwise) to the Borrower, a Guarantor or any other Restricted Subsidiary of the Borrower;

(d)any Guarantor may (i) merge, amalgamate or consolidate with or into any other Guarantor, (ii) merge, amalgamate or consolidate with or into any other Subsidiary which is not a Guarantor or Dispose of any or all of its assets (upon voluntary liquidation or otherwise) to any other Subsidiary that is not a Guarantor; provided that if such Guarantor is not the surviving entity, such merger, amalgamation or consolidation shall be deemed to be, and any such Disposition shall be, (A) an “Investment” and subject to the limitations set forth in Section 10.5 and (B) a “Disposition” and subject to the limitations set forth in Section 10.4(b), and (iii) Dispose of any or all of its assets (upon voluntary liquidation or otherwise) to the Borrower or any other Guarantor;

(e)any Restricted Subsidiary may liquidate or dissolve if (i) the Borrower determines in good faith that such liquidation or dissolution is in the best interests of the Borrower and is not materially disadvantageous to the Lenders and (ii) to the extent such Restricted Subsidiary is a Credit Party, any assets or business of such Restricted Subsidiary not otherwise Disposed of or transferred in accordance with Section 10.4 or Section 10.5, in the case of any such business, discontinued, shall be transferred to, or otherwise owned or conducted by, a Credit Party after giving effect to such liquidation or dissolution;

(f)the Borrower and its Restricted Subsidiaries may consummate (x) the Transactions or (y) the IPOCo Transactions of the type described in clauses (a) and (b) of the definition thereof;

(g)the Borrower and the Restricted Subsidiaries may consummate a merger, dissolution, liquidation, amalgamation, consolidation or Disposition, the purpose of which is to effect a Disposition permitted pursuant to Section 10.4 or an Investment permitted by Section 10.5; and

(h)any merger the sole purpose of which is to reincorporate or reorganize a Credit Party in another jurisdiction in the United States shall be permitted as long as such merger does not adversely affect the value of the Collateral in any material respect and the surviving entity assumes all Obligations of the applicable Credit Party under the Credit Documents and delivers any applicable information requested by the Administrative Agent or any Lender under applicable “know your customer” and anti-money laundering rules and regulations, including the Patriot Act.

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Section 10.4Limitation on Sale of Assets. The Borrower will not, and will not permit any of the Restricted Subsidiaries to, (x) convey, sell, lease, sell and leaseback, assign, farm-out, transfer or otherwise dispose (each of the foregoing a “Disposition”) of any of its property, business or assets (including receivables and leasehold interests), whether now owned or hereafter acquired or (y) sell to any Person (other than the Borrower or a Guarantor) any shares owned by it of any Restricted Subsidiary’s Stock and Stock Equivalents, except that:

(a)the Borrower and the Restricted Subsidiaries may Dispose of (i) inventory and other goods held for sale, including Hydrocarbons, obsolete, worn out, used or surplus equipment, vehicles and other assets (other than accounts receivable) in the ordinary course of business (including equipment that is no longer necessary for the business of the Borrower or its Restricted Subsidiaries or is replaced by equipment of at least comparable value and use), (ii) Permitted Investments, and (iii) assets (other than Borrowing Base Properties) for the purposes of charitable contributions or similar gifts to the extent such assets are not material to the ability of the Borrower and its Restricted Subsidiaries, taken as a whole, to conduct its business in the ordinary course;

(b)the Borrower and the Restricted Subsidiaries may Dispose of any Oil and Gas Properties or any interest therein or the Stock or Stock Equivalents of any Restricted Subsidiary or of any Minority Investment owning Oil and Gas Properties (and including, but without limitation, Dispositions in respect of Production Payments and Mineral Interests and in connection with net profits interests, operating agreements, farm-ins, farm-outs, joint exploration and development agreements and other agreements customary in the oil and gas industry for the purpose of developing such Oil and Gas Properties) for Fair Market Value; provided, that if such Disposition of Oil and Gas Properties or of any Stock or Stock Equivalents of any Restricted Subsidiary or Minority Investment owning Oil and Gas Properties involves Borrowing Base Properties included in the most recently delivered Reserve Report and the aggregate PV-9 (calculated at the time of such Disposition) of all such Borrowing Base Properties so directly or indirectly Disposed of since the later of (i) the later of (A) the Closing Date and (B) the last Redetermination Date and (ii) the last adjustment of the Borrowing Base made pursuant to Section 2.14(g) exceeds 5% of the then-effective Borrowing Base, then no later than two Business Days’ after the date of consummation of any such Disposition, the Borrower shall provide notice to the Administrative Agent of such Disposition and the Borrowing Base Properties so Disposed and, at the election of the Required Lenders, the Borrowing Base shall be adjusted in accordance with the provisions of Section 2.14(g);

(c)the Borrower and the Restricted Subsidiaries may Dispose of property or assets to the Borrower or to a Restricted Subsidiary; provided that if the transferor of such property is a Credit Party (i) the transferee thereof must be a Credit Party or (ii) such transaction is permitted under Section 10.5;

(d)the Borrower and any Restricted Subsidiary may effect any transaction permitted by Section 10.2, Section 10.3 (other than Section 10.3(g)), Section 10.5 (other than Section 10.5(x)) or Section 10.6;

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(e)the Borrower and the Restricted Subsidiaries may lease, sublease, license or sublicense (on a non-exclusive basis with respect to any intellectual property) real, personal or intellectual property in the ordinary course of business;

(f)Dispositions (including like-kind exchanges) of property (other than Borrowing Base Properties) to the extent that (i) such property is exchanged for credit against the purchase price of similar replacement property or (ii) the proceeds of such Disposition are applied to the purchase price of such replacement property, in each case under Section 1031 of the Code or otherwise;

(g)Dispositions of Hydrocarbon Interests to which no Proved Reserves are attributable and farm-outs of undeveloped acreage to which no Proved Reserves are attributable and assignments in connection with such farm-outs;

(h)Dispositions of Investments in joint ventures (regardless of the form of legal entity) to the extent required by, or made pursuant to, customary buy/sell arrangements between the joint venture parties set forth in joint venture arrangements and similar binding arrangements;

(i)Dispositions listed on Schedule 10.4 (“Scheduled Dispositions”);

(j)transfers of property subject to a Casualty Event or in connection with any condemnation proceeding with respect to Collateral;

(k)Dispositions of accounts receivable (i) in connection with the settlement, collection or compromise thereof or (ii) to the extent the proceeds thereof are used to prepay any Loans then outstanding;

(l)the unwinding or termination of any Hedge Agreement (subject to the terms of Section 2.14(f));

(m)Dispositions of Oil and Gas Properties or any interest therein and other assets not included in the Borrowing Base (including, without limitation, the Stock or Stock Equivalents of any Restricted Subsidiary or any Minority Investment owning Oil and Gas Properties that are not Borrowing Base Properties);

(n)to extent constituting a Disposition, customary after pay-out reversions of Oil and Gas Properties in agreements entered into in the ordinary course of business, provided that the before pay-out and after pay-out interests of the Borrower and its Restricted Subsidiaries are set forth in the Reserve Report;

(o)any issuance or sale of Stock or Stock Equivalents in, or sale of Indebtedness or other securities of, an Unrestricted Subsidiary (or a Restricted Subsidiary which owns an Unrestricted Subsidiary so long as such Restricted Subsidiary owns no assets other than the Stock or Stock Equivalents of such Unrestricted Subsidiary), including a Minerals Spinoff;

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(p)any surrender, expiration or waiver of contract rights or oil and natural gas leases or the settlement, release, recovery on or surrender of contract, tort or other rights or litigation claims of any kind in the ordinary course of business or consistent with industry practice;

(q)Disposition of any asset between or among the Borrower and/or its Restricted Subsidiaries as a substantially concurrent interim Disposition in connection with a Disposition otherwise permitted pursuant to Section 10.4(a) through (p) above;

(r)the lapse or abandonment in the ordinary course of business of any registrations or applications for registration of any immaterial intellectual property rights; and

(s)Dispositions of any assets having a Fair Market Value not to exceed the greater of $5,000,000 in the aggregate during any 12- month period.

To the extent any Collateral is Disposed of as permitted by this Section 10.4 to any Person other than a Credit Party, such Collateral shall be sold free and clear of the Liens created by the Credit Documents, and upon the certification by the Borrower that such Disposition is permitted by this Agreement (if requested by the Administrative Agent), the Administrative Agent shall be authorized (and is hereby directed by each of the Lenders) to take any actions reasonably requested by the Borrower in order to effect the foregoing at Borrower’s sole cost and expense.

Section 10.5Limitation on Investments. The Borrower will not, and will not permit any of the Restricted Subsidiaries, to make any Investment except:

(a)extensions of trade credit and purchases of assets and services (including purchases of inventory, supplies and materials) in the ordinary course of business;

(b)Investments in assets that constituted Permitted Investments at the time such Investments were made;

(c)loans and advances to officers, directors, employees and consultants of the Borrower (or any direct or indirect parent thereof) or any of its Restricted Subsidiaries (i) for reasonable and customary business-related travel, entertainment, relocation and analogous ordinary business purposes (including employee payroll advances), (ii) in connection with such Person’s purchase of Stock or Stock Equivalents of the Borrower (or any direct or indirect parent thereof; provided that, to the extent such loans and advances are made in cash, the amount of such loans and advances used to acquire such Stock or Stock Equivalents shall be contributed to the Borrower in cash) and (iii) for purposes not described in the foregoing subclauses (i) and (ii); provided that the aggregate principal amount outstanding pursuant to subclause (iii) shall not exceed $10,000,000;

(d)(i) Investments existing or contemplated on, or made pursuant to commitments in existence or contemplated on, the Closing Date as set forth on Schedule 10.5,(ii) Investments existing on the Closing Date of the Borrower or any Subsidiary in any other Subsidiary and (iii) any extensions, modifications, replacements, renewals or reinvestments thereof, so long as the amount of any Investment made pursuant to this

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Section 10.5(d) is not increased at any time above the amount of such Investment set forth on Schedule 10.5 (other than (a) pursuant to an increase as required by the terms of any such Investment as in existence on the Closing Date or (b) as otherwise permitted under this Section 10.5);

(e)any Investments received by the Borrower or any of its Restricted Subsidiaries: (i) in connection with or as a result of the bankruptcy, workout, reorganization or recapitalization of suppliers or customers or settlement of delinquent obligations of, and other disputes with or judgments against, customers, (ii) in satisfaction of judgments against other Persons, (iii) as a result of a foreclosure with respect to any secured Investment or other transfer of title with respect to any secured Investment or (iv) as a result of the settlement, compromise or resolution of litigation, arbitration or other disputes with Persons who are not Affiliates;

(f)Investments to the extent that payment for such Investments is made with Stock or Stock Equivalents (other than Disqualified Stock not otherwise permitted by Section 10.1) of the Borrower (or any direct or indirect parent thereof);

(g)Investments (i) by the Borrower in any Guarantor or by any Guarantor in the Borrower, (ii) by any Restricted Subsidiary that is not a Guarantor in the Borrower or any other Restricted Subsidiary (iii) constituting Permitted Intercompany Activities and (iv) by the Borrower or any Guarantor in any Restricted Subsidiary that is not a Guarantor, valued at the Fair Market Value (determined by the Borrower in good faith) of such Investment at the time each such Investment is made, in an aggregate amount pursuant to this Section 10.5(g)(iii) that, at the time such Investment is made, would not exceed the sum of (A) the greater of (x) $50,000,000 and (y) 1.25% of Total Assets at the time of such Investment (with the fair market value of each Investment being measured at the time made and without giving effect to subsequent changes in value), (B) the Applicable Equity Amount at such time and (C) to the extent not otherwise included in the determination of the Applicable Equity Amount, an amount equal to any repayments, interest, returns, profits, distributions, income and similar amounts actually received in cash in respect of any such Investment (which amount shall not exceed the amount of such Investment valued at the Fair Market Value of such Investment at the time such Investment was made) (it being understood that to the extent any Investment made pursuant to this Section 10.5(g)(iii) was made by using the Applicable Equity Amount, then the amounts referred to in clause (C) shall, to the extent of the original usage of the Applicable Equity Amount, be deemed to reconstitute such amounts).

(h)Investments constituting Permitted Acquisitions; provided that the aggregate amount of Permitted Acquisition Consideration of such Permitted Acquisitions made or provided by the Borrower or any Restricted Subsidiary to acquire any Person that does not become a Credit Party or merge, consolidate or amalgamate into a Credit Party or any assets that shall not, immediately after giving effect to such Permitted Acquisition, be owned by Credit Party, shall not exceed the sum of (i) the greater of (x) $80,000,000 and (y) 2.0% of Total Assets, (ii) the Applicable Equity Amount at such time and (iii) to the extent not otherwise included in the determination of the Applicable Equity Amount, an amount equal to any repayments, interest, returns, profits, distributions, income and similar amounts actually received in cash in respect of any such

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Investment (which amount shall not exceed the amount of such Investment valued at the Fair Market Value of such Investment at the time such Investment was made) (it being understood that to the extent any Investment made pursuant to this Section 10.5(h) was made by using the Applicable Equity Amount, then the amounts referred to in this clause (iii) shall, to the extent of the original usage of the Applicable Equity Amount, be deemed to reconstitute such amounts);

(i)Investments (including but not limited to (i) Minority Investments and Investments in Unrestricted Subsidiaries, (ii) Investments in joint ventures (regardless of the form of legal entity) or similar Persons that do not constitute Restricted Subsidiaries, (iii) Investments in Subsidiaries that are not Credit Parties, (iv) Permitted Acquisitions and (v) Investments in respect of royalty trusts and master limited partnerships), in each case valued at the Fair Market Value (determined by the Borrower acting in good faith) of such Investment at the time each such Investment is made, in an aggregate amount pursuant to this Section 10.5(i) that, at the time each such Investment is made, would not exceed the sum of (A) the greater of (x) $100,000,000 and (y) 2.5% of Total Assets at the time of such Investment (with the fair market value of each Investment being measured at the time made and without giving effect to subsequent changes in value)plus (B) the Applicable Equity Amount at such time plus (C) to the extent not otherwise included in the determination of the Applicable Equity Amount, an amount equal to any repayments, interest, returns, profits, distributions, income and similar amounts actually received in cash in respect of any such Investment (which amount shall not exceed the amount of such Investment valued at the Fair Market Value of such Investment at the time such Investment was made) (it being understood that to the extent any Investment made pursuant to this Section 10.5(i) was made by using the Applicable Equity Amount, then the amounts referred to in clause (C) shall, to the extent of the original usage of the Applicable Equity Amount, be deemed to reconstitute such amounts); provided that the foregoing limits shall not apply during the period in which, and Investments may be made pursuant to this Section 10.5(i) without limit at any such time during which, after giving Pro Forma Effect to the making of any such Investment, (i) no Event of Default shall have occurred and be continuing, (ii) Liquidity is not less than 15% of the then effective Loan Limit (on a Pro Forma Basis after giving effect to such Investment) and (iii) the Consolidated Total Debt to Consolidated EBITDAX Ratio is not greater than 2.75 to 1.00 (on a Pro Forma Basis after giving effect to such Investment); provided, further, that intercompany Current Liabilities incurred in the ordinary course of business and consistent with past practices, in connection with the cash management operations of the Borrower and the Subsidiaries shall not be included in calculating any limitations in this paragraph at any time;

(j)[reserved];

(k)[reserved];

(l)Investments constituting promissory notes and other non-cash proceeds of Dispositions of assets to the extent permitted by Section 10.4;

(m)Investments made to repurchase or retire Stock or Stock Equivalents of the Borrower or any direct or indirect parent thereof owned by the Sponsor or its Affiliates or

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any employee or any stock ownership plan or key employee stock ownership plan of the Borrower (or any direct or indirect parent thereof); provided that such Investment is otherwise permitted by Section 10.6(j);

(n)[reserved];

(o)loans and advances to any direct or indirect parent of the Borrower in lieu of, and not in excess of the amount of, Dividends to the extent permitted to be made to such parent in accordance with Section 10.6;

(p)Investments consisting of extensions of credit in the nature of accounts receivable or notes receivable arising from the grant of trade credit in the ordinary course of business, and Investments received in satisfaction or partial satisfaction thereof from financially troubled account debtors and other credits to suppliers in the ordinary course of business;

(q)Investments in the ordinary course of business consisting of endorsements for collection or deposit and customary trade arrangements with customers consistent with past practices or industry practice;

(r)advances of payroll payments to employees, consultants or independent contractors or other advances of salaries or compensation to employees, consultants or independent contractors, in each case in the ordinary course of business;

(s)guarantee obligations of the Borrower or any Restricted Subsidiary of leases (other than Capital Leases) or of other obligations that do not constitute Indebtedness, in each case entered into in the ordinary course of business;

(t)Investments held by a Person acquired (including by way of merger, amalgamation or consolidation) after the Closing Date otherwise in accordance with this Section 10.5 to the extent that such Investments were not made in contemplation of or in connection with such acquisition, merger, amalgamation or consolidation and were in existence on the date of such acquisition, merger, amalgamation or consolidation;

(u)Investments in Industry Investments and in interests in additional Oil and Gas Properties and gas gathering systems, gas processing plants and pipeline systems and any related infrastructure related thereto or Investments related to farm-out, farm-in, joint operating, joint venture (other than a joint venture in the form of a partnership, corporation, or limited liability company), joint development or other area of mutual interest agreements, other similar industry investments, gathering systems, pipelines or other similar oil and gas exploration and production business arrangements whether through direct ownership or ownership through a joint venture or similar arrangement (other than a joint venture in the form of a partnership, corporation, or limited liability company);

(v)to the extent constituting Investments, the Transactions;

(w)Investments in Hedge Agreements permitted by Section 10.1 and Section 10.10;

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(x)Investments consisting of Indebtedness, fundamental changes, Dispositions and Dividends permitted under Section 10.1, Section 10.3 (other than Section 10.3(a), (b) and (g)), Section 10.4 (other than Section 10.4(d)) and Section 10.6 (other than Section 10.6(c));

(y)Investments consisting of licensing of intellectual property pursuant to joint marketing arrangements with other Persons in the ordinary course of business;

(z)Investments resulting from pledges and deposits under clauses (d) and (e) of the definition of “Permitted Liens” and clauses (j) and (o) of Section 10.2;

(aa)advances in the form of a prepayment of expenses, so long as such expenses are being paid in accordance with customary trade terms of the Borrower or the relevant Restricted Subsidiary;

(bb)Investments made in the ordinary course of business in connection with obtaining, maintaining or renewing client contacts and loans or advances made to distributors in the ordinary course of business;

(cc)[reserved];

(dd)Investments consisting of the contribution of Stock or Stock Equivalents of any Foreign Subsidiary or FSHCO to any other Foreign Subsidiary or FSHCO;

(ee)Investments in Restricted Subsidiaries which are not Guarantors, joint ventures and Unrestricted Subsidiaries having an aggregate Fair Market Value (determined by the Borrower acting in good faith), taken together with all other Investments made pursuant to this Section 10.5(ee) that are at the time outstanding, without giving effect to the sale of an Unrestricted Subsidiary to the extent the proceeds of such sale do not consist of marketable securities (until such proceeds are converted to cash equivalents) not to exceed the greater of (x) $50,000,000 and (y) 1.25% of Total Assets at the time of such Investment (with the fair market value of each Investment being measured at the time made and without giving effect to subsequent changes in value);

(ff)any Investment by any Captive Insurance Subsidiary in connection with its provision of insurance to the Borrower or any of its Subsidiaries, which Investment is made in the ordinary course of business or consistent with industry practice of such Captive Insurance Subsidiary, or by reason of applicable law, rule, regulation or order, or that is required or approved by any regulatory authority having jurisdiction over such Captive Insurance Subsidiary or its business, as applicable;

(gg)[reserved];

(hh)[reserved];

(ii)any Investment constituting a Disposition or transfer of any asset between or among the Borrower and/or its Restricted Subsidiaries as a substantially concurrent interim Disposition or transfer in connection with an Investment otherwise permitted pursuant to clauses (a) through (ff) above.

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    For purposes of determining compliance with this Section 10.5, in the event that an item of Investment meets the criteria of more than one of the categories of Investments described in clauses (a) through (ii) above, the Borrower may, in its sole discretion, classify or later divide, classify or reclassify all or a portion of such item of Investment or any portion thereof in a manner that complies with this Section 10.5 and will only be required to include the amount and type of such Investment in one or more of the above clauses. In the event that a portion of the Investments could be classified as incurred under a “ratio-based” basket (giving pro forma effect to the making of such Investments), the Borrower, in its sole discretion, may classify such portion of such Investment as having been incurred pursuant to such “ratio-based” basket and thereafter the remainder of the Investments as having been incurred pursuant to one or more of the other clauses of this Section 10.5 and if any such test would be satisfied in any subsequent fiscal quarter following the relevant date of determination, then such reclassification shall be deemed to have automatically occurred at such time.

Section 10.6Limitation on Dividends. The Borrower will not, and will not permit any of its Restricted Subsidiaries to, pay any dividends (other than Dividends payable solely in its Stock that is not Disqualified Stock) or return any capital to its equity holders or make any other distribution, payment or delivery of property or cash to its equity holders as such, or redeem, retire, purchase or otherwise acquire for consideration any shares of any class of its Stock or Stock Equivalents or the Stock or Stock Equivalents of any direct or indirect parent now or hereafter outstanding, or set aside any funds for any of the foregoing purposes, or permit any of the Restricted Subsidiaries to purchase or otherwise acquire for consideration (other than in connection with an Investment permitted by Section 10.5) any Stock or Stock Equivalents of the Borrower (or any direct or indirect parent thereof), now or hereafter outstanding (all of the foregoing, “Dividends”); except that:

(a)the Borrower and its Restricted Subsidiaries may (or may pay Dividends to permit any direct or indirect parent thereof to) redeem in whole or in part any of its Stock or Stock Equivalents in exchange for another class of its (or such parent’s) Stock or Stock Equivalents or with proceeds from substantially concurrent equity contributions or issuances of new Stock or Stock Equivalents; provided that such new Stock or Stock Equivalents contain terms and provisions at least as advantageous to the Lenders in all material respects to their interests as those contained in the Stock or Stock Equivalents redeemed thereby; and the Borrower and its Restricted Subsidiaries may pay Dividends payable solely in the Stock and Stock Equivalents (other than Disqualified Stock not otherwise permitted by Section 10.1) of the Borrower;

(b)the Borrower and its Restricted Subsidiaries may (i) (or may pay dividends to permit any direct or indirect parent thereof to) redeem, acquire, retire or repurchase shares of its (or such parent’s) Stock or Stock Equivalents held by any future, present or former officer, manager, consultant, independent contractor, director or employee (or their respective Affiliates, estates, spouses, former spouses, successors, executors, administrators, heirs, legatees, distributees or immediate family members) of the Borrower and its Subsidiaries or any parent thereof, upon the death, disability, retirement or termination of employment of any such Person or otherwise in accordance with any equity option or equity appreciation rights plan, any management, director and/or employee equity ownership, benefit or incentive plan or agreement, equity subscription

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plan, employment termination agreement or any other employment agreements or equity holders’ agreement; provided that, except with respect to non-discretionary repurchases, acquisitions, retirements or redemptions pursuant to the terms of any equity option or equity appreciation rights plan, any management, director and/or employee equity ownership, benefit or incentive plan or agreement, equity subscription plan, employment termination agreement or any other employment agreements or equity holders’ agreement, the aggregate amount of all cash paid in respect of all such shares of Stock or Stock Equivalents so redeemed, acquired, retired or repurchased in any calendar year does not exceed the sum of (A) $15,000,000 (which shall increase to $30,000,000 subsequent to the consummation of a Qualified IPO) (with unused amounts in any calendar year being carried over to succeeding calendar years subject to a maximum of $30,000,000 in any calendar year (which shall increase to $40,000,000 subsequent to the consummation of a Qualified IPO)) plus (B) all net cash proceeds obtained by or contributed to the Borrower and its Subsidiaries during such calendar year from the sale of such Stock or Stock Equivalents to other future, present or former officers, consultants, employees, directors and managers in connection with any permitted compensation and incentive arrangements plus (C) all net cash proceeds obtained from any key-man life insurance policies received during such calendar year plus (D) the amount of any cash bonuses otherwise payable to members of management, directors or consultants of the Borrower or its Subsidiaries or any parent thereof in connection with the Transactions that are foregone in return for the receipt of Stock or Stock Equivalents; notwithstanding the foregoing, the Borrower may elect to apply all or any portion of the aggregate increase contemplated by clauses (B), (C) and (D) above in any calendar year; and (ii) pay Dividends in an amount equal to withholding or similar Taxes payable or expected to be payable by any future, present or former employee, officer, director, manager or consultant (or their respective Affiliates, estates or immediate family members) and any repurchases of Stock or Stock Equivalents in consideration of such payments including deemed repurchases in connection with the exercise of stock options so long as the amount of such payments does not exceed $7,500,000 in the aggregate; provided, further, that cancellation of Indebtedness owing to the Borrower or any of its Restricted Subsidiaries from any future, present or former employee, officer, director, manager or consultant (or their respective Affiliates, estates or immediate family members), of the Borrower, any Restricted Subsidiary, any direct or indirect parent company of the Borrower or any of the Borrower’s Restricted Subsidiaries in connection with a repurchase of Stock or Stock Equivalents of the Borrower or any of its direct or indirect parent companies will not be deemed to constitute a Dividend for purposes of this covenant or any other provision of this Agreement;

(c)to the extent constituting Dividends, the Borrower and its Restricted Subsidiaries may (i) make Investments permitted by Section 10.5 (other than Section 10.5(x)) and (ii) enter into and consummate transactions expressly permitted by any provision of Section 10.3;

(d)the Borrower and its Restricted Subsidiaries may make the Dividends set forth on Schedule 10.6 as of the Closing Date;

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(e)the Borrower and its Restricted Subsidiaries may repurchase Stock or Stock Equivalents of the Borrower (or any direct or indirect parent thereof) and its Restricted Subsidiaries upon exercise of stock options or warrants if such Stock or Stock Equivalents represents all or a portion of the exercise price of such options or warrants;

(f)the Borrower and its Restricted Subsidiaries may make and pay Dividends to any of their direct or indirect parent entities:

(i)the proceeds of which will be used to pay (or to make Dividends to allow any direct or indirect parent of the Borrower to pay) franchise and excise taxes, and other fees and expenses, required to maintain its organizational existence;

(ii)the proceeds of which shall be used to allow any direct or indirect parent of the Borrower and its Restricted Subsidiaries to pay its operating expenses incurred in the ordinary course of business and other corporate overhead costs and expenses (including professional, administrative, legal, accounting and similar expenses provided by third parties, real and personal property Taxes, franchise, excise or similar taxes and fees and expenses required to maintain its corporate existence or good standing under applicable law), which are reasonable and customary and incurred in the ordinary course of business, including any actual, reasonable and customary indemnification claims made by directors or officers of the Borrower (or any parent thereof) and its Restricted Subsidiaries;

(iii)the proceeds of which shall be used by such parents to pay Dividends permitted by Section 10.6(b);

(iv)the proceeds of which shall be used to make Dividends to allow any direct or indirect parent thereof to pay fees and expenses (other than to Affiliates) related to any equity issuance or offering or debt issuance, incurrence or offering, Disposition or acquisition or investment transaction permitted by this Agreement, whether or not consummated;

(v)the proceeds of which shall be used to pay customary salary, bonus, severance and other benefits payable to officers, employees and consultants of any direct or indirect parent thereof (to the extent such salaries, bonuses, severances and other benefits are attributable to the ownership or operation of the Borrower and its Restricted Subsidiaries);

(vi)in the form of Stock or Stock Equivalents of the Borrower and its Restricted Subsidiaries (other than Disqualified Stock not otherwise permitted by Section 10.1);

(vii)the proceeds of which will be used to pay (or to make Dividends to allow any parent entity to pay) with respect to any taxable period (x) for which the Borrower and/or any of its Subsidiaries are members of a consolidated, combined, affiliated, unitary or similar income tax group for U.S. federal and/or applicable state or local income Tax purposes of which any holding company of the

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Borrower and/or its Subsidiaries is the common parent, or (y) for which the Borrower and/or its Subsidiaries is a partnership or disregarded entity for U.S. federal income tax purposes that is wholly owned (directly or indirectly) by a C corporation for U.S. federal and/or applicable state or local income Tax purposes, in an amount not to exceed the amount of any U.S. federal, state and/or local income Taxes that the Borrower and/or its Subsidiaries, as applicable, would have paid for such taxable period had the Borrower and/or its Subsidiaries, as applicable, been a stand-alone corporate taxpayer or a stand-alone corporate group; provided that distributions pursuant to this clause (vii) in respect of an Unrestricted Subsidiary shall be permitted to the extent that cash distributions were made by such Unrestricted Subsidiary to the Borrower or any of its Restricted Subsidiaries for such purpose;

(viii)in such amounts as are needed to pay any amounts owed by a direct or indirect parent of the Borrower or IPOCo, as applicable, under any tax receivable agreement as contemplated by the definition of “IPOCo Transactions”; or

(ix)with respect to any taxable period ending after the Closing Date for which the Borrower and/or its Subsidiaries is a partnership or disregarded entity for U.S. federal income Tax purposes (other than a partnership or disregarded entity described in clause (vii)(y) above), distributions to each owner in an amount necessary to permit such owner to pay its U.S. federal (including, for the avoidance of doubt, any Taxes imposed on “net investment income” by Section 1411 of the Code), state and/or local income Taxes (including any estimated Taxes payable) (as applicable) attributable (including, for the avoidance of doubt, as a result of any guaranteed payments deemed received by such owner pursuant to Section 707(c) of the Code (other than guaranteed payments in respect of services performed by such owner)) to its direct or indirect ownership of the Borrower and its Subsidiaries with respect to such taxable period (assuming that each owner is subject to Tax at the highest combined marginal federal, state and/or local income tax rate applicable to an individual or corporate taxpayer, as applicable, resident of New York, New York for such taxable period and taking into account (i) the deductibility of state and local income taxes for U.S. federal income tax purposes (and any limitations thereon), (ii) any cumulative net taxable loss of the Borrower allocated to such owner for prior taxable periods and not already taken into account in determining the amount of Tax distributions under this clause (ix) to the extent such loss is of a character that would allow such loss to be available to reduce Taxes in the current taxable period (taking into account any limitations on the utilization of such loss to reduce such Taxes and provided such loss had not already been utilized), (iii) the character (e.g. long-term or short-term capital gain or ordinary or exempt) of the applicable income) and (iv) any adjustments made under Section 754 of the Code; provided that distributions pursuant to this clause (ix) in respect of an Unrestricted Subsidiary shall be permitted to the extent that cash distributions were made by such Unrestricted Subsidiary to the Borrower or any of its Restricted Subsidiaries for such purpose;

(x)to finance Permitted Acquisitions and other Investments or other acquisitions in each case otherwise permitted to be made under Section 10.5 if

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made by the Borrower and/or its Restricted Subsidiaries; provided, that (A) such Dividend shall be made substantially concurrently with the closing of such Investment or other acquisition, (B) such direct or indirect parent company shall, promptly following the closing thereof, cause (1) all property acquired (whether assets or Stock or Stock Equivalents) to be contributed to the capital of the Borrower or one or more of its Restricted Subsidiaries or (2) the merger, amalgamation, consolidation, or sale of the Person formed or acquired into the Borrower or one of its Restricted Subsidiaries (to the extent not prohibited by Section 10.3) in order to consummate such Investment or other acquisition, (C) such direct or indirect parent company and its Affiliates (other than the Borrower or a Restricted Subsidiary) receives no consideration or other payment in connection with such transaction except to the extent the Borrower or a Restricted Subsidiary would have been permitted to give such consideration or make such payment in compliance herewith, (D) any property received by the Borrower shall not increase the Applicable Equity Amount and (E) to the extent constituting an Investment, such Investment shall be deemed to be made by Borrower or such Restricted Subsidiary pursuant to Section 10.5 for the purposes of calculating compliance with the baskets thereunder;

(g)the Borrower or any of the Restricted Subsidiaries may (i) pay cash in lieu of fractional shares in connection with any dividend, split or combination thereof or any Permitted Acquisition or other Investment permitted under Section 10.5 and (ii) so long as, after giving Pro Forma Effect thereto, (A) no Default or Event of Default shall have occurred and be continuing and (B) no Borrowing Base Deficiency exists, honor any conversion request by a holder of convertible Indebtedness and make cash payments in lieu of fractional shares in connection with any such conversion and may make payments on convertible Indebtedness in accordance with its terms;

(h)the Borrower and/or its Restricted Subsidiaries may pay or consummate any Dividend (including the consummation of any irrevocable redemption) within 60 days after the date of declaration thereof, if at the date of declaration such payment would have complied with the provisions of this Agreement;

(i)so long as, after giving Pro Forma Effect thereto, (i) no Event of Default or Borrowing Base Deficiency shall have occurred and be continuing, (ii) Liquidity is not less than 20% of the then effective Loan Limit (on a Pro Forma Basis after giving effect to such Dividend) and (iii) the Consolidated Total Debt to Consolidated EBITDAX Ratio is not greater than 1.50 to 1.00 (on a Pro Forma Basis after giving effect to such Dividend), the Borrower or its Restricted Subsidiaries may declare and pay additional Dividends without limit in cash or other otherwise to the holders of its Stock and Stock Equivalents; provided, that, in the case of any Dividend in the form of assets other than cash, no such Dividend shall be made if a Borrowing Base Deficiency would result from an adjustment to the Borrowing Base resulting from such Dividend (unless the Borrower shall have cash on hand sufficient to eliminate any such potential Borrowing Base Deficiency);

(j)so long as, after giving Pro Forma Effect thereto, (i) no Event of Default or Borrowing Base Deficiency shall have occurred and be continuing, (ii) Liquidity is not less than 20% of the then effective Loan Limit (on a Pro Forma Basis after giving effect

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to such Dividend) and (iii) the Consolidated Total Debt to Consolidated EBITDAX Ratio is not greater than 2.50 to 1.00 (on a Pro Forma Basis after giving effect to such Dividend), the Borrower or its Restricted Subsidiaries may declare and pay additional Dividends in cash or otherwise in an amount not to exceed the greater of (A) Available Distributable Consolidated EBITDAX and (B) Available Free Cash Flow; provided, that, in the case of any Dividend in the form of assets other than cash, no such Dividend shall be made if a Borrowing Base Deficiency would result from an adjustment to the Borrowing Base resulting from such Dividend (unless the Borrower shall have cash on hand sufficient to eliminate any such potential Borrowing Base Deficiency);

(k)in addition to the foregoing Dividends and so long as (x) no Event of Default or Borrowing Base Deficiency shall have occurred and be continuing or would result therefrom before or after giving effect to the payment of any such Dividend and (y) the Borrower shall be in compliance on a Pro Forma Basis with the Financial Performance Covenants as such covenant is re-computed as of the last day of the most recently ended Test Period as if the amount of any Cure Amount made for such Test Period were not made if the amount of the Applicable Equity Amount after paying or declaring the proposed Dividends in this Section 10.6(k) is less than or equal to the amount of such Cure Amount, the Borrower or its Restricted Subsidiaries may declare and pay Dividends in an aggregate amount not to exceed the Applicable Equity Amount at the time such Dividend is paid;

(l)the Borrower and its Restricted Subsidiaries may consummate the Transactions (and pay fees and expenses in connection therewith on or following the Closing Date);

(m)payments and distributions to dissenting stockholders pursuant to applicable law, pursuant to or in connection with a consolidation, merger, amalgamation or transfer of all or substantially all of the assets of the Borrower and its Restricted Subsidiaries that complies with the terms of this Agreement; provided that the aggregate amount of all such payments and distributions under this clause (m) shall not exceed $20,000,000;

(n)the distribution, by dividend or otherwise, of Stock or Stock Equivalents of, or Indebtedness owed to the Borrower or a Restricted Subsidiary by, an Unrestricted Subsidiary, including a Minerals Spin-Off (or a Restricted Subsidiary that owns an Unrestricted Subsidiary); provided that such Restricted Subsidiary owns no assets other than Stock or Stock Equivalents of an Unrestricted Subsidiary (other than Unrestricted Subsidiaries the primary assets of which are cash and/or Permitted Investments);

(o)after or in connection with the consummation of a Qualified IPO, (i) the Borrower or any Restricted Subsidiary may make Dividends to any direct or indirect parent of the Borrower to pay costs associated with preparations for and implementation of Public Company Compliance, (ii) payments and distributions made in connection with the IPOCo Transactions of the type described in clauses (a) and (b) of the definition thereof and (iii) the payment of all reasonable and customary fees and expenses incurred in connection therewith or owed by the Borrower, a direct or indirect parent of the Borrower or Restricted Subsidiaries of the Borrower; and

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(p)any Restricted Subsidiary may make Dividends to the Borrower or any other Restricted Subsidiary; provided that in the case of any such Dividend by a Restricted Subsidiary that is not a wholly-owned Subsidiary, such Dividend is made to the Borrower or any of its Restricted Subsidiaries and to each other owner of Stock or Stock Equivalents of such Restricted Subsidiary based on their relative ownership interests of the relevant class of Stock or Stock Equivalents.

Section 10.7Limitations on Junior Debt Payments and Amendments.

(a)The Borrower will not, and will not permit any Restricted Subsidiary to, voluntarily prepay, repurchase or redeem or otherwise voluntarily defease prior to maturity any Permitted Additional Debt or Permitted Junior Lien Debt (other than AHYDO payments); provided, however, that the Borrower or any Subsidiary may prepay, repurchase, redeem or defease any such Permitted Additional Debt or Permitted Junior Lien Debt:

(i)with cash from any capital contributions or the net cash proceeds of the issuance of Stock (in each case, other than Disqualified Stock);

(ii)with the proceeds of any Permitted Refinancing Indebtedness;

(iii)by converting or exchanging any such Permitted Additional Debt or Permitted Junior Lien Debt to Stock or Stock Equivalents of the Borrower or any direct or indirect parent of the Borrower (other than Disqualified Stock);

(iv)so long as, after giving Pro Forma Effect thereto, (i) no Event of Default or Borrowing Base Deficiency shall have occurred and be continuing, (ii) Liquidity is not less than 20% of the then effective Loan Limit (on a Pro Forma Basis after giving effect to such prepayment, repurchase, redemption or defeasance) and (iii) the Consolidated Total Debt to Consolidated EBITDAX Ratio is not greater than 1.50 to 1.00 (on a Pro Forma Basis after giving effect to such prepayment, repurchase, redemption or defeasance); and

(v)in an amount not to exceed the greater of (A) Available Distributable Consolidated EBITDAX and (B) Available Free Cash Flow, in each case, so long as, after giving Pro Forma Effect thereto, (i) no Event of Default or Borrowing Base Deficiency shall have occurred and be continuing, (ii) Liquidity is not less than 20% of the then effective Loan Limit (on a Pro Forma Basis) and (iii) the Consolidated Total Debt to Consolidated EBITDAX Ratio is not greater than 2.50 to 1.00 (on a Pro Forma Basis).

(b)The Borrower will not amend or modify the documentation governing any Permitted Additional Debt or Permitted Junior Lien Debt or, in each case, the terms applicable thereto to the extent that any such amendment or modification, taken as a whole, would be adverse to the Lenders in any material respect, unless such Indebtedness in its amended or modified form could be incurred as Permitted Refinancing Indebtedness or as Indebtedness under Section 10.1.

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(c)Notwithstanding the foregoing and for the avoidance of doubt, nothing in this Section 10.7 shall prohibit (i) the repayment or prepayment of intercompany subordinated Indebtedness owed among the Borrower and/or the Restricted Subsidiaries, in either case unless a Payment or Bankruptcy Event of Default has occurred and is continuing and the Borrower has received a notice from the Collateral Agent instructing it not to make or permit the Borrower and/or the Restricted Subsidiaries to make any such repayment or prepayment, (ii) substantially concurrent transfers of credit positions in connection with intercompany debt restructurings so long as such Indebtedness is permitted by Section 10.1 after giving effect to such transfer or (iii) the prepayment, repurchase, redemption or other defeasance of any Permitted Junior Lien Debt or any Permitted Additional Debt with an aggregate amount not to exceed the Applicable Equity Amount (with the Applicable Equity Amount being re-computed as of the last day of the most recently ended Test Period as if (i) such prepayment, repurchase, redemption or other defeasance had occurred on the first day of such Test Period and (ii) the amount of any Cure Amount made during such Test Period were not made to the extent (A) the amount of the Applicable Equity Amount after making the proposed prepayment, repurchase, redemption or other defeasance is less than or equal to the amount of such Cure Amount and (B) such Cure Amount was necessary for the Borrower to be in compliance on a Pro Forma Basis with the Financial Performance Covenants) at the time of such prepayment, repurchase, redemption or defeasance.

Section 10.8Negative Pledge Agreements. The Borrower will not, and will not permit any of the Restricted Subsidiaries to, enter into or permit to exist any Contractual Requirement (other than this Agreement or any other Credit Document) that limits the ability of the Borrower or any Guarantor to create, incur, assume or suffer to exist Liens on property of such Person for the benefit of the Secured Parties with respect to the Obligations or under the Credit Documents; provided that the foregoing shall not apply to Contractual Requirements that (i)(x) exist on the Closing Date and (to the extent not otherwise permitted by this Section 10.8) are listed on Schedule 10.8 and (y) to the extent Contractual Requirements permitted by clause (x) are set forth in an agreement evidencing Indebtedness or other obligations, are set forth in any agreement evidencing any Permitted Refinancing Indebtedness incurred to Refinance such Indebtedness or obligation so long as such Permitted Refinancing Indebtedness does not expand the scope of such Contractual Requirement, (ii) are binding on a Restricted Subsidiary at the time such Restricted Subsidiary first becomes a Restricted Subsidiary of the Borrower, so long as such Contractual Requirements were not entered into solely in contemplation of such Person becoming a Restricted Subsidiary of the Borrower, (iii) represent Indebtedness of a Restricted Subsidiary of the Borrower that is not a Guarantor to the extent such Indebtedness is permitted by Section 10.1 so long as such Contractual Requirement applies only to such Subsidiary, (iv) arise pursuant to agreements entered into with respect to any sale, transfer, lease or other Disposition permitted by Section 10.4 and applicable solely to assets under such sale, transfer, lease or other Disposition, (v) are customary provisions in joint venture agreements and other similar agreements permitted by Section 10.5 and applicable solely to joint ventures or otherwise arise in agreements which restrict the Disposition or distribution of assets or property in oil and gas leases, joint operating agreements, joint exploration and/or development agreements, participation agreements and other similar agreements entered into in the ordinary course of the oil and gas exploration and development business, (vi) are negative pledges and restrictions on Liens in favor of any holder of secured Indebtedness permitted under Section 10.1, but solely to the extent any negative pledge relates to the property financed by or the subject of such

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Indebtedness, (vii) are customary restrictions on leases, subleases, licenses or asset sale agreements otherwise permitted hereby so long as such restrictions relate to the assets subject thereto, (viii) are restrictions imposed by any agreement relating to Indebtedness permitted pursuant to Section 10.1 or Permitted Refinancing Indebtedness thereof to the extent that such restrictions are not materially more restrictive, taken as a whole, than the restrictions contained in the Credit Documents as determined by the Borrower in good faith, (ix) are customary provisions restricting subletting or assignment of any lease governing a leasehold interest of the Borrower or any Subsidiary, (x) are customary provisions restricting assignment of any agreement entered into in the ordinary course of business, (xi) restrict the use of cash or other deposits imposed by customers under contracts entered into in the ordinary course of business, (xii) are imposed by Requirements of Law, (xiii) exist under any documentation governing any Permitted Refinancing Indebtedness incurred to Refinance any Indebtedness but only to the extent such Contractual Requirement is not materially more restrictive, taken as a whole, than the Contractual Requirement in the Indebtedness being refinanced, (xiv) customary net worth provisions contained in real property leases entered into by Subsidiaries of the Borrower, so long as the Borrower has determined in good faith that such net worth provisions would not reasonably be expected to impair the ability of the Borrower and its Subsidiaries to meet their ongoing obligation and (xv) any restrictions regarding licenses or sublicenses by the Borrower and its Restricted Subsidiaries of intellectual property in the ordinary course of business (in which case such restriction shall relate only to such intellectual property).

Section 10.9Limitation on Subsidiary Distributions. The Borrower will not, and will not permit any of its Restricted Subsidiaries that are not Guarantors to create or otherwise cause or suffer to exist or become effective any consensual encumbrance or consensual restriction on the ability of any such Restricted Subsidiary to pay dividends or make any other distributions to the Borrower or any Restricted Subsidiary on its Stock or with respect to any other interest or participation in, or measured by, its profits or transfer any property to the Borrower or any Restricted Subsidiary except (in each case) for such encumbrances or restrictions existing under or by reason of:

(a)contractual encumbrances or restrictions in effect on the Closing Date, including pursuant to the Credit Documents and any Hedging Obligations;

(b)purchase money obligations for property acquired in the ordinary course of business and Capitalized Lease Obligations that impose restrictions on transferring the property so acquired;

(c)Requirement of Law or any applicable rule, regulation or order;

(d)any agreement or other instrument of a Person acquired by or merged or consolidated with or into the Borrower or any Restricted Subsidiary, or of an Unrestricted Subsidiary that is designated a Restricted Subsidiary, or that is assumed in connection with the acquisition of assets from such Person, in each case that is in existence at the time of such transaction (but not created in contemplation thereof), which encumbrance or restriction is not applicable to any Person, or the properties or assets of any Person, other than the Person and its Subsidiaries, or the property or assets of the Person and its Subsidiaries, so acquired or designated;

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(e)contracts for the sale of assets, including customary restrictions with respect to a Subsidiary of the Borrower pursuant to an agreement that has been entered into for the sale or disposition of all or substantially all of the Stock or assets of such Subsidiary;

(f)secured Indebtedness otherwise permitted to be incurred pursuant to Section 10.1 and Section 10.2 as it relates to the right of the debtor to dispose of the assets securing such Indebtedness;

(g)restrictions on cash or other deposits or net worth imposed by customers under contracts entered into in the ordinary course of business;

(h)other Indebtedness, Disqualified Stock or preferred stock of the Borrower and its Restricted Subsidiaries permitted to be incurred subsequent to the Closing Date pursuant to Section 10.1 and either (A) the provisions relating to such encumbrance or restriction contained in such Indebtedness are no less favorable to the Borrower, taken as a whole, as determined by the board of directors of the Borrower in good faith, than the provisions contained in this Agreement as in effect on the Closing Date or (B) any such encumbrance or restriction contained in such Indebtedness does not prohibit (except upon a default or an event of default thereunder) the payment of dividends in an amount sufficient, as determined by the board of directors of the Borrower in good faith, to make scheduled payments of cash interest on the Loans when due;

(i)customary provisions in joint venture agreements or agreements governing property held with a common owner and other similar agreements or arrangements relating solely to such joint venture or property or are otherwise customary encumbrances or restrictions imposed pursuant to any agreement of the type described in the definition of “Industry Investment” entered into in the ordinary course of business;

(j)customary provisions contained in leases, sub-leases, licenses, sub-licenses or similar agreements, in each case, entered into in the ordinary course of business;

(k)any agreements entered into with respect to any sale, transfer, lease or other Disposition permitted by Section 10.4 and applicable solely to assets under such sale, transfer, lease or other Disposition; and

(l)any encumbrances or restrictions imposed by any amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings of the contracts, instruments or obligations referred to in Section 10.9(a) through Section 10.9(k) above; provided that such amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings are, in the good faith judgment of the Borrower’s board of directors, no more restrictive in any material respect with respect to such encumbrance and other restrictions taken as a whole than those prior to such amendment, modification, restatement, renewal, increase, supplement, refunding, replacement or refinancing.

Section 10.10Hedge Agreements. The Borrower will not, and will not permit any Restricted Subsidiary to, enter into any Hedge Agreements with any Person other than:

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(a)Hedge Agreements in respect of commodities entered into not for speculative purposes the net notional volumes for which (when aggregated with other commodity Hedge Agreements then in effect, other than puts and floors that are not related to corresponding calls, collars or swaps and with respect to which the Borrower or any Restricted Subsidiary has no payment obligation other than premiums and charges the total amount of which are fixed and known at the time such transaction is entered into, and basis differential swaps on volumes already hedged pursuant to other Hedge Agreements) do not exceed, as of the date the latest hedging transaction is entered into under a Hedge Agreement, 90% of the reasonably anticipated Hydrocarbon production from the Credit Parties’ total Proved Reserves (as forecast based upon the most recent Reserve Report; provided that the Borrower may at any time update any such forecast by providing the Administrative Agent additional information reasonably satisfactory to the Administrative Agent reflecting new reasonably anticipated Hydrocarbon production from new wells or other production improvements (any such information, a “Production Forecast Update”)) for the 66 month period from the date such hedging arrangement is created (the “Ongoing Hedges”).

(b)In addition to the Ongoing Hedges, in connection with a proposed Permitted Acquisition or pending acquisition of Oil and Gas Properties (a “Proposed Acquisition”), the Credit Parties may also enter into incremental hedging contracts with respect to the Credit Parties’ reasonably anticipated projected production from the total Proved Reserves to be acquired pursuant to such Proposed Acquisition, having notional volumes not in excess of 90% of such projected production from the total Proved Reserves to be acquired pursuant to such Proposed Acquisition, for a period not exceeding 48 months (the “Acquisition Hedges”) from the date such hedging arrangement is created during the period between (i) the date on which such Credit Party signs a definitive acquisition agreement in connection with a Proposed Acquisition and (ii) the earliest of (A) the date such Proposed Acquisition is consummated, (B) the date such acquisition is terminated and (C) 90 days after such definitive acquisition agreement was executed (or such longer period as to which the Administrative Agent may agree); provided that to the extent notional volumes hedged by the Credit Parties in connection with a Proposed Acquisition (when aggregated with other commodity Hedge Agreements then in effect) exceed more than 100% of the reasonably anticipated projected production of the Credit Parties (based on the most recently delivered Reserve Report, subject to Production Forecast Updates) prior to such Proposed Acquisition, the Borrower shall maintain Liquidity of not less than 15.0% of the Borrowing Base while the notional volumes hedged by the Credit Parties exceed 100% of such reasonably anticipated projected production of the Credit Parties (based on the most recently delivered Reserve Report, subject to Production Forecast Updates). However, in its sole discretion, the Administrative Agent may require that all such Acquisition Hedges entered into with respect to a Proposed Acquisition be terminated or unwound within 90 days following the date such acquisition is terminated (it being understood, for avoidance of doubt, that the Acquisition Hedges may be permitted as Ongoing Hedges to the extent such Acquisition Hedges could be entered into pursuant to Section 10.10(a)). It is understood that commodity Hedge Agreements which may, from time to time, “hedge” the same volumes, but different elements of commodity risk thereof, shall not be aggregated together when calculating the foregoing limitations on notional volumes.

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(c)Other Hedge Agreements (other than those contemplated in clauses (a) through (b) above and any Hedge Agreements in respect of equity or equity index swaps or options, bond or bond price or bond index swaps or options or forward bond or forward bond price or forward bond index transactions) entered into not for speculative purposes.

(d)If, after the end of any calendar month, the Borrower determines that the aggregate volume of all Ongoing Hedges for which settlement payments were calculated in such calendar month exceeded 100% of actual production of Hydrocarbons in such calendar month, then the Borrower shall terminate, create off-setting positions, allocate volumes to other production for which the Borrower or any Restricted Subsidiaries is marketing, or otherwise unwind existing Hedge Agreements such that, at such time, future hedging volumes will not exceed 100% of reasonably anticipated projected production for the then-current and any succeeding calendar months.

(e)It is understood that for purposes of this Section 10.10, the following Hedge Agreements shall not be deemed speculative or entered into for speculative purposes: (i) any commodity Hedge Agreement intended, at inception of execution, to hedge or manage any of the risks related to existing and or forecasted Hydrocarbon production of the Borrower or its Restricted Subsidiaries (whether or not contracted) and (ii) any Hedge Agreement intended, at inception of execution, (A) to hedge or manage the interest rate exposure associated with any debt securities, debt facilities or leases (existing or forecasted) of the Borrower or its Restricted Subsidiaries, (B) for foreign exchange or currency exchange management, (C) to manage commodity portfolio exposure associated with changes in interest rates or (D) to hedge any exposure that the Borrower or its Restricted Subsidiaries may have to counterparties under other Hedge Agreements such that the combination of such Hedge Agreements is not speculative taken as a whole.

(f)For purposes of entering into or maintaining Ongoing Hedges under Section 10.10(a), forecasts of reasonably projected Hydrocarbon production volumes and reasonably anticipated Hydrocarbon production from the Credit Parties’ total Proved Reserves based upon the Initial Reserve Report or the most recent Reserve Report delivered pursuant to Section 9.14(a), as applicable, shall be revised to account for any increase or decrease therein anticipated because of information obtained by Borrower or any other Credit Party subsequent to the publication of such Reserve Report including the Borrower’s or any other Credit Party’s internal forecasts of production decline rates for existing wells and additions to or deletions from anticipated future production from new wells and acquisitions coming on stream or failing to come on stream.

(g)Notwithstanding anything to the contrary herein, in no event shall any Hedge Agreement with any party other than a Hedge Bank contain any requirement, agreement or covenant for any Credit Party to post collateral or margin.

Section 10.11Financial Performance Covenants.

(a)Consolidated Total Debt to Consolidated EBITDAX Ratio. Commencing with the Test Period ending September 30, 2021, the Borrower will not permit the

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Consolidated Total Debt to Consolidated EBITDAX Ratio as of the last day for any Test Period to be greater than 3.5 to 1.0.

(b)Current Ratio. Commencing with the Test Period ending September 30, 2021, the Borrower will not permit the Current Ratio as of the last day of any Test Period to be less than 1.0 to 1.0.

ARTICLE XI
Events of Default

Upon the occurrence of any of the following specified events (each an “Event of Default”):

Section 11.1Payments. The Borrower shall (a) default in the payment when due of any principal of the Loans or (b) default, and such default shall continue for five or more days, in the payment when due of any interest on the Loans or any Unpaid Drawings, fees or of any other amounts owing hereunder or under any other Credit Document (other than any amount referred to in Section 11.1(a) above).

Section 11.2Representations, Etc. Any representation, warranty or statement made or deemed made by any Credit Party herein or in any other Credit Document or any certificate delivered or required to be delivered pursuant hereto or thereto shall prove to be untrue in any material respect on the date as of which made or deemed made.

Section 11.3Covenants. Any Credit Party shall:

(a)default in the due performance or observance by it of any term, covenant or agreement contained in Section 9.1(d)(i), 9.5 (solely with respect to the Borrower), 9.17, 9.18, 9.19 or Section 10 (provided that any Default due to a breach of Section 10.11 is subject to a cure pursuant to Section 11.13); or

(b)default in the due performance or observance by it of any term, covenant or agreement (other than those referred to in Section 11.1 or Section 11.2 or Section 11.3(a)) contained in this Agreement or any Security Document and such default shall continue unremedied for a period of at least 30 days after receipt of written notice thereof by the Borrower from the Administrative Agent.

Section 11.4Default Under Other Agreements.

(a)The Borrower or any of the Restricted Subsidiaries shall (i) default in any payment with respect to any Indebtedness (other than Indebtedness described in Section 11.1) in excess of $75,000,000, beyond the period of grace, if any, provided in the instrument or agreement under which such Indebtedness was created or (ii) default in the observance or performance of any agreement or condition relating to any such Indebtedness or contained in any instrument or agreement evidencing, securing or relating thereto, or any other event shall occur or condition exist (other than, (1) with respect to Indebtedness consisting of any Hedging Obligations, termination events or equivalent events pursuant to the terms of the related Hedge Agreements, (2) any event requiring prepayment pursuant to customary asset sale or change of control provisions and (3) secured Indebtedness that becomes due as a result of a Disposition (including as a

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result of Casualty Event) of the property or assets securing such Indebtedness permitted under this Agreement), the effect of which default or other event or condition is to cause, or to permit the holder or holders of such Indebtedness (or a trustee or agent on behalf of such holder or holders) to cause, any such Indebtedness to become due or to be repurchased, prepaid, defeased or redeemed (automatically or otherwise), or an offer to repurchase, prepay, defease or redeem such Indebtedness to be made, prior to its stated maturity, unless, in the case of each of the foregoing, such holder or holders shall have (or through its or their trustee or agent on its or their behalf) waived such default in a writing to the Borrower; or

(b)without limiting the provisions of clause (a) above, any such default under any such Indebtedness shall cause such Indebtedness to be declared to be due and payable, or required to be prepaid other than by a regularly scheduled required prepayment or as a mandatory prepayment (and (i) with respect to Indebtedness consisting of any Swap Obligations, other than due to a termination event or equivalent event pursuant to the terms of the related Hedge Agreements, (ii) other than pursuant to customary asset sale or change of control provisions and (iii) other than secured Indebtedness that becomes due as a result of a Disposition (including as a result of Casualty Event) of the property or assets securing such Indebtedness permitted under this Agreement), prior to the stated maturity thereof.

Section 11.5Bankruptcy, Etc. The Borrower or any Specified Subsidiary shall commence a voluntary case, proceeding or action concerning itself under (a) Title 11 of the United States Code entitled “Bankruptcy”; or (b) in the case of any Foreign Subsidiary that is a Specified Subsidiary, any domestic or foreign law relating to bankruptcy, judicial management, insolvency, reorganization, administration or relief of debtors in effect in its jurisdiction of incorporation, in each case as now or hereafter in effect, or any successor thereto (collectively, the “Bankruptcy Code”); or an involuntary case, proceeding or action is commenced against the Borrower or any Specified Subsidiary and the petition is not dismissed within 60 days after commencement of the case, proceeding or action or, in connection with any such voluntary proceeding or action, the Borrower or any Specified Subsidiary commences any other proceeding or action under any reorganization, arrangement, adjustment of debt, relief of debtors, dissolution, insolvency or liquidation or similar law of any jurisdiction whether now or hereafter in effect relating to the Borrower or any Specified Subsidiary; or a custodian (as defined in the Bankruptcy Code), receiver, receiver manager, trustee or similar Person is appointed for, or takes charge of, all or substantially all of the property of the Borrower or any Specified Subsidiary; or there is commenced against the Borrower or any Specified Subsidiary any such proceeding or action that remains undismissed for a period of 60 days; or any order of relief or other order approving any such case or proceeding or action is entered; or the Borrower or any Specified Subsidiary suffers any appointment of any custodian, receiver, receiver manager, trustee or the like for it or any substantial part of its property to continue undischarged or unstayed for a period of 60 days; or the Borrower or any Specified Subsidiary makes a general assignment for the benefit of creditors.

Section 11.6ERISA.

(a)Any Plan shall fail to satisfy the minimum funding standard required for any plan year or part thereof or a waiver of such standard or extension of any amortization period is sought or granted under Section 412 of the Code; any Plan is or

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shall have been terminated or is the subject of termination proceedings under ERISA (including the giving of written notice thereof); an event shall have occurred or a condition shall exist in either case entitling the PBGC to terminate any Plan or to appoint a trustee to administer any Plan (including the giving of written notice thereof); any Plan shall have an accumulated funding deficiency (whether or not waived); the Borrower or any ERISA Affiliate has incurred or is likely to incur a liability to or on account of a Plan under Section 409, 502(i), 502(l), 515, 4062, 4063, 4064, 4069, 4201 or 4204 of ERISA or Section 4971 or 4975 of the Code (including the giving of written notice thereof);

(b)there would result from any event or events set forth in Section 11.6(a) the imposition of a lien, the granting of a security interest, or a liability, or the reasonable likelihood of incurring a lien, security interest or liability; and

(c)such lien, security interest or liability will or would be reasonably likely to have a Material Adverse Effect.

Section 11.7Guarantee. The Guarantee or any material provision thereof shall cease to be in full force or effect (other than pursuant to the terms hereof and thereof) or any Guarantor or any other Credit Party shall deny or disaffirm in writing any such Guarantor’s obligations under the Guarantee are in effect or legal, valid and binding obligations (other than pursuant to the terms hereof or thereof).

Section 11.8Security Documents. The Security Agreement, Mortgage or any other Security Document pursuant to which the assets of the Borrower or any Credit Party are pledged as Collateral or any material provision thereof shall cease to be in full force or effect (other than pursuant to the terms hereof or thereof) or any grantor thereunder or any other Credit Party shall deny or disaffirm in writing any grantor’s obligations under the Security Agreement, the Mortgage or any other Security Document are in effect or legal, valid and binding obligations (other than pursuant to the terms hereof or thereof).

Section 11.9Judgments. One or more monetary judgments or decrees shall be entered against the Borrower or any of the Restricted Subsidiaries involving a liability in excess of $75,000,000 in the aggregate for all such judgments and decrees for the Borrower and the Restricted Subsidiaries (to the extent not paid or covered by insurance provided by a carrier not disputing coverage) and any such judgments or decrees shall not have been satisfied, vacated, discharged or stayed or bonded pending appeal within 60 days after the entry thereof.

Section 11.10Change of Control. A Change of Control shall occur.

Section 11.11Intercreditor Agreement. (i) Any of the Obligations of the Credit Parties under the Credit Documents for any reason shall cease to be (x) “Senior Debt,” “Senior Indebtedness,” “Guarantor Senior Debt” or “Senior Secured Financing” (or any comparable term) under, and as defined in, any document governing Permitted Junior Lien Debt Document or (y) “Controlling Senior Obligations,” “Initial Credit Agreement Obligations” or “Senior Obligations” (or any comparable term) under, and as defined in, any Customary Intercreditor Agreement or (ii) the subordination provisions set forth in any Permitted Junior Lien Debt Document shall, in whole or in part, cease to be effective or cease to be legally valid, binding and enforceable against the holders of such Permitted Junior Lien Debt, if applicable.

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then, and in any such event, and at any time thereafter, if any Event of Default shall then be continuing, the Administrative Agent may and, upon the written request of the Majority Lenders, shall, by written notice to the Borrower, take any or all of the following actions, without prejudice to the rights of the Administrative Agent or any Lender to enforce its claims against the Borrower or any other Credit Party, except as otherwise specifically provided for in this Agreement (provided that, if an Event of Default specified in Section 11.5 shall occur, the result that would occur upon the giving of written notice by the Administrative Agent as specified in clauses (a), (b) and (d) below shall occur automatically without the giving of any such notice): (a) declare the Total Commitment terminated, whereupon the Commitment of each Lender, as the case may be, shall forthwith terminate immediately and any fees theretofore accrued shall forthwith become due and payable without any other notice of any kind; (b) declare the principal of and any accrued interest and fees in respect of any or all Loans and any or all Obligations owing hereunder and under the other Credit Documents to be, whereupon the same shall become, forthwith due and payable without presentment, demand, protest or other notice of any kind, all of which are hereby waived by the Borrower; (c) terminate any outstanding Letter of Credit that may be terminated in accordance with its terms; and/or (d) direct the Borrower to pay (and the Borrower agrees that upon receipt of such notice, or upon the occurrence of an Event of Default specified in Section 11.5, it will pay) to the Administrative Agent at the Administrative Agent’s Office such additional amounts of cash, to be held as security for the Borrower’s respective reimbursement obligations for Drawings that may subsequently occur thereunder, equal to the aggregate Stated Amount of all Letters of Credit issued and then outstanding. In addition, after the occurrence and during the continuance of an Event of Default, the Administrative Agent and the Lenders will have all other rights and remedies available at law and equity.

Section 11.12Application of Proceeds. Any amount received by the Administrative Agent or the Collateral Agent from any Credit Party (or from proceeds of any Collateral) following any acceleration of the Obligations under this Agreement or any Event of Default under Section 11.5 shall be applied:

(a)first, to payment or reimbursement of that portion of the Obligations constituting fees, expenses and indemnities payable to the Administrative Agent and/or Collateral Agent in each Person’s capacity as such;

(b)second, to payment of that portion of the Obligations constituting fees, expenses and indemnities (other than principal, interest and Letter of Credit Fees) payable to the Lenders and any Letter of Credit Issuer arising under the Credit Documents, ratably among them in proportion to the respective amounts described in this clausesecond;

(c)third, to payment of that portion of the Obligations constituting accrued and unpaid Letter of Credit Fees and interest on the Loans and Unpaid Drawings, ratably among the Lenders and the Letter of Credit Issuers, in proportion to the respective amounts described in this clausethird payable to them;

(d)fourth, (a) to payment of that portion of the Obligations constituting unpaid principal of the Loans, the Unpaid Drawings and Obligations then owing under Secured Hedge Agreements and the Secured Cash Management Agreements and (b) to Cash Collateralize

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that portion of Letters of Credit Outstanding comprising the aggregate undrawn amount of Letters of Credit to the extent not otherwise Cash Collateralized by the Borrower pursuant to Section 3.8, ratably among the Lenders, the Letter of Credit Issuers, the Hedge Banks and the Cash Management Banks in proportion to the respective amounts described in this clause fourth held by them; provided that (x) any such amounts applied pursuant to the foregoing clause (b) shall be paid to the Administrative Agent for the ratable account of the applicable Letter of Credit Issuer to Cash Collateralize such Letters of Credit, (y) subject to Section 3.8, amounts used to Cash Collateralize the aggregate undrawn amount of Letters of Credit pursuant to this clausefourth shall be applied to satisfy drawings under such Letters of Credit as they occur and (z) upon the expiration of any Letter of Credit, the pro rata share of cash collateral attributable to such expired Letter of Credit shall be distributed in accordance with this clausefourth;

(e)fifth, to the payment of all other Obligations that are due and payable to the Administrative Agent and the other Secured Parties on such date, ratably based upon the respective aggregate amounts of all such Obligations owing to the Administrative Agent and the other Secured Parties on such date; and

(f)sixth, any surplus then remaining, after all of the Obligations then due shall have been indefeasibly paid in full in cash, shall be paid to the Borrower or its successors or assigns or to whomever may be lawfully entitled to receive the same or as a court of competent jurisdiction may award.

Notwithstanding the foregoing, amounts received from any Credit Party that is not an “eligible contract participant” under the Commodity Exchange Act shall not be applied to any Excluded Swap Obligations; it being understood, that if any amount is applied to any Obligations other than Excluded Swap Obligations as a result of this clause, Administrative Agent shall make such adjustments as it reasonably determines are appropriate to distributions pursuant to priority fourth and fifth above from amounts received from “eligible contract participants” under the Commodity Exchange Act to ensure, as nearly as possible, that the proportional aggregate recoveries with respect to Obligations described in priority fourth and fifth above by the holders of any Excluded Swap Obligations are the same as the proportional aggregate recoveries with respect to other Obligations pursuant to priority fourth and fifth above.

Section 11.13Equity Cure. (a) Notwithstanding anything to the contrary contained in this Section 11 or any Credit Document, in the event that the Borrower fails to comply with the Financial Performance Covenants, then until the expiration of the tenth Business Day subsequent to the date the compliance certificate for calculating such Financial Performance Covenants is required to be delivered pursuant to Section 9.1(c) (the “Cure Deadline”), the Borrower shall have the right to cure such failure (the “Cure Right”) by receiving cash proceeds (which cash proceeds shall be received no earlier than the first day of the applicable fiscal quarter for which there is a failure to comply with the Financial Performance Covenants and no later than the expiration of such tenth Business Day) from an issuance of Stock or Stock Equivalents (other than Disqualified Stock) for cash as a cash capital contribution (or from any other contribution of cash to capital or issuance or sale of any other Stock or Stock Equivalents on terms reasonably acceptable to the Administrative Agent), and upon receipt by the Borrower of such cash proceeds (such cash amount being referred to as the “Cure Amount”) pursuant to the exercise of such Cure

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Right, the Financial Performance Covenants shall be recalculated giving effect to the following pro forma adjustments:

(i)Consolidated EBITDAX and/or Current Assets, as applicable, shall be increased, solely for the purpose of determining the existence of an Event of Default resulting from a breach of the Financial Performance Covenants with respect to any Test Period that includes the fiscal quarter for which the Cure Right was exercised and not for any other purpose under this Agreement, by an amount equal to the Cure Amount;

(ii)Consolidated Total Debt, for such Test Period shall be decreased solely to the extent proceeds of the Cure Amount are actually applied to prepay any such Indebtedness (provided that any such Indebtedness so prepaid shall be a permanent repayment of such Indebtedness and termination of commitments thereunder) included in the calculation of Consolidated Total Debt;

(iii)if, after giving effect to the foregoing recalculations, the Borrower shall then be in compliance with the Financial Performance Covenants, the Borrower shall be deemed to have satisfied the requirements of the Financial Performance Covenants as of the relevant date of determination with the same effect as though there had been no failure to comply therewith at such date, and the applicable breach or default of the Financial Performance Covenants that had occurred shall be deemed cured for the purposes of this Agreement; provided that (A) in each period of four consecutive fiscal quarters there shall be at least two fiscal quarters in which no Cure Right is made, (B) there shall be a maximum of five Cure Rights made during the term of this Agreement, (C) each Cure Amount shall be no greater than the amount required to cause the Borrower to be in compliance with the Financial Performance Covenants (such amount, the “Necessary Cure Amount”); provided further that if the Cure Right is exercised prior to the date financial statements are required to be delivered for such fiscal quarter then the Cure Amount shall be equal to the amount reasonably determined by the Borrower in good faith that is required for purposes of complying with the Financial Performance Covenants for such fiscal quarter (such amount, the “Expected Cure Amount”), (D) all Cure Amounts shall be disregarded for the purposes of any financial ratio determination under the Credit Documents other than for determining compliance with the Financial Performance Covenants and (E) no Lender or Letter of Credit Issuer shall be required to make any extension of credit hereunder during the 10 Business Day period referred to above, unless the Borrower shall have received the Cure Amount; and

(iv)upon receipt by the Administrative Agent of written notice, on or prior to the Cure Deadline, that the Borrower intends to exercise the Cure Right in respect of a fiscal quarter, the Lenders shall not be permitted to accelerate Loans held by them or to exercise remedies against the Collateral on the basis of a failure to comply with the requirements of the Financial Performance Covenants, unless such failure is not cured pursuant to the exercise of the Cure Right on or prior to the Cure Deadline.

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(b)Expected Cure Amount. Notwithstanding anything herein to the contrary, to the extent that the Expected Cure Amount is (i) greater than the Necessary Cure Amount, then such difference may be used for the purposes of determining the Applicable Equity Amount and (ii) less than the Necessary Cure Amount, then not later than the applicable Cure Deadline, the Borrower must receive cash proceeds from issuance of Stock or Stock Equivalents (other than Disqualified Stock) or a cash capital contribution, which cash proceeds received by Borrower shall be equal to the shortfall between such Expected Cure Amount and such Necessary Cure Amount.

Section 11.14Action by Secured Parties. Without limiting the provisions of Section 13.3 or Section 13.8(b), each Letter of Credit Issuer and each Lender, and each Hedge Bank and Cash Management Bank, by its acceptance of the benefits of the Security Documents, agrees that:

(a)it will not, without the prior written consent of the Administrative Agent, exercise any right to set off or apply any deposits of any kind, or any other obligations owing by it to or for the order of the Borrower or any of its Subsidiaries, against any Hedging Obligations or Cash Management Obligations or any other amounts secured by Liens on Collateral; provided that nothing contained in this Section 11.14 or elsewhere in this Agreement shall impair the right of any Hedge Bank to declare an early termination date in respect of any Hedge Agreements, or to undertake payment or close-out netting or to otherwise setoff trades or transactions then existing under such Hedge Agreements;

(b)it will not, without the prior written consent of the Administrative Agent, (i) pursue or attempt to realize upon any Collateral or any part or portion thereof, or (ii) bid on any Collateral at a foreclosure sale, or take possession or operate any portion of the Collateral which constitutes real property;

(c)it will not transfer any portion of its rights in respect of any Secured Hedge Agreement or Hedging Obligationsor Secured Cash Management Agreement or Cash Management Obligations, unless the assignee agrees in writing to be bound by the terms of this Section 11.14 and a copy of such writing is delivered to the Administrative Agent; and

(d)if it exercises any right of setoff in contravention of this Section 11.14 or in contravention of Section 13.8(b), it shall indemnify the Administrative Agent and each other Lender, the Letter of Credit Issuer, each Hedge Bank and each Cash Management Bank, from any and all losses, expenses and damages (including attorneys’ fees and costs) it shall suffer or incur by reason of such setoff or other action, including losses, expenses and damages (including attorneys’ fees and costs) caused by or resulting from the release, loss or waiver of any Collateral or any Lien thereon securing Obligations, or the unenforceability of any Security Document or Credit Document or any assertions that any Collateral or Lien securing Obligations thereon was released, lost or waived.

The provisions of this Section 11.14 shall apply to the Letter of Credit Issuer, all Lenders, all Hedge Banks, all Cash Management Banks and their respective successors and assigns. The provisions of this Section 11.14 are solely for the benefit of the Administrative Agent, the Letter of Credit Issuer, the Lenders, the Hedge Banks and the Cash Management Banks, and neither the

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Borrower nor any Subsidiary shall have rights as a third party beneficiary of any such provisions. The provisions of this Section 11.14 are not intended to nor shall override, alter or amend any rights or obligations set forth in Section 12 that inure to the benefit of the Borrower.

ARTICLE XII
The Agents

Section 12.1Appointment.

(a)Each Lender hereby irrevocably designates and appoints the Administrative Agent as the agent of such Lender under this Agreement and the other Credit Documents and irrevocably authorizes the Administrative Agent, in such capacity, to take such action on its behalf under the provisions of this Agreement and the other Credit Documents and to exercise such powers and perform such duties as are expressly delegated to the Administrative Agent by the terms of this Agreement and the other Credit Documents, together with such other powers as are reasonably incidental thereto. The provisions of this Section 12 (other than Section 12.1(c) with respect to the Lead Arrangers and Section 12.9 with respect to the Borrower) are solely for the benefit of the Agents and the Lenders, and the Borrower shall not have rights as third party beneficiary of any such provision. Notwithstanding any provision to the contrary elsewhere in this Agreement, the Administrative Agent shall not have any duties or responsibilities, except those expressly set forth herein, or any fiduciary relationship with any Lender, and no implied covenants, functions, responsibilities, duties, obligations or liabilities shall be read into this Agreement or any other Credit Document or otherwise exist against the Administrative Agent.

(b)The Administrative Agent, each Lender and each Letter of Credit Issuer hereby irrevocably designate and appoint the Collateral Agent as the agent with respect to the Collateral, and each of the Administrative Agent, each Lender and the Letter of Credit Issuer irrevocably authorizes the Collateral Agent, in such capacity, to take such action on its behalf under the provisions of this Agreement and the other Credit Documents and to exercise such powers and perform such duties as are expressly delegated to the Collateral Agent by the terms of this Agreement and the other Credit Documents, together with such other powers as are reasonably incidental thereto. Notwithstanding any provision to the contrary elsewhere in this Agreement, the Collateral Agent shall not have any duties or responsibilities except those expressly set forth herein, or any fiduciary relationship with any of the Administrative Agent, the Lenders or the Letter of Credit Issuers, and no implied covenants, functions, responsibilities, duties, obligations or liabilities shall be read into this Agreement or any other Credit Document or otherwise exist against the Collateral Agent.

(c)Each Lead Arranger, in its capacity as such, shall not have any obligations, duties or responsibilities under this Agreement but shall be entitled to all benefits of this Section 12.

Section 12.2Delegation of Duties. The Administrative Agent and the Collateral Agent may each execute any of its duties under this Agreement and the other Credit Documents by or

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through agents, sub-agents, employees or attorneys-in-fact and shall be entitled to advice of counsel concerning all matters pertaining to such duties. Neither the Administrative Agent nor the Collateral Agent shall be responsible for the negligence or misconduct of any agents, sub-agents or attorneys-in-fact selected by it in the absence of gross negligence or willful misconduct (as determined in the final judgment of a court of competent jurisdiction).

Section 12.3Exculpatory Provisions. No Agent nor any of its officers, directors, employees, agents, attorneys-in-fact or Affiliates shall be (a) liable for any action lawfully taken or omitted to be taken by any of them under or in connection with this Agreement or any other Credit Document (except for its or such Person’s own gross negligence or willful misconduct, as determined in the final judgment of a court of competent jurisdiction, in connection with its duties expressly set forth herein) or (b) responsible in any manner to any of the Lenders or any participant for any recitals, statements, representations or warranties made by any of the Borrower, any other Credit Party or any officer thereof contained in this Agreement or any other Credit Document or in any certificate, report, statement or other document referred to or provided for in, or received by such Agent under or in connection with, this Agreement or any other Credit Document or for the value, validity, effectiveness, genuineness, enforceability or sufficiency of this Agreement or any other Credit Document, or the perfection or priority of any Lien or security interest created or purported to be created under the Security Documents, or for any failure of the Borrower or any other Credit Party to perform its obligations hereunder or thereunder. No Agent shall be under any obligation to any Lender to ascertain or to inquire as to the observance or performance of any of the agreements contained in, or conditions of, this Agreement or any other Credit Document, or to inspect the properties, books or records of any Credit Party or any Affiliate thereof. The Collateral Agent shall not be under any obligation to the Administrative Agent, any Lender or any Letter of Credit Issuer to ascertain or to inquire as to the observance or performance of any of the agreements contained in, or conditions of, this Agreement or any other Credit Document, or to inspect the properties, books or records of any Credit Party.

Section 12.4Reliance by Agents. The Administrative Agent and the Collateral Agent shall be entitled to rely, and shall be fully protected in relying, upon any writing, resolution, notice, consent, certificate, affidavit, letter, telecopy, telex or teletype message, statement, order or other document or instruction believed by it to be genuine and correct and to have been signed, sent or made by the proper Person or Persons and upon advice and statements of legal counsel (including counsel to the Borrower), independent accountants and other experts selected by the Administrative Agent or the Collateral Agent. The Administrative Agent may deem and treat the Lender specified in the Register with respect to any amount owing hereunder as the owner thereof for all purposes unless a written notice of assignment, negotiation or transfer thereof shall have been filed with the Administrative Agent. The Administrative Agent and the Collateral Agent shall be fully justified in failing or refusing to take any action under this Agreement or any other Credit Document unless it shall first receive such advice or concurrence of the Majority Lenders as it deems appropriate or it shall first be indemnified to its satisfaction by the Lenders against any and all liability and expense that may be incurred by it by reason of taking or continuing to take any such action. The Administrative Agent and the Collateral Agent shall in all cases be fully protected in acting, or in refraining from acting, under this Agreement and the other Credit Documents in accordance with a request of the Majority Lenders, and such request and any action taken or failure to act pursuant thereto shall be binding upon all the Lenders and all future holders of the Loans; provided that the Administrative Agent and

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Collateral Agent shall not be required to take any action that, in its opinion or in the opinion of its counsel, may expose it to liability or that is contrary to any Credit Document or applicable Requirements of Law. For purposes of determining compliance with the conditions specified in Sections 6 and 7 on the Closing Date, each Lender that has signed this Agreement shall be deemed to have consented to, approved or accepted or to be satisfied with, each document or other matter required thereunder to be consented to or approved by or acceptable or satisfactory to a Lender unless the Administrative Agent shall have received notice from such Lender prior to the proposed Closing Date specifying its objection thereto.

Section 12.5Notice of Default. Neither the Administrative Agent nor the Collateral Agent shall be deemed to have knowledge or notice of the occurrence of any Default or Event of Default hereunder unless the Administrative Agent or Collateral Agent, as applicable, has received notice from a Lender or the Borrower referring to this Agreement, describing such Default or Event of Default and stating that such notice is a “notice of default”. In the event that the Administrative Agent receives such a notice, it shall give notice thereof to the Lenders and the Collateral Agent. The Administrative Agent shall take such action with respect to such Default or Event of Default as shall be reasonably directed by the Majority Lenders; provided that unless and until the Administrative Agent shall have received such directions, the Administrative Agent may (but shall not be obligated to) take such action, or refrain from taking such action, with respect to such Default or Event of Default as it shall deem advisable in the best interests of the Lenders.

Section 12.6Non-Reliance on Administrative Agent, Collateral Agent and Other Lenders. Each Lender expressly acknowledges that neither the Administrative Agent nor the Collateral Agent nor any of their respective officers, directors, employees, agents, attorneys-in-fact or Affiliates has made any representations or warranties to it and that no act by the Administrative Agent or Collateral Agent hereinafter taken, including any review of the affairs of the Borrower or any other Credit Party, shall be deemed to constitute any representation or warranty by the Administrative Agent or Collateral Agent to any Lender or any Letter of Credit Issuer. Each Lender and each Letter of Credit Issuer represents to the Administrative Agent and the Collateral Agent that it has, independently and without reliance upon the Administrative Agent, Collateral Agent or any other Lender, and based on such documents and information as it has deemed appropriate, made its own appraisal of and investigation into the business, operations, property, financial and other condition and creditworthiness of the Borrower and each other Credit Party and made its own decision to make its Loans hereunder and enter into this Agreement. Each Lender also represents that it will, independently and without reliance upon the Administrative Agent, Collateral Agent or any other Lender, and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit analysis, appraisals and decisions in taking or not taking action under this Agreement and the other Credit Documents, and to make such investigation as it deems necessary to inform itself as to the business, operations, property, financial and other condition and creditworthiness of the Borrower and any other Credit Party. Except for notices, reports and other documents expressly required to be furnished to the Lenders by the Administrative Agent hereunder, neither the Administrative Agent nor the Collateral Agent shall have any duty or responsibility to provide any Lender with any credit or other information concerning the business, assets, operations, properties, financial condition, prospects or creditworthiness of the Borrower or any other Credit Party that may come into the possession of the Administrative Agent or Collateral Agent any of their respective officers, directors, employees, agents, attorneys-in-fact or Affiliates.

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Section 12.7Indemnification. The Lenders agree to indemnify the Administrative Agent, the Collateral Agent and each Letter of Credit Issuer, each in its capacity as such (to the extent not reimbursed by the Credit Parties and without limiting the obligation of the Credit Parties to do so), ratably according to their respective portions of the Commitments or Loans, as applicable, outstanding in effect on the date on which indemnification is sought (or, if indemnification is sought after the date upon which the Commitments shall have terminated and the Loans shall have been paid in full, ratably in accordance with their respective portions of the Total Exposure in effect immediately prior to such date), from and against any and all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind whatsoever that may at any time occur (including at any time following the payment of the Loans) be imposed on, incurred by or asserted against the Administrative Agent, the Collateral Agent or any Letter of Credit Issuer in any way relating to or arising out of the Commitments, this Agreement, any of the other Credit Documents or any documents contemplated by or referred to herein or therein or the transactions contemplated hereby or thereby or any action taken or omitted by the Administrative Agent, the Collateral Agent or any Letter of Credit Issuer under or in connection with any of the foregoing; provided that no Lender shall be liable to the Administrative Agent, the Collateral Agent or any Letter of Credit Issuer for the payment of any portion of such liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements resulting from such Administrative Agent’s, the Collateral Agent’s or such Letter of Credit Issuer’s, as applicable, gross negligence, bad faith or willful misconduct as determined by a final judgment of a court of competent jurisdiction; provided, further, that no action taken in accordance with the directions of the Majority Lenders (or such other number or percentage of the Lenders as shall be required by the Credit Documents) shall be deemed to constitute gross negligence, bad faith or willful misconduct for purposes of this Section 12.7. In the case of any investigation, litigation or proceeding giving rise to any liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind whatsoever that may at any time occur (including at any time following the payment of the Loans), this Section 12.7 applies whether any such investigation, litigation or proceeding is brought by any Lender or any other Person. Without limitation of the foregoing, each Lender shall reimburse the Administrative Agent and the Collateral Agent upon demand for its ratable share of any costs or out-of-pocket expenses (including attorneys’ fees) incurred by such Agent in connection with the preparation, execution, delivery, administration, modification, amendment or enforcement (whether through negotiations, legal proceedings or otherwise) of, or legal advice rendered in respect of rights or responsibilities under, this Agreement, any other Credit Document, or any document contemplated by or referred to herein, to the extent that such Agent is not reimbursed for such expenses by or on behalf of the Borrower; provided that such reimbursement by the Lenders shall not affect the Borrower’s continuing reimbursement obligations with respect thereto. If any indemnity furnished to any Agent or any Letter of Credit Issuer for any purpose shall, in the opinion of such Agent Letter of Credit Issuer, be insufficient or become impaired, such Agent or Letter of Credit Issuer may call for additional indemnity and cease, or not commence, to do the acts indemnified against until such additional indemnity is furnished; provided, in no event shall this sentence require any Lender to indemnify any Agent or Letter of Credit Issuer against any liability, obligation, loss, damage, penalty, action, judgment, suit, cost, expense or disbursement in excess of such Lender’s pro rata portion thereof; and provided further, this sentence shall not be deemed to require any Lender to indemnify any Agent or Letter of Credit Issuer against any liability, obligation, loss, damage, penalty, action, judgment, suit, cost, expense or disbursement resulting from such Agent’s or Letter of Credit Issuer’s gross negligence, bad faith or willful

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misconduct as determined by a final judgment of a court of competent jurisdiction. The agreements in this Section 12.7 shall survive the payment of the Loans and all other amounts payable hereunder.

Section 12.8Agents in Its Individual Capacities. Each Agent and its Affiliates may make loans to, accept deposits from and generally engage in any kind of business with the Borrower and any other Credit Party as though such Agent were not an Agent hereunder and under the other Credit Documents. With respect to the Loans made by it, each Agent shall have the same rights and powers under this Agreement and the other Credit Documents as any Lender and may exercise the same as though it were not an Agent, and the terms “Lender” and “Lenders” shall include each Agent in its individual capacity.

Section 12.9Successor Agents. Each of the Administrative Agent and Collateral Agent may at any time give notice of its resignation to the Lenders, the Letter of Credit Issuer and the Borrower. If the Administrative Agent and/or Collateral Agent becomes a Defaulting Lender, then such Administrative Agent or Collateral Agent may be removed as the Administrative Agent or Collateral Agent, as the case may be, at the reasonable request of the Borrower and the Required Lenders. Upon receipt of any such notice of resignation or removal, as the case may be, the Majority Lenders shall have the right, subject to the consent of the Borrower (not to be unreasonably withheld or delayed) so long as no Payment or Bankruptcy Event of Default is continuing, to appoint a successor, which shall be a bank with an office in the United States, or an Affiliate of any such bank with an office in the United States. If, in the case of a resignation of a retiring Agent, no such successor shall have been so appointed by the Majority Lenders and shall have accepted such appointment within 30 days after the retiring Agent gives notice of its resignation, then the retiring Agent may on behalf of the Lenders and the Letter of Credit Issuer, appoint a successor Agent meeting the qualifications set forth above. Upon the acceptance of a successor’s appointment as the Administrative Agent or Collateral Agent, as the case may be, hereunder, and upon the execution and filing or recording of such financing statements, or amendments thereto, and such other instruments or notices, as may be necessary or desirable, or as the Majority Lenders may request, in order to continue the perfection of the Liens granted or purported to be granted by the Security Documents, such successor shall succeed to and become vested with all of the rights, powers, privileges and duties of the retiring (or retired) Agent, and the retiring Agent shall be discharged from all of its duties and obligations hereunder or under the other Credit Documents (if not already discharged therefrom as provided above in this Section). The fees payable by the Borrower (following the effectiveness of such appointment) to such Agent shall be the same as those payable to its predecessor unless otherwise agreed between the Borrower and such successor. After the retiring Agent’s resignation hereunder and under the other Credit Documents, the provisions of this Section 12 (including Section 12.7) and Section 13.5 shall continue in effect for the benefit of such retiring Agent, its sub agents and their respective Related Parties in respect of any actions taken or omitted to be taken by any of them while the retiring Agent was acting as an Agent.

Any resignation of any Person as Administrative Agent pursuant to this Section may also constitute its resignation as Letter of Credit Issuer. In such case, upon the acceptance of a successor’s appointment as Administrative Agent hereunder, (a) such successor shall succeed to and become vested with all of the rights, powers, privileges and duties of the retiring Letter of Credit Issuer, (b) the retiring Letter of Credit Issuer shall be discharged from all of their respective duties and obligations hereunder or under the other Credit Documents, and (c) the

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successor Letter of Credit Issuer shall issue letters of credit in substitution for the Letters of Credit, if any, outstanding at the time of such succession or make other arrangements satisfactory to the retiring Letter of Credit Issuer to effectively assume the obligations of the retiring Letter of Credit Issuer with respect to such Letters of Credit.

Section 12.10Withholding Tax. To the extent required by any applicable Requirement of Law, the Administrative Agent may withhold from any payment to any Lender an amount equivalent to any applicable withholding tax. If the Internal Revenue Service or any authority of the United States or other jurisdiction asserts a claim that the Administrative Agent did not properly withhold tax from amounts paid to or for the account of any Lender (because the appropriate form was not delivered, was not properly executed, or because such Lender failed to notify the Administrative Agent of a change in circumstances that rendered the exemption from, or reduction of, withholding tax ineffective, or for any other reason), such Lender shall indemnify the Administrative Agent (to the extent that the Administrative Agent has not already been reimbursed by any applicable Credit Party and without limiting the obligation of any applicable Credit Party to do so) fully for all amounts paid, directly or indirectly, by the Administrative Agent as Tax or otherwise, including penalties, additions to Tax and interest, together with all expenses incurred, including legal expenses, allocated staff costs and any out of pocket expenses. Each Lender hereby authorizes the Administrative Agent to set off and apply any and all amounts at any time owing to such Lender under this Agreement or any other Credit Document against any amount due to the Administrative Agent under this Section 12.10. For the avoidance of doubt, for purposes of this Section 12.10, the term “Lender” includes any Letter of Credit Issuer.

Section 12.11Security Documents and Collateral Agent under Security Documents and Guarantee. Each Secured Party hereby further expressly and irrevocably authorizes and directs the Administrative Agent or Collateral Agent, as applicable, on behalf of and for the benefit of Secured Parties, to be the agent for and representative of the Secured Parties with respect to the Collateral and the Security Documents and irrevocably agrees that it will not take any action that will hinder the automatic release of any security interest, Lien or Guarantee provided for this Agreement or the other Credit Documents. Subject to Section 13.1, without further written consent or authorization from any Secured Party, the Administrative Agent or Collateral Agent, as applicable, shall (a) execute any documents or instruments necessary in connection with a Disposition of assets permitted by this Agreement, (b) release any Lien encumbering any item of Collateral that is the subject of such Disposition of assets or with respect to which Majority Lenders (or such other Lenders as may be required to give such consent under Section 13.1) have otherwise consented, (c) subordinate any Lien to the extent permitted by the terms of this Agreement or (d) release any Guarantor from the Guarantee with respect to which Majority Lenders (or such other Lenders as may be required to give such consent under Section 13.1) have otherwise consented.

Section 12.12Right to Realize on Collateral and Enforce Guarantee. Notwithstanding anything contained in any of the Credit Documents to the contrary, the Borrower, the Agents and each Secured Party hereby agree that (a) (i) no Secured Party shall have any right individually to realize upon any of the Collateral or to enforce any Guarantee, it being understood and agreed that all powers, rights and remedies under the Credit Documents, in connection with any Loan or otherwise may be exercised solely by the Collateral Agent on behalf of the Secured Parties in accordance with the terms thereof and (ii) each Lender (in its

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capacity as such and not, for the avoidance of doubt, in its capacity, if applicable, as an Administrative Agent, Collateral Agent, Hedge Bank or Cash Management Bank), whether or not a party hereto, expressly and irrevocably waives any right to take or institute any actions or proceedings, judicial or otherwise, for any right or remedy or assert any other cause of action against any Credit Party (including the exercise of any right of setoff, rights on account of any banker’s lien or similar claim or other rights of self-help), or institute any actions or proceedings or any other cause of action, or otherwise commence any remedial procedures, against the Borrower and/or any of its Subsidiaries or parent companies with respect to any Collateral or any other property of any such Person, without the prior written consent of the Majority Lenders and the Collateral Agent, including any actions, proceedings, any other cause of action, or any remedial procedures with respect to the Transactions; provided, that, for the avoidance of doubt, (1) this sentence may be enforced against any Lender by the Majority Lenders, the Agents or the Borrower (or any of its Affiliates) and each Lender and the Agents expressly acknowledge that this sentence shall be available as a defense of the Borrower (or any of its Affiliates) in any action, proceeding, cause of action or remedial procedure and (2) this sentence shall not impair or restrict the Agents’ powers, rights and remedies under the Credit Documents exercised in accordance with the terms thereof, and (b) in the event of a foreclosure by the Collateral Agent on any of the Collateral pursuant to a public or private sale or other disposition, the Collateral Agent or any Lender may be the purchaser or licensor of any or all of such Collateral at any such sale or other disposition, and the Collateral Agent, as agent for and representative of the Secured Parties (but not any Lender or Lenders in its or their respective individual capacities unless Majority Lenders shall otherwise agree in writing) shall be entitled, for the purpose of bidding and making settlement or payment of the purchase price for all or any portion of the Collateral sold at any such public sale, to use and apply any of the Obligations as a credit on account of the purchase price for any collateral payable by the Collateral Agent on behalf of the Lenders at such sale or other disposition. Each Lender, whether or not a party hereto, will be deemed, by its acceptance of the benefits of the Collateral and of the Guarantees of the Obligations, to have agreed to the foregoing provisions.

Section 12.13Credit Bidding. The Secured Parties hereby irrevocably authorize the Administrative Agent, at the direction of the Required Lenders, to credit bid all or any portion of the Obligations (including accepting some or all of the Collateral in satisfaction of some or all of the Obligations pursuant to a deed in lieu of foreclosure or otherwise) and in such manner purchase (either directly or through one or more acquisition vehicles) all or any portion of the Collateral (a) at any sale thereof conducted under the provisions of the Bankruptcy Code of the United States, including under Sections 363, 1123 or 1129 of the Bankruptcy Code of the United States, or any similar laws in any other jurisdictions to which a Credit Party is subject or (b) at any other sale or foreclosure or acceptance of collateral in lieu of debt conducted by (or with the consent or at the direction of) the Administrative Agent (whether by judicial action or otherwise) in accordance with any applicable law. In connection with any such credit bid and purchase, the Obligations owed to the Secured Parties shall be entitled to be, and shall be, credit bid on a ratable basis (with Obligations with respect to contingent or unliquidated claims receiving contingent interests in the acquired assets on a ratable basis that would vest upon the liquidation of such claims in an amount proportional to the liquidated portion of the contingent claim amount used in allocating the contingent interests) in the asset or assets so purchased (or in the Stock or Stock Equivalents or debt instruments of the acquisition vehicle or vehicles that are used to consummate such purchase). In connection with any such bid (i) the Administrative Agent shall be authorized to form one or more acquisition vehicles to make a bid, (ii) the

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Administrative Agent shall be authorized to adopt documents providing for the governance of the acquisition vehicle or vehicles (provided that any actions by the Administrative Agent with respect to such acquisition vehicle or vehicles, including any disposition of the assets or Stock or Stock Equivalents thereof shall be governed, directly or indirectly, by the vote of the Required Lenders, irrespective of the termination of this Agreement and without giving effect to the limitations on actions by the Required Lenders contained in 13.1, and (iii) to the extent that Obligations that are assigned to an acquisition vehicle are not used to acquire Collateral for any reason (as a result of another bid being higher or better, because the amount of Obligations assigned to the acquisition vehicle exceeds the amount of debt credit bid by the acquisition vehicle or otherwise), such Obligations shall automatically be reassigned to the Lenders pro rata and the Stock or Stock Equivalents and/or debt instruments issued by any acquisition vehicle on account of the Obligations that had been assigned to the acquisition vehicle shall automatically be cancelled, without the need for any Secured Party or any acquisition vehicle to take any further action.

Section 12.14Administrative Agent May File Proofs of Claim. In case of the pendency of any receivership, insolvency, liquidation, bankruptcy, reorganization, arrangement, adjustment, composition or other judicial proceeding, constituting an Event of Default under Section 11.5, the Administrative Agent (irrespective of whether the principal of any Loan shall then be due and payable as herein expressed or by declaration or otherwise and irrespective of whether the Administrative Agent shall have made any demand on the Borrower) shall be entitled and empowered, by intervention in such proceeding or otherwise:

(a)to file and prove a claim for the whole amount of the principal and interest owing and unpaid in respect of the Loans and all other Indebtedness that are owing and unpaid and to file such other documents as may be necessary or advisable in order to have the claims of the Lenders and the Administrative Agent (including any claim for the reasonable compensation, expenses, disbursements and advances of the Lenders and the Administrative Agent and their respective agents and counsel, to the extent due under Section 13.5) allowed in such judicial proceeding; and

(b)to collect and receive any monies or other property payable or deliverable on any such claims and to distribute the same;

and any custodian, receiver, assignee, trustee, liquidator, sequestrator or other similar official in any such judicial proceeding is hereby authorized by each Lender to make such payments to the Administrative Agent and, in the event that the Administrative Agent shall consent to the making of such payments directly to the Lenders, to pay to the Administrative Agent any amount due for the reasonable compensation, expenses, disbursements and advances of the Administrative Agent and its agents and counsel, to the extent due under Section 13.5.

Nothing contained herein shall be deemed to authorize the Administrative Agent to authorize or consent to or accept or adopt on behalf of any Lender any plan of reorganization, arrangement, adjustment or composition affecting the Indebtedness or the rights of any Lender or to authorize the Administrative Agent to vote in respect of the claim of any Lender in any such proceeding.

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Section 12.15Intercreditor Agreement. (a) Each Lender (and each Person that becomes a Lender hereunder pursuant to Section 13.6 or an Incremental Agreement) hereby irrevocably authorizes and directs the Administrative Agent and the Collateral Agent to enter into any Customary Intercreditor Agreement on behalf of such Lender, in each case, as needed to effectuate the transactions permitted by this Agreement and agrees that the Administrative Agent and the Collateral Agent may take such actions on its behalf as is contemplated by the terms of such applicable intercreditor agreement. Without limiting the provisions of Section 12.2, each Lender hereby irrevocably consents to the Administrative Agent and the Collateral Agent and any successor serving in either such capacity and agrees not to assert any claim (including as a result of any conflict of interest) against the Administrative Agent, the Collateral Agent, or any such successor, arising from the role of the Administrative Agent, the Collateral Agent or such successor under the Credit Documents or any such intercreditor agreement so long as it is either acting in accordance with the terms of such documents and otherwise has not engaged in gross negligence or willful misconduct (as determined in a final and non-appealable judgment by a court of competent jurisdiction). In addition, the Administrative Agent, the Collateral Agent, or any such successor, shall be authorized, without the consent of any Lender, to execute or to enter into amendments of, and amendments and restatements of, the Security Documents, any such intercreditor agreement and any additional and replacement intercreditor agreements, in each case, in order to effect transactions permitted by this Agreement, and to establish certain relative rights as between the holders of the Obligations and the holders of the Indebtedness secured by such Liens junior or pari passu with the Obligations.

Section 12.16Erroneous Payments.

(a)Each Lender and each Letter of Credit Issuer hereby severally agrees that if (i) the Administrative Agent notifies (which such notice shall be conclusive absent manifest error) such Lender or Letter of Credit Issuer that the Administrative Agent has determined in its sole discretion that any funds received by such Lender or Letter of Credit Issuer from the Administrative Agent or any of its Affiliates were erroneously transmitted to, or otherwise erroneously or mistakenly received by, such Lender or Letter of Credit Issuer (whether or not known to such Lender or Letter of Credit Issuer) or (ii) it receives any payment from the Administrative Agent (or any of its Affiliates) (x) that is in a different amount than, or on a different date from, that specified in a notice of payment sent by the Administrative Agent (or any of its Affiliates) with respect to such payment, (y) that was not preceded or accompanied by a notice of payment sent by the Administrative Agent (or any of its Affiliates) with respect to such payment or (z) that such Lender or Letter of Credit Issuer otherwise becomes aware was transmitted, or received, in error or by mistake (in whole or in part) then, in each case an error in payment has been made (any such amounts specified in clauses (i) or (ii) of this Section 12.16(a), whether received as a payment, prepayment or repayment of principal, interest, fees or otherwise; individually and collectively, an “Erroneous Payment”) and the Lender or Letter of Credit Issuer, as the case may be, is deemed to have knowledge of such error at the time of its receipt of such Erroneous Payment and to the extent permitted by applicable law, such Lender or Letter of Credit Issuer shall not assert any right or claim to the Erroneous Payment, and hereby waives, any claim, counterclaim, defense or right of set-off or recoupment with respect to any demand, claim or counterclaim by the

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Administrative Agent for the return of any Erroneous Payments received, including without limitation waiver of any defense based on “discharge for value” or any similar doctrine.

(b)Without limiting the immediately preceding clause (a), each Lender and each Letter of Credit Issuer agrees that, in the case of clause (a)(ii) above, it shall promptly (and, in all events, within one Business Day of its knowledge (or deemed knowledge) of such error) notify the Administrative Agent in writing of such occurrence and, in the case of either clause (a)(i) or (a)(ii) above upon demand from the Administrative Agent, it shall promptly, but in all events no later than two Business Days thereafter, return to the Administrative Agent the amount of any such Erroneous Payment (or portion thereof) as to which such a demand was made in same day funds (in the currency so received), together with interest thereon in respect of each day from and including the date such Erroneous Payment (or portion thereof) was received by such Lender or Letter of Credit Issuer to the date such amount is repaid to the Administrative Agent in same day funds at the greater of the Federal Funds Effective Rate and a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation from time to time in effect.

(c)The Borrower hereby agrees that (x) in the event an Erroneous Payment (or portion thereof) has been demanded by the Administrative Agent pursuant to Section 12.16(b) and has not been recovered from any Lender or Letter of Credit Issuer that has received such Erroneous Payment (or portion thereof) for any reason, the Administrative Agent shall be subrogated to all the rights of such Lender or Letter of Credit Issuer with respect to such amount unless and until such amounts are recovered by the Administrative Agent, (y) an Erroneous Payment shall not pay, prepay, repay, discharge or otherwise satisfy any Obligations owed by the Borrower or any other Credit Party and (z) to the extent that an Erroneous Payment was in any way or at any time credited as payment or satisfaction of any of the Obligations, the Obligations or any part thereof that were so credited, and all rights of the applicable Lender or Letter of Credit Issuer (as subrogated by the Administrative Agent pursuant to the terms of clause (x) above), the Administrative Agent or other Secured Party, as the case may be, shall be reinstated and continue in full force and effect as if such payment or satisfaction had never been received.

(d)The Credit Parties’ agreements, and the Administrative Agent’s, each Letter of Credit Issuer’s and each Lender’s obligations, under this Section 12.16 shall survive the resignation or replacement of the Administrative Agent, any transfer of rights or obligations by, or the replacement of, a Lender, and Payment in Full.

ARTICLE XIII
Miscellaneous

Section 13.1Amendments, Waivers and Releases.

(a)Except as expressly set forth in this Agreement, neither this Agreement nor any other Credit Document, nor any terms hereof or thereof, may be amended,

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supplemented or modified except in accordance with the provisions of this Section 13.1. The Majority Lenders may, or, with the written consent of the Majority Lenders, the Administrative Agent and/or the Collateral Agent shall, from time to time:

(i)enter into with the relevant Credit Party or Credit Parties written amendments, supplements or modifications hereto and to the other Credit Documents for the purpose of adding any provisions to this Agreement or the other Credit Documents or changing in any manner the rights of the Lenders or of the Credit Parties hereunder or thereunder or

(ii)waive in writing, on such terms and conditions as the Majority Lenders or the Administrative Agent and/or Collateral Agent, as the case may be, may specify in such instrument, any of the requirements of this Agreement or the other Credit Documents or any Default or Event of Default and its consequences; provided, however, that each such waiver and each such amendment, supplement or modification shall be effective only in the specific instance and for the specific purpose for which given; provided, further, that no such waiver and no such amendment, supplement or modification shall:

(A)forgive or reduce any portion of any Loan or reduce the stated rate (it being understood that only the consent of the Majority Lenders shall be necessary to waive any obligation of the Borrower to pay interest at the Default Rate or amend Section 2.8(e)), or forgive any portion, or extend the date for the payment (including the Maturity Date), of any principal, interest or fee payable hereunder (other than as a result of waiving the applicability of any post-default increase in interest rates), or extend the final expiration date of any Lender’s Commitment (provided that any Lender, upon the request of the Borrower, may extend the final expiration date of its Commitment without the consent of any other Lender, including the Majority Lenders) or extend the final expiration date of any Letter of Credit beyond the L/C Maturity Date, or increase the amount of the Commitment, Elected Commitment Amount or Maximum Credit Amount of any Lender (provided that, any Lender, upon the request of the Borrower, may increase the amount of its Commitment, Elected Commitment Amount or Maximum Credit Amount without the consent of any other Lender, including the Majority Lenders), or make any Loan, interest, fee or other amount payable in any currency other than Dollars, in each case without the written consent of each Lender directly and adversely affected thereby, or

(B)amend, modify or waive any provision of this Section 13.1, amend or modify any of the provisions of Section 13.8(a) to the extent it would alter the ratable allocation of payments thereunder, consent to the assignment or transfer by the Borrower of its rights and obligations under any Credit Document to which it is a party (except as permitted pursuant to Section 10.3) or alter the order of application set forth in Section 11.12 or modify any definition used in such section if the effect thereof would be to alter the order of payment specified therein, in each case without the written consent of each Lender directly and adversely affected thereby, or

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(C)reduce the percentages specified in the definitions of the terms “Majority Lenders”, “Required Lenders” or “Borrowing Base Required Lenders” without the written consent of each Lender directly and adversely affected thereby, or

(D)amend, modify or waive any provision of Section 12 without the written consent of the then-current Administrative Agent and Collateral Agent, as applicable, or any other former or current Agent to whom Section 12 then applies in a manner that directly and adversely affects such Person, or

(E)amend, modify or waive any provision of Section 3 with respect to any Letter of Credit without the written consent of each Letter of Credit Issuer to whom Section 3 then applies in a manner that directly and adversely affects such Person, or otherwise amend, modify or otherwise affect the rights or duties of any Letter of Credit Issuer without the written consent of such Letter of Credit Issuer, or

(F)release all or substantially all of the Guarantors under the Guarantee (except as expressly permitted by the Guarantee or this Agreement) without the prior written consent of each Lender, or

(G)release all or substantially all of the Collateral under the Security Documents (except as expressly permitted by the Security Documents or this Agreement) without the prior written consent of each Lender, or

(H)amend Section 2.9 so as to permit Interest Period intervals greater than six months without regard to availability to Lenders, without the written consent of each Lender directly and adversely affected thereby, or

(I)increase the Borrowing Base without the written consent of the Borrowing Base Required Lenders (other than Defaulting Lenders) or decrease or maintain the Borrowing Base without the written consent of the Required Lenders (other than Defaulting Lenders); provided that a Scheduled Redetermination and the delivery of a Reserve Report or any other Engineering Report may be postponed by the Majority Lenders; provided further, that it is understood (a) that any waiver (or amendment or modification that would have the effect of a waiver) of the right of the Required Lenders to adjust, or automatic adjustment of, the Borrowing Base under the Borrowing Base Adjustment Provisions in connection with the occurrence of a relevant event giving rise to such right shall require the consent of the Required Lenders and (b) that this clause (I) shall not apply (or be deemed to apply) to any waiver, consent, amendment or other modification that directly or indirectly reduces the amount of, or waives

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the implementation of, any provision that would otherwise reduce the Borrowing Base, or

(J)affect the rights or duties of, or any fees or other amounts payable to, any Agent under this Agreement or any other Credit Document without the prior written consent of such Agent.

(b)Notwithstanding anything to the contrary in the Credit Documents, the provisions of this Agreement or any other Credit Document may be amended by an agreement in writing entered into by the Borrower and the Administrative Agent and/or the Collateral Agent, as applicable, to (i) cure any ambiguity, omission, defect, typographical error, inconsistency or other manifest error, (ii) make administrative or operational changes not adverse to any Lender or make changes favorable to the Lenders or (iii) adhere to any local Requirement of Law or advice of local counsel so long as, in each case, the Lenders shall have received at least five Business Days’ prior written notice thereof and the Administrative Agent shall not have received, within five Business Days of the date of such notice to the Lenders, a written notice from the Majority Lenders stating that the Majority Lenders object to such amendment. Any such waiver and any such amendment, supplement or modification shall apply equally to each of the affected Lenders and shall be binding upon the Borrower, such Lenders, the Administrative Agent and all future holders of the affected Loans. In the case of any waiver, the Borrower, the Lenders and the Administrative Agent shall be restored to their former positions and rights hereunder and under the other Credit Documents after giving effect to such waiver, and any Default or Event of Default waived shall be deemed to be cured and not continuing; it being understood that no such waiver shall extend to any subsequent or other Default or Event of Default or impair any right consequent thereon. In connection with the foregoing provisions, the Administrative Agent may, but shall have no obligations to, with the concurrence of any Lender, execute amendments, modifications, waivers or consents on behalf of such Lender.

(c)Notwithstanding anything to the contrary contained in the Credit Documents, the Administrative Agent and/or the Collateral Agent, as applicable, without the consent of any Lender, shall be permitted (and each Lender hereby directs the Administrative Agent and/or the Collateral Agent) to enter into any amendments, waivers, modifications or supplements to any Customary Intercreditor Agreement, if the Administrative Agent and/or the Collateral Agent, as applicable, would have been permitted hereunder to enter into a new Customary Intercreditor Agreement, which contained the terms set forth in such amendment, waiver, modification or supplement, at the time when such amendment, waiver, modification or supplement is entered into.

(d)Notwithstanding anything to the contrary herein, the Administrative Agent (and, if applicable, the Borrower) may, without the consent of any Lender, enter into amendments or modifications to this Agreement or any of the other Credit Documents or to enter into additional Credit Documents in order to implement any Benchmark Replacement or any Benchmark Replacement Conforming Changes or otherwise effectuate the terms of Section 2.18 in accordance with the terms of Section 2.18.

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(e)Notwithstanding anything to the contrary herein, no Lender consent is required to effect any amendment, modification or supplement to any Customary Intercreditor Agreement, any subordination agreement or other intercreditor agreement or arrangement permitted under this Agreement or in any document pertaining to any Indebtedness permitted hereby that is permitted to be secured by the Collateral (i) that is for the purpose of adding the holders of such secured or subordinated Indebtedness permitted to be incurred under this Agreement (or, in each case, a representative with respect thereto), as parties thereto, as expressly contemplated by the terms of such Customary Intercreditor Agreement, such subordination agreement or such other intercreditor agreement or arrangement permitted under this Agreement, as applicable (it being understood that any such amendment or supplement may make such other changes to the applicable intercreditor agreement as, in the good faith determination of the Administrative Agent, are required to effectuate the foregoing and provided that such other changes are not adverse, in any material respect (taken as a whole), to the interests of the Lenders) or (ii) that is expressly contemplated by any Customary Intercreditor Agreement, any subordination agreement or other intercreditor agreement or arrangement permitted under this Agreement or in any document pertaining to any Indebtedness permitted hereby that is permitted to be secured by the Collateral or (iii) otherwise, with respect to any material amendments, modifications or supplements, to the extent such amendment, modification or supplement is reasonably satisfactory to the Administrative Agent; provided, further, that no such agreement shall amend, modify or otherwise affect the rights or duties of the Administrative Agent or Collateral Agent hereunder or under any other Credit Document without the prior written consent of the Administrative Agent or Collateral Agent, as applicable.

(f)Notwithstanding anything to the contrary contained in the Credit Documents, the Administrative Agent and/or the Collateral Agent, as applicable, and the Borrower may enter into any amendment, modification or waiver of this Agreement or any other Credit Document or enter into any agreement or instrument to effect the granting, perfection, protection, expansion or enhancement of any security interest in any Collateral or property to become Collateral for the benefit of the Secured Parties or as required by any Requirement of Law to give effect to, protect or otherwise enhance the rights or benefits of any Secured Party under the Credit Documents without the consent of any Lender.

(g)Notwithstanding the foregoing, this Agreement may be amended (or amended and restated) with the written consent of the Majority Lenders, the Administrative Agent and the Borrower (a) to add one or more additional credit or debt facilities to this Agreement and to permit the extensions of credit from time to time outstanding thereunder and the accrued interest and fees in respect thereof to share ratably in the benefits of this Agreement and the other Credit Documents with the Loans and the Commitments and the accrued interest and fees in respect thereof and (b) to include appropriately the Lenders holding such credit or debt facilities in any determination of the Majority Lenders and the Required Lenders on substantially the same basis as the Lenders prior to such inclusion.

(h)In addition, notwithstanding the foregoing, this Agreement may be amended with the written consent of the Administrative Agent, the Borrower and the

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Lenders providing the Replacement Loans (as defined below) to permit the refinancing of all outstanding Loans of any Class (“Replaced Loans”) with replacement loans (“Replacement Loans”) hereunder; provided that (i) the aggregate principal amount of such Replacement Loans shall not exceed the aggregate principal amount of such Replaced Loans, plus accrued interest, fees, premiums (if any) and penalties thereon and reasonable fees, expenses, original issue discount and upfront fees associated with such Replacement Loans, (ii) the All-In Yield with respect to such Replacement Loans shall not be higher than the All-In Yield for such Replaced Loans immediately prior to such refinancing unless the maturity of the Replacement Loans is at least one year later than the maturity of the Replaced Loans and (iii) all other terms applicable to such Replacement Loans shall be substantially identical to, or less favorable to the Lenders providing such Replacement Loans than, those applicable to such Replaced Loans, except to the extent necessary to provide for covenants and other terms applicable to any period after the Latest Maturity Date of the Loans in effect immediately prior to such refinancing. Each amendment to this Agreement providing for Replacement Loans may, without the consent of any other Lenders, effect such amendments to this Agreement and the other Credit Documents as may be necessary or appropriate, in the opinion of the Administrative Agent and the Borrower to effect the provisions of this paragraph, and for the avoidance of doubt, this paragraph shall supersede any other provisions in this Section 13.1 to the contrary.

Section 13.2Notices. Unless otherwise expressly provided herein, all notices and other communications provided for hereunder or under any other Credit Document shall be in writing (including by facsimile transmission). All such written notices shall be mailed, faxed or delivered to the applicable address, facsimile number or electronic mail address, and all notices and other communications expressly permitted hereunder to be given by telephone shall be made to the applicable telephone number, as follows:

(a)if to the Borrower, the Administrative Agent, the Collateral Agent or the Letter of Credit Issuer, to the address, facsimile number, electronic mail address or telephone number specified for such Person on Schedule 13.2 or to such other address, facsimile number, electronic mail address or telephone number as shall be designated by such party in a notice to the other parties; and

(b)if to any other Lender, to the address, facsimile number, electronic mail address or telephone number specified in its Administrative Questionnaire or to such other address, facsimile number, electronic mail address or telephone number as shall be designated by such party in a notice to the Borrower, the Administrative Agent, the Collateral Agent and the Letter of Credit Issuer.

All such notices and other communications shall be deemed to be given or made upon the earlier to occur of (i) actual receipt by the relevant party hereto and (ii)(A) if delivered by hand or by courier, when signed for by or on behalf of the relevant party hereto; (B) if delivered by mail, three Business Days after deposit in the mails, postage prepaid; (C) if delivered by facsimile, when sent and receipt has been confirmed by telephone; and (D) if delivered by electronic mail, when delivered; provided that notices and other communications to the Administrative Agent or the Lenders pursuant to Section 2.3, Section 2.6, Section 2.9, Section 4.2 and Section 5.1 shall not be effective until received.

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Section 13.3No Waiver; Cumulative Remedies.

(a)No failure to exercise and no delay in exercising, on the part of the Administrative Agent, the Collateral Agent or any Lender, any right, remedy, power or privilege hereunder or under the other Credit Documents shall operate as a waiver thereof, nor shall any single or partial exercise of any right, remedy, power or privilege hereunder preclude any other or further exercise thereof or the exercise of any other right, remedy, power or privilege. The rights, remedies, powers and privileges herein provided are cumulative and not exclusive of any rights, remedies, powers and privileges provided by Requirements of Law.

(b)Notwithstanding anything to the contrary contained herein or in any other Credit Document, and without limiting the provisions of Section 11.13, the authority to enforce rights and remedies hereunder and under the other Credit Documents against the Credit Parties or any of them shall be vested exclusively in, and all actions and proceedings at law in connection with such enforcement shall be instituted and maintained exclusively by, the Agents for the benefit of the Secured Parties; provided, however, that the foregoing shall not prohibit (a) any Agent from exercising on its own behalf the rights and remedies that inure to its benefit (solely in its capacity as an Agent) hereunder and under the other Credit Documents, (b) the Letter of Credit Issuer from exercising, with the consent of the Administrative Agent, the rights and remedies that inure to its benefit (solely in its capacity as Letter of Credit Issuer) hereunder and under the other Credit Documents, (c) any Lender from exercising, with the consent of the Administrative Agent, setoff rights in accordance with Section 13.8 (subject to the limitations set forth therein and subject to terms of Section 11.13), or (d) any Secured Party from filing proofs of claim or appearing and filing pleadings on its own behalf during the pendency of a proceeding relative to any Credit Party under the Bankruptcy Code or other debtor relief law.

Section 13.4Survival of Representations and Warranties. All representations and warranties made hereunder, in the other Credit Documents and in any document, certificate or statement delivered pursuant hereto or in connection herewith shall survive the execution and delivery of this Agreement and the making of the Loans hereunder.

Section 13.5Payment of Expenses; Indemnification. The Borrower agrees (a) if the Closing Date occurs, to pay or reimburse the Agents for all their reasonable and documented out-of-pocket costs and expenses incurred in connection with the preparation and execution and delivery of, and any amendment, waiver, supplement or modification to, this Agreement and the other Credit Documents and any other documents prepared in connection herewith or therewith, and the consummation and administration of the transactions contemplated hereby and thereby, including the reasonable fees, disbursements and other charges of Paul Hastings LLP, in their capacity as counsel to the Administrative Agent, and one counsel in each appropriate local jurisdiction (other than any allocated costs of in-house counsel), (b) to pay or reimburse each Agent and each Letter of Credit Issuer for all its reasonable and documented out-of-pocket costs and expenses incurred in connection with the enforcement or preservation of any rights under this Agreement, the other Credit Documents and any such other documents, including the reasonable fees, disbursements and other charges of one counsel to the Administrative Agent, Collateral Agent and the other Agents (unless there is an actual or perceived conflict of interest in which case each such Person may retain its own counsel), (c) to pay, indemnify, and hold

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harmless each Lender, Letter of Credit Issuer and Agent from, any and all recording and filing fees and (d) to pay, indemnify, and hold harmless each Lender, Letter of Credit Issuer and Agent and their respective Related Parties from and against any and all other liabilities, obligations, losses, damages, penalties, claims, demands, actions, judgments, suits, costs, expenses or disbursements of any kind or nature whatsoever, whether or not such proceedings are brought by the Borrower, any of its Related Parties or any other third Person, including reasonable and documented fees, disbursements and other charges of one counsel for all such Persons, taken as a whole, and, if necessary, by a single firm of local counsel in each appropriate jurisdiction for all such Persons, taken as a whole (unless there is an actual or perceived conflict of interest in which case each such Person may, with the consent of the Borrower (not to be unreasonably withheld or delayed) retain its own counsel), with respect to (i) any claim, litigation, investigation or proceeding (each, a “Proceeding”) arising from the execution, delivery, enforcement, performance and administration of this Agreement, the other Credit Documents and any such other documents and (ii) any Loan or Letter of Credit or the use of proceeds therefrom (including any refusal by any Letter of Credit Issuer to honor a demand for payment under a Letter of Credit if the document presented in connection with such demand do not strictly comply with the terms of such Letter of Credit), including, without limitation, any of the foregoing relating to violation by the Borrower, any of its Subsidiaries or any of the Oil and Gas Properties of, noncompliance by the Borrower, any of its Subsidiaries or any of the Oil and Gas Properties with or liability of the Borrower or any of its Subsidiaries under, any Environmental Law (other than by such indemnified Person or any of its Related Parties (other than any trustee or advisor)) or to any actual or alleged presence, release or threatened release of Hazardous Materials involving or attributable to the operations of the Borrower, any of its Subsidiaries or any of the Oil and Gas Properties (all the foregoing in this clause (d), collectively, the “Indemnified Liabilities”); provided that the Borrower shall have no obligation hereunder to any Agent or any Lender or any of their respective Related Parties with respect to Indemnified Liabilities to the extent it has been determined by a final non-appealable judgment of a court of competent jurisdiction to have resulted from (i) the gross negligence, bad faith or willful misconduct of the party to be indemnified or any of its Related Parties, (ii) any material breach (or, in the case of a Proceeding brought by the Borrower, any breach) of any Credit Document by the party to be indemnified or (iii) Proceedings not arising from any act or omission by the Borrower or its Affiliates, brought by an indemnified Person against any other indemnified Person (in the case of this clause (iii), other than Proceedings involving claims against any Agent in its capacity as such). No Person entitled to indemnification under Section 13.5(d) shall be liable for any damages arising from the use by others of any information or other materials obtained through internet, electronic, telecommunications or other information transmission systems (including IntraLinks or SyndTrak Online) in connection with this Agreement, except to the extent that such damages have resulted from the willful misconduct, bad faith or gross negligence of the party to be indemnified or any of its Related Parties (as determined by a court of competent jurisdiction in a final and non-appealable decision), nor shall any such Person, the Borrower or any of its Affiliates have any liability for any special, punitive, indirect or consequential damages (including, without limitation, any loss of profits, business or anticipated savings) relating to this Agreement or any other Credit Document or arising out of its activities in connection herewith or therewith (whether before or after the Closing Date); provided that that the foregoing shall not limit the Borrower’s and the other Credit Parties’ indemnification obligations to the indemnified Persons pursuant to this Section 13.5 in respect of damages incurred or paid by an indemnified Person to a third party. All amounts payable under this Section 13.5 shall be paid within 10 Business Days of receipt by the Borrower of an invoice relating thereto setting forth such expense in reasonable detail. The agreements in this Section 13.5 shall survive repayment of the

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Loans and all other amounts payable hereunder. This Section 13.5 shall not apply with respect to any Taxes other than any Taxes that represent losses, claims, damages, etc. arising from any non-Tax claim.

Section 13.6Successors and Assigns; Participations and Assignments.

(a)The provisions of this Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted hereby (including any Affiliate of the Letter of Credit Issuer that issues any Letter of Credit), except that (i) except as expressly permitted by Section 10.3, the Borrower may not assign or otherwise transfer any of its rights or obligations hereunder without the prior written consent of the Administrative Agent and each Lender (and any attempted assignment or transfer by the Borrower without such consent shall be null and void) and (ii) no Lender may assign or otherwise transfer its rights or obligations hereunder except in accordance with this Section 13.6. Nothing in this Agreement, expressed or implied, shall be construed to confer upon any Person (other than the parties hereto, their respective successors and assigns permitted hereby (including any Affiliate of the Letter of Credit Issuer that issues any Letter of Credit), Participants (to the extent provided in Section 13.6(c)) and, to the extent expressly contemplated hereby, the Related Parties of each of the Administrative Agent, the Collateral Agent, the Letter of Credit Issuer and the Lenders and each other Person entitled to indemnification under Section 13.5) any legal or equitable right, remedy or claim under or by reason of this Agreement.

(b)(i) Subject to the conditions set forth in Section 13.6(b)(ii) below, any Lender may at any time assign to one or more assignees (other than the Borrower, its Subsidiaries, the Sponsor or its Affiliates, any natural person, any Disqualified Institution or any Defaulting Lender) all or a portion of its rights and obligations under this Agreement (including all or a portion of its Commitments and the Loans (including participations in L/C Obligations) at the time owing to it) with the prior written consent (such consent not be unreasonably withheld or delayed; it being understood that the Borrower shall have the right to withhold or delay its consent to any assignment solely if, in order for such assignment to comply with applicable Requirements of Law, the Borrower would be required to obtain the consent of, or make any filing or registration with, any Governmental Authority) of:

(A)the Borrower; provided that no consent of the Borrower shall be required for (1) an assignment if a Payment or Bankruptcy Event of Default has occurred and is continuing or (2) the assignee is a Lender or an Affiliate of a Lender;

(B)the Administrative Agent (not to be unreasonably withheld or delayed); provided that no consent of the Administrative Agent shall be required for an assignment to a Lender, an Affiliate of a Lender or an Approved Fund; and

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(C)each Letter of Credit Issuer (not to be unreasonably withheld or delayed).

(ii)Assignments shall be subject to the following additional conditions:

(A)except in the case of an assignment to a Lender, an Affiliate of a Lender or an Approved Fund or an assignment of the entire remaining amount of the assigning Lender’s Commitment or Loans, the amount of the Commitment or Loans of the assigning Lender subject to each such assignment (determined as of the date the Assignment and Acceptance with respect to such assignment is delivered to the Administrative Agent) shall not be less than $1,000,000 and increments of $500,000 in excess thereof, unless each of the Borrower, each Letter of Credit Issuer and the Administrative Agent otherwise consents (which consents shall not be unreasonably withheld or delayed); provided that no such consent of the Borrower shall be required if a Payment or Bankruptcy Event of Default has occurred and is continuing; provided, further, that contemporaneous assignments to a single assignee made by Affiliates of Lenders and related Approved Funds shall be aggregated for purposes of meeting the minimum assignment amount requirements stated above;

(B)each partial assignment shall be made as an assignment of a proportionate part of all the assigning Lender’s rights and obligations under this Agreement;

(C)the parties to each assignment shall execute and deliver to the Administrative Agent an Assignment and Acceptance, together with a processing and recordation fee in the amount of $3,500; provided that the Administrative Agent may, in its sole discretion, elect to waive such processing and recordation fee in the case of any assignment; and

(D)the assignee, if it shall not be a Lender, shall deliver to the Administrative Agent an Administrative Questionnaire.

(iii)Subject to acceptance and recording thereof pursuant to Section 13.6(b)(iv), from and after the effective date specified in each Assignment and Acceptance, the assignee thereunder shall be a party hereto and, to the extent of the interest assigned by such Assignment and Acceptance, have the rights and obligations of a Lender under this Agreement, and the assigning Lender thereunder shall, to the extent of the interest assigned by such Assignment and Acceptance, be released from its obligations under this Agreement (and, in the case of an Assignment and Acceptance covering all of the assigning Lender’s rights and obligations under this Agreement, such Lender shall cease to be a party hereto but shall continue to be entitled to the benefits of Section 2.10, Section 2.11, Section 3.5, Section 5.4 and Section 13.5). Any assignment or transfer by a Lender of rights or obligations under this Agreement that does not comply with this Section 13.6 shall be treated for purposes of this Agreement as a sale by such

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Lender of a participation in such rights and obligations in accordance with Section 13.6(c).

(iv)The Administrative Agent, acting for this purpose as a non-fiduciary agent of the Borrower, shall maintain at the Administrative Agent’s Office a copy of each Assignment and Acceptance delivered to it and a register for the recordation of the names and addresses of the Lenders, and the Commitments of, and principal amount (and stated interest amounts) of the Loans and L/C Obligations and any payment made by the Letter of Credit Issuer under any Letter of Credit owing to, each Lender pursuant to the terms hereof from time to time (the “Register”). Further, the Register shall contain the name and address of the Administrative Agent and the lending office through which each such Person acts under this Agreement. The entries in the Register shall be conclusive absent manifest error, and the Borrower, the Administrative Agent, the Collateral Agent, the Letter of Credit Issuer and the Lenders shall treat each Person whose name is recorded in the Register pursuant to the terms hereof as a Lender hereunder for all purposes of this Agreement, notwithstanding notice to the contrary. The Register shall be available for inspection by the Borrower, the Collateral Agent, the Letter of Credit Issuer and, solely with respect to itself, each other Lender, at any reasonable time and from time to time upon reasonable prior notice.

(v)Upon its receipt of a duly completed Assignment and Acceptance executed by an assigning Lender and an assignee, the assignee’s completed Administrative Questionnaire (unless the assignee shall already be a Lender hereunder), the processing and recordation fee referred to in Section 13.6(b) (unless waived) and any written consent to such assignment required by Section 13.6(b), the Administrative Agent shall accept such Assignment and Acceptance and record the information contained therein in the Register.

(c)

(i)Any Lender may, with the prior written consent of the Borrower (such consent not to be unreasonably withheld or delayed; provided, that no consent of the Borrower shall be required for any participation if (A) a Payment or Bankruptcy Event of Default has occurred and is continuing or (B) the assignee is a Lender or an Affiliate of a Lender), sell participations to one or more banks or other entities other than the Borrower or Subsidiary of the Borrower or the Sponsor or any of their Affiliates or any natural person (each, a “Participant”) in all or a portion of such Lender’s rights and obligations under this Agreement (including all or a portion of its Commitments and the Loans owing to it); provided that (1) such Lender’s obligations under this Agreement shall remain unchanged, (2) such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations and (3) the Borrower, the Administrative Agent, the Letter of Credit Issuer and the other Lenders shall continue to deal solely and directly with such Lender in connection with such Lender’s rights and obligations under this Agreement. Any agreement or instrument pursuant to which a Lender sells such a participation shall provide that

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such Lender shall retain the sole right to enforce this Agreement and to approve any amendment, modification or waiver of any provision of this Agreement or any other Credit Document; provided that such agreement or instrument may provide that such Lender will not, without the consent of the Participant, agree to any amendment, modification or waiver described in Section 13.1(a)(ii)(A), Section 13.1(a)(ii)(B) and Section 13.1(a)(ii)(C) that affects such Participant. Subject to Section 13.6(c)(i)(B), the Borrower agrees that each Participant shall be entitled to the benefits of Section 2.10, Section 2.11, Section 3.5 and Section 5.4 to the same extent as if it were a Lender (subject to the limitations and requirements of those Sections as though it were a Lender and had acquired its interest by assignment pursuant to Section 13.6(b), including the requirements of Section 5.4(e)). To the extent permitted by Requirements of Law, each Participant also shall be entitled to the benefits of Section 13.8(b) as though it were a Lender; provided such Participant agrees to be subject to Section 13.8(a) as though it were a Lender.

(ii)Notwithstanding anything to the contrary in this Agreement, a Participant shall not be entitled to receive any greater payment under Section 2.9, Section 2.10, Section 3.5 or Section 5.4 than the applicable Lender would have been entitled to receive with respect to the participation sold to such Participant, unless the sale of the participation to such Participant is made with the Borrower’s prior written consent expressly acknowledging that such Participant is entitled to the benefit of such provisions of this Agreement; provided that the Participant shall be subject to the provisions in Section 2.10 as if it were an assignee under Section 13.6(a) and Section 13.6(b). Each Lender that sells a participation shall, acting solely for this purpose as a non-fiduciary agent of the Borrower, maintain a register on which it enters the name and address of each participant and the principal amounts (and related interest amounts) of each participant’s interest in the Loans or other obligations under this Agreement (the “Participant Register”). The entries in the Participant Register shall be conclusive, absent manifest error, and such Lender shall treat each Person whose name is recorded in the Participant Register as the owner of such participation for all purposes of this Agreement notwithstanding any notice to the contrary. No Lender shall have any obligation to disclose all or any portion of the Participant Register to any Person (including the identity of any Participant or any information relating to a Participant’s interest in any commitments, loans, letters of credit or its other obligations under any Credit Document) except to the extent that such disclosure is necessary to establish that such commitment, loan, letter of credit or other obligation is in registered form under Section 5f.103-1(c) of the Treasury Regulations. For the avoidance of doubt, the Administrative Agent (in its capacity as Administrative Agent) shall have no responsibility for maintaining a Participant Register.

(d)Any Lender may, without the consent of the Borrower or the Administrative Agent, at any time pledge or assign a security interest in all or any portion of its rights under this Agreement to secure obligations of such Lender, including any pledge or assignment to secure obligations to a Federal Reserve Bank or any central bank having jurisdiction over such Lender, and this Section 13.6 shall not apply to any such

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pledge or assignment of a security interest; provided that no such pledge or assignment of a security interest shall release a Lender from any of its obligations hereunder or substitute any such pledgee or assignee for such Lender as a party hereto. In order to facilitate such pledge or assignment or for any other reason, the Borrower hereby agrees that, upon request of any Lender at any time and from time to time after the Borrower has made its initial borrowing hereunder, the Borrower shall provide to such Lender, at the Borrower’s own expense, a promissory note, substantially in the form of Exhibit O, as the case may be, evidencing the Loans owing to such Lender.

(e)Subject to Section 13.16, the Borrower authorizes each Lender to disclose to any Participant, secured creditor of such Lender or assignee (each, a “Transferee”) and any prospective Transferee any and all financial information in such Lender’s possession concerning the Borrower and its Affiliates that has been delivered to such Lender by or on behalf of the Borrower and its Affiliates pursuant to this Agreement or that has been delivered to such Lender by or on behalf of the Borrower and its Affiliates in connection with such Lender’s credit evaluation of the Borrower and its Affiliates prior to becoming a party to this Agreement.

(f)The Administrative Agent shall not be responsible or have any liability for, or have any duty to ascertain, inquire into, monitor or enforce, compliance with the provisions hereof relating to Disqualified Institutions. Without limiting the generality of the foregoing, the Administrative Agent shall not (a) be obligated to ascertain, monitor or inquire as to whether any Lender or participant or prospective Lender or participant is a Disqualified Institution or (b) have any liability with respect to or arising out of any assignment or participation of Loans, or disclosure of confidential information, to any Disqualified Institution.

Section 13.7Replacements of Lenders under Certain Circumstances.

(a)The Borrower shall be permitted to replace any Lender that (i) requests reimbursement for amounts owing pursuant to Section 2.10, Section 3.5 or Section 5.4, (ii) is affected in the manner described in Section 2.10(a)(iii) and as a result thereof any of the actions described in such Section is required to be taken or (iii) becomes a Defaulting Lender, with a replacement bank, lending institution or other financial institution; provided that (A) such replacement does not conflict with any Requirement of Law, (B) no Payment or Bankruptcy Event of Default shall have occurred and be continuing at the time of such replacement, (C) the replacement bank or institution shall purchase, at par, all Loans and the Borrower shall pay all other amounts (other than any disputed amounts), pursuant to Section 2.10, Section 3.5 or Section 5.4, as the case may be, owing to such replaced Lender prior to the date of replacement, (D) the replacement bank or institution, if not already a Lender, and the terms and conditions of such replacement, shall be reasonably satisfactory to the Administrative Agent, (E) the replaced Lender shall be obligated to make such replacement in accordance with the provisions of Section 13.6(b) (provided that the Borrower shall be obligated to pay the registration and processing fee referred to therein) and (F) any such replacement shall not be deemed to be a waiver of any rights that the Borrower, the Administrative Agent or any other Lender shall have against the replaced Lender.

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(b)If any Lender (such Lender, a “Non-Consenting Lender”) has failed to consent to a proposed amendment, waiver, discharge or termination that pursuant to the terms of Section 13.1 requires the consent of all of the Lenders affected or the Required Lenders and with respect to which the Majority Lenders shall have granted their consent, then provided no Event of Default then exists, the Borrower shall have the right (unless such Non-Consenting Lender grants such consent) to replace such Non-Consenting Lender by requiring such Non-Consenting Lender to assign its Loans and its Commitments hereunder to one or more assignees reasonably acceptable to the Administrative Agent; provided that: (i) all Obligations of the Borrower owing to such Non-Consenting Lender being replaced (other than principal and interest) shall be paid in full to such Non-Consenting Lender concurrently with such assignment and (ii) the replacement Lender shall purchase the foregoing by paying to such Non-Consenting Lender a price equal to the principal amount thereof plus accrued and unpaid interest thereon. In connection with any such assignment, the Borrower, Administrative Agent, such Non-Consenting Lender and the replacement Lender shall otherwise comply with Section 13.6.

(c)Notwithstanding anything herein to the contrary, each party hereto agrees that any assignment pursuant to the terms of this Section 13.7 may be effected pursuant to an Assignment and Acceptance executed by the Borrower, the Administrative Agent and the assignee and that the Lender making such assignment need not be a party thereto.

Section 13.8Adjustments; Set-off.

(a)If any Lender (a “Benefited Lender”) shall at any time receive any payment in respect of any principal of or interest on all or part of the Loans made by it, or the participations in Letter of Credit Obligations held by it, or receive any collateral in respect thereof (whether voluntarily or involuntarily, by set-off, pursuant to events or proceedings of the nature referred to in Section 11.5, or otherwise), in a greater proportion than any such payment to or collateral received by any other Lender, if any, in respect of such other Lender’s Loans or interest thereon or participations in Letter of Credit Obligations, such Benefited Lender shall (i) notify the Administrative Agent of such fact, and (ii) purchase for cash at face value from the other Lenders a participating interest in such portion of each such other Lender’s Loans and Letters of Credit, or shall provide such other Lenders with the benefits of any such collateral, or the proceeds thereof, as shall be necessary to cause such Benefited Lender to share the excess payment or benefits of such collateral or proceeds ratably in accordance with the aggregate principal of and accrued interest on their respective Loans and other amounts owing them; provided, however, that, (A) if all or any portion of such excess payment or benefits is thereafter recovered from such Benefited Lender, such purchase shall be rescinded, and the purchase price and benefits returned, to the extent of such recovery, but without interest and (B) the provisions of this paragraph shall not be construed to apply to (1) any payment made by the Borrower or any other Credit Party pursuant to and in accordance with the express terms of this Agreement and the other Credit Documents, (2) any payment obtained by a Lender as consideration for the assignment of or sale of a participation in any of its Loans, Commitments or participations in Drawings to any assignee or participant or (3) any disproportionate payment obtained by a Lender as a result of the extension by Lenders of the maturity date or expiration date of some but not

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all Loans or Commitments or any increase in the Applicable Margin in respect of Loans or Commitments of Lenders that have consented to any such extension. Each Credit Party consents to the foregoing and agrees, to the extent it may effectively do so under Requirements of Law, that any Lender acquiring a participation pursuant to the foregoing arrangements may exercise against such Credit Party rights of set-off and counterclaim with respect to such participation as fully as if such Lender were a direct creditor of such Credit Party in the amount of such participation.

(b)Subject to Section 11.14, after the occurrence and during the continuance of an Event of Default, in addition to any rights and remedies of the Lenders provided by Requirements of Law, each Lender shall have the right, without prior notice to the Borrower, any such notice being expressly waived by the Borrower to the extent permitted by applicable Requirements of Law, upon any amount becoming due and payable by the Borrower hereunder or under any Credit Document (whether at the stated maturity, by acceleration or otherwise) to set-off and appropriate and apply against such amount any and all deposits (general or special, time or demand, provisional or final), in any currency, and any other credits, indebtedness or claims, in any currency, in each case whether direct or indirect, absolute or contingent, matured or unmatured, at any time held or owing by such Lender or any branch or agency thereof to or for the credit or the account of the Borrower. Each Lender agrees promptly to notify the Borrower (and the Credit Parties, if applicable) and the Administrative Agent after any such set-off and application made by such Lender; provided that the failure to give such notice shall not affect the validity of such set-off and application.

Section 13.9Counterparts. This Agreement may be executed by one or more of the parties to this Agreement on any number of separate counterparts (including by facsimile or other electronic transmission, i.e. a “pdf” or a “tif”), and all of said counterparts taken together shall be deemed to constitute one and the same instrument. A set of the copies of this Agreement signed by all the parties shall be lodged with the Borrower and the Administrative Agent. The words “execute,” “execution,” “signed,” “signature,” “delivery” and words of like import in or related to this Agreement, any other Credit Document or any document, amendment, approval, consent, waiver, modification, information, notice, certificate, report, statement, disclosure, or authorization to be signed or delivered in connection with this Agreement or any other Credit Document or the transactions contemplated hereby shall be deemed to include Electronic Signatures or execution in the form of an Electronic Record, and contract formations on electronic platforms approved by the Administrative Agent, deliveries or the keeping of records in electronic form, each of which shall be of the same legal effect, validity or enforceability as a manually executed signature or the use of a paper-based recordkeeping system, as the case may be, to the extent and as provided for in any applicable law, including the Federal Electronic Signatures in Global and National Commerce Act, the New York State Electronic Signatures and Records Act, or any other similar state laws based on the Uniform Electronic Transactions Act.  Each party hereto agrees that any Electronic Signature or execution in the form of an Electronic Record shall be valid and binding on itself and each of the other parties hereto to the same extent as a manual, original signature.  For the avoidance of doubt, the authorization under this paragraph may include, without limitation, use or acceptance by the parties of a manually signed paper which has been converted into electronic form (such as scanned into PDF format), or an electronically signed paper converted into another format, for transmission, delivery and/or retention.  Notwithstanding anything contained herein to the contrary, the Administrative Agent

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is under no obligation to accept an Electronic Signature in any form or in any format unless expressly agreed to by the Administrative Agent pursuant to procedures approved by it; provided that without limiting the foregoing, (a) to the extent the Administrative Agent has agreed to accept such Electronic Signature from any party hereto, the Administrative Agent and the other parties hereto shall be entitled to rely on any such Electronic Signature purportedly given by or on behalf of the executing party without further verification and (b) upon the request of the Administrative Agent or any Lender, any Electronic Signature shall be promptly followed by an original manually executed counterpart thereof.  Without limiting the generality of the foregoing, each party hereto hereby (i) agrees that, for all purposes, including without limitation, in connection with any workout, restructuring, enforcement of remedies, bankruptcy proceedings or litigation among the Administrative Agent, the Lenders and any of the Credit Parties, electronic images of this Agreement or any other Credit Document (in each case, including with respect to any signature pages thereto)  shall have the same legal effect, validity and enforceability as any paper original, and (ii) waives any argument, defense or right to contest the validity or enforceability of the Credit Documents based solely on the lack of paper original copies of any Credit Documents, including with respect to any signature pages thereto.

Section 13.10Severability. Any provision of this Agreement that is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

Section 13.11Integration. This Agreement and the other Credit Documents represent the agreement of the Borrower, the Guarantors, the Collateral Agent, the Administrative Agent and the Lenders with respect to the subject matter hereof and thereof, and there are no promises, undertakings, representations or warranties by the Borrower, the Guarantors, any Agent nor any Lender relative to subject matter hereof not expressly set forth or referred to herein or in the other Credit Documents.

Section 13.12GOVERNING LAW. THIS AGREEMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY, AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK.

Section 13.13Submission to Jurisdiction; Waivers. Each party hereto hereby irrevocably and unconditionally:

(a)submits for itself and its property in any legal action or proceeding relating to this Agreement and the other Credit Documents to which it is a party, or for recognition and enforcement of any judgment in respect thereof, to the exclusive general jurisdiction of the courts of the State of New York located in New York County, the courts of the United States of America for the Southern District of New York located in New York County and appellate courts from any thereof;

(b)consents that any such action or proceeding shall be brought in such courts and waives any objection that it may now or hereafter have to the venue of any such

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action or proceeding in any such court or that such action or proceeding was brought in an inconvenient court and agrees not to plead or claim the same;

(c)agrees that service of process in any such action or proceeding may be effected by mailing a copy thereof by registered or certified mail (or any substantially similar form of mail), postage prepaid, to such Person at its address set forth on Schedule 13.2 at such other address of which the Administrative Agent shall have been notified pursuant to Section 13.2;

(d)agrees that nothing herein shall affect the right to effect service of process in any other manner permitted by Requirements of Law or shall limit the right to sue in any other jurisdiction;

(e)waives, to the maximum extent not prohibited by law, any right it may have to claim or recover in any legal action or proceeding referred to in this Section 13.13 any special, exemplary, punitive or consequential damages; and

(f)agrees that a final judgment in any action or proceeding shall be conclusive and may be enforced in other jurisdictions by suit on the judgment or in any other manner provided by law.

Section 13.14Acknowledgments. The Borrower hereby acknowledges that:

(a)it has been advised by counsel in the negotiation, execution and delivery of this Agreement and the other Credit Documents;

(b)(i) the credit facilities provided for hereunder and any related arranging or other services in connection therewith (including in connection with any amendment, waiver or other modification hereof or of any other Credit Document) are an arm’s-length commercial transaction between the Borrower and the other Credit Parties, on the one hand, and the Administrative Agent, the Lenders and the other Agents on the other hand, and the Borrower and the other Credit Parties are capable of evaluating and understanding and understand and accept the terms, risks and conditions of the transactions contemplated hereby and by the other Credit Documents (including any amendment, waiver or other modification hereof or thereof); (ii) in connection with the process leading to such transaction, each of the Administrative Agent, other Agents and the Lenders, is and has been acting solely as a principal and is not the financial advisor, agent or fiduciary for any of the Borrower, any other Credit Parties or any of their respective Affiliates, equity holders, creditors or employees or any other Person; (iii) neither the Administrative Agent, any other Agent, any Lead Arranger nor any Lender has assumed or will assume an advisory, agency or fiduciary responsibility in favor of the Borrower or any other Credit Party with respect to any of the transactions contemplated hereby or the process leading thereto, including with respect to any amendment, waiver or other modification hereof or of any other Credit Document (irrespective of whether the Administrative Agent or any other Agent or any Lead Arranger or any Lender has advised or is currently advising any of the Borrower, the other Credit Parties or their respective Affiliates on other matters) and none of the Administrative Agent, any Agent, any Lead Arranger or any Lender has any obligation to any of the Borrower, the other Credit Parties or their respective Affiliates with respect to the transactions contemplated

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hereby except those obligations expressly set forth herein and in the other Credit Documents; (iv) the Administrative Agent and its Affiliates, each other Agent and each of its Affiliates and each Lender and its Affiliates may be engaged in a broad range of transactions that involve interests that differ from those of the Borrower and its respective Affiliates, and none of the Administrative Agent, any other Agent or any Lender has any obligation to disclose any of such interests by virtue of any advisory, agency or fiduciary relationship; and (v) none of the Administrative Agent, any Agent or any Lender has provided and none will provide any legal, accounting, regulatory or tax advice with respect to any of the transactions contemplated hereby (including any amendment, waiver or other modification hereof or of any other Credit Document) and the Borrower has consulted its own legal, accounting, regulatory and tax advisors to the extent it has deemed appropriate. The Borrower hereby waives and releases, to the fullest extent permitted by law, any claims that it may have against the Administrative Agent and each Agent with respect to any breach or alleged breach of agency or fiduciary duty; and

(c)no joint venture is created hereby or by the other Credit Documents or otherwise exists by virtue of the transactions contemplated hereby among the Lenders or among the Borrower, on the one hand, and any Lender, on the other hand.

Section 13.15WAIVERS OF JURY TRIAL. THE BORROWER, EACH AGENT, EACH LETTER OF CREDIT ISSUER AND EACH LENDER HEREBY IRREVOCABLY AND UNCONDITIONALLY WAIVE TRIAL BY JURY IN ANY LEGAL ACTION OR PROCEEDING RELATING TO THIS AGREEMENT OR ANY OTHER CREDIT DOCUMENT AND FOR ANY COUNTERCLAIM THEREIN.

Section 13.16Confidentiality. The Administrative Agent, each other Agent, any Letter of Credit Issuer and each other Lender shall hold all non-public information furnished by or on behalf of the Borrower or any of its Subsidiaries in connection with such Lender’s evaluation of whether to become a Lender hereunder or obtained by such Lender, the Administrative Agent, any Letter of Credit Issuer or such other Agent pursuant to the requirements of this Agreement (“Confidential Information”), confidential in accordance with its customary procedure for handling confidential information of this nature and in any event may make disclosure (a) as required or requested by any Governmental Authority, self-regulatory agency or representative thereof or pursuant to legal process or applicable Requirements of Law, (b) to such Lender’s or the Administrative Agent’s, any Letter of Credit Issuer’s or such other Agent’s attorneys, professional advisors, independent auditors, trustees or Affiliates, in each case who need to know such information in connection with the administration of the Credit Documents and are informed of the confidential nature of such information, (c) to an investor or prospective investor in a securitization that agrees its access to information regarding the Credit Parties, the Loans and the Credit Documents is solely for purposes of evaluating an investment in a securitization and who agrees to treat such information as confidential, (d) to a trustee, collateral manager, servicer, backup servicer, noteholder or secured party in connection with the administration, servicing and reporting on the assets serving as collateral for a securitization and who agrees to treat such information as confidential, (e) to a nationally recognized ratings agency that requires access to information regarding the Credit Parties, the Loans and Credit Documents in connection with ratings issued with respect to a securitization, (f) to any other party hereto, (g) in connection with the exercise of any remedies hereunder or under any other Credit Document or any action or proceeding relating to this Agreement or any other Credit Document or the enforcement of rights hereunder or thereunder, (h) with the consent of the Borrower, (i) to the

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extent such information (x) becomes publicly available other than as a result of a breach of this section, or (y) becomes available to the Administrative Agent, any Lender, any Letter of Credit Issuer or any of their respective Affiliates on a nonconfidential basis from a source other than the Borrower who did not acquire such information as a result of a breach of this section or (j) to prospective Transferees or to any pledgee referred to in Section 13.6 or to prospective direct or indirect contractual counterparties in Hedge Agreements to be entered into in connection with Loans made hereunder as long as such Person is advised of and agrees to be bound by the provisions of this Section 13.16 or confidentiality provisions at least as restrictive as those set forth in the Section 13.16; provided that unless specifically prohibited by applicable Requirements of Law, each Lender, the Administrative Agent, any Letter of Credit Issuer and each other Agent shall endeavor to notify the Borrower (without any liability for a failure to so notify the Borrower) of any request made to such Lender, the Administrative Agent, any Letter of Credit Issuer or such other Agent, as applicable, by any governmental, regulatory or self-regulatory agency or representative thereof (other than any such request in connection with an examination of the financial condition of such Lender by such governmental agency) for disclosure of any such non-public information prior to disclosure of such information; provided further that in no event shall any Lender, the Administrative Agent, any Letter of Credit Issuer or any other Agent be obligated or required to return any materials furnished by the Borrower or any Subsidiary. In addition, the Administrative Agent and the Lenders may disclose the existence of this Agreement and information about this Agreement to market data collectors, similar service providers to the lending industry and service providers to the Agents or any Lender in connection with the administration of this Agreement and the other Credit Documents.

Section 13.17Release of Collateral and Guarantee Obligations.

(a)Each Secured Party hereby irrevocably agrees that the Liens granted to the Collateral Agent by the Credit Parties on any Collateral shall be automatically released (i) in full, as set forth in clause (b) below, (ii) upon the Disposition of such Collateral (including as part of or in connection with any other Disposition permitted hereunder) to any Person other than another Credit Party, to the extent such Disposition is made in compliance with the terms of this Agreement (and the Collateral Agent may rely conclusively on a certificate to that effect provided to it by any Credit Party upon its reasonable request without further inquiry), (iii) to the extent such Collateral is comprised of property leased to a Credit Party, upon termination or expiration of such lease, (iv) if the release of such Lien is approved, authorized or ratified in writing by the Majority Lenders (or such other percentage of the Lenders whose consent may be required in accordance with Section 13.1), (v) to the extent the property constituting such Collateral is owned by any Guarantor, upon the release of such Guarantor from its obligations under the Guarantee (in accordance with the second succeeding sentence and Section 5.14(b) of the Guarantee), (vi) as required by the Collateral Agent to effect any Disposition of Collateral in connection with any exercise of remedies of the Collateral Agent pursuant to the Security Documents and (vii) upon such Collateral no longer constituting Collateral pursuant to the terms of the Credit Documents. Any such release shall not in any manner discharge, affect, or impair the Obligations or any Liens (other than those being released) upon (or obligations (other than those being released) of the Credit Parties in respect of) all interests retained by the Credit Parties, including the proceeds of any Disposition, all of which shall continue to constitute part of the Collateral except to the extent otherwise released in accordance with the provisions of the Credit Documents. Additionally, the

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Secured Parties hereby irrevocably agree that the Guarantors shall be released from the Guarantees upon consummation of any transaction permitted hereunder resulting in such Subsidiary ceasing to constitute a Restricted Subsidiary or otherwise becoming an Excluded Subsidiary. The Secured Parties hereby authorize the Administrative Agent and the Collateral Agent, as applicable, to execute and deliver any instruments, documents, and agreements necessary or desirable to evidence and confirm the release of any Guarantor or Collateral pursuant to the foregoing provisions of this paragraph, all without the further consent or joinder of any Secured Party. Any representation, warranty or covenant contained in any Credit Document relating to any such Collateral or Guarantor shall no longer be deemed to be repeated.

(b)Notwithstanding anything to the contrary contained herein or any other Credit Document, upon Payment in Full, upon request of the Borrower, the Administrative Agent and/or Collateral Agent, as applicable, shall (without notice to, or vote or consent of, any Secured Party) take such actions as shall be required to release its security interest in all Collateral, and to release all obligations under any Credit Document, whether or not on the date of such release there may be any (i) Hedging Obligations in respect of any Secured Hedge Agreements, (ii) Cash Management Obligations in respect of any Secured Cash Management Agreements and (iii) any contingent or indemnification obligations not then due. Any such release of Obligations shall be deemed subject to the provision that such Obligations shall be reinstated if after such release any portion of any payment in respect of the Obligations guaranteed thereby shall be rescinded or must otherwise be restored or returned upon the insolvency, bankruptcy, dissolution, liquidation or reorganization of the Borrower or any Guarantor, or upon or as a result of the appointment of a receiver, intervenor or conservator of, or trustee or similar officer for, the Borrower or any Guarantor or any substantial part of its property, or otherwise, all as though such payment had not been made.

Section 13.18USA PATRIOT Act. The Agents and each Lender hereby notifies the Borrower that pursuant to the requirements of the USA Patriot Act (Title III of Pub. L. 107-56 (signed into law October 26, 2001)) (the “Patriot Act”), it is required to obtain, verify and record information that identifies each Credit Party, which information includes the name and address of each Credit Party and other information that will allow such Agent and such Lender to identify each Credit Party in accordance with the Patriot Act.

Section 13.19Payments Set Aside. To the extent that any payment by or on behalf of the Borrower is made to any Agent or any Lender, or any Agent or any Lender exercises its right of setoff, and such payment or the proceeds of such setoff or any part thereof is subsequently invalidated, declared to be fraudulent or preferential, set aside or required (including pursuant to any settlement entered into by such Agent or such Lender in its discretion) to be repaid to a trustee, receiver or any other party, in connection with any proceeding or otherwise, then (a) to the extent of such recovery, the obligation or part thereof originally intended to be satisfied shall be revived and continued in full force and effect as if such payment had not been made or such setoff had not occurred, and (b) each Lender severally agrees to pay to the Administrative Agent upon demand its applicable share of any amount so recovered from or repaid by any Agent, plus interest thereon from the date of such demand to the date such payment is made at a rate per annum equal to the applicable Overnight Rate from time to time in effect.

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Section 13.20Reinstatement. This Agreement shall continue to be effective, or be reinstated, as the case may be, if at any time payment, or any part thereof, of any of the Obligations is rescinded or must otherwise be restored or returned by the Administrative Agent or any other Secured Party upon the insolvency, bankruptcy, dissolution, liquidation or reorganization of the Borrower or any other Credit Party, or upon or as a result of the appointment of a receiver, intervenor or conservator of, or trustee or similar officer for, the Borrower or any other Credit Party or any substantial part of its property, or otherwise, all as though such payments had not been made.

Section 13.21Disposition of Proceeds. The Security Documents contain an assignment by the Borrower and/or the Guarantors unto and in favor of the Collateral Agent for the benefit of the Lenders of all of the Borrower’s or each Guarantor’s interest in and to their as-extracted collateral in the form of production and all proceeds attributable thereto which may be produced from or allocated to the Mortgaged Property. The Security Documents further provide in general for the application of such proceeds to the satisfaction of the Obligations described therein and secured thereby. Notwithstanding the assignment contained in such Security Documents, until the occurrence and during the continuance of an Event of Default, (a) the Administrative Agent and the Lenders agree that they will neither notify the purchaser or purchasers of such production nor take any other action to cause such proceeds to be remitted to the Administrative Agent or the Lenders, but the Lenders will instead permit such proceeds to be paid to the Borrower and its Subsidiaries and (b) the Lenders hereby authorize the Administrative Agent to take such actions as may be necessary to cause such proceeds to be paid to the Borrower and/or such Subsidiaries.

Section 13.22Collateral Matters; Hedge Agreements. The benefit of the Security Documents and of the provisions of this Agreement relating to any Collateral securing the Obligations shall also extend to and be available on a pro rata basis to any Secured Party (a) under any Secured Hedge Agreement, in each case, after giving effect to all netting arrangements relating to such Hedge Agreements or (b) under any Secured Cash Management Agreement. No Secured Party shall have any voting rights under any Credit Document solely as a result of the existence of obligations owed to it under any Secured Hedge Agreement or Secured Cash Management Agreement.

Section 13.23Flood Insurance Provisions. Notwithstanding anything in this Agreement or any other Credit Document to the contrary, in no event is any “Building” (as defined in the applicable Flood Insurance Law) or “Manufactured (Mobile) Home” (as defined in the applicable Flood Insurance Law) included in the definition of “Mortgaged Property” (as defined in any Credit Document) and no “Building” or “Manufactured (Mobile) Home” is hereby encumbered by this Agreement or any other Credit Document.

Section 13.24Headings. Article and Section headings and the Table of Contents used herein are for convenience of reference only, are not part of this Agreement and shall not affect the construction of, or be taken into consideration in interpreting, this Agreement.

Section 13.25No Third Party Beneficiaries. This Agreement, the other Credit Documents, and the agreement of the Lenders to make Loans and the Letter of Credit Issuers to issue, amend, renew or extend Letters of Credit hereunder are solely for the benefit of the

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Borrower, and no other Person (including, without limitation, any other Credit Party, any obligor, contractor, subcontractor, supplier or materialsman) shall have any rights, claims, remedies or privileges hereunder or under any other Credit Document against the Administrative Agent, any other Agent, the Letter of Credit Issuer or any Lender for any reason whatsoever. Except as specified in Section 13.5, there are no third party beneficiaries.

Section 13.26Keepwell. The Borrower hereby guarantees the payment and performance of all Swap Obligations of each Credit Party (other than the Borrower) and absolutely, unconditionally and irrevocably undertakes to provide such funds or other support as may be needed from time to time by each Credit Party (other than the Borrower) in order for such Credit Party to honor its obligations under the Guarantee including obligations with respect to Hedge Agreements (provided, however, that the Borrower shall only be liable under this Section 13.26 for the maximum amount of such liability that can be hereby incurred without rendering its obligations under this Section 13.26, or otherwise under this Agreement or any Credit Document, as it relates to such other Credit Parties, voidable under applicable law relating to fraudulent conveyance or fraudulent transfer, and not for any greater amount). The obligations of the Borrower under this Section 13.26 shall remain in full force and effect until Payment in Full. The Borrower intends that this Section 13.26 constitute, and this Section 13.26 shall be deemed to constitute, a “keepwell, support, or other agreement” for the benefit of each other Credit Party for all purposes of Section 1a(18)(A)(v)(II) of the Commodity Exchange Act.

Section 13.27Certain ERISA Matters.

(a)Each Lender (x) represents and warrants, as of the date such Person became a Lender party hereto, to, and (y) covenants, from the date such Person became a Lender party hereto to the date such Person ceases being a Lender party hereto, for the benefit of the Administrative Agent, the Lead Arrangers and their respective Affiliates, and not, for the avoidance of doubt, to or for the benefits of the Borrower or any other Credit Party, that at least one of the following is and will be true:

(i)such Lender is not using “plan assets” (within the meaning of 29 CFR § 2510.3-101, as modified by Section 3(42) of ERISA) of one or more Benefit Plans in connection with the Loans, the Letters of Credit or the Commitments;

(ii)the transaction exemption set forth in one or more PTEs, such as PTE 84-14 (a class exemption for certain transactions determined by independent qualified professional asset managers), PTE 95-60 (a class exemption for certain transactions involving insurance company general accounts), PTE 90-1 (a class exemption for certain transactions involving insurance company pooled separate accounts), PTE 91-38 (a class exemption for certain transactions involving bank collective investment funds) or PTE 96-23 (a class exemption for certain transactions determined by in-house asset managers), is applicable with respect to such Lender’s entrance into, participation in, administration of and performance of the Loans, the Letters of Credit, the Commitments and this Agreement and will

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not result in a non-exempt prohibited transaction under ERISA or Section 4975 of the Code; or

(iii)(A) such Lender is an investment fund managed by a “Qualified Professional Asset Manager” (within the meaning of Part VI of PTE 84-14), (B) such Qualified Professional Asset Manager made the investment decision on behalf of such Lender to enter into, participate in, administer and perform the Loans, the Letters of Credit, the Commitments and this Agreement, (C) the entrance into, participation in, administration of and performance of the Loans, the Letters of Credit, the Commitments and this Agreement satisfies the requirements of sub-sections (b) through (g) of Part I of PTE 84-14 and (D) to the best knowledge of such Lender, the requirements of subsection (a) of Part I of PTE 84-14 are satisfied with respect to such Lender’s entrance into, participation in, administration of and performance of the Loans, the Letters of Credit, the Commitments and this Agreement; or

(iv)such other representation, warranty and covenant as may be agreed in writing between the Administrative Agent, in its sole discretion, and such Lender.

(b)In addition, unless sub-clause (i) in the immediately preceding clause (a) is true with respect to a Lender or such Lender has not provided another representation, warranty and covenant as provided in sub-clause (iv) in the immediately preceding clause (a), such Lender further (x) represents and warrants, as of the date such Person became a Lender party hereto, to, and (y) covenants, from the date such Person became a Lender party hereto to the date such Person ceases being a Lender party hereto, for the benefit of the Administrative Agent, the Lead Arrangers and their respective Affiliates, and not, for the avoidance of doubt, to or for the benefit of the Borrower or any other Credit Party that the Administrative Agent is not a fiduciary with respect to the assets of such Lender (including in connection with the reservation or exercise of any rights by the Administrative Agent under this Agreement, any Credit Document or any documents related to hereto or thereto).

Section 13.28Acknowledgement Regarding Any Supported QFCs.

(a)To the extent that the Credit Documents provide support, through a guarantee or otherwise, for any Hedge Agreement or any other agreement or instrument that is a QFC (such support, “QFC Credit Support”, and each such QFC, a “Supported QFC”), the parties acknowledge and agree as follows with respect to the resolution power of the Federal Deposit Insurance Corporation under the Federal Deposit Insurance Act and Title II of the Dodd-Frank Wall Street Reform and Consumer Protection Act (together with the regulations promulgated thereunder, the “U.S. Special Resolution Regimes”) in respect of such Supported QFC and QFC Credit Support (with the provisions below applicable notwithstanding that the Credit Documents and any Supported QFC may in fact be stated to be governed by the laws of the State of New York and/or of the United States or any other state of the United States):

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(b)In the event a Covered Entity that is party to a Supported QFC (each, a “Covered Party”) becomes subject to a proceeding under a U.S. Special Resolution Regime, the transfer of such Supported QFC and the benefit of such QFC Credit Support (and any interest and obligation in or under such Supported QFC and such QFC Credit Support, and any rights in property securing such Supported QFC or such QFC Credit Support) from such Covered Party will be effective to the same extent as the transfer would be effective under the U.S. Special Resolution Regime if the Supported QFC and such QFC Credit Support (and any such interest, obligation and rights in property) were governed by the laws of the United States or a state of the United States. In the event a Covered Party or a BHC Act Affiliate of a Covered Party becomes subject to a proceeding under a U.S. Special Resolution Regime, Default Rights under the Credit Documents that might otherwise apply to such Supported QFC or any QFC Credit Support that may be exercised against such Covered Party are permitted to be exercised to no greater extent than such Default Rights could be exercised under the U.S. Special Resolution Regime if the Supported QFC and the Credit Documents were governed by the laws of the United States or a state of the United States. Without limitation of the foregoing, it is understood and agreed that rights and remedies of the parties with respect to a Defaulting Lender shall in no event affect the rights of any Covered Party with respect to a Supported QFC or any QFC Credit Support.

[Signature pages follow.]

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IN WITNESS WHEREOF, each of the parties hereto has caused a counterpart of this Agreement to be duly executed and delivered as of the date first above written.

INDEPENDENCE ENERGY FINANCE LLC,
as Borrower

By: Independence Energy LLC, its sole member

By: Independence Energy MM LLC, its managing member

/s/ Brandi Kendall    

Name:    Brandi Kendall

Title:    Chief Financial Officer

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WELLS FARGO BANK, NATIONAL ASSOCIATION,
as Administrative Agent, Collateral Agent, Letter of Credit Issuer and a Lender

/s/ Jay Buckman    

Name:     Jay Buckman

Title:    Director

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JPMORGAN CHASE BANK, N.A.,
as a Letter of Credit Issuer and a Lender

/s/ Michael A. Kamauf    

Name:    Michael A. Kamauf

Title:    Authorized Officer

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BANK OF AMERICA, N.A.,
as a Lender

/s/ Tyler Ellis    

Name:    Tyler Ellis

Title:    Director

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FIFTH THIRD BANK, NATIONAL ASSOCIATION,
as a Lender

/s/ Thomas Kleiderer    

Name:    Thomas Kleiderer

Title:    Manager Director

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KEYBANK NATIONAL ASSOCIATION,
as a Lender

/s/ George E. McKean    

Name:    George E. McKean

Title:    Senior Vice President

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MIZUHO BANK, LTD.,
as a Lender

/s/ Edward Sacks    

Name:    Edward Sacks

Title:    Authorized Signatory

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ROYAL BANK OF CANADA,
as a Lender

/s/ Kristan Spivey    

Name:    Kristan Spivey

Title:    Authorized Signatory

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TRUIST BANK,
as a Lender

/s/ James Giordano    

Name:     James Giordano

Title:    Managing Director

226

MORGAN STANLEY SENIOR FUNDING, INC.,
as a Lender

/s/ Michael King    

Name:    Michael King

Title:    Authorized Signatory

227

EX-10.23

Execution Version

First Amendment to Credit Agreement

This First Amendment to Credit Agreement (this “First Amendment”) dated as of September 24, 2021, is among Independence Energy Finance LLC, a Delaware limited liability company (the “Borrower”); each of the undersigned Guarantors (collectively with the Borrower, the “Obligors”); Wells Fargo Bank, National Association, as administrative agent for the Lenders (in such capacity, together with its successors, the “Administrative Agent”), Collateral Agent and a Letter of Credit Issuer; and the Lenders signatory hereto.

    Recitals

A.    The Borrower, the Administrative Agent, the Collateral Agent, the Letter of Credit Issuers and the Lenders are parties to that certain Credit Agreement dated as of May 6, 2021 (as amended, modified, supplemented or restated from time to time prior to the date hereof, the “Credit Agreement”), pursuant to which the Lenders have made certain credit available to and on behalf of the Borrower.

B.    The Borrower, the Administrative Agent and the Lenders have agreed to amend certain provisions of the Credit Agreement as more fully set forth herein.

C.    NOW, THEREFORE, in consideration of the premises and the mutual covenants herein contained, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

Section 1.Defined Terms. Each capitalized term which is defined in the Credit Agreement, but which is not defined in this First Amendment, shall have the meaning ascribed such term in the Credit Agreement. Unless otherwise indicated, all section, exhibit and schedule references in this First Amendment refer to sections, exhibits and schedules of the Credit Agreement. In addition, as used in this First Amendment, each of the following terms shall have the meaning set forth below:

“Contango” means Contango Oil & Gas Company, a Texas corporation.

“Contango Acquisition” means the acquisition by the Borrower of L Merger Sub, the successor by merger to Contango, pursuant to the terms and conditions of the Contango Transaction Agreement.

“Contango Credit Parties” means, collectively, L Merger Sub, Contango Operators Inc., Contaro Company, Contango Midstream Company, Contango Alta Investments, Inc., Contango Resources, Inc., Michael Merger Sub LLC, Mid-Con Energy Properties, LLC, Mid-Con Energy GP, LLC and Mid-Con Energy Finance Corporation.

“Contango Properties” means the Oil and Gas Properties and other Properties acquired by the Borrower and its Restricted Subsidiaries pursuant to the Contango Transaction Agreement.

“Contango Reserve Reports” means, collectively, the reserve reports prepared as of July 1, 2021 with respect to the Contango Properties.

“Contango Transaction Agreement” means that certain Transaction Agreement, dated as of June 7, 2021, by and among Contango, Independence Energy LLC, a

LEGAL_US_W # 109188563.8

Delaware limited liability company, IE PubCo Inc., a Delaware corporation, OpCo, IE C Merger Sub Inc., a Delaware corporation and L Merger Sub.

“First Amendment Reserve Reports” shall mean, collectively, (i) the reserve reports of the Credit Parties, prepared internally by the petroleum engineers of the Credit Parties, with respect to the Oil and Gas Properties of the Credit Parties (other than the Contango Credit Parties) as of July 1, 2021 and (ii) the Contango Reserve Reports.

“L Merger Sub” means IE L Merger Sub LLC, a Delaware limited liability company.

“OpCo” means IE OpCo LLC, a Delaware limited liability company.

Section 2.Amendments to Credit Agreement on First Amendment Signing Date. Subject to the conditions precedent contained in Section 3 hereof, the Credit Agreement shall be amended effective as of the First Amendment Signing Date in the manner provided in this Section 2.

2.1Amendments to Section 1.02.

(a)Each of the following definitions is hereby amended and restated in its entirety to read as follows:

“Agreement” shall mean this Credit Agreement, as amended by the First Amendment, as the same may from time to time be amended, restated, amended and restated, supplemented or otherwise modified.

“Benchmark Replacement Adjustment” means, with respect to any replacement of the then-current Benchmark with an Unadjusted Benchmark Replacement for any applicable Interest Period and Available Tenor for any setting of such Unadjusted Benchmark Replacement:

(1)    for purposes of clauses (a)(1) and (b) of the definition of “Benchmark Replacement,” an amount equal to (A) 0.11448% (11.448 basis points) for an Available Tenor of one-month’s duration, (B) 0.26161% (26.161 basis points) for an Available Tenor of three-months’ duration and (C) 0.42826% (42.826 basis points) for an Available Tenor of six-months’ duration;

(2)    for purposes of clause (a)(2) of the definition of “Benchmark Replacement,” an amount equal to 0.26161% (26.161 basis points); and

(3)    for purposes of clause (a)(3) of the definition of “Benchmark Replacement,” the spread adjustment, or method for calculating or determining such spread adjustment, (which may be a positive or negative value or zero) that has been selected by the Administrative Agent and the Borrower giving due consideration to (i) any selection or recommendation of a spread adjustment, or method for calculating or determining such spread adjustment, for the replacement of such Available Tenor of such Benchmark with the applicable Unadjusted Benchmark Replacement by the Relevant Governmental Body on the applicable Benchmark Replacement Date or (ii) any evolving or then-prevailing market convention for determining a spread adjustment, or method for calculating or determining such spread adjustment, for the replacement of such Available Tenor of such Benchmark with the applicable Unadjusted Benchmark Replacement for Dollar-denominated syndicated credit facilities.

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(b)The following definition is hereby added where alphabetically appropriate to read as follows:

“First Amendment” shall mean that certain First Amendment to Credit Agreement, dated as of September 24, 2021, among the Borrower, the Administrative Agent and the Lenders party thereto.

(c)The definition of “ISDA Definitions” is hereby deleted.

2.2Amendment to Section 2.14(e). Section 2.14(e) is hereby amended and restated in its entirety to read as follows:

(e)    Reduction of Borrowing Base Upon Incurrence of Permitted Junior Lien Debt and/or Permitted Additional Debt. Upon the issuance or incurrence of any Permitted Junior Lien Debt and/or Permitted Additional Debt in accordance with Section 10.1(o) (other than (x) Permitted Additional Debt or Permitted Junior Lien Debt incurred on or after September 24, 2021, in an aggregate principal amount up to $300,000,000 and (y) Permitted Junior Lien Debt or Permitted Additional Debt constituting Permitted Refinancing Indebtedness incurred to Refinance such Indebtedness), unless otherwise determined by the Required Lenders, the Borrowing Base then in effect shall be reduced by an amount equal to the product of 0.25 multiplied by the stated principal amount of such Permitted Additional Debt or Permitted Junior Lien Debt, as applicable, (without regard to any original issue discount), and the Borrowing Base as so reduced shall become the new Borrowing Base one Business Day after such issuance or incurrence, effective and applicable to the Borrower, the Administrative Agent, the Letter of Credit Issuers and the Lenders on such date until the next redetermination or modification thereof hereunder.

2.3Amendment to Section 2.18(a)(i). Section 2.18(a)(i) is hereby amended by adding the following new sentence at the end thereof: “If an Unadjusted Benchmark Replacement is Daily Simple SOFR, all interest payments will be payable on a quarterly basis.”

Section 3.Conditions Precedent to First Amendment Signing Date. Section 2 of this First Amendment shall become effective on the date (such date, the “First Amendment Signing Date”) on which the Administrative Agent shall have received from each Lender and each Obligor counterparts (in such number as may be reasonably requested by the Administrative Agent) of this First Amendment signed on behalf of such Persons.

Section 4.Initial Increase of Elected Commitments.

4.1Initial Increase. The Borrower has informed the Lenders that it desires to increase the Aggregate Elected Commitments on the Initial ECA Increase Effective Date (as defined below) to an amount equal to either $600,000,000, $650,000,000 or $700,000,000. Subject to the conditions precedent contained in Section 4.2, each of the Lenders hereby agrees to increase its Elected Commitment Amount on the Initial ECA Increase Effective Date as follows: (a) if the Initial ECA Increase Notice (as defined below) specifies an Aggregate Elected Commitment Amount equal to $600,000,000, each Lender’s Elected Commitment Amount on the Initial ECA Increase Effective Date shall be the Elected Commitment Amount specified for such Lender on Exhibit A to this First Amendment; (b) if the Initial ECA Increase Notice specifies an Aggregate Elected Commitment Amount equal to $650,000,000, each Lender’s Elected Commitment Amount on the Initial ECA Increase Effective Date shall be the Elected Commitment Amount specified for such Lender on Exhibit B to this First Amendment; or (c) if the Initial ECA Increase Notice specifies an Aggregate Elected Commitment Amount equal to $700,000,000, each Lender’s Elected Commitment Amount on the Initial ECA Increase Effective Date shall be the Elected Commitment Amount specified for such Lender on Exhibit C

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to this First Amendment. This First Amendment shall constitute an Incremental Agreement with respect to the increase of the Elected Commitment Amounts set forth in this Section 4.1.

4.2Conditions Precedent to Initial ECA Increase Effective Date. Section 4.1 of this First Amendment shall become effective on the date (such date, the “Initial ECA Increase Effective Date”) when each of the following conditions is satisfied (or waived in accordance with Section 13.1):

(a)Notice of Elected Commitment Amount Increase. The Administrative Agent shall have received a written notice from an Authorized Officer of the Borrower (which notice shall be irrevocable) at least three Business Days prior to the Initial ECA Increase Effective Date, specifying (a) that the Borrower desires for the Initial ECA Increase Effective Date to occur pursuant to the terms of this First Amendment and (b) the Aggregate Elected Commitment Amount to become effective on the Initial ECA Increase Effective Date, which amount shall be equal to either $600,000,000, $650,000,000 or $700,000,000 (as selected by the Borrower in its sole discretion) (such notice, the “Initial ECA Increase Notice”).

(b)No Event of Default. No Event of Default shall have occurred and be continuing as of the Initial ECA Increase Effective Date.

The Administrative Agent is hereby authorized and directed to declare Section 4.1 of this First Amendment to be effective (and the Initial ECA Increase Effective Date shall occur) when it has received documents confirming or certifying, to the satisfaction of the Administrative Agent, compliance with the conditions set forth in this Section 4.2 or the waiver of such conditions as permitted in Section 13.1 of the Credit Agreement. Such declaration shall be final, conclusive and binding upon all parties to the Credit Agreement for all purposes. Notwithstanding anything to the contrary contained herein, if the Initial ECA Increase Effective Date does not occur on or prior to 5:00 p.m. (Houston time) on December 1, 2021, then none of the conditions contained in this Section 4.2 shall be deemed to be satisfied, and the Initial ECA Increase Effective Date shall not occur (and for the avoidance of doubt, Section 4.1 of this First Amendment shall be of no force or effect).

4.3Assignment and Reallocation of Commitments and Loans. Effective as of the Initial ECA Increase Effective Date, each Lender has, in consultation with the Borrower, agreed to, and, for an agreed consideration, does hereby reallocate its respective Maximum Credit Amount, Commitment, Loans and L/C Participations (the “Assignment and Reallocation”). On the Initial ECA Increase Effective Date, and after giving effect to the Assignment and Reallocation, the Maximum Credit Amount and Commitment of each Lender shall be as set forth on Amended Schedule 1.1(a) (as defined below), which Amended Schedule 1.1(a) amends and restates Schedule 1.1(a) to the Credit Agreement in its entirety. Each of the Administrative Agent, each Lender, each Letter of Credit Issuer and the Borrower hereby consents and agrees to the Assignment and Reallocation. With respect to the Assignment and Reallocation, each Lender shall be deemed to have sold and assigned its Maximum Credit Amount, Commitment, Loans and L/C Participations, and each Lender shall be deemed to have acquired its Maximum Credit Amount, Commitment, Loans and L/C Participations allocated to it from each other Lender pursuant to the terms and conditions of the Assignment and Acceptance attached as Exhibit A to the Credit Agreement (the “Assignment Agreement”), including Annex 1 to the Assignment Agreement (the “Standard Terms and Conditions”) and the Credit Agreement, as if each Lender had executed such Assignment Agreement with respect to the Assignment and Reallocation, pursuant to which (i) each Lender shall be an “Assignee”, (ii) each Lender shall be an “Assignor” and (iii) the term “Effective Date” shall be the Initial ECA Increase Effective Date as defined herein. Such Assignment and Reallocation shall be without recourse to each Lender and, except as expressly provided in the Assignment Agreement, without representation or warranty by such Lender. On the Initial ECA Increase Effective Date, (i) the Administrative Agent shall take the actions specified in Section 13.6(c)(v), including recording the Assignment and Reallocation described herein in the Register, and (ii) the

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Assignment and Reallocation shall be effective for all purposes of the Credit Agreement. Notwithstanding Section 13.6(b)(ii)(C), no Lender shall be required to pay a processing and recordation fee of $3,500 to the Administrative Agent in connection with the Assignment and Reallocation. The Standard Terms and Conditions are hereby agreed to and incorporated herein by reference and made a part of the terms of the Assignment and Reallocation pursuant to this Section 4.3 as if set forth herein in full. As used herein, “Amended Schedule 1.1(a)” means (a) if the Initial ECA Increase Notice specifies an Aggregate Elected Commitment Amount equal to $600,000,000, Exhibit A to this First Amendment; (b) if the Initial ECA Increase Notice specifies an Aggregate Elected Commitment Amount equal to $650,000,000, Exhibit B to this First Amendment; or (c) if the Initial ECA Increase Notice specifies an Aggregate Elected Commitment Amount equal to $700,000,000, Exhibit C to this First Amendment.

Section 5.Additional Increase of Elected Commitments.

5.1Additional Increase. In the event that the Aggregate Elected Commitment Amount on the Initial ECA Increase Effective Date is either $600,000,000 or $650,000,000, and subject to the conditions precedent contained in Section 5.2, each of the Lenders hereby agrees to further increase its Elected Commitment Amount on the Additional ECA Increase Effective Date (as defined below) as follows: (a) if the Additional ECA Increase Notice (as defined below) specifies an Aggregate Elected Commitment Amount equal to $650,000,000, each Lender’s Elected Commitment Amount on the Additional ECA Increase Effective Date shall be the Elected Commitment Amount specified for such Lender on Exhibit B to this First Amendment; or (b) if the Additional ECA Increase Notice specifies an Aggregate Elected Commitment Amount equal to $700,000,000, each Lender’s Elected Commitment Amount on the Additional ECA Increase Effective Date shall be the Elected Commitment Amount specified for such Lender on Exhibit C to this First Amendment. This First Amendment shall constitute an Incremental Agreement with respect to the increase of the Elected Commitment Amounts set forth in this Section 5.1.

5.2Conditions Precedent to Additional ECA Increase Effective Date. Section 5.1 of this First Amendment shall become effective on the date (such date, the “Additional ECA Increase Effective Date”) when each of the following conditions is satisfied (or waived in accordance with Section 13.1):

(a)Notice of Elected Commitment Amount Increase. The Administrative Agent shall have received a written notice from an Authorized Officer of the Borrower (which notice shall be irrevocable) at least three Business Days prior to the Additional ECA Increase Effective Date, specifying (a) that the Borrower desires for the Additional ECA Increase Effective Date to occur pursuant to the terms of this First Amendment and (b) the Aggregate Elected Commitment Amount to become effective on the Additional ECA Increase Effective Date, which amount shall be equal to either $650,000,000 or $700,000,000 (as selected by the Borrower in its sole discretion) (such notice, the “Additional ECA Increase Notice”).

(b)No Event of Default. No Event of Default shall have occurred and be continuing as of the Additional ECA Increase Effective Date.

The Administrative Agent is hereby authorized and directed to declare Section 5.1 of this First Amendment to be effective (and the Additional ECA Increase Effective Date shall occur) when it has received documents confirming or certifying, to the satisfaction of the Administrative Agent, compliance with the conditions set forth in this Section 5.2 or the waiver of such conditions as permitted in Section 13.1 of the Credit Agreement. Such declaration shall be final, conclusive and binding upon all parties to the Credit Agreement for all purposes. Notwithstanding anything to the contrary contained herein, if the Additional ECA Increase Effective Date does not occur on or prior to 5:00 p.m. (Houston time) on December 1, 2021, then none of the conditions contained in this Section 5.2 shall be deemed to be satisfied, and the

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Additional ECA Increase Effective Date shall not occur (and for the avoidance of doubt, Section 5.1 of this First Amendment shall be of no force or effect).

5.3Additional Assignment and Reallocation of Commitments and Loans. Effective as of the Additional ECA Increase Effective Date, each Lender has, in consultation with the Borrower, agreed to, and, for an agreed consideration, does hereby reallocate its respective Maximum Credit Amount, Commitment, Loans and L/C Participations (the “Additional Assignment and Reallocation”). On the Additional ECA Increase Effective Date, and after giving effect to the Additional Assignment and Reallocation, the Maximum Credit Amount and Commitment of each Lender shall be as set forth on Additional Amended Schedule 1.1(a) (as defined below), which Additional Amended Schedule 1.1(a) amends and restates Schedule 1.1(a) to the Credit Agreement in its entirety. Each of the Administrative Agent, each Lender, each Letter of Credit Issuer and the Borrower hereby consents and agrees to the Additional Assignment and Reallocation. With respect to the Additional Assignment and Reallocation, each Lender shall be deemed to have sold and assigned its Maximum Credit Amount, Commitment, Loans and L/C Participations, and each Lender shall be deemed to have acquired its Maximum Credit Amount, Commitment, Loans and L/C Participations allocated to it from each other Lender pursuant to the terms and conditions of the Assignment Agreement, including the Standard Terms and Conditions and the Credit Agreement, as if each Lender had executed such Assignment Agreement with respect to the Additional Assignment and Reallocation, pursuant to which (i) each Lender shall be an “Assignee”, (ii) each Lender shall be an “Assignor” and (iii) the term “Effective Date” shall be the Additional ECA Increase Effective Date as defined herein. Such Additional Assignment and Reallocation shall be without recourse to each Lender and, except as expressly provided in the Assignment Agreement, without representation or warranty by such Lender. On the Additional ECA Increase Effective Date, (i) the Administrative Agent shall take the actions specified in Section 13.6(c)(v), including recording the Additional Assignment and Reallocation described herein in the Register, and (ii) the Additional Assignment and Reallocation shall be effective for all purposes of the Credit Agreement. Notwithstanding Section 13.6(b)(ii)(C), no Lender shall be required to pay a processing and recordation fee of $3,500 to the Administrative Agent in connection with the Additional Assignment and Reallocation. The Standard Terms and Conditions are hereby agreed to and incorporated herein by reference and made a part of the terms of the Additional Assignment and Reallocation pursuant to this Section 5.3 as if set forth herein in full. As used herein, “Additional Amended Schedule 1.1(a)” means (a) if the Additional ECA Increase Notice specifies an Aggregate Elected Commitment Amount equal to $650,000,000, Exhibit B to this First Amendment; or (b) if the Additional ECA Increase Notice specifies an Aggregate Elected Commitment Amount equal to $700,000,000, Exhibit C to this First Amendment.

Section 6.Amendments to Credit Agreement Amendments to Credit Agreement on First Amendment Effective Date. Subject to the conditions precedent contained in Section 7 hereof, the Credit Agreement shall be amended effective as of the First Amendment Effective Date in the manner provided in this Section 6.

6.1Amendments to Section 1.02.

(a)Each of the following definitions is hereby amended and restated in its entirety to read as follows:

“Letter of Credit” shall have the meaning provided in Section 3.1 and shall include the Existing Letters of Credit and the Contango Existing Letters of Credit.

“Letter of Credit Issuer” shall mean (a) Wells Fargo Bank, National Association, (b) JPMorgan Chase Bank, N.A., (c) any of their Affiliates or any replacement or successor appointed pursuant to Section 3.6, (d) solely with respect to the RBC Contango Letter of Credit, Royal Bank of Canada in its capacity as the issuer of the RBC Contango Letter of Credit and (e) if requested

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by the Borrower (subject to the consent of the Administrative Agent, which consent shall not be unreasonably withheld, delayed or conditioned) any other Person who is at the time of such request a Lender that agrees to act as Letter of Credit Issuer (it being understood that if any such Person ceases to be a Lender hereunder, such Person will remain a Letter of Credit Issuer with respect to any Letters of Credit issued by such Person that remained outstanding as of the date such Person ceased to be a Lender). Each Letter of Credit Issuer may, in its discretion, arrange for such Letter of Credit to be issued by any Lender or any Affiliate thereof that agrees to act as Letter of Credit Issuer, and in each such case the term “Letter of Credit Issuer” shall include any such Lender or Affiliate with respect to Letters of Credit issued by such Lender or Affiliate. References herein and in the other Credit Documents to the Letter of Credit Issuer shall be deemed to refer to the Letter of Credit Issuer in respect of the applicable Letter of Credit or to all Letter of Credit Issuers, as the context requires.

(b)Each of the following definitions is hereby added where alphabetically appropriate to read as follows:

“Contango Existing Letters of Credit” shall mean (i) the RBC Contango Letter of Credit existing on the First Amendment Effective Date, (ii) that certain Irrevocable Standby Letter of Credit No. IS000034149U issued by Wells Fargo Bank, National Association to Mid-Con Energy Properties, LLC for the benefit of American Contractors Indemnity Company and/or U.S. Specialty Insurance Company, Tokio Marine HCC Surety, in an aggregate face amount equal to $1,000,000.00, existing on the First Amendment Effective Date and (iii) any amendments, extensions and renewals of the foregoing.

“First Amendment Effective Date” has the meaning assigned to such term in the First Amendment.

“RBC Contango Letter of Credit” shall mean that certain Irrevocable Standby Letter of Credit No. 1185/S25311 issued by Royal Bank of Canada, as Letter of Credit Issuer, for the benefit of Apache Corporation, in an aggregate face amount equal to $1,800,000.00.

(c)The definition of “Initial Borrowing Base” is hereby deleted in its entirety.

6.2Amendment to Section 2.14(a). Section 2.14(a) is hereby amended and restated in its entirety to read as follows:

(a)    First Amendment Borrowing Base. For the period from and including the First Amendment Effective Date to but excluding the first Redetermination Date to occur thereafter, the amount of the Borrowing Base shall be equal to the difference of (i) $1,300,000,000 minus (ii) the amount of any adjustment to the Borrowing Base pursuant to the Borrowing Base Adjustment Provisions that occurred during the period from and after September 24, 2021 through and including the First Amendment Effective Date. Notwithstanding the foregoing, the Borrowing Base may be subject to further adjustments from time to time pursuant to the Borrowing Base Adjustment Provisions. For the avoidance of doubt and notwithstanding anything to the contrary set forth in the Credit Agreement, (i) the redetermination of the Borrowing Base on the First Amendment Effective Date pursuant to this Section 2.14(a) shall constitute the November 2021 Redetermination, (ii) this First Amendment shall constitute the New Borrowing Base Notice for the November 2021 Redetermination and (iii) the

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First Amendment Effective Date shall constitute the Scheduled Redetermination Date for the November 2021 Redetermination.

6.3Amendment to Section 3.3(a). Section 3.3(a) is hereby amended by replacing the parenthetical phrase “(and on the Closing Date, with respect to the Existing Letters of Credit)” with the parenthetical phrase “(and (x) on the Closing Date, with respect to the Existing Letters of Credit and (y) on the First Amendment Effective Date, with respect to the Contango Existing Letters of Credit)”.

6.4Amendment to Article III. Article III is hereby amended by adding a new Section 3.13 to read as follows:

Section 3.13    Contango Existing Letters of Credit. Subject to the terms and conditions hereof, on the First Amendment Effective Date, the Contango Existing Letters of Credit shall, without any further action by the Borrower, be deemed to have been issued by the applicable Letter of Credit Issuer pursuant to, and shall constitute a Letter of Credit for all purposes under, this Agreement, in each case without payment of any fees otherwise due upon the issuance of a Letter of Credit, and each Contango Existing Letter of Credit shall be subject to and governed by the terms and conditions hereof.

6.5Amendment to Section 7.3(b). Section 7.3(b) is hereby amended by replacing the parenthetical phrase “(other than the Existing Letters of Credit)” with the parenthetical phrase “(other than the Existing Letters of Credit and the Contango Existing Letters of Credit)”.

6.6Amendment to Section 9.14(a). The last sentence of Section 9.14(a) is hereby deleted in its entirety.

Section 7.Conditions Precedent to First Amendment Effective Date. Section 6 of this First Amendment shall become effective on the date (such date, the “First Amendment Effective Date”) when each of the following conditions is satisfied (or waived in accordance with Section 13.1):

7.1Fees and Expenses. The Administrative Agent and the Lenders shall have received all fees and other amounts due and payable on or prior to the First Amendment Effective Date, including (to the extent invoiced at least three (3) Business Days prior), reimbursement or payment of all reasonable and documented out-of-pocket expenses required to be reimbursed or paid by the Borrower under the Credit Agreement.

7.2Contango Transaction Closing. The Contango Acquisition shall have been (or contemporaneously with the First Amendment Effective Date shall be) consummated in accordance with the terms of the Contango Transaction Agreement. The Administrative Agent shall have received an officer’s certificate from the Borrower, certifying that (i) the Contango Acquisition has been consummated in accordance with applicable law and the terms described in the Contango Transaction Agreement without giving effect to any waiver, modification or consent thereunder that is materially adverse to the interests of the Lenders (in their capacities as such), and in connection therewith, either (x) the Borrower (or one or more of the other Credit Parties) has acquired all of the Contango Properties evaluated in the Contango Reserve Reports or (y) the PV-9 of the Contango Properties evaluated in the Contango Reserve Reports not acquired is not in excess of 5% of the total Borrowing Base value attributable to the Contango Properties evaluated in the Contango Reserve Report (and setting forth such Contango Properties not acquired on a schedule to such certificate), (ii) all of the Stock and Stock Equivalents of L Merger Sub have been contributed to the Borrower, and as a result thereof, each of the Contango Credit Parties constitutes a wholly owned direct or indirect Subsidiary of the Borrower and (iii) attached thereto is a true and complete executed copy of the Contango Transaction Agreement.

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7.3Secretary’s Certificate. The Administrative Agent shall have received a certificate of an Authorized Officer of each Contango Credit Party, attaching (a) a copy of the resolutions, in form and substance reasonably satisfactory to the Administrative Agent, of the board of directors or managers of such Contango Credit Party (or a duly authorized committee thereof) authorizing the execution, delivery and performance of the Credit Documents (and any agreements relating thereto) to which it is a party, (b) true and complete copies of each of the organizational documents of such Contango Credit Party, (c) certifications as to the incumbency and specimen signature of each officer of such Contango Credit Party executing any Credit Document and (d) certificates of the appropriate State agencies (or other customary evidence) with respect to the existence, qualification and good standing (as applicable in each such jurisdiction) of such Contango Credit Party in each jurisdiction where such Contango Credit Party is organized.

7.4Joinder Documentation. The Administrative Agent shall have received (a) from each Contango Credit Party counterparts of (i) an Assumption Agreement (as such term is defined in the Guarantee), (ii) a supplement to the Security Agreement, substantially in the form of Exhibit 1 to the Security Agreement, (iii) a supplement to the Pledge Agreement, substantially in the form of Annex A to the Pledge Agreement and (iv) an Intercompany Note Joinder, substantially in the form of Annex I to the Intercompany Note, in each case signed on behalf of such Contango Credit Party and (b) from the Borrower counterparts of a supplement to the Pledge Agreement, substantially in the form of Annex A to the Pledge Agreement, signed on behalf of the Borrower.

7.5Legal Opinions. The Administrative Agent shall have received the executed legal opinions of Kirkland & Ellis LLP, counsel to the Contango Credit Parties, in each case in form and substance reasonably satisfactory to the Administrative Agent.

7.6Payoff of Contango Credit Facility. The Administrative Agent shall have received evidence, in form and substance reasonably satisfactory to the Administrative Agent, that all outstanding indebtedness (other than with respect to contingent obligations not then due and payable) of Contango and its subsidiaries under that certain Credit Agreement, dated as of September 17, 2019, by and among Contango, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto, shall have been, or substantially concurrently with the First Amendment Effective Date, will be, repaid in full, all commitments in respect thereof have been terminated, and all security and guarantees in respect thereof discharged and released.

7.7Releases. The Administrative Agent shall have received (a) evidence reasonably satisfactory to it that all Liens on the Contango Properties (provided that Permitted Liens may exist) have been released or terminated, subject only to the filing of applicable terminations, releases or assignments and (b) duly executed recordable releases and terminations reasonably acceptable to the Administrative Agent with respect thereto.

7.8KYC. The Administrative Agent and Lenders shall have received, and be reasonably satisfied in form and substance with all documentation and other information about the Contango Credit Parties as shall have been reasonably requested in writing by the Administrative Agent and Lenders at least five days prior to the First Amendment Effective Date in respect of applicable “know your customer” rules and anti-money laundering laws and regulations, including, without limitation, the Patriot Act.

7.9No Default. No Default or Event of Default shall have occurred and be continuing as of the First Amendment Effective Date.

The Administrative Agent is hereby authorized and directed to declare Section 6 of this First Amendment to be effective (and the First Amendment Effective Date shall occur) when it has received documents confirming or certifying, to the satisfaction of the Administrative Agent,

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compliance with the conditions set forth in this Section 7 or the waiver of such conditions as permitted in Section 13.1 of the Credit Agreement. Such declaration shall be final, conclusive and binding upon all parties to the Credit Agreement for all purposes. For purposes of determining compliance with the conditions specified in this Section 7, each Lender that has signed this Amendment shall be deemed to have consented to, approved or accepted, or to be satisfied with, each document or other matter required thereunder to be consented to or approved by or acceptable or satisfactory to such Lender. Notwithstanding anything to the contrary contained herein, if the First Amendment Effective Date does not occur prior to December 1, 2021, then none of the conditions contained in this Section 7 shall be deemed to be satisfied, and the First Amendment Effective Date shall not occur (and for the avoidance of doubt, Section 6 of this First Amendment shall be of no force or effect).

Section 8.Post-First Amendment Effective Date Covenants

8.1Mortgages. Within 15 days (or such longer period as the Administrative Agent may agree) of the First Amendment Effective Date, the Administrative Agent shall have received duly executed and notarized Mortgages or supplements to existing Mortgages in form reasonably satisfactory to the Administrative Agent, to the extent necessary to satisfy the Collateral Coverage Minimum (based upon the PV-9 of the total Proved Reserves evaluated in the First Amendment Reserve Reports (on a combined basis)). In connection therewith, the Administrative Agent shall have received the executed legal opinions of local counsel to the Contango Credit Parties in the States of Louisiana, Montana and Oklahoma, in each case in form and substance reasonably satisfactory to the Administrative Agent.

8.2Title. Within 15 days (or such longer period as the Administrative Agent may agree) of the First Amendment Effective Date, the Administrative Agent shall have received title information reasonably satisfactory to the Administrative Agent setting forth the status of title to at least 85% of the PV-9 of the total Proved Reserves evaluated in the First Amendment Reserve Reports (on a combined basis).

8.3Certain Collateral. Within 15 days (or such longer period as the Administrative Agent may agree) of the First Amendment Effective Date, the Collateral Agent shall have received all certificates, if any, representing such securities pledged under the Pledge Agreement in connection with the acquisition of the Contango Credit Parties, accompanied by instruments of transfer and/or undated powers endorsed in blank.

Section 9.Miscellaneous.

9.1Confirmation.  The provisions of the Credit Agreement, as amended by this First Amendment, shall remain in full force and effect following the First Amendment Effective Date.

9.2Ratification and Affirmation; Representations and Warranties.  The Borrower hereby: (a) acknowledges the terms of this First Amendment; (b) ratifies and affirms its obligations under, and acknowledges its continued liability under, each Credit Document to which it is a party and agrees that each such Credit Document remains in full force and effect as expressly amended hereby; (c) agrees that from and after the date hereof, each reference to the Credit Agreement in the other Credit Documents shall be deemed to be a reference to the Credit Agreement, as amended by this First Amendment; and (d) represents and warrants to the Lenders that as of the date hereof, after giving effect to the terms of this First Amendment: (i) the representations and warranties set forth in each Credit Document to which it is a party are true and correct in all material respects (except where such representations and warranties expressly relate to an earlier date, in which case such representations and warranties shall have been true and correct in all material respects as of such earlier date), provided that such representations shall be true and correct in all respects to the extent already qualified by materiality, and (ii) no Default or Event of Default has occurred and is continuing.

Page 10

9.3Counterparts.  This First Amendment may be executed in counterparts (and by different parties hereto on different counterparts), each of which shall constitute an original, but all of which when taken together shall constitute a single contract. Each party hereto agrees that any Electronic Signature or execution in the form of an Electronic Record shall be valid and binding on itself and each of the other parties hereto to the same extent as a manual, original signature.

9.4No Oral Agreement.  This First Amendment and the other Credit Documents represent the agreement of the Borrower, the Guarantors, the Collateral Agent, the Administrative Agent and the Lenders with respect to the subject matter hereof and thereof, and there are no promises, undertakings, representations or warranties by the Borrower, the Guarantors, any Agent nor any Lender relative to the subject matter hereof not expressly set forth or referred to herein or in the other Credit Documents.

9.5GOVERNING LAW.  THIS FIRST AMENDMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY, AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

9.6Payment of Expenses.  In accordance with and to the extent required by Section 13.5, the Borrower agrees to pay or reimburse the Administrative Agent for all of its reasonable and documented out-of-pocket costs and expenses incurred in connection with this First Amendment, any other documents prepared in connection herewith and the transactions contemplated hereby, including, without limitation, the reasonable and documented fees, charges and disbursements of counsel to the Administrative Agent.

9.7Severability.  Any provision of this First Amendment that is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

9.8Successors and Assigns.  This First Amendment shall be binding upon and inure to the benefit of the parties hereto and their respective successors and permitted assigns.

9.9Credit Document. This First Amendment is a “Credit Document” as defined and described in the Credit Agreement, and all of the terms and provisions of the Credit Agreement relating to Credit Documents shall apply hereto.

[Signature Pages Follow]

Page 11

IN WITNESS WHEREOF, the parties hereto have caused this First Amendment to be duly executed.

BORROWER:	INDEPENDENCE ENERGY FINANCE LLC
	By: /s/ Brandi Kendall     Name: Brandi Kendall Title: Chief Financial Officer
GUARANTORS:

INDEPENDENCE ENERGY HOLDING LLC INDEPENDENCE MINERALS HOLDINGS LLC IE BUFFALO MINERALS LLC
By:	/s/ Brandi Kendall
Name: Brandi Kendall
Title: Vice President

INDEPENDENCE UPSTREAM HOLDINGS L.P. By: Independence Upstream Holdings GP LLC
By:	/s/ Brandi Kendall
Name: Brandi Kendall
Title: Authorized Person

COLT ADMIRAL A HOLDING L.P. TITAN ENERGY HOLDINGS L.P. By: Colt Admiral A Holding GP LLC
By:	/s/ Brandi Kendall
Name: Brandi Kendall
Title: Authorized Person

Signature Page to Independence Energy Finance LLC First Amendment to Credit Agreement

PALO VERDE HOLDINGS GP LLC INDEPENDENCE UPSTREAM HOLDINGS GP LLC COLT ADMIRAL A HOLDING GP LLC
By:	/s/ Brandi Kendall
Name: Brandi Kendall
Title: Authorized Person

VENADO EF C-I HOLDINGS L.P. By: Venado EF Holdings GP LLC
By:	/s/ Brandi Kendall
Name: Brandi Kendall
Title: Authorized Person

PALO VERDE C-I HOLDINGS L.P. By: Palo Verde Holdings GP LLC
By:	/s/ Brandi Kendall
Name: Brandi Kendall
Title: Authorized Person

BRIDGE ENERGY LLC BRIDGE ENERGY HOLDINGS LLC
By:	/s/ Brandi Kendall
Name: Brandi Kendall
Title: Authorized Person

Signature Page to Independence Energy Finance LLC First Amendment to Credit Agreement

VENADO OIL & GAS, LLC SPRINGFIELD GS HOLDINGS LLC VENADO EFA GP LLC VOG PALO VERDE GP LLC VENADO MARKETING, LLC
By:	/s/ Brandi Kendall
Name: Brandi Kendall
Title: Authorized Person

VENADO EFA HOLDINGS LLC VENADO PARTNERS, LLC VENADO OG, LLC By: Venado Oil & Gas, LLC
By:	/s/ Brandi Kendall
Name: Brandi Kendall
Title: Authorized Person

VENADO EF L.P. By: Venado EF GP LLC
By:	/s/ Brandi Kendall
Name: Brandi Kendall
Title: Authorized Person

PALO VERDE AGGREGATOR L.P. By: Venado EFA GP LLC
By:	/s/ Brandi Kendall
Name: Brandi Kendall
Title: Authorized Person

Signature Page to Independence Energy Finance LLC First Amendment to Credit Agreement

VOG PALO VERDE LP By: VOG Palo Verde GP LLC
By:	/s/ Brandi Kendall
Name: Brandi Kendall
Title: Authorized Person

VENADO EF GP LLC By: Venado EF Aggregator L.P.
By:	/s/ Brandi Kendall
Name: Brandi Kendall
Title: Authorized Person

VENADO EF AGGREGATOR L.P. By: Venado EFA GP LLC
By:	/s/ Brandi Kendall
Name: Brandi Kendall
Title: Authorized Person

Signature Page to Independence Energy Finance LLC First Amendment to Credit Agreement

TE NEWARK AGENT CORP.
By:	/s/ Jason Carss
Name: Jason Carss
Title: Assistant Secretary

Signature Page to Independence Energy Finance LLC First Amendment to Credit Agreement

EIGF TE GP RESOURCE INVESTORS GP LLC RENEE HOLDING GP LLC EIGF MINERALS GP LLC INDEPENDENCE MINERALS GP LLC IE BUFFALO HOLDINGS LLC VINE ROYALTY GP LLC EIGF TE RESOURCE HOLDINGS GP I LLC EIGF TE GP RESOURCE HOLDINGS GP I LLC TE RENEE AGENT CORP. RENEE C-I HOLDING AGENT CORP. RENEE ACQUISITION LLC KNR RENEE AGENT CORP KNR RESOURCE INVESTORS GP LLC KNR RESOURCE HOLDINGS GP I LLC EIGF TE GP NEWARK ACQUISITION GP I LLC NEWARK C-I HOLDING GP I LLC NEWARK ACQUISITION GP I LLC
By:	/s/ David Rockecharlie
Name: David Rockecharlie
Title: Vice President

NEWARK HOLDING AGENT CORP.
By:	/s/ David Rockecharlie
Name: David Rockecharlie
Title: Chief Executive Officer

Signature Page to Independence Energy Finance LLC First Amendment to Credit Agreement

EIGF TE GP RESOURCE INVESTORS L.P. By: EIGF TE GP Resource Investors GP LLC
By:	/s/ David Rockecharlie
Name: David Rockecharlie
Title: Vice President
EIGF TE GP NEWARK INVESTORS L.P. By: EIGF TE GP Resource Investors GP LLC
By:	/s/ David Rockecharlie
Name: David Rockecharlie
Title: Vice President

NEWARK C-I HOLDING L.P. By: Newark C-I Holding GP I LLC
By:	/s/ David Rockecharlie
Name: David Rockecharlie
Title: Vice President

EIGF MINERALS L.P. By: EIGF Minerals GP LLC
By:	/s/ David Rockecharlie
Name: David Rockecharlie
Title: Vice President

Signature Page to Independence Energy Finance LLC First Amendment to Credit Agreement

INDEPENDENCE MINERALS L.P. DMA ROYALTY INVESTMENTS L.P. FALCON HOLDING L.P. MINERAL ACQUISITION COMPANY I, LP By: Independence Minerals GP LLC
By:	/s/ David Rockecharlie
Name: David Rockecharlie
Title: Vice President

Signature Page to Independence Energy Finance LLC First Amendment to Credit Agreement

VINE ROYALTY L.P. By: Vine Royalty GP LLC
By:	/s/ David Rockecharlie
Name: David Rockecharlie
Title: Vice President

EIGF TE RESOURCE HOLDINGS I L.P. By: EIGF TE Resource Holdings GP I LLC
By:	/s/ David Rockecharlie
Name: David Rockecharlie
Title: Vice President

EIGF TE GP RESOURCE HOLDINGS I L.P. By: EIGF TE GP Resource Holdings GP I LLC
By:	/s/ David Rockecharlie
Name: David Rockecharlie
Title: Vice President

KNR RESOURCE INVESTORS L.P. By: KNR Resource Investors GP LLC
By:	/s/ David Rockecharlie
Name: David Rockecharlie
Title: Vice President

Signature Page to Independence Energy Finance LLC First Amendment to Credit Agreement

RENEE C-I HOLDING L.P. By: Renee Holding GP LLC
By:	/s/ David Rockecharlie
Name: David Rockecharlie
Title: Vice President

KNR RESOURCE HOLDINGS I L.P. By: KNR Resource Holdings GP I LLC
By:	/s/ David Rockecharlie
Name: David Rockecharlie
Title: Vice President

EIGF TE NEWARK HOLDINGS I L.P. By: EIGF TE Resource Holdings GP I LLC
By:	/s/ David Rockecharlie
Name: David Rockecharlie
Title: Vice President

EIGF TE GP NEWARK ACQUISITION I L.P. By: EIGF TE GP Newark Acquisition GP I LLC
By:	/s/ David Rockecharlie
Name: David Rockecharlie
Title: Vice President

Signature Page to Independence Energy Finance LLC First Amendment to Credit Agreement

NEWARK ACQUISITION I L.P. By: Newark Acquisition GP I LLC
By:	/s/ David Rockecharlie
Name: David Rockecharlie
Title: Vice President

Signature Page to Independence Energy Finance LLC First Amendment to Credit Agreement

INDEPENDENCE UPSTREAM L.P. By: Independence Upstream GP LLC
By:	/s/ Stephen Jordan
Name: Stephen Jordan
Title: Vice President

INDEPENDENCE UPSTREAM GP LLC
By:	/s/ Stephen Jordan
Name: Stephen Jordan
Title: Vice President

Signature Page to Independence Energy Finance LLC First Amendment to Credit Agreement

ADMINISTRATIVE AGENT, COLLATERAL AGENT, LETTER OF CREDIT ISSUER and LENDER: WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent, Collateral Agent, a Letter of Credit Issuer and Lender By:     /s/ Jay Buckman         Name:    Jay Buckman Title: Director

Signature Page to Independence Energy Finance LLC First Amendment to Credit Agreement

LETTER OF CREDIT ISSUER and LENDER: JPMORGAN CHASE BANK, N.A., as a Letter of Credit Issuer and Lender By:     /s/ Michael Kamauf             Name:    Michael Kamauf Title: Authorized Officer

Signature Page to Independence Energy Finance LLC First Amendment to Credit Agreement

LENDER: BANK OF AMERICA, N.A., as a Lender By:     /s/ Kimberly Miller             Name:    Kimberly Miller Title: Director

Signature Page to Independence Energy Finance LLC First Amendment to Credit Agreement

LENDER: FIFTH THIRD BANK, NATIONAL ASSOCIATION, as a Lender By:     /s/ Thomas Kleiderer             Name:    Thomas Kleiderer Title: Managing Director

Signature Page to Independence Energy Finance LLC First Amendment to Credit Agreement

LENDER: KEYBANK NATIONAL ASSOCIATION, as a Lender By:     /s/ George E. McKean             Name:    George E. McKean Title: Senior Vice President

Signature Page to Independence Energy Finance LLC First Amendment to Credit Agreement

LENDER: MIZUHO BANK, LTD., as a Lender By:     /s/ Edward Sacks             Name:    Edward Sacks Title: Authorized Signatory

Signature Page to Independence Energy Finance LLC First Amendment to Credit Agreement

LENDER: ROYAL BANK OF CANADA, as a Lender By:     /s/ Kristan Spivey             Name:    Kristan Spivey Title: Authorized Signatory

Signature Page to Independence Energy Finance LLC First Amendment to Credit Agreement

LENDER: TRUIST BANK, as a Lender By:     /s/ James Giordano             Name:    James Giordano Title: Managing Director

Signature Page to Independence Energy Finance LLC First Amendment to Credit Agreement

LENDER: MORGAN STANLEY SENIOR FUNDING, INC., as a Lender By:     /s/ Rikin Pandya             Name:    Rikin Pandya Title: Vice President

Signature Page to Independence Energy Finance LLC First Amendment to Credit Agreement

EX-21.1

Exhibit 21.1

Crescent Energy Company Subsidiaries	Jurisdiction
Bridge Energy Holdings LLC	Delaware
Bridge Energy LLC	Delaware
Bridge Energy Management LLC	Delaware
CMP Legacy Co. LLC	Delaware
CMP Venture Co. LLC	Delaware
Colt Admiral A Holding GP LLC	Delaware
Colt Admiral A Holding L.P.	Delaware
Contango AgentCo Onshore, Inc.	Delaware
Contango Alta Investments, LLC	Delaware
Contango Crescent VentureCo I LLC	Delaware
Contango Midstream Company, LLC	Delaware
Contango Oil & Gas Management LLC	Delaware
Contango Resources, LLC	Delaware
Contaro Company, LLC	Delaware
Crescent Conventional LLC	Delaware
Crescent Energy Finance LLC	Delaware
Crescent Energy OpCo LLC	Delaware
Crescent Minerals Partners Management LLC	Delaware
DMA Royalty Investments L.P.	Delaware
EIGF Minerals GP LLC	Delaware
EIGF Minerals L.P.	Delaware
Falcon Holding L.P.	Delaware
IE Buffalo Holdings LLC	Delaware
IE Buffalo Minerals LLC	Delaware
IE L Merger Sub LLC	Delaware
Independence Energy Holding LLC	Delaware
Independence Energy Management LLC	Delaware
Independence Minerals GP LLC	Delaware
Independence Minerals Holdings LLC	Delaware
Independence Minerals L.P.	Delaware
Independence Upstream GP LLC	Delaware
Independence Upstream Holdings GP LLC	Delaware
Independence Upstream Holdings L.P.	Delaware
Independence Upstream L.P.	Delaware
Javelin EF Aggregator L.P. fka Venado EF Aggregator L.P.	Delaware
Javelin EF GP LLC fka Venado EF GP LLC	Delaware
Javelin EF L.P. fka Venado EF L.P.	Delaware
Javelin EFA GP LLC fka Venado EFA GP LLC	Delaware
Javelin EFA Holdings LLC fka Venado EFA Holdings LLC	Delaware
Javelin Energy Partners Management LLC	Delaware
Javelin Marketing, LLC fka Venado Marketing, LLC	Delaware
Javelin Oil & Gas, LLC fka Venado Oil & Gas, LLC	Delaware
Javelin Palo Verde Aggregator L.P. fka Palo Verde Aggregator L.P.	Delaware
Javelin Palo Verde GP LLC fka VOG Palo Verde GP LLC	Delaware
Javelin Palo Verde LP fka VOG Palo Verde LP	Delaware
Javelin VentureCo LLC	Delaware

Crescent Energy Company Subsidiaries	Jurisdiction
KNR Renee Agent Corp	Delaware
KNR Resource Holdings GP I LLC	Delaware
KNR Resource Holdings I L.P.	Delaware
KNR Resource Investors GP LLC	Delaware
KNR Resource Investors L.P.	Delaware
KNR Resources Investors GP LLC	Delaware
Madden AgentCo Inc.	Delaware
Madden AssetCo LLC	Delaware
Mineral Acquisition Company I, LP	Delaware
Newark Acquisition GP I LLC	Delaware
Newark Acquisition I L.P.	Delaware
Newark C-I Holding L.P.	Delaware
Newark Holding Agent Corp.	Delaware
Palo Verde Aggregator L.P.	Delaware
Renee Acquisition LLC	Delaware
Renee C-I Holding Agent Corp.	Delaware
Renee C-I Holding L.P.	Delaware
Renee Holding GP LLC	Delaware
Springfield GS Holdings LLC	Delaware
Sunrise Independence WI AgentCo Inc.	Delaware
Titan Energy Holdings L.P.	Delaware
Vine Royalty GP LLC	Delaware
Vine Royalty L.P.	Delaware

EX-23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-261604 on Form S-8 of our report dated March 9, 2022, relating to the financial statements of Crescent Energy Company appearing in this Annual Report on Form 10-K for the year ended December 31, 2021.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 9, 2022

EX-23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

As independent petroleum engineers, we hereby consent to the incorporation by reference into or inclusion in this Annual Report on Form 10-K (including any amendments or supplements thereto, related appendices, and financial statements) (this "Annual Report") of Crescent Energy Company (the "Company") of our firm’s audit letter dated January 14, 2022 and reserves report dated January 17, 2022, respectively, each prepared for the Company as of December 31, 2021. We hereby further consent to all references to our firm or such letters included in or incorporated by reference into this Annual Report. We also hereby consent to the incorporation by references to our firm’s audit letter dated January 14, 2022 and reserves report dated January 17, 2022, respectively, each prepared for the Company as of December 31, 2021, into the Registration Statements on Form S-8 (Nos. 333- 261604) of the Company, including any amendments thereto.

NETHERLAND, SEWELL & ASSOCIATES, INC.

By:    /s/ Danny D. Simmons, P.E.    

Danny D. Simmons, P.E.

President and Chief Operating Officer

Houston, Texas

March 9, 2022

EX-23.3

    750 N. St. Paul Street

    Suite 1750

    Dallas, Texas 75201

    Phone (214) 754-7090

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

As independent petroleum engineers, we hereby consent to the inclusion of information included in this Annual Report on Form 10-K of Crescent Energy Company with respect to the information from our firm’s reserves reports dated January 31, 2022, prepared for Crescent Energy Company as of December 31, 2021, in reliance upon the reports of this firm and upon the authority of this firm as experts in petroleum engineering. We also hereby consent to the incorporation by references to the information from our firm’s reserves reports dated January 31, 2022, prepared for Crescent Energy Company as of December 31, 2021, into the Registration Statements on Form S-8 (Nos. 333- 261604) of Crescent Energy Company, including any amendments thereto.

HAAS PETROLEUM ENGINEERING SERVICES, INC.

Texas Registered Engineering Firm

/s/ J. Thaddeus Toups    

J. Thaddeus Toups, P.E.

President

Dallas, Texas

March 9, 2022

EX-23.4

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

As independent petroleum engineers, we hereby consent to the references to our firm, in the context in which they appear, and to the references to, and the inclusion of, our reserve report and oil, natural gas and NGL reserves estimates and forecasts of economics as of December 31, 2021, included in or made part of this Annual Report on Form 10-K of Crescent Energy Company. We also hereby consent to the incorporation by references to our firm, in the context in which they appear, and to the references to, and the inclusion of, our reserve report and oil, natural gas and NGL reserves estimates and forecasts of economics as of December 31, 2021, into the Registration Statements on Form S-8 (Nos. 333- 261604) of Crescent Energy Company, including any amendments thereto.

CAWLEY, GILLESPIE & ASSOCIATES, INC.

Texas Registered Engineering Firm

/s/ W. TODD BROOKER    

W. Todd Brooker, P.E.

President

Austin, Texas

March 9, 2022

EX-23.5

WILLIAM M. COBB & ASSOCIATES, INC.

Worldwide Petroleum Consultants

12770 Coit Road, Suite 907    Tel: (972) 385-0354

Dallas, Texas 75251    Fax: (972) 788-5165

    E-Mail: office@wmcobb.com    

March 9, 2022

Crescent Energy Company

600 Travis Street, Suite 7200

Houston, Texas, 77002

Re: Crescent Energy Company

Gentlemen:

The firm of William M. Cobb & Associates, Inc. consents to the use of its name and to the use of its projections for Crescent Energy Company’s Proved Reserves and Future Net Revenue included in this Annual Report on Form 10-K of Crescent Energy Company. The firm of William M. Cobb & Associates, Inc. also hereby consents to the incorporation by references to the use of its name and to the use of its projections for Crescent Energy Company’s Proved Reserves and Future Net Revenue into the Registration Statements on Form S-8 (Nos. 333- 261604) of Crescent Energy Company, including any amendments thereto.

William M. Cobb & Associates, Inc. has no interests in Crescent Energy Company or in any affiliated companies or subsidiaries and is not to receive any such interest as payment for such reports and has no director, officer, or employee otherwise connected with Crescent Energy Company. Crescent Energy Company does not employ us on a contingent basis.

Sincerely,

WILLIAM M. COBB & ASSOCIATES, INC.

Texas Registered Engineering Firm F-84

/s/ Tor Meling

Tor Meling

Senior Vice President

EX-31.1

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, David C. Rockecharlie, certify that:

1.I have reviewed this Annual Report on Form 10-K of Crescent Energy Company (“registrant”);

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

March 9, 2022

/s/ David Rockecharlie

David Rockecharlie

Chief Executive Officer

(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Brandi Kendall, certify that:

1.I have reviewed this Annual Report on Form 10-K of Crescent Energy Company (“registrant”);

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

March 9, 2022

/s/ Brandi Kendall

Brandi Kendall

Chief Financial Officer

(Principal Financial Officer)

EX-32.1

Exhibit 32.1

CERTIFICATION OF

CHIEF EXECUTIVE OFFICER AND

CHIEF FINANCIAL OFFICER

UNDER SECTION 906 OF THE

SARBANES OXLEY ACT OF 2002, 18 U.S.C. § 1350

In connection with the accompanying Annual Report on Form 10-K of Crescent Energy Company (the “Company”) for the year ended December 31, 2021 that is being filed with the Securities and Exchange Commission on the date hereof (the “Report”), David Rockecharlie, Chief Executive Officer of the Company, and Brandi Kendall, Chief Financial Officer of the Company, each certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to his/her knowledge:

i. the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

ii. the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

March 9, 2022

/s/ David Rockecharlie

David Rockecharlie

Chief Executive Officer

(Principal Executive Officer)

/s/ Brandi Kendall

Brandi Kendall

Chief Financial Officer

(Principal Financial Officer)

EX-99.1

January 14, 2022

Mr. Brett Knight

Crescent Energy Company

600 Travis Street, Suite 7200

Houston, Texas 77002

Dear Mr. Knight:

In accordance with your request, we have audited the estimates prepared by Crescent Energy Company (Crescent), as of December 31, 2021, of the proved reserves and future revenue to the Crescent interest in certain oil and gas properties located in the United States. It is our understanding that the proved reserves estimates shown herein constitute approximately 16 percent of all proved reserves owned by Crescent. We have examined the estimates with respect to reserves quantities, reserves categorization, future producing rates, future net revenue, and the present value of such future net revenue, using the definitions set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Rule 4-10(a). The estimates of reserves and future revenue have been prepared in accordance with the definitions and regulations of the SEC and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. We completed our audit on or about the date of this letter. This report has been prepared for Crescent's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

The following table sets forth Crescent's estimates of the net reserves and future net revenue, as of December 31, 2021, for the audited properties:

	Net Reserves			Future Net Revenue (M$)
	Oil	NGL	Gas		Present Worth
Category	(MBBL)	(MBBL)	(MMCF)	Total	at 10%
Proved Developed Producing	20,055.8	15,329.4	203,445.7	1,368,963.4	844,472.6
Proved Developed Non-Producing	,653.2	281.4	2,744.1	29,691.5	18,697.8
Proved Undeveloped	5,317.5	4,426.3	30,852.2	258,134.7	111,367.1
Total Proved	26,026.6	20,037.1	237,042.0	1,656,789.7	974,537.5

Totals may not add because of rounding.

The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

When compared on a well-by-well basis, some of the estimates of Crescent are greater and some are less than the estimates of Netherland, Sewell & Associates, Inc. (NSAI). However, in our opinion the estimates shown herein of Crescent's reserves and future revenue are reasonable when aggregated at the proved level and have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). Additionally, these estimates are within the recommended 10 percent tolerance threshold set forth in the SPE Standards. We are satisfied with the methods and procedures used by Crescent in preparing the December 31, 2021, estimates of reserves and future revenue, and we saw nothing of an unusual nature that would cause us to take exception with the estimates, in the aggregate, as prepared by Crescent.

Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk. Crescent's estimates do not include probable or possible reserves that may exist for these properties, nor do they include any value for undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated.

Prices used by Crescent are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2021. For oil and NGL volumes, the average West Texas Intermediate spot price of $66.56 per barrel is adjusted for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $3.598 per MMBTU is adjusted for energy content, transportation fees, and market differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $63.86 per barrel of oil, $26.03 per barrel of NGL, and $3.634 per MCF of gas.

Operating costs used by Crescent are based on historical operating expense records. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. However, these overhead expenses have not been included in the confirmation of economic producibility or in the determination of economic limits for the properties. Operating costs have been divided into per-well costs and per-unit-of-production costs. Since all properties are nonoperated, headquarters general and administrative overhead expenses are not included. Capital costs used by Crescent are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for tubing installations, artificial lift installations, new development wells, and production equipment. Abandonment costs used are Crescent's estimates of the costs to abandon the wells and production facilities, net of any salvage value. Operating, capital, and abandonment costs are not escalated for inflation.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, estimates of Crescent and NSAI are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by Crescent, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing these estimates.

It should be understood that our audit does not constitute a complete reserves study of the audited oil and gas properties. Our audit consisted primarily of substantive testing, wherein we conducted a detailed review of all properties. In the conduct of our audit, we have not independently verified the accuracy and completeness of information and data furnished by Crescent with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. However, if in the course of our examination something came to our attention that brought into question the validity or sufficiency of any such information or data, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or had independently verified such information or data. Our audit did not include a review of Crescent's overall reserves management processes and practices.

We used standard engineering and geoscience methods, or a combination of methods, including performance analysis and analogy, that we considered to be appropriate and necessary to establish the conclusions set forth

herein. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

Supporting data documenting this audit, along with data provided by Crescent, are on file in our office. The technical person primarily responsible for conducting this audit meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Connor B. Riseden, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2006 and has over 4 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

    Sincerely,

    NETHERLAND, SEWELL & ASSOCIATES, INC.

    Texas Registered Engineering Firm F-2699

            /s/ C.H. (Scott) Rees III

            By:        

            C.H. (Scott) Rees III, P.E.

            Chairman and Chief Executive Officer

            /s/ Connor B. Riseden

            By:        

            Connor B. Riseden, P.E. 100566

            Vice President

        Date Signed: January 14, 2022

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2018 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i)    Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii)    Same environment of deposition;

(iii)    Similar geological structure; and

(iv)    Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i)    Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii)    Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Supplemental definitions from the 2018 Petroleum Resources Management System:

Developed Producing Reserves – Expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate. Improved recovery Reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves – Shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals that are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i)    Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

(ii)    Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

Definitions - Page 1 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(iii)    Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

(iv)    Provide improved recovery systems.

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i)    Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.

(ii)    Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

(iii)    Dry hole contributions and bottom hole contributions.

(iv)    Costs of drilling and equipping exploratory wells.

(v)    Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

(i)    Oil and gas producing activities include:

(A)    The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;

(B)    The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C)    The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

(1)    Lifting the oil and gas to the surface; and

(2)    Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

Definitions - Page 2 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(D)    Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a.    The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

b.    In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii)    Oil and gas producing activities do not include:

(A)    Transporting, refining, or marketing oil and gas;

(B)    Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

(C)    Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D)    Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i)    When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii)    Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii)    Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv)    The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v)    Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi)    Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i)    When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

Definitions - Page 3 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(ii)    Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii)    Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv)    See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.

(i)    Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

(A)    Costs of labor to operate the wells and related equipment and facilities.

(B)    Repairs and maintenance.

(C)    Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

(D)    Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(E)    Severance taxes.

(ii)    Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i)    The area of the reservoir considered as proved includes:

(A)    The area identified by drilling and limited by fluid contacts, if any, and

(B)    Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii)    In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii)    Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv)    Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A)    Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous

Definitions - Page 4 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B)    The project has been approved for development by all necessary parties and entities, including governmental entities.

(v)    Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:

932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:

    a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)

    b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.

932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

    a. Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.

    b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.

    c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.

    d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

Definitions - Page 5 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

              e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing

                     of the future net cash flows relating to proved oil and gas reserves.

    f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the

                     computed discount.

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i)    Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii)    Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):

Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.

Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);

The company's historical record at completing development of comparable long-term projects;

The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;

The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and

The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

(iii)    Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.

Definitions - Page 6 of 6

EX-99.2

January 17, 2022

Mr. Brett Knight

Crescent Energy Company

600 Travis Street, Suite 7200

Houston, Texas 77002

Dear Mr. Knight:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2021, to the Crescent Energy Company (Crescent) interest in certain oil and gas properties located in Brea-Olinda Field, Los Angeles and Orange Counties, California. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute approximately 3 percent of all proved reserves owned by Crescent. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Crescent's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the Crescent interest in these properties, as of December 31, 2021, to be:

	Net Reserves		Future Net Revenue (M$)
	Oil	NGL		Present Worth
Category	(MBBL)	(MBBL)	Total	at 10%
Proved Developed Producing	14,140.4	353.5	421,056.1	177,661.7
Proved Developed Non-Producing	1,472.7	36.8	50,768.9	19,209.9
Total Proved Developed	15,613.1	390.3	471,825.0	196,871.6

The oil volumes shown include crude oil only. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Residual produced gas is consumed in field operations.

Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. Our study indicates that as of December 31, 2021, there are no proved undeveloped reserves for these properties. As requested, probable reserves that exist for these properties have not been included. No study was made to determine whether possible reserves might be established for these properties. The estimates of reserves and future revenue included herein have not been adjusted for risk. This report does not include any value that could be attributed to interests in undeveloped acreage.

Gross revenue is Crescent's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Crescent's share of production taxes, ad valorem taxes, capital costs, abandonment costs, operating expenses, and payments to net profits interests but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2021. For oil and NGL volumes, the average West Texas Intermediate spot price of $66.56 per barrel is adjusted for quality, transportation fees, and market differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $66.98 per barrel of oil and $53.91 per barrel of NGL.

Operating costs used in this report are based on operating expense records of Bridge Energy LLC (Bridge), the operator of the properties. As requested, operating costs are limited to direct lease- and field-level costs and Bridge's estimate of the portion of its headquarters general and administrative overhead expenses necessary to operate the properties. Operating costs have been divided into field-level costs, per-well costs, and per-unit-of-production costs and are not escalated for inflation.

Capital costs used in this report were provided by Bridge and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Abandonment costs used in this report are Bridge's estimates of the costs to abandon the wells and production facilities, net of any salvage value. Capital costs and abandonment costs are not escalated for inflation.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Crescent interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Crescent receiving its net revenue interest share of estimated future gross production. Additionally, we have made no specific investigation of any firm transportation contracts that may be in place for these properties; our estimates of future revenue include the effects of such contracts only to the extent that the associated fees are accounted for in the historical field- and lease-level accounting statements.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by Bridge, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis and analogy,

that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from Crescent, Bridge, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons primarily responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. C. Ashley Smith, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2006 and has over 5 years of prior industry experience. Shane M. Howell, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 2005 and has over 7 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

    Sincerely,

    NETHERLAND, SEWELL & ASSOCIATES, INC.

    Texas Registered Engineering Firm F-2699

            /s/ C.H. (Scott) Rees III

            By:        

            C.H. (Scott) Rees III, P.E.

            Chairman and Chief Executive Officer

    /s/ C. Ashley Smith        /s/ Shane M. Howell

By:            By:        

    C. Ashley Smith, P.E. 100560        Shane M. Howell, P.G. 11276

    Vice President        Vice President

Date Signed: January 17, 2022    Date Signed: January 17, 2022

CAS:RQH

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2018 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i)    Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii)    Same environment of deposition;

(iii)    Similar geological structure; and

(iv)    Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i)    Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii)    Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Supplemental definitions from the 2018 Petroleum Resources Management System:

Developed Producing Reserves – Expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate. Improved recovery Reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves – Shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals that are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i)    Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

(ii)    Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

Definitions - Page 1 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(iii)    Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

(iv)    Provide improved recovery systems.

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i)    Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.

(ii)    Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

(iii)    Dry hole contributions and bottom hole contributions.

(iv)    Costs of drilling and equipping exploratory wells.

(v)    Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

(i)    Oil and gas producing activities include:

(A)    The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;

(B)    The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C)    The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

(1)    Lifting the oil and gas to the surface; and

(2)    Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

Definitions - Page 2 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(D)    Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a.    The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

b.    In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii)    Oil and gas producing activities do not include:

(A)    Transporting, refining, or marketing oil and gas;

(B)    Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

(C)    Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D)    Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i)    When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii)    Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii)    Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv)    The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v)    Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi)    Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i)    When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

Definitions - Page 3 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(ii)    Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii)    Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv)    See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.

(i)    Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

(A)    Costs of labor to operate the wells and related equipment and facilities.

(B)    Repairs and maintenance.

(C)    Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

(D)    Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(E)    Severance taxes.

(ii)    Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i)    The area of the reservoir considered as proved includes:

(A)    The area identified by drilling and limited by fluid contacts, if any, and

(B)    Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii)    In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii)    Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv)    Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A)    Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous

Definitions - Page 4 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B)    The project has been approved for development by all necessary parties and entities, including governmental entities.

(v)    Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:

932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:

    a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)

    b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.

932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

    a. Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.

    b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.

    c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.

    d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

Definitions - Page 5 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

    e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing

                      of the future net cash flows relating to proved oil and gas reserves.

    f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less

                      the computed discount.

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i)    Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii)    Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):

Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.

Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);

The company's historical record at completing development of comparable long-term projects;

The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;

The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and

The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

(iii)    Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.

Definitions - Page 6 of 6

EX-99.3

750 N St Paul St.

Suite 1750

Dallas, Texas 75201

Phone (214) 754-7090

March 8, 2022

Mr. Brett Knight

Director, Corporate Reserves

Crescent Energy Company

600 Travis Street, Suite 7200

Houston, Texas 77022

Mr. Knight:

As requested, Haas Petroleum Engineering Services, Inc. (hereinafter referred to as “Haas Engineering”) has performed an Audit of the provided economics and databases prepared by Crescent Energy Company (hereinafter referred to as “Crescent”), as of December 31, 2021.  The properties contained in this Audit are the Gardendale, Newark, and Renee areas, which are located in Texas and Wyoming. These areas have been combined into a single report, at the request of Crescent. Production data was generally available through August 31, 2021.   It is the understanding of Haas Engineering that this evaluation comprises approximately 34% of the Proved Reserves of Crescent.   

Haas Engineering has completed this audit in accordance with the definitions of the Securities and Exchange Commission (“SEC”) Regulation S-X Rule 4-10(a).  This estimate of Reserves was completed on or about the date of this report.  This report has been prepared for the purposes of Crescent’s SEC filing.  It is Haas Engineering’s opinion that the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for this purpose.  As of December 31, 2021, Crescent’s net Reserves, future net income (“FNI”), and net present worth discounted at 10 percent per annum (“NPV”) have been estimated to be as follows:

TABLE 1
		As of 12/31/2021
		Net Reserves		Sales Volumes
		Oil &	Wet Gas (Mcf)			Residue Gas (Mcf)		NPV
		Condensate			NGL		FNI	Disc. @ 10%
	Reserve Class/Cat	(bbl)			(bbl)		($)	($)
	Proved Producing	36,849,153	662,589,450		21,599,062	593,726,063	1,667,635,376	948,673,440
	Proved Non-Producing	4,658,952	76,291,127		1,221,794	70,801,026	281,281,613	121,575,999
	Proved Undeveloped	4,372,374	2,517,986		309,712	1,699,640	159,535,376	70,982,260
	Total Proved	45,880,479	741,398,563		23,130,568	666,226,729	2,108,452,365	1,141,231,699

* Totals in Table 1 may not exactly match values in the attached cash flow summaries and tabular summaries due to computer rounding.

In this unqualified audit of Crescent’s Reserves, Haas Engineering noted some variances from our internal estimations including forecast differences, price adjustments, taxes, recoveries, and operating expenses. However, these differences, in aggregate, did not exceed the 10 percent tolerance of auditing standards.

It is the opinion of Haas Engineering that the Reserves, FNI, and NPV estimates listed in Table 1 are, in the aggregate, reasonable and meet Audit standards for the top 80% of value in the portfolio. FNI is after deducting estimated operating and future development costs, severance and ad valorem taxes, but before Federal income taxes. Total net Proved Reserves are defined as those natural gas and hydrocarbon liquid Reserves to Crescent’s interests after deducting all royalties, overriding royalties, and reversionary interests owned by outside parties that become effective upon payout of specified monetary balances. All Reserves estimates have been prepared using standard engineering practices

generally accepted by the petroleum industry and conform to guidelines developed and adopted by the SEC. All hydrocarbon liquid Reserves are expressed in United States barrels (“bbl”) of 42 gallons. Natural gas Reserves are expressed in thousand standard cubic feet (“Mcf”) at the contractual pressure and temperature bases and include shrinkage adjustment related to field and plant losses.

RESERVES ESTIMATE METHODOLOGY

It is the opinion of Haas Engineering that the Reserves estimates contained in this report have been prepared using standard engineering practices generally accepted by the petroleum industry. Decline curve analysis was used to estimate the remaining Reserves of pressure depletion reservoirs with enough historical production data to establish decline trends. Reservoirs under non-pressure depletion drive mechanisms and non-producing Reserves were estimated by volumetric analysis, research of analogous reservoirs, probabilistic methods, or a combination of methods. The appropriate methodology was used, as deemed necessary, to estimate Reserves in conformance with SEC regulations. The maximum remaining Reserves life assigned to wells included in this report is 48 years for Gardendale, 50 years for Newark, and 39 years for Renee. This report does not include any gas sales imbalances.

RESERVES CLASSIFICATION

It is the opinion of Haas Engineering that the Reserves estimates contained in this report conform to guidelines specified by the SEC. For more information regarding Reserves classification definitions see Appendix A. A complete discussion of the Reserves classification definitions can be found on the United States Securities and Exchange Commission website (www.sec.gov). It should be noted that this evaluation contains cases with negative FNI, due to the inclusion of abandonment costs, or expense modeling (G&A, expense capital, etc.). All volumes are related to commercial production.

The SEC requires a development plan be in place for these assets. This Audit report defines a budget for that development plan, but Haas Engineering makes no representation about the company’s ability to fund this development. All Proved Undeveloped (“PUD”) locations are developed within 5 years. Please note that, as of the effective date of this report, no wells were being drilled, completed, or are waiting on completion.

COMMODITY PRICES

It is the opinion of Haas Engineering that, pursuant to SEC guidelines, the cash flow projections in this report utilize the unweighted 12-month arithmetic average of the first-day-of month benchmark prices for January 2021 through December 2021. The benchmark price for natural gas is taken to be the price received at Henry Hub and the benchmark price for hydrocarbon liquids is taken to be the price received for West Texas Intermediate (“WTI”) crude oil at the Cushing, OK sales point.

The unweighted arithmetic average cash market price for natural gas delivered at Henry Hub during this time period is $3.598 per MMBTU. The Henry Hub price was held constant throughout the life of the wells and is adjusted for BTU content, basis differentials, and marketing costs, resulting in a weighted average net price of $3.33 per Mcf for Gardendale, $3.44 per Mcf for Newark, and $3.27 per Mcf for Renee. Please note that transportation costs for natural gas have been included as expense.

The unweighted arithmetic average cash market price for WTI crude oil sold at Cushing, OK during this time period is $66.56 per bbl. For natural gas liquids (“NGL”), the WTI crude oil price was held constant throughout the life of the wells and is adjusted for BTU content, plant processing fees and basis differentials, resulting in a weighted average net price of $28.62 per bbl for Gardendale, $23.97 per bbl for Newark, $31.50 per bbl for Renee. For crude oil, the WTI crude oil price was held constant throughout the life of the wells and is adjusted for crude quality, marketing fees, BS&W, transportation

Crescent Energy Company | March 8, 2022| Page 2 of 5

costs, purchaser bonuses and basis differentials, resulting in a weighted average net price of $66.16 per bbl for Gardendale, $63.85 per bbl for Newark, and $66.02 per bbl for Renee.

Summary level revenue accounting data for the period of August 1, 2020 through July 31, 2021 was generally used in this evaluation. The pricing adjustments were provided by Crescent and reviewed for the top 80 percent of the NPV. Haas Engineering verified the reasonableness of Crescent’s pricing models and differentials using accounting data furnished by Crescent.

OPERATING EXPENSES & CAPITAL COSTS

It is the opinion of Haas Engineering that, in most cases, the lease operating costs used in this evaluation represent the average of recent historical monthly operating costs. In cases where historical costs were not available or deemed to be unreliable, operating costs were estimated based on knowledge of analogous wells producing under similar conditions. The lease operating expenses in this report represent field level operating costs and do not include COPAS charges for operated properties.

It is the opinion of Haas Engineering that capital costs were estimated using recent historical information reported for analogous expenditures. Where recent historical information was not available, Authority for Expenditure (“AFE”) documents, or supplemental documentation was provided by the operator and used to estimate capital costs. AFE and supplemental documents provided by the operator have been checked for reasonableness. It should also be understood that abandonment costs have been included at both the field and well level. The abandonment costs used are Crescent’s estimates of the costs to abandon the wells and production facilities, net of salvage value, and have been reviewed for reasonableness.

Operating expenses for the period of August 1, 2020 through July 31, 2021 was generally used in this evaluation. Operating expenses, capital costs, and abandonment costs were not escalated in this evaluation.

DISCLAIMERS

In this unqualified audit of Crescent’s Reserves, Haas Engineering noted some variances from our internal estimations including forecast differences, price adjustments, taxes, recoveries, and operating expenses. However, these differences, in aggregate, did not exceed the 10 percent tolerance of auditing standards.

It should also be clear that abandonment costs have been included at the field and well level. The abandonment costs used are Crescent’s estimates of the costs to abandon the wells and production facilities, net of salvage value, and have been reviewed for reasonableness.

The Proved Reserves presented in this report are estimates only and should not be construed as being exact quantities. They may or may not be actually recovered; and, if recovered, the revenues therefrom and the actual costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the product prices and the costs incurred in recovering these Reserves may vary from the price and cost assumptions in this report. Because these estimates are based on existing governmental regulations, changes could affect the ability to recover these Reserves. In any case, quantities of Reserves may increase or decrease as a result of future operations.

Reserves estimates for individual properties included in this report are only valid when considered within the context of the overall report and should not be considered independently. The future net income and net present value estimates contained in this report do not represent an estimate of fair market value.

Crescent Energy Company | March 8, 2022| Page 3 of 5

All information pertaining to the operating expenses, prices, and the interests of Crescent in the properties appraised has been accepted as represented. It was not considered necessary to make a field examination of the appraised properties. Data used in performing this appraisal were obtained from Crescent, public sources, and our own files. Supporting work papers pertinent to the appraisal are retained in our files and are available to you or designated parties at your convenience.

It was beyond the scope of this Haas Engineering report to evaluate the potential environmental liability costs from the operation and abandonment of these properties. In addition, no evaluation was made to determine the degree of operator compliance with current environmental rules, regulations, and reporting requirements. Therefore, no estimate of the potential economic liability, if any, from environmental concerns is included in the forecasts presented herein.

The technical persons primarily responsible for conducting this Audit meets the requirements regarding qualifications, independence, objectivity, and confidentiality, as defined by the SPE Standards. Michael A. Link, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at Haas Engineering since 2015 and has over 20 years of industry experience. Franklin Stagg, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at Haas Engineering since 2016 and has over 7 years of industry experience.

Haas Engineering is independent with respect to Crescent as provided in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

GENERAL INFORMATION

Attached are summary tables of economic analysis of predicted future performance. Other tables identify the properties appraised with summary Reserves and the economic factors applicable to each. A list of tables is included.

We appreciate this opportunity to have been of service and hope that this report will fulfill your requirements.

[Remainder of page intentionally left blank. Signature page follows.]

Crescent Energy Company | March 8, 2022| Page 4 of 5

Haas Petroleum Engineering Services, Inc.

F-0002950

/s/ Michael A. Link, P.E.

Michael A. Link, P.E.

March 8, 2022

/s/ Franklin W. Stagg, P.E.

Franklin W. Stagg, P.E.

March 8, 2022

Crescent Energy Company | March 8, 2022| Page 5 of 5

Appendix A

Definitions of Oil and Gas Reserves - Securities and Exchange Commission

The list of definitions below were compiled by HPESI. They represent selected definitions from the Securities and Exchange Commission’s Rule 4-10 document. This document was amended on January 14, 2009, and the definitions below reflect the changes resulting from the amendment. Comprehensive versions of Rule 4-10 and the amendments to Rule 4-10 can be obtained online at https://www.sec.gov/info/smallbus/secg/oilgasreporting-secg.htm

(a)Definitions. The following definitions apply to the terms listed below as they are used in this section:

(1)Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i)Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii)Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

(2)Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i)When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii)Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii)Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv)The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v)Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi)Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(3)Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i)When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii)Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

Appendix A

Definitions of Oil and Gas Reserves - Securities and Exchange Commission

(iii)Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv)See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(4)Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i)The area of the reservoir considered as proved includes:

(A)The area identified by drilling and limited by fluid contacts, if any, and

(B)Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii)In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii)Where direct observation from well penetrations has defined a highest known oil(HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv)Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A)Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B)The project has been approved for development by all necessary parties and entities, including governmental entities.

(v)Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(5)Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(6)Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Appendix A

Definitions of Oil and Gas Reserves - Securities and Exchange Commission

(7)Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir ( i.e. , absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources ( i.e. , potentially recoverable resources from undiscovered accumulations).

(8)Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i)Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii)Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii)Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

EX-99.4

Cawley, Gillespie & Associates, Inc.

petroleum consultants

13640 BRIARWICK DRIVE, SUITE 100    306 WEST SEVENTH STREET, SUITE 302    1000 LOUISIANA STREET, SUITE 1900

AUSTIN, TEXAS 78729-1107    FORT WORTH, TEXAS 76102-4987    HOUSTON, TEXAS 77002-5008

512-249-7000    817- 336-2461    713-651-9944

www.cgaus.com    

    January 13, 2022

Mr. Brett Knight

Director, Corporate Reserves

Crescent Energy Company

600 Travis, Suite 7200

Houston, Texas 77002

Re:    Evaluation Summary – SEC Pricing

Crescent Energy Company Interests

     Total Proved Reserves

     Certain Properties in Texas

     As of December 31, 2021

         Pursuant to the Guidelines of the Securities and

         Exchange Commission for Reporting Corporate

     Reserves andFuture Net Revenue

Dear Mr. Knight:

    As requested by Crescent Energy Company (“Company”), this report was prepared on January 13, 2022 for the purpose of submitting our estimates of total proved reserves and forecasts attributable to the Company ownership interests. We evaluated approximately 23% of the Company’s proved reserves, which are made up of certain oil and gas properties located in the Eagle Ford trend of Texas. This evaluation utilized an effective date of December 31, 2021, was prepared using constant prices and costs, and conforms to Item 1202(a)(8) of Regulation S-K and other rules of the Securities and Exchange Commission (SEC). This report has been prepared for the Company’s use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose. The results of this evaluation are presented in the table below:

			Proved		Proved		Proved						Total
			Developed		Developed		Developed			Proved			Proved
			Producing		Non-Producing		Shut-In			Undeveloped			Summary
Net Reserves
Oil	- Mbbl		31,451.0		4,747.2		186.8		41,039.4			77,424.4
Gas	- MMcf		92,766.3		2,386.0		68.6		32,544.5			127,765.4
NGL	- Mbbl		15,511.5		323.4		10.9		5,315.7			21,161.5
MBOE	- Mbbl		62,423.5		5,468.3		209.1		51,779.2			119,880.1
Net Revenue
Oil	- M$	2,035,118.4		306,002.7		12,042.5		2,648,026.3			5,001,189.5
Gas	- M$	347,333.9		9,055.3		258.5		122,018.8			478,666.4
NGL	- M$	461,901.3		9,281.2		308.4		151,883.8			623,374.8
Other	- M$	136,316.9		0.0		0.0		0.0			136,316.6
Severance Taxes	- M$	129,067.1		15,168.4		589.0		135,864.7			280,689.4
Ad Valorem Taxes	- M$	70,331.8		8,635.8		336.6		77,220.5			156,524.7
Operating Expenses	- M$	1,105,959.8		40,341.5		5,012.3		434,839.8			1,586,152.9
Workover Expenses	- M$	137,372.9		9,054.5		1,794.5		96,354.0			244,576.3
Future Development Costs	- M$	42,990.8		20,532.9		472.4		762,465.6			826,461.8
Net Operating Income (BFIT)	- M$	1,494,948.4		230,606.0		4,404.7		1,415,184.3			3,145,143.0
Discounted @ 10%	- M$	920,308.5		134,952.1		3,071.8		637,360.3			1,695,693.0

Crescent Energy Company Interests

January 13, 2022

Page 2

    Proved Developed (“PD”) reserves are the summation of the Proved Developed Producing (“PDP”), Proved Developed Non-Producing (“PDNP”) and Proved Developed Shut-In (“PDSI”) estimates. Proved Developed reserves were estimated at 36,385.0 Mbbl oil, 95,220.9 MMcf gas and 15,845.8 Mbbl NGLs (or 68,100.9 MBOE). Of the Proved Developed reserves, 62,423.5 MBOE was attributed to producing zones in existing wells and 5,677.4 MBOE was attributed to zones in existing wells not producing.

    Future net revenue is prior to deducting state production taxes and ad valorem taxes. Future net cash flow (net operating income) is after deducting these taxes, future development costs and operating expenses, but before consideration of federal income taxes. In accordance with SEC guidelines, the future net cash flow has been discounted at an annual rate of ten percent to determine its “present worth”. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties by Cawley, Gillespie & Associates, Inc. (“CG&A”).

Hydrocarbon Pricing

    The base SEC oil and gas prices calculated for December 31, 2021 were $66.56/bbl and $3.598/MMBTU, respectively. As specified by the SEC, a company must use a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The base oil price is based upon WTI-Cushing spot prices (EIA) during 2021 and the base gas price is based upon Henry Hub spot prices (Gas Daily) during 2021.

    The base prices were adjusted for differentials on a per-property basis, which may include local basis differentials, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. After these adjustments, the net realized prices for the SEC price case over the life of the proved properties was estimated to be $64.595 per barrel for oil, $3.746 per MCF for natural gas and $29.459 per barrel for NGL. All economic factors were held constant in accordance with SEC guidelines.

Economic Parameters

    Operating expenses, 3rd party COPAS and capital expenditures (future development costs) were not escalated in accordance with SEC guidelines. Lease operating expenses and 3rd party COPAS fees were applied on a per property basis as estimated by the Company from the October 2020 through October 2021 lease operating statements. Lease operating expenses (LOE), workover expenses and future development costs were provided by the Company and audited by us at a summary level. Our audit determined that the commercial parameters being applied were reasonable and appropriate, and therefore no changes were made to cost parameters. Severance tax values were determined by applying normal state severance tax rates. Ad valorem tax rates were forecast as provided at approximately 2.5% of revenue. Variable operating expenses were applied to all wells to capture gas and/or liquids transportation costs plus water disposal costs.

    For the non-producing PUD properties, LOE was also scheduled as provided by production lift type and type curve area. Future development capital information was provided by the Company based upon their significant drilling and completion activities in recent years. The drill and complete (D&C) costs were applied by lateral length and completions type for all Eagle Ford locations.

SEC Conformance and Regulations

    The reserve classifications and the economic considerations used herein conform to the criteria of the SEC as defined in pages 6 and 7 below in the Appendix. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.

Crescent Energy Company Interests

January 13, 2022

Page 3

CG&A evaluated 2086 PDP properties for this report, each with daily production data through 11/30/2021 as provided by the Company. We also evaluated a “Springfield Credits” cost case as part of the PDP value. This report also includes 23 PDSI properties, of which seven (7) are scheduled to return to production, along with 12 PDNP properties, each drilled and cased but awaiting final completion as of the date of this report.

In addition, CG&A evaluated 213 commercial PUD drilling opportunitiesall targeting the Eagle Ford reservoir. All PUD drills were modeled as horizontal wells offsetting production from existing horizontal producers. Reserves for each PUD location were assigned by type curve area depending upon the region and nearby analogous production. Each of these drilling locations proposed as part of the Company’s development plan conforms to the proved undeveloped standards as set forth by the SEC. In our opinion, the Company has indicated they have every intent to complete this development plan within the next five years. Furthermore, the Company has demonstrated that they have the proper staffing, financial backing and prior development success to ensure this five year development plan will be fully executed.

Reserve Estimation Methods

The methods employed in estimating reserves are described on page 5 below in the Appendix. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy.

    Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for the Company properties, due to the mature nature of their properties targeted for development and an abundance of subsurface control data. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.

General Discussion

    The estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. To some extent information from public records has been used to check and/or supplement these data. The basic engineering and geological data were subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data. All estimates represent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.

    An on-site field inspection of the properties has not been performed. The mechanical operation or condition of the wells and their related facilities have not been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging and the salvage value of equipment at abandonment has been included in this evaluation, as provided by the Company.

    Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 60 years. This evaluation was supervised by W. Todd Brooker, President at Cawley, Gillespie & Associates, Inc. and a State of Texas Licensed Professional Engineer (License #83462). We do not own an interest in the properties, Crescent Energy Company or its subsidiaries

Crescent Energy Company Interests

January 13, 2022

Page 4

and are not employed on a contingent basis. We have used all methods and procedures that we consider necessary under the circumstances to prepare this report. Our work-papers and related data utilized in the preparation of these estimates are available in our office.

Yours very truly,

/s/ W. Todd Brooker, P.E.

W. Todd Brooker, P.E.

    President

CAWLEY, GILLESPIE & ASSOCIATES, INC.

    Texas Registered Engineering Firm F-693

Crescent Energy Company Interests

January 13, 2022

Page 5

APPENDIX

Methods Employed in the Estimation of Reserves

    The four methods customarily employed in the estimation of reserves are (1) productionperformance, (2) materialbalance, (3) volumetric and (4) analogy. Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data available and the characteristics of the reservoirs.

    Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the quality, quantity and types of information available on individual properties. Operators are generally required by regulatory authorities to file monthly production reports and may be required to measure and report periodically such data as well pressures, gas-oil ratios, well tests, etc. As a general rule, an operator has complete discretion in obtaining and/or making available geological and engineering data. The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in significant differences in the accuracy and reliability of estimates.

    A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows:

Production performance. This method employs graphical analyses of production data on the premise that all factors which have controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance. The only information required is production history. Capacity production can usually be analyzed from graphs of rates versus time or cumulative production. This procedure is referred to as "decline curve" analysis. Both capacity and restricted production can, in some cases, be analyzed from graphs of producing rate relationships of the various production components. Reserve estimates obtained by this method are generally considered to have a relatively high degree of accuracy with the degree of accuracy increasing as production history accumulates.

Material balance. This method employs the analysis of the relationship of production and pressure performance on the premise that the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzing changes in pressure with respect to production relationships. This method requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir. The material balance method is applicable to all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids. Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available. Estimates for other reservoir types require extensive data and involve complex calculations most suited to computer models which makes this method generally applicable only to reservoirs where there is economic justification for its use. Reserve estimates obtained by this method are generally considered to have a degree of accuracy that is directly related to the complexity of the reservoir and the quality and quantity of data available.

Volumetric. This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of hydrocarbons in-place. The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric method is most applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated.

Analogy. This method, which employs experience and judgment to estimate reserves, is based on observations of similar situations and includes consideration of theoretical performance. The analogy method is a common approach used for “resource plays,” where an abundance of wells with similar production profiles facilitates the reliable estimation of future reserves with a relatively high degree of accuracy. The analogy method may also be applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve estimates obtained in this manner are generally considered to have a relatively low degree of accuracy.

    Much of the information used in the estimation of reserves is itself arrived at by the use of estimates. These estimates are subject to continuing change as additional information becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtained about well and reservoir performance.

Crescent Energy Company Interests

January 13, 2022

Page 6

APPENDIX

Reserve Definitions and Classifications

    The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves:

    "(22)    Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations— prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

"(i)    The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

     "(ii)    In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

     "(iii)    Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

     "(iv)    Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

     "(v)    Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

    "(6)    Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

“(i)    Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

“(ii)    Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

    "(31)    Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

“(i)    Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

“(ii)    Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

“(iii)    Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

    "(18)    Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

Crescent Energy Company Interests

January 13, 2022

Page 7

“(i)    When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

“(ii)    Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

“(iii)    Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

“(iv)    See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).

    "(17)    Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

“(i)    When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

“(ii)    Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

“(iii)    Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

“(iv)    The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

“(v)    Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

“(vi)    Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.”

Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that "a registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S–K." This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant is permitted, but not required, to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”

    "(26)    Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

“Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).”

EX-99.5

Mr. Brett Knight                            Dallas, January 20, 2022

Director, Corporate Reserves

Crescent Energy Company

600 Travis Street, Suite 7200

Houston, TX 77002

Dear Mr. Knight:

In accordance with your request, William M. Cobb & Associates, Inc. (Cobb & Associates) has estimated the proved reserves and future income as of January 1, 2022, attributable to the Crescent Energy Company and its subsidiaries (Crescent) interests in certain hydrocarbon-producing properties located in Kansas, Louisiana, state and federal waters of the Gulf of Mexico off the coast of Louisiana, Mississippi, Montana, New Mexico, Oklahoma, Texas and Wyoming. This report is based on unescalated prices and costs in accordance with the guidelines of the Securities and Exchange Commission (SEC). This evaluation was completed on January 20, 2022.

Reserves presented in this report are classified as proved and are further categorized as Proved Developed Producing (PDP), Proved Developed Not Producing (PDNP), Proved Developed Shut-In (PDSI) and Proved Un-Developed (PUD). Table 1 summarizes our estimate of the proved oil and gas reserves and their pre-federal income tax value undiscounted and discounted at ten percent using the year-end 2021 SEC price.

TABLE 1

CRESCENT ENERGY COMPANY

CRESCENT ENERGY COMPANY PROPERTIES

RESERVES AND CASH FLOW SUMMARY AS OF JANUARY 1,2022

YEAR-END 2021 SEC PRICE

	Net Reserves				Future Net Cash Flow
Reserves Category	Oil	Gas	NGL	Oil Equiv.	Undiscounted	Discounted @ 10% per Year
	(MBBL)	(MMcf)	(MBBL)	(MBOE)	(M$)	(M$)
Proved Developed	43,876	438,632	11,734	128,715	1,945,486	1,115,886
PDP - Producing	42,444	438,391	11,678	127,187	1,873,120	1,072,252
PDNP - Non Producing	1,432	241	56	1,527	72,366	43,634
PDSI - Shut-In	0	0	0	0	0	0
Proved Undeveloped	1,340	286	40	1,427	63,210	34,604
PUD - Undeveloped	1,340	286	40	1,427	63,210	34,604
TOTAL PROVED	45,215	438,919	11,773	130,142	2,008,696	1,150,490

        Page 1

Values shown were determined utilizing constant oil and gas prices and well operating expenses. The discounted net present values of future income shown in Table 1 are not intended to represent an estimate of fair market value. These estimates were prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Certification Topic 932, Extraction Activities – Oil and Gas.

Oil and NGL volumes are expressed in thousand stock tank barrels (MBBL). A stock tank barrel is equivalent to 42 United States gallons. Gas volumes are expressed in million standard cubic feet (MMcf) as determined at 60° Fahrenheit and the legal pressure base for the specific location of the gas reserves.

Cobb & Associates reviewed 100 per cent of the properties included in this report. This report, which was prepared for Crescent’s use in filing with the SEC and will be filed with Crescent’s Form 10-K for fiscal year ending December 31, 2021 (the “Form 10-K”) and covers 22 percent of the total company present value discounted at ten percent (PV10) presented in Crescent’s Form 10-K. All assumptions, data, methods, and procedures considered necessary and appropriate were used to prepare this report.

DISCUSSION

The Crescent Energy Company properties are divided into four regions: Midcontinent, Permian, Rockies and Other. Cobb & Associates have reviewed 100% of the properties contained in this report, which constitutes 24% of the total proved reserves and 22% of the total Net Present Value for Crescent Energy Company.

The region with the largest net present value is the Rockies, which account for 42.6% of the total value. The Rockies region consists of properties in Montana and Wyoming. 35.9% of the total value is made up by the Midcontinent region and consists of properties in Kansas, Oklahoma and Texas. The Permian region makes up 20.4% of the total value from properties New Mexico and Texas. The remaining 1.0% of the total value comes from the Other region with properties in state and federal waters of the Gulf of Mexico off the coast of Louisiana, Louisiana, Mississippi and Texas.

Reserve estimates were prepared using generally accepted petroleum engineering principles and practices. The method, or combination of methods, utilized in the study of each property or reservoir included an assessment of the stage of reservoir development, quality of data, and length of production history. Geologic and engineering data was obtained from Crescent, public sources, and the non-confidential files of Cobb & Associates.

Performance data through September 2021 was used to forecast reserves for all producing properties where available. Reserve classification was based on the status of each well as of January 1, 2022 for operated wells, and on the most recently available information for non-operated wells.

For most regions in the report, the PDP reserve estimates were based on decline curve analysis. Some of the properties have produced for only a short period of time and did not exhibit an identifiable performance decline trend. In these cases, reserve estimates were based primarily on geological interpretation, mapping, and analogy to offset producers. Past performance, and offsetting performance data were used to estimate behind pipe and undeveloped reserves. Fields where additional analysis or methodology was used for the reserve assignments are discussed in more detail. These fields include Eugene Island 11 and the Big Horn or Madden Deep gas field in Wyoming.

        Page 2

Offshore - Eugene Island 11

Eugene Island 11 is located in federal and Louisiana state waters of the Gulf of Mexico, at a water depth of approximately 13 feet. Production is primarily from a single CibOp sand, the JRM-1 sand, at a depth of approximately 15,000 feet. The field was discovered in September, 2006 by Crescent Energy Company's Dutch 1 well. Crescent has since drilled four more wells, the Dutch 2, 3, 4 and 5, on Federal acreage. The Dutch 5 well is depleted and was abandoned in December 2021.

Crescent also has properties in Louisiana state waters in this field. These properties are referred to as the Mary Rose prospect. Five Mary Rose wells have been drilled to date. Four Mary Rose wells, numbers 1 through 4, have produced from the main CibOp sand. The Mary Rose 4 well is depleted and has been abandoned. The Mary Rose 3 is also depleted, with abandonment scheduled for May 2023.

The Mary Rose 5 well produced from a separate, and much smaller, CibOp reservoir that is now depleted. Abandonment of the Mary Rose 5 was completed in 2019.

Proved reserves for the Eugene Island 10 main CibOp sand are based on analysis of historical rate versus time decline curves and P/Z performance plots, supplemented by volumetric calculations of original-gas-in-place (OGIP) using all available well log and 3D seismic data. The reservoir has been effectively drilled to the lowest structural datum and no significant aquifer has been found. Performance to date indicates a depletion drive system.

All Dutch and Mary Rose wells now flow to compression on the ‘H’ platform, allowing for a decrease in producing flowing tubing pressures. This two-stage compression lowers line pressure to approximately 200 psi. There are no remaining capital or startup costs for compression on the ‘H’ platform. Abandonment costs were provided by Crescent and scheduled at the end-of-project life for all wells and the ‘H’ platform.

The Mary Rose 1 well suffered a failure during 2021. Well investigation work indicate that there is not an easy fix to bring the well back online. Should it be impossible to develop a cost effective method to recover the production capacity lost from Mary Rose 1, it will likely bring forward the abandonment of the entire field. For this report, it has been assumed that the Mary Rose 1 is permanently lost and that none of the other wells will be increasing their production as a result of Mary Rose 1 no longer producing.

Big Horn / Madden Deep Gas Field

The Madden Deep reservoir is located in the Wind River Basin in Wyoming and was discovered and developed by Burlington Resources in the early 1990s. The reservoir is a fractured dolomitized limestone with around 200 feet of net pay. The structure is a fault bounded, three way dip structure with a total closure of around 1,500 feet. The average reservoir permeability is 1-10 mD with high permeability streaks around 100 mD. The reservoir as well as the reservoir fluids are challenging, the reservoir is located at a depth of around 25,000 feet and the reservoir temperature is 435 degrees Fahrenheit. The gas in the reservoir consists of 67.4% methane, 20% CO2 and 12.6% H2S. None of the 9 wells penetrating the reservoir have tagged the gas water contact (GWC), so there is some uncertainty about the exact location of the GWC.

        Page 3

Conoco Phillips purchased the Asset from Burlington Resources in 2006 and owned it until it was purchased by Crescent in 2021.

The Gas in place for the field have been assessed using all available seismic data, static and dynamic well data. Three models have been constructed to model field performance:

1)1 A Material Balance, Nodal Analysis, Surface Network model. The material balance portion of this model includes a detailed and history matched P/Z model using the measured P/Z data from the individual wells in the field.

2)A reservoir simulation model has been constructed and history matched and

3)A rate versus cumulative gas produced well by well production forecasting model.

The Gas Initially In Place numbers from the material balance and simulation models match well. The forecast used in the reserve report was taken from the rate versus cumulative gas model as this was best able to describe the production when one of the processing trains will be decommissioned in one of the coming years and the field experience higher deliverability than there is available processing capacity.

OIL AND GAS PRICING

Projections of proved reserves contained in this report utilize constant product prices of $65.56 per barrel of oil and $3.598 per MMBTU of gas. These are the so called SEC prices, which are the average first-of-the-month prices for the prior 12-month period for West Texas Intermediate (WTI) oil and Henry Hub gas. Appropriate oil and gas pricing differentials, residue gas shrink, NGL yields, and NGL pricing as a fraction of WTI were calculated for each field using 12 months of revenue data where available. After applying appropriate differentials for each property, the weighted average realized product prices for 2021 were $63.87 per barrel of oil and $3.321 per MCF of gas, resulting in average 2021 differentials of negative $1.69 per barrel of oil and negative $0.277 per MCF of gas.

OPERATING COSTS

Future operating costs for each of the Crescent wells are held constant at current values for the life of the property. These costs were calculated using 12-month lease operating expense (LOE) statements provided by Crescent. In general, the LOE statements for each of the properties were analyzed by production area. LOE data was available for most areas through August 2021. In general, each well was assigned a fixed monthly operating cost, variable costs for oil and gas, and water handling costs per barrel of water produced. Oil, gas and NGL transportation and processing fees were also assigned to each well by area using net revenue data in a similar manner that product differentials were determined.

LOE data for the Eugene Island 11 properties was analyzed by cost centre. Fixed operating costs were divided into three categories: producing well, non-producing well and platform expenses. Non-producing wells are wells that are no longer producing and awaiting abandonment in 2022 or beyond and had costs attributable to insurance. Platform expenses include shared compression equipment rental and operating costs, pipeline costs, and other costs that were assigned to platform cost centers.

        Page 4

CAPITAL & ABANDONMENT COSTS

Capital expenditures to recomplete behind-pipe zones in existing wells, re-activate or work over existing wells, drill new wells and install production facilities were provided by Crescent and appear to be reasonable.

Abandonment costs for Eugene Island 11 were included for each well and the platform expense case as it was supplied to Cobb & Associates by Crescent. Cobb & Associates have not done a field visit or in any other way attempted to verify the abandonment estimates apart from determining that the numbers looked reasonable.

Abandonment costs for all other properties in the report were been included by area. Yearly estimates of abandonment costs and equipment salvage values were scheduled based on current well status and life estimations.

PROFESSIONAL GUIDELINES

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years, from known reservoirs under expected economic and operating conditions. Reserves are considered proved if economic productivity is supported by either actual production or conclusive formation tests.

Probable reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves, but more certain to be recovered than possible reserves. Possible reserves are those additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than probable reserves.

The reserve estimates shown in this report are those estimated to be recoverable in accordance with the reserves definitions of Rules 4-10(a) (1)-(32) of Regulation S-X and the guidelines specified in Item 1202 (a)(8) of Regulation S-K of the U.S. Securities and Exchange Commission (SEC), and with the exception of the exclusion of future income taxes, conforms to the FASB Accounting Standards Codification Topic 932, Extractive Industries - Oil and Gas. The definitions for oil and gas reserves in accordance with SEC Regulation S-X are set forth in this report.

The reserves included in this report are estimates only and should not be construed as being exact quantities. Governmental policies, uncertainties of supply and demand, the prices actually received for the reserves, and the costs incurred in recovering such reserves, may vary from the price and cost assumptions in this report. Estimated reserves using price escalations may vary from values obtained using constant price scenarios. In any case, estimates of reserves, resources, and revenues may increase or decrease as a result of future operations.

Cobb & Associates has not examined titles to the appraised properties nor has the actual degree of interest owned been independently confirmed. The data used in this evaluation were obtained from Crescent Energy Company and the non-confidential files of Cobb & Associates and were considered accurate.

We have not made a field examination of the Crescent properties. Therefore, operating ability and condition of the production equipment have not been considered. Also, environmental liabilities, if any, caused by Crescent or any other operator have not been considered, nor has the cost to restore the property to acceptable conditions, as may be required by regulation, been taken into account.

        Page 5

In evaluating available information concerning this appraisal, Cobb & Associates has excluded from its consideration all matters as to which legal or accounting interpretation, rather than engineering, may be controlling. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering data and conclusions necessarily represent only informed professional judgments.

William M. Cobb & Associates, Inc. is an independent consulting firm founded in 1983. Its compensation is not contingent on the results obtained or reported. Frank J. Marek, a Registered Texas Professional Engineer and a senior technical advisor of William M. Cobb & Associates, Inc., is primarily responsible for overseeing the preparation of the reserve report. His professional qualifications meet or exceed the qualifications of reserve estimators set forth in the “Standards Pertaining to Estimation and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers. His qualifications include: Bachelor of Science degree in Petroleum Engineering from Texas A&M University 1977; member of the Society of Petroleum Engineers; member of the Society of Petroleum Evaluation Engineers; and over 40 years of experience in estimating and evaluating reserve information and estimating and evaluating reserves.

William M. Cobb & Associates, Inc. appreciate the opportunity to be of service to Crescent Energy Company on this project. Please contact us if there are any questions regarding this report.

    Sincerely,

    WILLIAM M. COBB & ASSOCIATES, INC.

    Texas Registered Engineering Firm F-84

        Page 6

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	Dec. 31, 2021	Feb. 28, 2022
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Audit Information	12 Months Ended
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CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Current assets:
Cash and cash equivalents	$ 128,578	$ 36,861
Accounts receivable, net	321,855	111,821
Accounts receivable – affiliates	20,341	0
Derivative assets – current	0	30,926
Drilling advances	200	38,892
Prepaid and other current assets	8,644	1,948
Total current assets	479,618	220,448
Oil and natural gas properties at cost, successful efforts method
Proved	6,043,602	4,910,059
Unproved	308,721	288,459
Oil and natural gas properties at cost, successful efforts method	6,352,323	5,198,518
Field and other property and equipment, at cost	144,318	138,371
Total property, plant and equipment	6,496,641	5,336,889
Less: accumulated depreciation, depletion, amortization and impairment	(1,941,528)	(1,694,742)
Property, plant and equipment, net	4,555,113	3,642,147
Goodwill	76,564	0
Derivative assets – noncurrent	579	22,352
Equity method investments	15,415	0
Other assets	30,173	22,422
TOTAL ASSETS	5,157,462	3,907,369
Current liabilities:
Accounts payable and accrued liabilities	337,881	80,688
Accounts payable – affiliates	8,675	9,019
Derivative liabilities – current	253,525	26,392
Financing lease obligations – current	1,606	0
Other current liabilities	14,438	4,572
Total current liabilities	616,125	120,671
Long-term debt	1,030,406	751,075
Derivative liabilities – noncurrent	133,471	23,958
Asset retirement obligations	258,102	106,403
Deferred tax liability	82,537	0
Financing lease obligations – noncurrent	3,512	0
Other liabilities	13,652	12,102
Total liabilities	2,137,805	1,014,209
Commitments and contingencies (Note 12)
Redeemable noncontrolling interests	2,325,013	0
Equity:
Members’ equity – Class A units, no units and 1,220,421 units outstanding as of December 31, 2021 and 2020, respectively		2,716,892
Preferred stock, $0.0001 par value; 500,000,000 shares authorized and 1,000 Series I preferred shares issued and outstanding as of December 31, 2021; no shares issued and outstanding as of December 31, 2020	0
Treasury stock, at cost; 1,150,991 shares of Class A common stock as of December 31, 2021 and no shares of Class A Common Stock as of December 31, 2020	(18,448)
Additional paid-in capital	720,016
Accumulated deficit	(19,376)
Noncontrolling interests	12,435
Noncontrolling interests		176,268
Total equity	694,644
Total equity		2,893,160
TOTAL LIABILITIES, REDEEMABLE NONCONTROLLING INTERESTS AND EQUITY	5,157,462	$ 3,907,369
Class A
Equity:
Common stock	4
Class B
Equity:
Common stock	$ 13

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2021	Dec. 31, 2020
Members’ equity outstanding (in shares)	0	1,220,421
Preferred stock, par value (in USD per share)	$ 0.0001	$ 0.0001
Preferred stock authorized (in shares)	500,000,000	500,000,000
Preferred stock issued (in shares)	1,000	0
Preferred stock outstanding (in shares)	1,000	0
Class A
Common stock, par value (in USD per share)	$ 0.0001	$ 0.0001
Common stock authorized (in shares)	1,000,000,000	1,000,000,000
Common stock issued (in shares)	43,105,376	0
Common stock outstanding (in shares)	41,954,385	0
Treasury stock (in shares)	1,150,991	0
Class B
Common stock, par value (in USD per share)	$ 0.0001	$ 0.0001
Common stock authorized (in shares)	500,000,000	500,000,000
Common stock issued (in shares)	127,536,463	0
Common stock outstanding (in shares)	127,536,463	0

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COMBINED AND CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Revenues:
Total revenues	$ 1,476,977	$ 754,221	$ 1,087,240
Expenses:
Lease operating expense	243,501	202,180	255,106
Workover expense	10,842	6,385	9,789
Asset operating expense	45,940	39,023	40,364
Gathering, transportation and marketing	187,059	173,122	142,214
Production and other taxes	108,992	61,124	88,696
Depreciation, depletion and amortization	312,787	372,300	311,185
Impairment of oil and natural gas properties	0	247,215	0
Exploration expense	1,180	486	469
Midstream operating expense	13,389	9,472	9,968
General and administrative expense	78,342	16,542	2,357
Gain on sale of assets	(8,794)	0	(22)
Total expenses	993,238	1,127,849	860,126
Income (loss) from operations	483,739	(373,628)	227,114
Other income (expense):
Interest expense	(50,740)	(38,107)	(53,577)
Other income (expense)	120	341	402
Income from equity method investments	368	0	0
Gain (loss) on derivatives	(866,020)	195,284	(127,202)
Total other income (expense)	(916,272)	157,518	(180,377)
Income (loss) before taxes	(432,533)	(216,110)	46,737
Income tax benefit (expense)	306	(14)	(28)
Net income (loss)	(432,227)	(216,124)	46,709
Less: net (income) loss attributable to Predecessor	339,168	118,649	(45,839)
Less: net (income) loss attributable to noncontrolling interests	14,922	97,475	(870)
Less: net loss attributable to redeemable noncontrolling interests	58,761	0	0
Net loss attributable to Crescent Energy	$ (19,376)	0	0
Class A common stock
Net Loss per Share:
Basic (in USD per share)	$ (0.46)
Diluted (in USD per share)	$ (0.46)
Weighted Average Shares Outstanding:
Basic (in shares)	41,954,385
Diluted (in shares)	41,954,385
Class B common stock
Net Loss per Share:
Basic (in USD per share)	$ 0
Diluted (in USD per share)	$ 0
Weighted Average Shares Outstanding:
Basic (in shares)	127,536,463
Diluted (in shares)	127,536,463
Oil
Revenues:
Total revenues	$ 883,087	491,780	785,750
Natural gas
Revenues:
Total revenues	354,298	149,317	173,386
Natural gas liquids
Revenues:
Total revenues	185,530	69,902	86,473
Midstream and other
Revenues:
Total revenues	$ 54,062	$ 43,222	$ 41,631

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COMBINED AND CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($) $ in Thousands	Total	Members' Equity	Common Stock Class A	Common Stock Class B	Series I Preferred Stock	Treasury Stock	Additional Paid-in Capital	Accumulated Deficit	Noncontrolling Interest
Members' equity at beginning of period (in shares) at Dec. 31, 2018		0
Members' equity at beginning of period at Dec. 31, 2018	$ 2,807,844	$ 1,960,730							$ 847,114
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	46,709	45,839							870
Contributions	250								250
Distributions	(142,737)	$ (124,836)							(17,901)
Noncontrolling Interest Carve-out	0
Members' equity at end of period (in shares) at Dec. 31, 2019		0
Members' equity at end of period at Dec. 31, 2019	2,712,066	$ 1,881,733							830,333
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(216,124)	(118,649)							(97,475)
Contributions	4,704	4,704
Distributions	(62,567)	$ (61,421)							(1,146)
Issuance of Class A Units in exchange for the Contributed Entities (in shares)		620,000
Reclassification of noncontrolling interests	0	$ (101,926)							101,926
Issuance of Class A Units in exchange for the acquisition of Titan Energy (in shares)		380,000
Issuance of Class A Units in exchange for the acquisition of Titan Energy	455,081	$ 455,081
Noncontrolling Interest Carve-out	0
Exchange (in shares)		220,000
Exchange	$ 0	$ 657,370							(657,370)
Members' equity at end of period (in shares) at Dec. 31, 2020	1,220,421	1,220,000
Members' equity at end of period at Dec. 31, 2020	$ 2,893,160	$ 2,716,892							176,268
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Contributions	42,735	7,275							35,460
Distributions	(36,506)	$ (35,331)							(1,175)
Noncontrolling Interest Carve-out	(121,872)								(121,872)
Exchange (in shares)		10,000
Exchange	0	$ 62,051							(62,051)
Repurchase of noncontrolling interest	(2,462)								(2,462)
Merger Transactions (in shares)		(1,230,000)	43,105,000	127,536,000	1,000
Merger Transactions	(1,699,361)	$ (2,411,719)	$ 4	$ 13			$ 712,341
Equity-based compensation, net of withholding taxes (in shares)			(1,151,000)			1,151,000
Equity-based compensation, net of withholding taxes	8,728					$ (18,448)	23,987		3,189
Cancellation of OpCo Units associated with repurchase of treasury stock	(16,091)						(16,091)
Change in deferred taxes attributable to change in OpCo ownership	$ (221)						(221)
Members' equity at end of period (in shares) at Dec. 31, 2021	0
Balance at end of period (in shares) at Dec. 31, 2021			41,954,000	127,536,000	1,000	1,151,000
Balance at end of period at Dec. 31, 2021	$ 694,644		$ 4	$ 13	$ 0	$ (18,448)	$ 720,016	$ (19,376)	$ 12,435

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COMBINED AND CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash flows from operating activities:
Net income (loss)	$ (432,227)	$ (216,124)	$ 46,709
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	312,787	372,300	311,185
Impairment of oil and natural gas properties	0	247,215	0
Deferred income taxes (benefit)	(935)	0	0
Gain on sale of oil and natural gas properties	(8,794)	0	(22)
(Gain) loss on derivatives	866,020	(195,284)	127,202
Net cash (paid) received on settlement of derivatives	(535,269)	186,495	(22,743)
Non-cash equity-based compensation expense	39,919	(797)	(2,721)
Amortization of debt issuance costs and discount	7,647	4,941	4,730
Write-off of debt issuance costs	2,541	0	0
Write-off of other long-term assets and other	(928)	(29)	3,909
Changes in operating assets and liabilities:
Accounts receivable	(71,301)	14,652	24,104
Accounts receivable – affiliates	(20,333)	0	0
Prepaid and other current assets	39,986	17,886	(1,088)
Accounts payable and accrued liabilities	31,110	(15,138)	(5,514)
Accounts payable – affiliates	(358)	657	27
Other	3,282	(5,746)	(263)
Net cash provided by operating activities	233,147	411,028	485,515
Cash flows from investing activities:
Development of oil and natural gas properties	(155,607)	(126,164)	(338,646)
Acquisitions of oil and natural gas properties, net of cash acquired	(115,076)	0	0
Proceeds from the sale of oil and natural gas properties	25,723	9,362	15,798
Purchases of restricted investment securities – HTM	(8,537)	(9,071)	(5,412)
Maturities of restricted investment securities – HTM	11,703	9,052	5,414
Due from related party and other	(2,801)	(8,119)	(5,312)
Net cash used in investing activities	(244,595)	(124,940)	(328,158)
Cash flows from financing activities:
Proceeds from issuance of the Senior Notes, net of discount	490,625	0	0
Payment of debt issuance costs	(14,611)	(3,333)	(1,619)
Repayments of debt acquired in Merger Transactions	(140,000)	0	0
Member contributions	110	5,186	0
Noncontrolling interest contributions	35,460	0	250
Repurchase of noncontrolling interest	(2,462)	0	0
Member distributions	(35,331)	(61,422)	(124,837)
Noncontrolling interest distributions	(1,695)	(1,145)	(17,901)
Cash paid for treasury stock acquired for equity-based compensation tax withholding	(18,448)	0	0
Due to related party and other	(428)	9,650	2,515
Net cash provided by (used in) financing activities	105,145	(272,089)	(153,192)
Net change in cash, cash equivalents and restricted cash	93,697	13,999	4,165
Cash, cash equivalents and restricted cash, beginning of period	41,420	27,421	23,256
Cash, cash equivalents, and restricted cash, end of period	135,117	41,420	27,421
Prior Credit Agreement
Cash flows from financing activities:
Borrowings	53,900	275,850	553,300
Repayments	(804,975)	(496,875)	(564,900)
New Credit Agreement
Cash flows from financing activities:
Borrowings	702,000	0	0
Repayments	$ (159,000)	$ 0	$ 0

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Organization and Basis of Presentation

12 Months Ended

Dec. 31, 2021

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and Basis of Presentation

Organization and Basis of Presentation

Organization

We are a well-capitalized U.S. independent energy company with a portfolio of assets in key proven basins across the lower 48 states with substantial cash flow supported by a predictable base of production. We seek to generate attractive risk-adjusted investment returns and predictable cash flows across cycles by employing our differentiated approach to investing in the oil and natural gas industry. Our approach includes a cash flow-based investment mandate with a focus on operated working interests and is complemented by non-operated working interests, mineral and royalty interests and midstream infrastructure, as well as an active risk management strategy. We pursue our strategy through the production, development and acquisition of crude oil, natural gas and natural gas liquids ("NGLs") reserves. We maintain a diverse portfolio of assets in key proven basins across the United States, including the Eagle Ford, Rockies, Barnett, Permian and Mid-Con.

We have evaluated how we are organized and managed and have identified only one reportable segment, which is the exploration and production of crude oil, natural gas and NGLs. We consider our gathering, processing and marketing functions as ancillary to our oil and gas producing activities. All of our operations and assets are located in the United States, and our revenues are attributable to United States customers.

Merger Transactions

On December 7, 2021, we completed the Merger Transactions, pursuant to which Contango’s business combined with Independence's business under a new publicly traded holding company named "Crescent Energy Company." Our Class A Common Stock is listed on The New York Stock Exchange under the symbol “CRGY.” The new combined company is structured as an “Up-C,” with all of our assets and operations and those of Contango held by Crescent, which is the sole managing member of Crescent Energy OpCo LLC ("OpCo"). Crescent is a holding company, the sole material asset of which consists of units of OpCo ("OpCo Units"). Crescent is the sole managing member of OpCo and is responsible for all operational, management and administrative decisions related to OpCo’s business. Because the unit holders of OpCo lack the characteristics of a controlling financial interest, OpCo was determined to be a variable interest entity. Crescent is considered the primary beneficiary of OpCo as it has both the power to direct OpCo and the right to receive benefits from OpCo. As a result, Crescent consolidates the financial results of OpCo and its subsidiaries. The assets and liabilities of OpCo represent substantially all of our consolidated assets and liabilities with the exception of certain current and deferred taxes and certain liabilities under the Management Agreement, as defined within NOTE 14 - Related Party Transactions. Certain restrictions and covenants related to the transfer of assets from OpCo are discussed further in NOTE 8 - Debt. Former Contango shareholders now own shares of Crescent Class A Common Stock, which have both voting and economic rights with respect to Crescent. The former owners of our predecessor, Independence Energy LLC, now own economic, non-voting OpCo Units and corresponding shares of Crescent Class B Common Stock, which have voting (but no economic) rights with respect to Crescent.

As a result of the Merger Transactions, (a) former owners of Independence own approximately 75% of OpCo, 100% of the total outstanding Crescent Class B Common Stock and approximately 75% of the total outstanding Crescent Energy Class A Common Stock and Crescent Class B Common Stock taken together, (b) former stockholders of Contango own Crescent Class A Common Stock representing approximately 25% of the outstanding Crescent Class A Common Stock and Crescent Class B Common Stock, taken together and (c) Crescent owns approximately 25% of the OpCo Units. Additionally, Independence Energy Aggregator LP, an affiliate of certain former owners of Independence, is the sole holder of Crescent's non-economic Series I preferred stock, $0.0001 par value per share, which entitles the holder thereof to appoint the Board of Directors of Crescent and to certain other approval rights.

Basis of Presentation

Our combined and consolidated financial statements (the “financial statements”) include the accounts of the Company and its subsidiaries after the elimination of intercompany transactions and balances and are presented in accordance with U.S. general accepted accounting principles (“GAAP”). We have no elements of other comprehensive income for the periods presented.

In August 2020, through a series of transactions, we underwent a reorganization (the “Independence Reorganization”) in connection with the Titan Acquisition (as defined in NOTE 3 – Acquisitions and Divestitures), carried out under the direction of our Managing Member (as defined in our Amended and Restated Limited Liability Company Agreement, dated August 18, 2020), whereby certain entities (the “Contributed Entities”) previously owned and under the common control of affiliates of Kohlberg Kravis Roberts & Co. L.P. ("KKR Group") were contributed to us. The financial statements include the accounts of the Contributed Entities from the date of the Independence Reorganization, which is the date the Company obtained a controlling financial interest in the Contributed Entities on a consolidated basis. As required by GAAP, the contributions of the Contributed Entities in connection with the Independence Reorganization were accounted for as a reorganization of entities under common control, in a manner similar to a pooling of interests, with all assets and liabilities transferred to us at their carrying amounts. The Isla Merger, whereby Independence merged with and into OpCo on December 7, 2021 in connection with the Merger Transactions, was also accounted for as a reorganization of entities under common control. Because the Independence Reorganization and the Isla Merger resulted in changes in the reporting entity, and in order to furnish comparative financial information prior to the Independence Reorganization and the Isla Merger, our financial statements have been retrospectively recast to reflect the historical accounts of the Contributed Entities and Independence, our accounting predecessor (the "Predecessor"), on a combined basis.

Crescent is a holding company that conducts substantially all of its business through its consolidated subsidiaries, including OpCo, which is owned approximately 25% by Crescent and approximately 75% by holders of our redeemable noncontrolling interests representing former owners of Independence, and Crescent Energy Finance LLC, OpCo's wholly owned subsidiary. Crescent and OpCo have no operations, or material cash flows, assets or liabilities other than their investment in Crescent Energy Finance LLC.

The financial statements include undivided interests in oil and natural gas properties. We account for our share of oil and natural gas properties by reporting our proportionate share of assets, liabilities, revenues, costs, and cash flows within the accompanying consolidated balance sheets, combined and consolidated statements of operations, and combined and consolidated statements of cash flows.

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make use of estimates and assumptions that affect the reported amount of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We use historical experience and various other assumptions and information that are believed to be reasonable under the circumstances in developing our estimates and judgments. Estimates and assumptions about future events and their effects cannot be predicted with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. While we believe that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results may differ from these estimates. Our significant estimates include the fair value of acquired assets and liabilities, oil and natural gas reserves, impairment of proved and unproved oil and natural gas properties and valuation of derivative instruments.

Cash and Cash Equivalents

Cash and cash equivalents consist of cash deposited in commercial bank accounts and highly liquid investments purchased with an original maturity of three months or less at the date of purchase. Cash and cash equivalents are maintained with major financial institutions in the U.S. Deposits with these financial institutions may exceed the amount of insurance provided on such deposits; however, the financial stability of the financial institutions is regularly monitored, and we believe that we do not have exposure to any significant default risk.

Restricted Cash

Restricted cash consists of funds earmarked for a special purpose and therefore not available for immediate and general use. The majority of our restricted cash is comprised of cash that is contractually required to be restricted to pay for the future

abandonment of certain wells in California. Restricted cash is included in other current assets and other assets on our balance sheets.

The following table provides a reconciliation of cash and restricted cash presented on our balance sheets to amounts shown in the statements of cash flows:

	As of December 31,
	2021		2020		2019
	(in thousands)
Cash and cash equivalents	$	128,578	$	36,861	$	19,894
Restricted cash – current	—		—		3,932
Restricted cash – noncurrent	6,539		4,559		3,595
Total cash, cash equivalents and restricted cash	$	135,117	$	41,420	$	27,421

Accounts Receivable

We routinely assess the recoverability of our accounts receivable, which primarily comprise amounts due from (i) purchasers of our oil, natural gas and NGL production and (ii) joint interest owners on properties that we operate. We monitor our exposure to credit risk primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s creditworthiness. Generally, our oil and natural gas receivables are collected within 45 to 60 days of production. Our joint interest billings are collected within the month after they are billed, and we have the ability to withhold future revenue distributions to recover any nonpayment of our joint interest billings.

As a result of adopting ASU 2016-13, Measurement of Credit Losses on Financial Instruments, we establish allowances for credit losses equal to the estimable portions of accounts receivable for which failure to collect is expected to occur primarily based on a historical loss rate analysis. We estimate uncollectible amounts based on the length of time that the accounts receivables have been outstanding, historical collection experience and current and future economic and market conditions. We consider forecasts of future economic conditions in the estimate of our expected credit losses, in particular whether there is an increase in the probability that our counterparties will be unable to pay their obligations when due, and adjust our allowance for expected credit losses, when necessary. Our allowances for expected credit losses and bad debt were immaterial as of December 31, 2021 and 2020. We did not incur credit loss expense or bad debt expense related to our accounts receivable during the years ended December 31, 2021, 2020, and 2019. We do not have any off-balance sheet credit exposure related to our customers.

Restricted Investment Securities

We hold U.S. Treasury securities, which are contractually required to be set aside to pay for the future abandonment of certain wells in California. Due to this restriction, we report these investment securities as noncurrent and include them within other assets on our consolidated balance sheets.

We classify our investment in these debt securities at the acquisition date and re-evaluate the classification at each balance sheet date. We classify debt securities purchased with the positive intent and ability to hold until their maturity date as held-to-maturity investments (“HTM”) and carry these investments at amortized cost. Premiums and discounts on purchases are amortized over the remaining time to maturity of the security and the amortization is recorded as an adjustment to interest income. At December 31, 2021 and 2020, we had restricted investment securities – HTM with a carrying value of

$5.3 million and $8.5 million, respectively.

Oil and Natural Gas Properties

Oil and natural gas producing activities are accounted for under the successful efforts method of accounting. Under this method, exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. Costs that are associated with the drilling of successful exploration wells are capitalized if proved reserves are found. Capitalized costs attributed to the properties are charged as an operating expense through depreciation, depletion and amortization (“DD&A”). Dry hole costs associated with developing proved fields are capitalized. Costs associated with the drilling of exploratory wells that do not find proved reserves, geological and geophysical costs and costs of certain nonproducing leasehold costs are expensed once evaluated and determined to be a dry hole. We incurred exploration expense of $1.2 million, $0.5 million, and $0.5 million for the years ended December 31, 2021, 2020 and 2019, respectively.

Delay and surface rentals are charged to expense as incurred. The costs to acquire mineral interests in oil and natural gas properties and lease acquisition costs are capitalized when incurred. If proved reserves are found on an undeveloped property, leasehold costs are transferred to proved properties.

The capitalized costs of producing oil and natural gas properties are depleted on a field-by-field basis using the units-of-production method based on the ratio of current production to estimated total net proved oil, natural gas and NGL reserves. Proved developed reserves are used in computing depletion rates for drilling and development costs and total proved reserves are used for depletion rates of leasehold costs.

Upon the sale of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated DD&A are removed from the property accounts and any gain or loss is recognized.

Estimated dismantlement and abandonment costs for oil and natural gas properties are capitalized at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. See discussion of Asset Retirement Obligations below for additional discussion.

During the years ended December 31, 2021, 2020 and 2019, we recognized depletion expense of $300.0 million, $364.7 million and $300.9 million, respectively.

Other Property, Plant and Equipment

We have other property, plant, and equipment that consists principally of gathering and processing facilities, vehicles, computer hardware and software, office furniture and equipment, buildings and leasehold improvements. Other property, plant, and equipment is recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the respective assets which range from three to thirty years. Leasehold improvements are amortized over the shorter of their economic lives or the lease term. The cost of maintenance and repairs are expensed in the period incurred. Expenditures that extend the life or improve existing property and equipment are capitalized.

Impairment

Proved and unproved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. When a triggering event is identified, we compare the carrying amount of our oil and natural gas properties to the estimated undiscounted cash flows our oil and natural gas properties will generate to determine if the carrying amount is recoverable. We perform this analysis on a field-by-field basis. If the carrying amount exceeds the estimated undiscounted cash flows, we will write-down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, and discount rates commensurate with the risk associated with realizing the projected cash flows.

In March 2020, crude oil demand experienced significant declines due to the coronavirus disease 2019 (COVID-19) global pandemic and resulting governmental led shut-downs in economic activity. During the second quarter of 2020, as it became apparent that the pandemic would continue indefinitely with sustained significant decline in crude oil prices, we assessed our oil and natural gas properties for impairment and incurred impairment expense of $247.2 million during the year ended December 31, 2020. We did not incur any impairment expense during the years ended December 31, 2021 and 2019.

Drilling Advances

We pay advances for certain D&C costs on our non-operated properties, as required by our joint operating agreements. At December 31, 2021 and 2020, we had $0.2 million and $38.9 million, respectively, of outstanding advances on our consolidated balance sheets.

Equity Method Investments

If an entity is organized as a limited partnership or limited liability company and maintains separate ownership accounts, we generally account for our investment using the equity method if our ownership interest is between 3% and 50%, unless our interest is so minor that we have virtually no influence over the investee’s operating and financial policies. For all other types of investments, we generally apply the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the investee’s operating and financial policies. We eliminate our proportionate share of

profits and losses from transactions with equity affiliates to the extent such amounts remain on our consolidated balance sheets (or those of our equity affiliates).

Under the equity method, our proportionate share of each investees' net income increases the balance of our investment, while a net loss or receipt of dividends decreases the balance of our investment. Our proportionate share of net income from our equity affiliates are reported as a single line item within income (loss) from equity method investments in our combined and consolidated statements of operations.

Subsequent to the Merger Transactions, we have significant influence, but not control, over Exaro Energy III, LLC ("Exaro") and Lost Creek Gathering LLC ("Lost Creek"). We have a 37% ownership interest in Exaro and a 65% ownership interest in Lost Creek, but we do not control this entity as our partner has substantive participating rights. As a result, our investments in Exaro of $4.7 million and Lost Creek of $10.7 million are accounted for using the equity method within investments in equity affiliates in our consolidated balance sheet as of December 31, 2021.

Other Long-Term Assets

We acquired certain long-term joint interest receivables that are settled through the underlying oil and natural gas interests of certain joint interest owners. The outstanding balance of these long-term receivables was $1.2 million and $1.3 million as of December 31, 2021 and 2020. We recognized write-offs of acquired long-term joint interest receivables totaling $3.8 million within operating expense in the combined and consolidated statement of operations for the year ended December 31, 2019.

Redeemable Noncontrolling Interests

In connection with the Merger Transactions, 127.5 million OpCo Units were issued to the former owners of Independence. The former owners of Independence also own all outstanding shares of our Class B Common Stock. Pursuant to the OpCo LLC Agreement, holders of OpCo Units, other than the Company, may redeem all or a portion of their OpCo Units, together with a corresponding number of shares of Class B Common Stock, for either (a) shares of Class A Common Stock or (b) an approximately equivalent amount of cash as determined pursuant to the terms of the OpCo LLC Agreement, at the election of the Company. In connection with the exercise of such redemption, a corresponding number of shares of Class B Common Stock will be cancelled. The redemption election is not considered to be within the control of the Company because the holders of Class B Common Stock and their affiliates control the Company through direct representation on the Board of Directors. As a result, we present the noncontrolling interests in OpCo as redeemable noncontrolling interests outside of permanent equity. Redeemable noncontrolling interest is recorded at the greater of the carrying value or redemption amount with a corresponding adjustment to additional paid-in capital.

From the date of the Merger Transactions through December 31, 2021, we recorded adjustments to the value of our redeemable noncontrolling interests as shown below:

	Redeemable Noncontrolling Interest
	(in thousands)
Balance as of December 7, 2021	$	2,353,977
Net loss attributable to redeemable noncontrolling interests	(58,761)
Accrued OpCo distribution	(2,706)
Equity-based compensation, net of withholding taxes	16,412
Cancellation of OpCo Units associated with repurchase of treasury stock	16,091
Balance as of December 31, 2021	$	2,325,013

Stockholders' Equity

Class A and Class B Common Stock

As of December 31, 2021, we had 41,954,385 and 127,536,463 shares of Class A Common Stock and Class B Common Stock outstanding, respectively. Our Class A Common Stock is publicly traded, while our Class B Common Stock is 100% owned by the former owners of Independence.

As a result of the Merger Transactions, (a) former owners of Independence own 100% of the total outstanding Class B Common Stock and approximately 75% of the total outstanding Class A Common Stock and Class B Common Stock taken

together, and (b) former stockholders of Contango own Class A Common Stock that represents approximately 25% of the outstanding Class A Common Stock and Class B Common Stock, taken together.

Treasury stock

Treasury stock shares represent shares we withheld associated with the payroll tax withholding obligations due from employees upon the vesting of stock awards. We include the shares withheld as treasury stock on our consolidated balance sheets and separately pay the payroll tax obligation. These retained shares are not part of a publicly announced program to repurchase shares of our Class A Common Stock and are accounted for at cost. We do not have a publicly announced program to repurchase shares of our Class A Common Stock.

Predecessor members' equity

Prior to the Merger Transactions, Independence had two classes of equity in the form of Class A Units and Class B Units. Both Class A Units and Class B Units were considered common units, and distributions were made pro rata in accordance with each unit’s respective ownership percentage. At the time of the Merger Transactions, only Class A Units were issued and outstanding. As a result of the Merger Transactions, all Class A Units were exchanged for our Class B Common Stock and no Class A Units or Class B Units remain issued or outstanding.

Noncontrolling interest

We record noncontrolling interest associated with third party ownership interests in our subsidiaries. Income or loss associated with these interests is classified as net income (loss) attributable to noncontrolling interest on our combined and consolidated statements of operations.

In April 2021, certain minority investors exchanged 100% of their interests in our Barnett Basin natural gas assets for 9,508 of our Predecessor's Class A Units ("April 2021 Exchange"). Since we already consolidate the results of these assets, this transaction was accounted for as an equity transaction and reflected as a reclassification from noncontrolling interests to members’ equity with no gain or loss recognized on exchange.

In December 2020, certain other minority owners of our consolidated subsidiaries elected to exchange 100% of their interests in those individual consolidated subsidiaries for 220,421 of our Predecessor's Class A Units (“December 2020 Exchange”). Since we already consolidate the results of these subsidiaries, this transaction was accounted for as a reclassification of $657.4 million from noncontrolling interest to members’ equity with no gain or loss recognized on the exchange.

In August 2020, in connection with the Independence Reorganization, certain interests in our consolidated subsidiaries owned by a third-party investor were not contributed to the Predecessor. These interests were reclassified from members’ equity to noncontrolling interest as of the date of the Independence Reorganization and all income and loss attributable to these interests is recorded as net income (loss) attributable to noncontrolling interests from the date of the Independence Reorganization. In May 2021, these noncontrolling equity interests were redeemed in exchange for the third-party investor’s proportionate share of the underlying oil and natural gas interests held by its consolidated subsidiaries ("Noncontrolling Interest Carve-out"). Additionally, the third-party investor contributed cash of approximately $35.5 million to repay its proportionate share of the underlying debt outstanding under our Prior Credit Agreements and other liabilities. The percentage ownership of these certain consolidated subsidiaries owned by the third-party investor ranges from 2.21% to 7.38%.

The following table discloses the effects on equity of changes in our ownership interest in our subsidiaries related to transactions with holders of noncontrolling interests:

	Year Ended December 31,
	2021		2020		2019
	(in thousands)
Net income (loss) attributable to Crescent Energy and its Predecessor	$	(358,544)	$	(118,649)	$	45,839
Transfers (to) from noncontrolling interest
Decrease in Predecessor members’ equity related to the Independence Reorganization	—		(101,926)		—
Increase in Predecessor members’ equity related to the December 2020 Exchange	—		657,370		—
Increase in Predecessor members’ equity related to the April 2021 Exchange	62,051		—		—
Net transfers (to) from noncontrolling interest	62,051		555,444		—
Changes from net income (loss) attributable to Crescent Energy and its Predecessor and transfers (to) from noncontrolling interest	$	(296,493)	$	436,795	$	45,839

Debt Issuance Costs

We capitalize costs incurred in connection with obtaining financing associated with our revolving credit facilities and amortize such costs as additional interest expense over the life of the underlying indebtedness. These costs include fees paid to financial institutions and legal fees and are included in other assets in our consolidated balance sheets.

Revenue Recognition

Oil, Gas and NGL Revenues

We hold operated and non-operated working interests and mineral and royalty interests in producing assets that function as follows:

Operated working interests: We are responsible for the day-to-day management and operation of the field as well as negotiations required for post-production transportation, gathering, processing and marketing; we remit proceeds from sales of resulting hydrocarbons to third parties back to non-operators less costs as agreed in the applicable joint operating agreement.

Non-operated working interests: An operator of these assets is responsible for the day-to-day management and operation of the field as well as negotiations required for post-production transportation, gathering, processing, and marketing; the operator then remits proceeds from sales of resulting hydrocarbons to third parties back to non-operators less costs as agreed in the applicable joint operating agreement.

Mineral and royalty interests: Ownership of a percentage of production or production revenues produced from leased acreage. The owner of this share of production does not bear any of the cost of exploration, drilling, producing, operating or any other expense associated with drilling and producing an oil and gas well. Mineral and royalty interests may be burdened by some or all of the post-production costs related to gathering, processing and marketing.

We sell oil production at the lease and collect an agreed-upon index price, net of pricing differentials.

Under our natural gas contracts, we deliver natural gas to a midstream processor at a contractually specified delivery point. The midstream processor gathers and processes the natural gas and then markets and remits proceeds to us for the resulting sale of the residue gas and NGLs.

Our non-operated production is marketed by operators, after which the operators remit net proceeds from the sale of our share of production to us. Proceeds reflect post-production expenses such as gathering, processing and other expenses incurred in marketing of that production.

Performance Obligations

Under product sales contracts, each unit of product generally represents a separate performance obligation. We record revenue for our product sales contracts at the point-in-time control of a commodity is transferred to the customer. However, settlement statements from non-operated working interests may not be received for 30 to 60 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the customer and the net commodity price that will be received for the sale of these commodity products.

At the end of the reporting period, we did not have any unsatisfied performance obligations. Our contracts with customers typically include variable consideration based on monthly pricing tied to local indices and volumes delivered in the current month. The nature of our contracts with customers does not require us to constrain variable consideration for accounting purposes.

Revenue is recognized to the extent it is determined that it is probable that a significant reversal will not occur. We record the differences between our revenue estimates and the actual amounts received in the month that payment is received from the operator.

Incentive Compensation Arrangements

Incentive compensation includes share-based payment awards and incentive cash bonus plans that are issued to employees and non-employees in exchange for services provided to us. Equity-classified share-based payment awards are recognized at fair value on the grant date, and amortized over the life of the award. Liability-classified share-based payment awards are remeasured at fair value until settlement. For awards with service-based vesting conditions only, we recognize compensation cost using straight-line attribution. For awards that contain market or performance conditions we use accelerated attribution. Our policy is to recognize forfeitures as they occur. Certain of our consolidated subsidiaries have also issued incentive awards that are accounted for similar to cash bonus plans, whereby compensation cost is measured based on the present value of probable expected benefits to be paid and recognized over the period services are provided. Incentive awards similar to cash bonus plans may also have market-based or time-based vesting conditions and are included in accounts payable and accrued liabilities on our consolidated balance sheets.

Incentive compensation cost is presented as general and administrative expense on our combined and consolidated statements of operations. See NOTE 13 – Incentive Compensation Arrangements for additional discussion.

Defined Contribution Plan

In conjunction with the Merger Transactions we will begin offering our employees a defined contribution 401(k) Plan (the “401(k) Plan”) for the benefit of substantially all of our employees. The 401(k) Plan allows eligible employees to make tax-deferred contributions, not to exceed annual limits established by the Internal Revenue Service. The Company matches contributions of 100% of employee contributions, up to 5% of compensation with immediate vesting for existing employees. The Company did not make any contributions to the 401(k) Plan for the years ended December 31, 2021, 2020 and 2019 since the plan's inception began in January 2022 in conjunction with the start of the benefit plan year; however, the Company expects to make contributions to the plan in 2022.

Business Combinations

We recognize the identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values. Fair value is the price that would be received to sell an asset or would be paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value measurement is based on the assumptions of market participants and not those of the reporting entity. Therefore, entity-specific intentions do not impact the measurement of fair value. These fair values are accounted for at the date of acquisition and included in our consolidated balance sheets as of December 31, 2021 and 2020. The results of operations of an acquired business are included in our combined and consolidated statements of operations from the date of the acquisition.

Credit and Concentration Risk

We sell a significant amount of our oil, natural gas and NGL production to a limited number of purchasers. This concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our purchasers may be similarly affected by changes in economic, industry or other conditions. If these counterparties were to fail to pay amounts due to us, our financial position and results of operations could be materially affected.

The below purchasers represented greater than 10% of our revenues during the years ended December 31, 2021, 2020 and 2019:

	2021		2020		2019
SN EF Maverick, LLC	*		15.5	%	20.0	%
Eighty Eight Oil	*		11.7	%	*
Shell Trading US Company	18.3	%	10.4	%	*
Cokinos Energy Corporation	*		*		18.1	%
BP Products North America	*		*		13.1	%

*Purchaser did not account for greater than 10% of revenue for the year

We believe that the loss of any of our purchasers would not result in a material adverse effect on our ability to market future oil and natural gas production.

Risks and Uncertainties

Our future financial condition, results of operations and cash flows are dependent on the demand and prices received for oil, natural gas and NGL production. These prices historically have been volatile, and we expect such volatility to continue in the future, as they are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for oil, natural gas and NGL, market uncertainty and a variety of additional factors beyond our control. These factors include weather conditions, government regulations and taxes, the price and availability of alternative fuels and overall economic conditions. A decline in oil, natural gas or NGL prices may adversely affect our financial position, cash flows and results of operations. Lower oil, natural gas or NGL prices also may reduce the amount of oil, natural gas and NGL that can be produced economically.

Our revenues are derived principally from uncollateralized sales to numerous companies in the oil and natural gas industry; therefore, our customers may be similarly affected by changes in economic and other conditions within the industry.

Risk Management

We periodically enter into derivative contracts to manage our exposure to commodity price and interest rate changes. These derivative contracts may take the form of forward contracts, futures contracts, swaps, swaptions, collars or other options. We do not use derivative contracts for speculative purposes and have not designated any derivative instruments as hedging instruments for accounting purposes. As such, unrealized gains and losses from changes in the valuation of our unsettled derivative contracts, as well as realized gains and losses on the settlement of derivative contracts, are reported in gain (loss) on derivatives in our combined and consolidated statements of operations.

Such derivative instruments are initially recorded at fair value on the date on which a derivative contract is entered into and are subsequently remeasured at fair value at each reporting date. Derivatives are carried as assets when the fair value is positive or as liabilities when the fair value is negative and are classified as current and long term based on the delivery periods of the financial instruments. If the right of offset exists and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on our consolidated balance sheets.

See NOTE 6 – Fair Value Measurements for additional discussion.

Contingencies

Certain conditions may exist as of the date our financial statements are issued, which may result in a loss to us but which will only be resolved when one or more future events occur or fail to occur. In the preparation of our financial statements, management assesses the need for accounting recognition or disclosure of these contingencies, if any, and such assessment inherently involves an exercise in judgment. In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in such proceedings, our management and legal counsel evaluate the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.

When applicable, we will accrue an undiscounted liability for contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum amount within the range is accrued. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when it is believed to be only reasonably possible or remote.

For contingencies where an unfavorable outcome is reasonably possible and the impact would be material, we disclose the nature of the contingency and, if feasible, an estimate of the possible loss or range of loss. Loss contingencies considered remote are generally not disclosed. See NOTE 12 – Commitments and Contingencies.

Income Taxes

Crescent is a holding company of which our sole material assets are OpCo Units. OpCo is a partnership and is generally not subject to U.S. federal and certain state taxes. Crescent is subject to U.S. federal and certain state taxes on our allocable share of any taxable income of OpCo. Taxable income or loss generated by OpCo is generally allocated and passed through to Crescent at our proportionate share of OpCo unit ownership, except for activity related to items contributed by Contango with a pre-contribution gain which are allocated solely to Crescent.

The amount of income taxes we record requires interpretations of complex rules and regulations of various tax jurisdictions throughout the United States. We recognize deferred tax assets and liabilities for temporary differences, operating losses and tax credit carryforwards. Temporary differences arise when there are differences between the financial statement carrying amount and the tax basis of existing assets and liabilities as these differences create taxable or tax-deductible amounts for future periods. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized. For additional information regarding income taxes, see NOTE 10 – Income Taxes.

ASC 740, Income Taxes, specifies the accounting for uncertainty in income taxes by prescribing a minimum recognition threshold for a tax position to be reflected in the financial statements. If recognized, the tax benefit is measured as the largest amount of tax benefit that is more likely than not to be realized upon ultimate settlement. Management has considered the amounts and the probabilities of the outcomes that could be realized upon ultimate settlement and believes that it is more likely than not that the Company's recorded income tax benefits will be fully realized, or recognizes a valuation allowance against deferred tax assets in cases where we do not forecast sufficient future income to recognize the deferred tax asset.

Goodwill

Goodwill represents the excess of the consideration transferred for business combinations over the fair value of the identifiable net assets acquired. We test goodwill for impairment annually or more frequently if events or changes in circumstances indicate that the asset might be impaired.

Asset Retirement Obligations

An ARO represents the legal obligation associated with the future abandonment of tangible assets, such as wells, service assets, pipelines, and other facilities. We record an ARO and capitalize the asset retirement cost in oil and natural gas properties in the period in which the ARO is incurred based upon the estimated fair value of the obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO liability is accreted to its future estimated value using an estimated credited-adjusted risk-free rate and the capitalized asset retirement cost is depleted on a unit-of-production basis. Both the accretion expense and the depletion expense are included in depreciation, depletion and amortization expense on our combined and consolidated statements of operations.

Measuring the future ARO requires management to make estimates, assumptions and judgments inherent in the present value calculation including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the related asset. If the ARO is settled for an amount other than the recorded amount, a gain or loss is recognized at settlement.

See NOTE 9 – Asset Retirement Obligations.

Environmental Expenditures

In addition to ARO, management also reviews our estimates of the cleanup costs of various sites on an annual basis. When it is probable that obligations have been incurred, and where a reasonable estimate of the cost of compliance or remediation can be determined, the applicable amount is accrued. For other potential liabilities, the timing of accruals coincides with the related

ongoing site assessments. We do not discount any of these liabilities. Recoveries for environmental remediation costs from third parties, which are probable of realization, are separately recorded and are not offset against the related environmental liability. As of December 31, 2021 and 2020, we did not have any significant probable environmental remediation costs.

Supplemental Cash Flow Disclosures

The following are our supplemental cash flow disclosures for the years ended December 31, 2021, 2020 and 2019:

	Year Ended December 31,
	2021		2020		2019
	(in thousands)
Supplemental cash flow disclosures:
Interest paid, net of amounts capitalized	$	35,055	$	33,902	$	49,397
Income taxes paid	562		14		28
Non-cash investing and financing activities:
Capital expenditures included in accounts payable and accrued liabilities	47,173		12,267		28,305
Equity consideration for acquisitions, net of cash acquired	647,579		454,599		—
Right-of-use assets obtained in exchange for leases	8,573		—		—
April 2021 Exchange and December 2020 Exchange	62,051		657,370		—
Noncontrolling Interest Carve-out	(121,872)		—		—
Capitalized non-cash equity-based compensation	3,373		—		—

Recent Accounting Standards

In February 2016, the FASB issued ASU 2016-02, Leases, ("ASC Topic 842") which establishes comprehensive accounting and financial reporting requirements for leasing arrangements. ASC Topic 842 requires lessees to recognize substantially all lease assets and lease liabilities on the balance sheets. Additional disclosures about an entity’s lease transactions will also be required. ASC Topic 842 defines a lease as “a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment (an identified asset) for a period of time in exchange for consideration.” Lessees and lessors can elect to recognize and measure leases as of the date of adoption using a modified retrospective approach. We adopted ASC Topic 842 effective January 1, 2021. Adoption of ASC Topic 842 resulted in the recognition of additional lease assets and liabilities on our consolidated balance sheets as well as additional disclosures. The adoption did not have a material impact to our combined and consolidated financial statements.

In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848) - Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”). ASU 2020-04 provides optional guidance, for a limited period of time, to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. The amendments in ASU 2020-04 provide optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by reference rate reform if certain criteria are met. The amendments in this ASU apply only to contracts, hedging relationships and other transactions that reference LIBOR, or another reference rate, expected to be discontinued because of reference rate reform. The guidance was effective beginning March 12, 2020 and can be applied prospectively through December 31, 2022. In January 2021, the FASB issued ASU 2021-01, Reference Rate Reform - Scope, which clarified the scope and application of the original guidance. The Company is currently assessing the potential impact of ASU 2020-04 on its consolidated financial statements.

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Acquisitions and Divestitures

12 Months Ended

Dec. 31, 2021

Business Combination and Asset Acquisition [Abstract]

Acquisitions and Divestitures

Acquisitions and Divestitures

During the three years ended December 31, 2021, we completed the following acquisitions and divestitures:

Contango Merger

In December 2021, we acquired all of Contango's outstanding common stock through the issuance of 39,834,461 shares of Crescent Class A Common Stock and settled Contango's equity-based compensation plans through the issuance of 3,270,915 shares of Crescent Class A Common Stock, of which 1,150,991 shares of treasury stock were repurchased to meet employee payroll tax withholding obligations. Contango's properties are primarily located in Oklahoma, Texas, Wyoming and Louisiana. We accounted for the Contango Merger as a business combination using the acquisition method under GAAP. The fair value of consideration transferred totaled $654.6 million based on the closing share price of Contango's common stock on the date of the

Merger Transactions as shares of Crescent Class A common stock were not yet publicly traded. The purchase price allocation for the acquisition is preliminary for assets acquired and liabilities assumed. We expect to complete a final valuation analysis during the second half of 2022. As a result of the acquisition, we recognized $76.6 million of goodwill that is primarily attributable to deferred tax liabilities associated with the transaction and expected synergies from our combined operations. This goodwill is not expected to be deductible for income tax reporting purposes.

From the date of the Contango acquisition through December 31, 2021, revenues and net income associated with the operations acquired through the acquisition were $36.4 million and $5.6 million, respectively. We recognized transaction related expenses of $12.9 million for the year ended December 31, 2021.

The following table summarizes our unaudited pro forma financial information for the years ended December 31, 2021 and 2020 as if the Contango acquisition occurred on January 1, 2020 (unaudited):

	Year Ended December 31,
	2021		2020
	(in thousands)
Revenues	$	1,943,741	$	970,921
Net loss	$	(432,328)	$	(507,837)

The unaudited pro forma information is presented for illustration purposes only and is not necessarily indicative of the operating results that would have occurred had the acquisition been completed on January 1, 2020, nor is it necessarily indicative of future operating results of the combined entity.

Central Basin Platform Acquisition

In December 2021, we acquired from an unrelated third-party certain operated producing oil and natural gas properties predominately located in the Central Basin Platform in Texas and New Mexico, with additional properties in the southwestern Permian and Powder River Basins, for total cash consideration of $60.4 million, including customary purchase price adjustments. The purchase price was funded using cash on hand and borrowings under our Revolving Credit Facility (as defined in NOTE 8 – Debt). We accounted for the Central Basin Platform Acquisition as an asset acquisition and recorded an additional $73.7 million of proved oil and natural gas properties, including an ARO asset of $12.6 million.

DJ Basin Acquisition

In March 2021, we acquired a portfolio of oil and natural gas mineral assets located in the DJ Basin from an unrelated third-party operator for total consideration of $60.8 million (the "DJ Basin Acquisition"). The DJ Basin Acquisition was funded using cash on hand and borrowings under our Prior Credit Agreements. We accounted for the DJ Basin Acquisition as an asset acquisition and the purchase price was allocated 35.6% to proved oil and natural gas properties and 64.4% to unproved oil and natural gas properties. In conjunction with the DJ Basin Acquisition, we issued equity-based compensation, a portion of which is classified within permanent equity as noncontrolling interest and the remainder of which is classified as other liabilities, to certain parties of the transaction. See NOTE 13 – Incentive Compensation Arrangements.

Titan Acquisition

In August 2020, through a series of transactions, we consummated the acquisition of all of the outstanding membership interests in Liberty Energy LLC (and the oil and natural gas assets owned thereby) pursuant to the Contribution Agreement, dated as of July 19, 2020, by and among Independence Energy LLC, Liberty Energy Holdings, LLC (“Liberty Holdco”) and the other parties thereto, in consideration for the issuance of certain membership interests in Independence Energy LLC to an entity substantially owned by Liberty Holdco. Subsequent to the acquisition, we changed the name of Liberty Energy, LLC to Titan. Titan owns certain working interests in non-operated producing and non-producing oil and natural gas properties in the Permian, Rockies, Eagle Ford and Arkoma Basins, which includes a 50% interest in the DJ Basin Erie Hub Gathering System. During the year ended December 31, 2020, we transferred $455.1 million of equity consideration in the form of 0.4 million Class A units of our Predecessor. During the year ended December 31, 2021, due to post-closing adjustments that increased the purchase price, we issued an additional $7.2 million in equity consideration in our Predecessor. We recognized transaction related expenses of $8.7 million for the year ended December 31, 2020.

The following table summarizes the consideration transferred and the estimated fair value of identified assets acquired and liabilities assumed for the Contango and Titan business combinations:

	Contango		Titan
	(in thousands)
Consideration transferred:
Equity consideration	$	654,616	$	461,983
Total	$	654,616	$	461,983
Assets acquired and liabilities assumed:
Cash and cash equivalents	$	14,202	$	482
Accounts receivable, net	145,727		29,044
Derivative assets – current	—		12,000
Prepaid and other current assets	8,275		49,079
Oil and natural gas properties - proved	1,002,165		375,014
Field and other property and equipment	6,955		30,232
Derivative assets – noncurrent	—		114
Goodwill	76,564		—
Investment in equity affiliates	15,047		—
Other assets	3,514		—
Accounts payable and accrued liabilities	(186,689)		(6,539)
Derivative liabilities – current	(44,002)		(4,550)
Long-term debt	(140,000)		—
Deferred tax liability	(83,250)		—
Derivative liabilities – noncurrent	(14,592)		(1,484)
Asset retirement obligations	(142,100)		(21,409)
Other liabilities	(7,200)		—
Fair value of net assets acquired	$	654,616	$	461,983

Claiborne Parish Divestiture

Certain producing properties and oil and natural gas leases in Claiborne Parish, Louisiana were acquired in the Contango Merger and were classified as held for sale and included within “Oil and natural gas properties – proved” in our preliminary purchase price allocation. In December 2021, we entered into a purchase and sale agreement with an unaffiliated third-party that encompassed the sale of certain producing properties and oil and natural gas leases in Claiborne Parish, Louisiana in exchange for cash consideration, net of closing adjustments, of $4.3 million. We did not recognize a gain or loss for the year ended December 31, 2021 as a result of the transaction.

Arkoma Basin Divestiture

In May 2021, we executed a purchase and sale agreement with an unaffiliated third-party that encompassed the sale of certain producing properties and oil and natural gas leases in the Arkoma Basin in exchange for cash consideration, net of closing adjustments, of $22.1 million. We recognized a $8.8 million gain on sale of assets in our combined and consolidated statements of operations for the year ended December 31, 2021, as a result of the transaction.

Midland and Ector County Divestiture

In March 2020, we received the remaining $3.9 million from the deep rights sale, described further below, and recognized the reduction to our oil and gas properties for the full sale of $7.9 million.

In December 2019, we entered into a Term Assignment of Oil and Gas Lease conveying all of our interest in the Midland and Ector county leases between the top of the Mississippian formation down to the base of the Woodford formation, “deep rights”, for total bonus consideration of $7.9 million and a primary term of four years from the effective date, January 1, 2020. We received $4.0 million in December 2019 when the agreement was signed and the remainder was received in March 2020.

Eagle Ford Divestiture

In September 2019, we entered into a purchase, sale and exchange agreement with an unaffiliated third party, which encompassed the sale of certain producing properties and exchange of oil and gas leases in the Eagle Ford area of South Texas in exchange for cash consideration of $15.2 million and additional post-closing settlement consideration of $1.8 million, $1.2 million of which was received in 2021.

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2021

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property, Plant and Equipment

The following table summarizes our oil and natural gas properties as of December 31, 2021 and 2020:

	As of December 31,
	2021		2020
	(in thousands)
Proved oil and natural gas properties (successful efforts method)	$	6,043,602	$	4,910,059
Unproved oil and natural gas properties	308,721		288,459
Oil and natural gas properties, at cost	6,352,323		5,198,518
Less accumulated depreciation, depletion, amortization and impairment	(1,881,934)		(1,633,664)
Oil and natural gas properties, net	$	4,470,389	$	3,564,854

Other Property

The following table summarizes other property, plant and equipment as of December 31, 2021 and 2020:

	Estimated useful life	As of December 31,
		2021		2020
	(years)	(in thousands)
Gathering and pipeline system	30	$	106,023	$	108,777
Vehicles	3-5	10,836		7,273
Computers, furniture, and equipment	3-10	7,175		6,812
Buildings and improvements	5-30	6,641		6,797
Land		5,467		5,700
Financing right of use asset		5,249		—
Field inventory		2,927		3,012
Total field and other property and equipment, at cost		144,318		138,371
Less: accumulated depreciation, amortization and impairment		(59,594)		(61,078)
Total field and other property and equipment, net		$	84,724	$	77,293

Capitalized Exploratory Well Costs

Capitalized exploratory well costs are included in unproved oil and natural gas properties. The following table reflects the net changes in capitalized exploratory well costs for the years ended December 31, 2021 and 2020:

	As of December 31,
	2021		2020
	(in thousands)
Balance at beginning of period	$	—	$	—
Additions pending the determination of proved reserves	—		—
Reclassifications to proved properties	—		—
Cost charged to expense	—		—
Balance at end of period	$	—	$	—

As of December 31, 2021, we did not have any capitalized exploratory well costs.

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Derivatives

12 Months Ended

Dec. 31, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

Derivatives

In the normal course of business, we are exposed to certain risks including changes in the prices of oil, natural gas and NGLs which may impact the cash flows associated with the sale of our future oil and natural gas production. We enter into derivative contracts with lenders under our revolving credit facilities that consist of either a single derivative instrument or a combination of instruments to manage our exposure to these risks.

As of December 31, 2021, our commodity derivative instruments consisted of fixed price swaps and collars which are described below:

Fixed Price and Basis Swaps: Fixed price swaps receive a fixed price and pay a floating market price to counterparty on the notional amount. Our basis swaps fix the basis differentials between the index price at which we sell our production as compared to the index price used in the basis swap. Under a swap contract, we will receive payment if the settlement price is less than the fixed price and would be required to make a payment to the counterparty if the settlement price is greater than the fixed price.

Collars: Collars provide a minimum and maximum price on a notional amount of sales volume. Under a collar, we will receive payment if the settlement price is less than the minimum price of the range and make a payment to the counterparty if the settlement price is greater than the maximum price of the range. We would not be required to make a payment or receive payment if the settlement price falls within the range.

The following table details our net volume positions by commodity as of December 31, 2021:

Production Period	Volumes	Weighted Average Fixed Price			Fair Value
	(in thousands)				(in thousands)
Crude oil swaps (Bbls):
WTI
2022	10,464	$60.63			$	(121,508)
2023	7,627	$58.50			(59,395)
2024	2,975	$57.35			(16,542)
Brent
2022	500	$56.36			(9,258)
2023	527	$52.52			(9,103)
2024	189	$63.71			(766)
Natural gas swaps (MMBtu):
2022	84,527	$2.77			(76,861)
2023	56,728	$2.54			(47,722)
2024	454	$2.94			(82)
NGL swaps (Bbls):
2022	2,983	$22.23			(38,596)
Crude oil basis swaps (Bbls):
2022	5,843	$(0.11)			(4,403)
Natural gas basis swaps (MMBtu):
2022	26,061	$(0.17)			(3,243)
CMA roll swaps (Bbls):
2022	1,468	$1.08			563
Natural gas collars (MMBtu):
2022	510	$3.00	-	$3.41	(220)
2023	550	$2.63	-	$3.01	(469)
2024	9,150	$3.00		$3.87	1,187
Total					$	(386,418)

We have variable rate debt outstanding, which is subject to interest rate risk based on volatility in underlying interest rates. As of December 31, 2020, the fair value of our pay-fixed, receive-variable interest rate swaps was an unrealized loss of $7.0 million. Our interest rate swaps matured in 2021.

We use derivative commodity instruments and enter into swap contracts which are governed by International Swaps and Derivatives Association master agreements. The following table shows the effects of master netting arrangements on the fair value of our derivative contracts at December 31, 2021 and 2020:

	Gross Fair Value		Effect of Counterparty Netting		Net Carrying Value
	(in thousands)
December 31, 2021
Assets:
Derivative assets – current	$	2,983	$	(2,983)	$	—
Derivative assets – noncurrent	4,834		(4,255)		579
Total assets	$	7,817	$	(7,238)	$	579
Liabilities:
Derivative liabilities – current	$	(256,508)	$	2,983	$	(253,525)
Derivative liabilities – noncurrent	(137,726)		4,255		(133,471)
Total liabilities	$	(394,234)	$	7,238	$	(386,996)

	Gross Fair Value		Effect of Counterparty Netting		Net Carrying Value
	(in thousands)
December 31, 2020
Assets:
Derivative assets – current	$	52,833	$	(21,907)	$	30,926
Derivative assets – noncurrent	34,257		(11,905)		22,352
Total assets	$	87,090	$	(33,812)	$	53,278
Liabilities:
Derivative liabilities – current	$	(48,299)	$	21,907	$	(26,392)
Derivative liabilities – noncurrent	(35,863)		11,905		(23,958)
Total liabilities	$	(84,162)	$	33,812	$	(50,350)

The amount of gain (loss) recognized in gain (loss) on derivatives in our combined and consolidated statements of operations was as follows for the years ended December 31, 2021, 2020 and 2019:

	Years ended December 31,
	2021		2020		2019
	(in thousands)
Derivatives not designated as hedging instruments:
Realized gain (loss) on oil positions	$	(180,572)	$	149,713	$	(44,265)
Realized loss on early settlement of certain oil positions	(198,688)		—		—
Realized gain (loss) on natural gas positions	(80,253)		32,638		4,245
Realized gain (loss) on NGL positions	(68,766)		14,458		13,033
Realized gain (loss) on interest hedges	(7,373)		(12,435)		(2,189)
Total realized gain (loss)	(535,652)		184,374		(29,176)
Unrealized gain (loss) on commodity hedges	(337,715)		8,836		(94,766)
Unrealized gain (loss) on interest hedges	7,347		2,074		(3,260)
Total unrealized gain (loss)	(330,368)		10,910		(98,026)
Total gain (loss) on derivatives	$	(866,020)	$	195,284	$	(127,202)

During the year ended December 31, 2021, we settled certain of our outstanding derivative oil commodity contracts for open positions associated with calendar years 2022 and 2023. Subsequent to the settlement, we entered into new commodity derivative contracts at prevailing market prices.

See NOTE 6 – Fair Value Measurements.

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Fair Value Measurements

12 Months Ended

Dec. 31, 2021

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

GAAP defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Generally, the determination of fair value requires the use of significant judgment and different approaches and models under varying circumstances. Under a market-based approach, we consider prices of similar assets, consult with brokers and experts, or employ other valuation techniques. Under an income-based approach, we generally estimate future cash flows and then discount them at a risk-adjusted rate. We classify the inputs used to measure the fair value of our financial assets and liabilities into the following hierarchy:

Level 1: Quoted prices (unadjusted) in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2: Quoted market prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets and liabilities in markets that are not active or other than quoted prices that are observable, either directly or indirectly, and can be corroborated by observable market data.

Level 3: Unobservable inputs that reflect management’s best estimates and assumptions of what market participants would use in measuring the fair value of an asset or liability.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of significance for a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities within the fair value hierarchy levels.

Recurring Fair Value Measurements

The following table presents the location and fair value of our derivative assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2021 and 2020, by level within the fair value hierarchy:

	Fair Value Measurement Using
	Level 1		Level 2		Level 3		Total
	(in thousands)
December 31, 2021
Financial assets:
Derivative assets	$	—	$	7,817	$	—	$	7,817
Financial Liabilities:
Derivative liabilities	$	—	$	(394,234)	$	—	$	(394,234)
December 31, 2020
Financial assets:
Derivative assets	$	—	$	87,090	$	—	$	87,090
Financial Liabilities:
Derivative liabilities	$	—	$	(84,162)	$	—	$	(84,162)

Non-Recurring Fair Value Measurements

Certain nonfinancial assets and liabilities are measured at fair value on a non-recurring basis. We utilize fair value measurement on a non-recurring basis to value our oil and natural gas properties when the carrying value of such property exceeds the respective undiscounted future cash flows. The inputs used to determine such fair value are primarily based upon internally developed cash flow models, as well as market-based valuations as discussed in Note 2 and are classified within Level 3.

As stated in NOTE 2 - Summary of Significant Accounting Policies, oil and natural gas properties were written down to their fair value resulting in an impairment expense of $247.2 million in 2020. The fair value was determined using a discounted cash flow model based on the expected present value of the future net cash flows from our oil and natural gas reserves. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis include estimates

of future prices, production costs, development expenditures, anticipated production, appropriate risk-adjusted discount rates and other relevant data.

Our other non-recurring fair value measurements include the estimates of the fair value of assets and liabilities acquired through business combinations. Both the Contango Merger and Titan Acquisition were accounted for using the acquisition method under GAAP, which requires all assets acquired and liabilities assumed in the acquisitions to be recorded at fair values at the acquisition date of each transaction. Oil and natural gas properties were valued based on an income approach using a discounted cash flow model utilizing Level 3 inputs, including internally generated development and production profiles and price and cost assumptions. Net derivative liabilities assumed in the acquisitions were valued based on Level 2 inputs similar to the Company's other commodity price derivatives. See NOTE 3 – Acquisitions and Divestitures.

Other Fair Value Measurements

The carrying value of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate their fair values due to the short-term maturities of these instruments. Our long-term debt obligations under our Revolving Credit Facility also approximate fair value because the associated variable rates of interest are market based. The fair value of the Senior Notes (as defined in NOTE 8 – Debt) as of December 31, 2021 was $521.5 million based on quoted market prices.

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Accounts Payable and Accrued Liabilities

12 Months Ended

Dec. 31, 2021

Payables and Accruals [Abstract]

Accounts Payable and Accrued Liabilities

Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities consisted of the following as of December 31, 2021 and 2020:

	As of December 31,
	2021		2020
	(in thousands)
Accounts payable and accrued liabilities:
Accounts payable	$	87,336	$	15,019
Accrued lease operating expense	46,231		20,126
Accrued asset operating expense	8,997		3,591
Accrued capital expenditure	60,647		12,267
Accrued general and administrative	12,193		9,549
Accrued transportation expense	19,684		8,399
Accrued deficiency fees	955		5,050
Accrued revenue and royalties payable	75,827		2,142
Accrued interest and other	26,011		4,545
Total accounts payable and accrued liabilities	$	337,881	$	80,688

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Debt

12 Months Ended

Dec. 31, 2021

Debt Disclosure [Abstract]

Debt

Debt

$500.0 million Senior Notes Issuance

On May 6, 2021, Independence Energy Finance LLC (n/k/a Crescent Energy Finance LLC), our wholly owned subsidiary, issued $500.0 million aggregate principal amount of 7.25% Senior Notes due 2026 (the "Senior Notes"). The Senior Notes bear interest at an annual rate of 7.25%, which is payable on May 1 and November 1 of each year and mature on May 1, 2026.

The Senior Notes are our senior unsecured obligations and the Senior Notes and the related guarantees rank equally in right of payment with the borrowings under our Revolving Credit Facility and any of our other future senior indebtedness and senior to any of our future subordinated indebtedness. The Senior Notes are guaranteed on a senior unsecured basis by each of our existing and future subsidiaries that will guarantee our Revolving Credit Facility. The Senior Notes and the guarantees are effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under our Revolving Credit Facility) to the extent of the value of the collateral securing such indebtedness and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any future subsidiaries that do not guarantee the Senior Notes.

The Senior Notes indenture contains covenants that, among other things, limit the ability of the our restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends or distributions in respect of its equity or redeem, repurchase or retire its equity or subordinated indebtedness; (iii) transfer or sell assets; (iv) make

investments; (v) create certain liens; (vi) enter into agreements that restrict dividends or other payments from any non-Guarantor restricted subsidiary to it; (vii) consolidate, merge or transfer all or substantially all of its assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries.

We may, at our option, redeem all or a portion of the Senior Notes at any time on or after May 1, 2023 at certain redemption prices. We may also redeem up to 40% of the aggregate principal amount of the Senior Notes before May 1, 2023 with an amount of cash not greater than the net proceeds that we raise in certain equity offerings at a redemption price equal to 107.250% of the principal amount of the Senior Notes being redeemed, plus accrued and unpaid interest, if any, to, but excluding, the redemption date. In addition, prior to May 1, 2023, we may redeem some or all of the Senior Notes at a price equal to 100% of the principal amount thereof, plus a "make-whole" premium, plus accrued and unpaid interest, if any, to, but excluding, the redemption date.

If we experience certain kinds of changes of control accompanied by a ratings decline, holders of the Senior Notes may require us to repurchase all or a portion of their notes at certain redemption prices. The Senior Notes are not listed, and we do not intend to list the notes in the future, on any securities exchange, and currently there is no public market for the notes.

See NOTE 16 – Subsequent Events for discussion of the issuance of an additional $200.0 million in aggregate principal amount of 7.25% Senior Notes due 2026 during 2022.

Revolving Credit Facility

Overview

In connection with the Senior Notes issuance, we entered into a senior secured reserve-based revolving credit agreement (as amended, restated, amended and restated or otherwise modified to date, the "Revolving Credit Facility") with Wells Fargo Bank, N.A., as administrative agent for the lenders and letter of credit issuer, and the lenders from time to time party thereto. The Revolving Credit Facility matures on May 6, 2025. In September 2021, we entered into the first amendment to the Revolving Credit Facility. The first amendment to the Revolving Credit Facility, amongst other things, increased the committed amount from $500.0 million up to $700.0 million and increased our borrowing base from $850.0 million to $1.3 billion. At December 31, 2021, we had $543.0 million of borrowings under the Revolving Credit Facility and $20.7 million in outstanding letters of credit.

The obligations under the Revolving Credit Facility remain secured by first priority liens on substantially all of the Company’s and the guarantors’ tangible and intangible assets, including without limitation, oil and natural gas properties and associated assets and equity interests owned by the Company and such guarantors. In connection with each redetermination of the borrowing base, the Company must maintain mortgages on at least 85% of the net present value, discounted at 9% per annum (“PV-9”) of the oil and natural gas properties that constitute borrowing base properties. The Company’s domestic direct and indirect subsidiaries are required to be guarantors under the Revolving Credit Facility, subject to certain exceptions.

The borrowing base is subject to semi-annual scheduled redeterminations on or about April 1 and October 1 of each year, as well as (i) elective borrowing base interim redeterminations at our request not more than twice during any consecutive 12-month period or the required lenders not more than once during any consecutive 12-month period and (ii) elective borrowing base interim redeterminations at our request following any acquisition of oil and natural gas properties with a purchase price in the aggregate of at least 5.0% of the then effective borrowing base. The borrowing base will be automatically reduced upon (i) the issuance of certain permitted junior lien debt and other permitted additional debt, (ii) the sale or other disposition of borrowing base properties if the aggregate PV-9 of such properties sold or disposed of is in excess of 5.0% of the borrowing base then in effect and (iii) early termination or set-off of swap agreements (a) the administrative agent relied on in determining the borrowing base or (b) if the value of such swap agreements so terminated is in excess of 5.0% of the borrowing base then in effect.

,.

The combined proceeds from the Senior Notes issuance, Revolving Credit Facility and Noncontrolling Interest Carve-Out were used to fully repay all amounts outstanding under our Prior Credit Agreements (as defined below), which were then terminated upon the repayment of the remaining principal and accrued interest.

Interest

Borrowings under the Revolving Credit Facility bear interest at either a U.S. dollar alternative base rate (based on the prime rate, the federal funds effective rate or an adjusted London Interbank Offered Rate (“LIBOR”)), plus an applicable margin or LIBOR, plus an applicable margin, at the election of the borrowers. The applicable margin varies based upon our borrowing base utilization then in effect. The fee payable for the unused revolving commitments is 0.5% per year and is included within

interest expense on our combined and consolidated statements of operations. Our weighted average interest rate on loan amounts outstanding as of December 31, 2021 was 3.125%.

Covenants

The Revolving Credit Facility contains certain covenants that restrict the payment of cash dividends, certain borrowings, sales of assets, loans to others, investments, merger activity, commodity swap agreements, liens and other transactions without the adherence to certain financial covenants or the prior consent of our lenders. We are subject to (i) maximum leverage ratio and (ii) current ratio financial covenants calculated as of the last day of each fiscal quarter. The Revolving Credit Facility also contains representations, warranties, indemnifications and affirmative and negative covenants, including events of default relating to nonpayment of principal, interest or fees, inaccuracy of representations or warranties in any material respect when made or when deemed made, violation of covenants, bankruptcy and insolvency events, certain unsatisfied judgments and change of control. If an event of default occurs and we are unable to cure such default, the lenders will be able to accelerate maturity and exercise other rights and remedies.

Letters of Credit

From time to time, we may request the issuance of letters of credit for our own account. Letters of credit accrue interest at a rate equal to the margin associated with LIBOR borrowings. At December 31, 2021, we had letters of credit outstanding of $20.7 million, which reduces the amount available to borrow under our Revolving Credit Facility.

Prior Credit Agreements

At December 31, 2020, certain of our subsidiaries had revolving credit facilities with syndicates of lenders. The amounts we were able to borrow under each of the Prior Credit Agreements was limited by a borrowing base, which was based on the oil and natural gas properties, proved reserves, total indebtedness and other factors and was consistent with customary lending criteria. On May 6, 2021, we early terminated the Prior Credit Agreements with the proceeds from the issuance of the Senior Notes and the Noncontrolling Interest Carve-out and borrowings under our Revolving Credit Facility.

The following table summarizes our debt balances as of December 31, 2021 and 2020:

	As of December 31, 2021
	Debt Outstanding		Letters of Credit Issued		Borrowing Base		Maturity
	(in thousands)
Revolving Credit Facility	$	543,000	$	20,653	$	1,300,000	5/6/2025
7.25% Senior Notes due 2026	500,000		—		—		5/1/2026
Less: Unamortized discount and issuance costs	(12,594)
Total long-term debt	$	1,030,406

	As of December 31, 2020
	Debt Outstanding		Letters of Credit Issued		Borrowing Base		Maturity
	(in thousands)
Independence Upstream Holdings LLC	$	32,500	$	—	$	100,000	6/7/2022
Independence Minerals Holdings LLC	15,000		—		37,000		10/25/2024
KNR Resource Investors LP	5,565		250		12,000		6/7/2022
Renee Acquisition LLC	101,310		5,667		145,000		1/31/2023
Newark Acquisition I LP	135,400		6,280		190,000		5/31/2023
Bridge Energy Holdings LLC	35,800		5,574		50,000		7/21/2022
Venado EF LP	156,500		—		160,000		3/10/2022
VOG Palo Verde LP	269,000		—		320,000		2/28/2023
Total long-term debt	$	751,075

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2021

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Asset Retirement Obligations

Our ARO liabilities are based on our net ownership in wells and facilities and management’s estimate of the costs to abandon and remediate those wells and facilities together with management’s estimate of the future timing of the costs to be incurred. The following table summarizes activity related to our ARO liabilities for the years ended December 31, 2021 and 2020:

	Year Ended December 31,
	2021		2020
	(in thousands)
Balance at beginning of period	$	109,616	$	83,141
Additions(1)	156,201		21,860
Retirements	(1,252)		(881)
Accretion expense	7,121		5,694
Revisions	—		(198)
Noncontrolling Interest Carve-out	(3,810)		—
Sale	(1,869)		—
Balance at end of period	266,007		109,616
Less: current portion	(7,905)		(3,213)
Balance at end of period, noncurrent portion	$	258,102	$	106,403

(1)During the year ended December 31, 2021, our ARO additions related to properties acquired in our 2021 acquisitions. During the year ended December 31, 2020, our ARO additions primarily related to properties acquired in the Titan Acquisition. See NOTE 3 – Acquisitions and Divestitures for additional information.

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Income Taxes

12 Months Ended

Dec. 31, 2021

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

Prior to the Merger Transactions, we were organized as Delaware limited liability companies and Delaware limited partnerships and were treated as flow-through entities for U.S. federal income tax purposes. As a result, our tax provisions for the years ended December 31, 2020 and 2019 were minimal. Subsequent to the Merger Transactions we are subject to U.S. federal income and state tax on our allocable share of any taxable income of OpCo. Details of income tax provisions and deferred income taxes are provided in the following tables:

	Year Ended December 31,
	2021		2020		2019
Federal income tax provision (benefit)	(in thousands)
Current	$	—	$	—	$	—
Deferred	(935)		—		—
State income tax provision (benefit)
Current	629		14		28
Deferred	—		—		—
Total income tax provision (benefit)	$	(306)	$	14	$	28

The difference between the statutory federal income tax rate and the Company's effective income tax rate is explained as follows:

	Year Ended December 31,
	2021		2020		2019
Federal income taxes statutory rate	21.0	%	—	%	—	%
Increase (decrease) in rate as a result of:
State current income tax provision, net of federal benefit	(0.1)	%	—	%	—	%
Permanent adjustments (1)	(1.7)	%	—	%	—	%
Income attributable to Predecessor that was not subject to corporate income tax (2)	(18.4)	%	—	%	—	%
Income attributable to noncontrolling interests	(0.7)	%	—	%	—	%
Effective income tax rate	0.1	%	—	%	—	%

(1)During the year ended December 31, 2021, the permanent items primarily related to disallowed officer compensation under Section 162(m) of the Internal Revenue Code.

(2)    During the year ended December 31, 2021, the income attributable to Predecessor was not subject to corporate income tax as we were organized as limited liability companies and limited partnerships that were treated as flow-through entities for U.S federal income tax purposes prior to the Merger Transactions.

Significant components of the Company's deferred income taxes were as follows:

	Year Ended December 31,
	2021		2020
Deferred tax liabilities	(in thousands)
Outside Basis in OpCo	$	98,079	$	—
Deferred tax assets
Federal and state NOL (1)	38,317		—
Federal and state NOL valuation allowance	(30,567)		—
Recognized built-in loss carryforward	6,872		—
Other	920		—
Total deferred tax assets, net of valuation allowance	15,542		—
Net deferred income tax liability	$	82,537	$	—

(1)We have Federal NOLs of $1.9 million, net of tax, that have expiration dates beginning in 2026. We also have NOLs of $36.4 million, net of tax, that were generated after 2017 and have indefinite lives but are limited to offsetting 80% of taxable income in a given tax year.

We assess the available positive and negative evidence to determine if sufficient future taxable income will be generated to use the existing deferred tax assets. On the basis of this evaluation, as of December 31, 2021, a valuation allowance has been recorded to recognize only the portion of the deferred tax assets that are more likely than not to be realized. The amount of the deferred tax asset considered realizable, however, could be adjusted in the future.

As part of the Merger Transactions, we acquired the federal and state NOLs subject to a valuation allowance of $30.6 million due to the Section 382 limitation. During the year ended December 31, 2021, after the Merger Transactions, we recorded an additional valuation allowance related to additional state NOLs incurred that we do not believe are recoverable.

Pursuant to Sections 382 and 383 of the Internal Revenue Code, utilization of our NOLs and credits is subject to a small annual limitation. These annual limitations may result in the expiration of NOLs and credits prior to utilization.

As of December 31, 2021 and 2020, we did not have any uncertain tax positions.

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Leases

12 Months Ended

Dec. 31, 2021

Leases [Abstract]

Leases

LeasesAdoption of ASC Topic 842, Leases

On January 1, 2021, we adopted ASC Topic 842 using the modified retrospective method. We elected the package of practical expedients, including the hindsight and land easement expedients, upon transition which will retain the lease classification for leases and any unamortized initial direct costs that existed prior to the adoption of this standard.

In accordance with the adoption of ASC Topic 842, we now record a net operating lease right-of-use ("ROU") asset and operating lease liability on the consolidated balance sheets for all operating leases with a lease term in excess of 12 months. Prior to the adoption of ASC Topic 842, these same leases were treated as operating leases under ASC Topic 840 and therefore were not recorded on the consolidated balance sheets as of December 31, 2020. There was no impact to retained earnings and no significant impact on the combined and consolidated statements of operations or the combined and consolidated statements of cash flows as a result of adopting ASC Topic 842.

Lease Recognition

We enter into contractual lease arrangements to rent buildings, compressors, drilling rigs, office and rental equipment and vehicles from third-party lessors. ROU assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make future lease payments arising from the lease. Operating lease ROU assets and liabilities are recorded at commencement date based on the present value of lease payments over the lease term. Leases with an initial term of 12 months or less are not recorded on the consolidated balance sheets. The Company recognizes lease expense for these short-term leases on a straight-line basis over the lease term. We use our incremental borrowing rate based on the information available at commencement date of the contract in determining the present value of future lease payments. The incremental borrowing rate is calculated using our collateralized incremental borrowing rate based on our debt structure. The operating lease ROU asset also includes any lease incentives received in the recognition of the present value of future lease payments. Certain of our leases may also include escalation clauses or options to extend or terminate the lease. These options are included in the present value recorded for the leases when it is reasonably certain that we will exercise that option. Lease expense for lease payments is recognized on a straight-line basis over the lease term.

If an arrangement is determined to be a lease, we record the resulting ROU asset on the consolidated balance sheets with offsetting liabilities at the commencement date. We recognize a lease in the financial statements when the arrangement either explicitly or implicitly involves property, plant or equipment ("PP&E"), the contract terms are dependent on the use of the PP&E, and we have the ability or right to control the PP&E or to direct others to control the PP&E and receive the majority of the economic benefits of the assets.

The following tables show the presentation of the right-of-use assets and lease liabilities within our combined and consolidated financial statements:

	As of December 31, 2021
	(in thousands)
Field and other property and equipment, at cost
Financing right-of-use asset	$	5,249
Other assets
Operating right-of-use asset	2,299
Other current liabilities
Short-term operating lease liability	(1,292)
Other liabilities
Long-term operating lease liability	(1,007)

	Year Ended December 31, 2021
	(in thousands)
Lease cost included in combined and consolidated statement of operations
Operating lease cost	$	939
Financing lease cost - amortization of ROU assets	20
Financing lease cost - interest on lease liabilities	131
Administrative lease cost (1)	100
Short-term lease cost (2)	876
Total lease cost	$	2,066

(1)     Costs related primarily to office equipment and IT solutions with lease terms of more than one month and less than one year.

(2)     Costs related primarily to generators, compressors and vehicle agreements with lease terms of more than one month and less than one year.

Lease term and discount rate related to our leases are as follows:

	As of December 31, 2021
	Operating	Financing
Weighted-average remaining lease term (years)	2.3	3.1
Weighted-average discount rate	4.50%	4.50%

As of December 31, 2021, the maturity analysis for our lease liabilities under the scope of ASC 842 is as follows:

	As of December 31, 2021
	Operating		Financing
Year Ended December 31,	(in thousands)
2022	$	1,292	$	1,606
2023	666		1,887
2024	412		1,370
2025	18		633
2026	18		16
After 2026	24		—
Less: interest	(131)		(394)
Present value of lease liabilities	$	2,299	$	5,118

Leases

LeasesAdoption of ASC Topic 842, Leases

On January 1, 2021, we adopted ASC Topic 842 using the modified retrospective method. We elected the package of practical expedients, including the hindsight and land easement expedients, upon transition which will retain the lease classification for leases and any unamortized initial direct costs that existed prior to the adoption of this standard.

In accordance with the adoption of ASC Topic 842, we now record a net operating lease right-of-use ("ROU") asset and operating lease liability on the consolidated balance sheets for all operating leases with a lease term in excess of 12 months. Prior to the adoption of ASC Topic 842, these same leases were treated as operating leases under ASC Topic 840 and therefore were not recorded on the consolidated balance sheets as of December 31, 2020. There was no impact to retained earnings and no significant impact on the combined and consolidated statements of operations or the combined and consolidated statements of cash flows as a result of adopting ASC Topic 842.

Lease Recognition

We enter into contractual lease arrangements to rent buildings, compressors, drilling rigs, office and rental equipment and vehicles from third-party lessors. ROU assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make future lease payments arising from the lease. Operating lease ROU assets and liabilities are recorded at commencement date based on the present value of lease payments over the lease term. Leases with an initial term of 12 months or less are not recorded on the consolidated balance sheets. The Company recognizes lease expense for these short-term leases on a straight-line basis over the lease term. We use our incremental borrowing rate based on the information available at commencement date of the contract in determining the present value of future lease payments. The incremental borrowing rate is calculated using our collateralized incremental borrowing rate based on our debt structure. The operating lease ROU asset also includes any lease incentives received in the recognition of the present value of future lease payments. Certain of our leases may also include escalation clauses or options to extend or terminate the lease. These options are included in the present value recorded for the leases when it is reasonably certain that we will exercise that option. Lease expense for lease payments is recognized on a straight-line basis over the lease term.

If an arrangement is determined to be a lease, we record the resulting ROU asset on the consolidated balance sheets with offsetting liabilities at the commencement date. We recognize a lease in the financial statements when the arrangement either explicitly or implicitly involves property, plant or equipment ("PP&E"), the contract terms are dependent on the use of the PP&E, and we have the ability or right to control the PP&E or to direct others to control the PP&E and receive the majority of the economic benefits of the assets.

The following tables show the presentation of the right-of-use assets and lease liabilities within our combined and consolidated financial statements:

	As of December 31, 2021
	(in thousands)
Field and other property and equipment, at cost
Financing right-of-use asset	$	5,249
Other assets
Operating right-of-use asset	2,299
Other current liabilities
Short-term operating lease liability	(1,292)
Other liabilities
Long-term operating lease liability	(1,007)

	Year Ended December 31, 2021
	(in thousands)
Lease cost included in combined and consolidated statement of operations
Operating lease cost	$	939
Financing lease cost - amortization of ROU assets	20
Financing lease cost - interest on lease liabilities	131
Administrative lease cost (1)	100
Short-term lease cost (2)	876
Total lease cost	$	2,066

(1)     Costs related primarily to office equipment and IT solutions with lease terms of more than one month and less than one year.

(2)     Costs related primarily to generators, compressors and vehicle agreements with lease terms of more than one month and less than one year.

Lease term and discount rate related to our leases are as follows:

	As of December 31, 2021
	Operating	Financing
Weighted-average remaining lease term (years)	2.3	3.1
Weighted-average discount rate	4.50%	4.50%

As of December 31, 2021, the maturity analysis for our lease liabilities under the scope of ASC 842 is as follows:

	As of December 31, 2021
	Operating		Financing
Year Ended December 31,	(in thousands)
2022	$	1,292	$	1,606
2023	666		1,887
2024	412		1,370
2025	18		633
2026	18		16
After 2026	24		—
Less: interest	(131)		(394)
Present value of lease liabilities	$	2,299	$	5,118

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2021

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

From time to time, we may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of business. We are currently unaware of any proceedings that, in the opinion of management, will individually or in the aggregate have a material adverse effect on our financial position, results of operations or cash flows.

We are subject to extensive federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require us to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. We believe we are currently in compliance with all applicable federal, state and local regulations. Accordingly, no liability or loss associated with environmental remediation was recognized as of December 31, 2021 except for the following:

We were engaged with the Environmental Protection Agency (EPA) for alleged violations of the Clean Water Act between 2016 and 2018. We have settled these allegations with the EPA and have recorded $1.4 million as a liability and expense at December 31, 2020, all of which was paid during 2021.

On February 14, 2022, the New Mexico Energy, Minerals and Natural Resources Department’s Oil Conservation Division announced a civil penalty of $913,200 to Contango for failure to file form C-115 according to required deadlines and having too many inactive wells. The parties are discussing a resolution to the matter.

Following the filing of the preliminary joint proxy statement/prospectus related to the Merger Transactions on July 26, 2021, four lawsuits have been filed in the United States District Court for the Southern District of New York, and one lawsuit has been filed in the United States District for the Eastern District of New York, each in connection with the Merger Transactions (the “Shareholder Actions”): Stein v. Contango Oil & Gas Co., et al., No. 1:21-cv-06769 (S.D.N.Y. Aug. 11, 2021) (the “Stein Action”); Prus v. Contango Oil & Gas Co., et al., No. 1:21-cv-04656 (E.D.N.Y. Aug. 18, 2021) (the “Prus Action”); Whitfield v. Contango Oil & Gas Co., et al., No. 1:21-cv-0700 (S.D.N.Y. Aug. 19, 2021) (the “Whitfield Action”); Byerly v. Contango Oil & Gas Co., et al., 1:21-cv-07327 (S.D.N.Y. Aug. 31, 2021) (the “Byerly Action”); Provost v. Contango Oil & Gas Co., et al., 1:21-cv-07874 (S.D.N.Y. Sept. 21, 2021) (the “Provost Action”). Each of the Shareholder Actions names Contango and the members of the Contango board as defendants, and the Whitfield Action names Independence Energy, LLC, OpCo, Crescent Energy Company (f/k/a IE PubCo Inc.) and other affiliates as additional defendants. Each of the Shareholder Actions alleges, among other things, that the registration statement on Form S-4 filed by IE PubCo Inc. on July 26, 2021 in connection with the Merger Transactions (the “Registration Statement”) is false and misleading and/or omits certain information allegedly material to Contango shareholders in violation of Sections 14(a) and 20(a) of the Securities and Exchange Act of 1934 (as amended, the “Exchange Act”) and Rule 14a-9 promulgated thereunder. The plaintiffs in the Shareholder Actions seek, among other relief, an injunction enjoining the Merger Transactions unless and until the defendants disclose the allegedly omitted material information, a rescission of the Contango Agreement to the extent already implemented (or an award of rescissory damages), an order directing the defendants to account for all damages resulting from the alleged wrongdoing, and an award of plaintiffs’ attorneys’ and experts’ fees and other relief. The Byerly Action also requests that the court determine that the lawsuit is a proper class action and certify Byerly as class representative and his counsel as class counsel. On September 20, 2021, the court consolidated the Stein and Whitfield Actions with the Byerly Action. On October 13, 2021, the court consolidated the Provost Action with the Byerly Action. Contango has also received a demand letter sent on behalf of Catherine Coffman, a purported Contango shareholder. The letter demanded that Contango make supplemental disclosures to investors regarding the Merger Transactions based on factual and legal arguments that are substantially similar to those in the Stein, Prus, Whitfield, Byerly, and Provost Actions.

On November 26, 2021, in order to avoid the risk of the Shareholder Actions delaying the Merger Transactions and to minimize the expense of defending the Shareholder Actions, and without admitting any liability or wrongdoing, Contango and Independence voluntarily made certain disclosures that supplement those contained in the joint proxy statement/prospectus. Thereafter, plaintiffs filed voluntary notices of dismissal dismissing the Whitfield and Prus Actions. Pursuant to a scheduling order issued in the consolidated Byerly Action, plaintiff is required to file a Consolidated Amended Complaint within 10 days of an order appointing Byerly as lead plaintiff in the consolidated action.

We believe that the Shareholder Actions are without merit and, along with the individual and other defendants intend to defend against the Shareholder Actions; however, Crescent cannot predict the amount of time and expense that will be required to resolve the Shareholder Actions nor their outcomes. Additional lawsuits arising out of or related to the Merger Transactions may also be filed in the future. At December 31, 2021, we had no amounts reserved on our consolidated balance sheet related to this matter.

Oil Gathering Agreement

In connection with the execution of an oil gathering agreement with a midstream service provider, we received ownership in a Series D class of equity in the midstream service provider. The Series D units do not give us voting or other control rights, but do provide us with an incentive distribution right if other unit classes receive distributions equal to contributed capital plus targeted rates of return. We account for the Series D units through the fair value option available under ASC 825, Financial Instruments. As of December 31, 2021 and 2020, we have concluded the fair value of our investment is not material, based on the nature of the Series D units and overall risk inherent in receiving future cash flows given the stage of development of the entity and required return hurdles.

Carbon Dioxide Purchase Agreement

We assumed one take-or-pay carbon dioxide purchase agreement as part of a prior acquisition. The agreement includes a minimum volume commitment to purchase carbon dioxide at a price stipulated in the contract. The agreement provides carbon dioxide for use in our enhanced recovery projects in certain of our properties. The daily minimum volume commitments are 140 MMcf/per day from June 2021 to May 2026, with the commitment effectively ending in May 2026. We expect to purchase more carbon dioxide through the end of the agreement in 2026 than our minimum volume commitments, and, in accordance

with the agreement, if we do not meet our minimum volume commitments for a year (or years), we can make up the volumes in future years through 2029 as long as we pay for our minimum volumes each year. As of December 31, 2021 and 2020, we have met required minimum volumes.

Oil and Natural Gas Transportation and Gathering Agreements

We have entered into certain oil and natural gas transportation and gathering agreements with various pipeline carriers. Under these agreements, we are obligated to ship minimum daily quantities or pay for any deficiencies at a specified rate. We are also obligated under certain of these arrangements to pay a demand charge for firm capacity rights on pipeline systems regardless of the amount of pipeline capacity that we utilize. If we do not utilize the capacity, we can release it to others, thus reducing our potential liability. We recognized $5.8 million, $14.5 million and $1.9 million of transportation expense in our combined and consolidated statements of operations related to minimum volume deficiencies for the years ended December 31, 2021, 2020 and 2019, respectively.

The following table summarizes our future commitments related to these oil and natural gas transportation and gathering agreements as of December 31, 2021:

	As of December 31, 2021
	(in thousands)
2022	$	105,606
2023	80,340
2024	65,848
2025	61,346
2026	32,652
Thereafter	62,957
Total minimum future commitments	$	408,749

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Incentive Compensation Arrangements

12 Months Ended

Dec. 31, 2021

Share-based Payment Arrangement [Abstract]

Incentive Compensation Arrangements

Incentive Compensation Arrangements

Overview

We and certain of our subsidiaries have entered into incentive compensation award agreements to grant profits interest, restricted stock, performance stock units (PSUs) and other incentive awards to our employees, our Manager, and non-employee directors. The following table summarizes compensation expense we recognized in connection with our incentive compensation awards for the years indicated:

	Year Ended December 31,
	2021		2020		2019
	(in thousands)
ASC 710 profits interest awards	$	—	$	—	$	—
ASC 718 liability-classified profits interest awards	(2,043)		(797)		(2,721)
ASC 718 equity-classified profits interest awards	1,563		—		—
ASC 718 equity-classified PSU awards	1,120		—		—
ASC 718 equity-classified Contango PSU awards	39,279		—		—
Total expense (income)	$	39,919	$	(797)	$	(2,721)

Our incentive compensation awards may contain certain service-based, performance-based, and market-based vesting conditions, which are further discussed below.

ASC 710 compensation awards

Incentive unit awards

Certain of our subsidiaries have issued incentive awards that require continuous service in order to receive distributions, and do not represent an equity interest. As these incentive awards are similar to a cash bonus plan, compensation cost is measured

based on the present value of expected benefits that are probable of being paid and recognized over the period services are provided. Compensation cost is remeasured at each reporting period based on expected future benefits. We did not recognize any compensation cost for this type of incentive award during the years ended December 31, 2021, 2020 and 2019.

ASC 718 stock-based compensation awards

Liability-classified profits interest awards

Certain of our subsidiaries issue profits interests that are liability-classified stock-based compensation awards. These awards contain different vesting conditions ranging from performance-based conditions that vest upon the achievement of certain return thresholds to time-based service requirements ranging from one year to four years. Each of these profits interests is liability-classified because of certain features within these awards that predominantly contain characteristics of liability instruments. Compensation cost for these awards is presented within general and administrative expense on the combined and consolidated statements of operations with a corresponding credit to other long-term liabilities on the consolidated balance sheets.

The fair value of liability-classified stock-based compensation profits interest awards that vested during the years ended December 31, 2021 and 2020 was $2.9 million and $7.7 million, using the fair value measurements as of December 31, 2021 and 2020, respectively. Unrecognized compensation cost related to time-based unvested awards was $23.6 million as of December 31, 2021, and is expected to be recognized over a weighted average period of 3.9 years. Unrecognized compensation cost related to performance-based unvested awards was $2.8 million as of December 31, 2021 and is expected to be recognized as the result of a realization event. No realization events occurred during the years ended December 31, 2021 and 2020. We paid cash of $0.9 million to settle liability-classified stock-based compensation profits interest awards during the year ended December 31, 2021. There were no cash settlements of liability-classified stock based compensation profits interest awards during the year ended December 31, 2020. We carried $7.1 million and $8.0 million liabilities related to these awards as of December 31, 2021 and 2020, respectively in other long term liabilities on the consolidated balance sheets. Transactions involving all of our unvested liability-classified stock-based compensation profits interest awards is summarized below:

	Year Ended December 31,
	2021	2020	2019
	(units in thousands)
Beginning Balance	888	1,215	1,163
Granted	708	—	285
Vested	(110)	(203)	(233)
Forfeited	(778)	(125)	—
Ending Balance	708	888	1,215

We capitalized $1.8 million into Proved and Unproved Oil and natural gas properties on the consolidated balance sheets associated with services provided in exchange for liability-classified stock-based compensation profits interest during the year ended December 31, 2021.

Equity-classified profits interest awards

Certain of our subsidiaries issue equity-classified profits interests awards. These awards contain different vesting conditions ranging from performance-based conditions that vest upon the achievement of certain return thresholds to time-based service requirements ranging from one year to four years. Each of these profits interests is equity-classified because of certain features within these awards that predominantly contain characteristics of equity instruments. Compensation cost for these awards is presented within General and administrative expense on the combined and consolidated statements of operations with a corresponding credit to Additional paid-in capital on the consolidated balance sheets.

The fair value of equity-classified profits interest awards that vested during the year ended December 31, 2021 was $1.8 million. We did not have any equity-classified profits interest awards that vested during the year ended December 31, 2020. We did not have any unrecognized compensation cost related to unvested equity-classified profits interest awards as of December 31, 2021. We paid cash of $0.2 million to settle equity-classified profits interest awards during the year ended December 31, 2021. There were no cash settlements of equity-classified profits interest awards during the year ended December 31, 2020. Transactions involving all of our unvested equity-classified profits interest awards, including weighted average grant date fair values, are summarized below:

	Units	Weighted average grant date fair value
	(in thousands)
Unvested at December 31, 2020	—	$	—
Granted	477	10.98
Vested	(25)	10.61
Forfeited	(253)	11.02
Unvested at December 31, 2021	200	—

We capitalized $1.6 million into Proved and Unproved Oil and natural gas properties on the consolidated balance sheets associated with services provided in exchange for equity-classified profits interest awards during the year ended December 31, 2021.

Equity-classified PSU Awards

In conjunction with the Merger Transactions, we granted equity-classified Manager Incentive Plan PSUs in accordance with the Manager Incentive Plan. The PSU performance periods are generally three years with the performance period end dates ranging from 2024 through December 2028. Each of these units represent the right to receive a target 2% of our issued and outstanding Class A Common Stock on each unit's performance period end date, modified by an amount ranging from 0% to 240% based on certain absolute and relative shareholder return components. Compensation cost for these awards is presented within General and administrative expense on the combined and consolidated statements of operations with a corresponding credit to Additional paid-in capital on the consolidated balance sheets.

Unrecognized compensation cost related to unvested awards was $71.6 million as of December 31, 2021 and is expected to be recognized over a weighted-average period of 5.0 years. Transactions involving all of our unvested units, including weighted average grant date fair values, are summarized below:

	Target Class A Shares	Weighted average grant date fair value
	(in thousands)
Unvested at December 31, 2020	—	$	—
Granted	4,195	17.33
Vested	—	—
Forfeited	—	—
Unvested at December 31, 2021	4,195	17.33

Equity-classified Contango PSU Awards

Prior to the Merger Transaction, Contango issued equity-classified PSU awards to its employees in exchange for their services to Contango over each award's respective performance period. As part of the Merger Transactions, Contango's equity-classified PSUs were modified to pay out 300% of the target PSU award amount at the close of the Merger Transactions. Because the PSU awards were modified as part of the Merger Transactions, we recorded compensation cost in the amount of the increase in the fair value of the Contango equity-classified PSUs as a result of the modification immediately after the close of the Merger Transactions within General and administrative expense on the combined and consolidated statements of operations with corresponding credits to Additional paid-in capital and Redeemable noncontrolling interests on the consolidated balance sheets.

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Related Party Transactions

12 Months Ended

Dec. 31, 2021

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

KKR Group

Management Agreement

In connection with the Merger Transactions, we entered into a management agreement (the "Management Agreement") with KKR Energy Assets Manager LLC (the "Manager"). Pursuant to the Management Agreement, the Manager provides the Company with its executive management team and certain management services. The Management Agreement has an initial term of three years and shall renew automatically at the end of the initial term for an additional three-year period unless the Company or the Manager elects not to renew the Management Agreement.

As consideration for the services rendered pursuant to the Management Agreement and the Manager’s overhead, including compensation of the executive management team, the Manager is entitled to receive compensation ("Management Compensation") equal to $13.5 million per annum, which represents our pro rata portion (based on our relative ownership of OpCo) of $53.3 million. This amount will increase over time as our ownership percentage of OpCo increases. In addition, as our business and assets expand, Management Compensation may increase by an amount equal to 1.5% per annum of the net proceeds from all future issuances of our equity securities (including in connection with acquisitions). However, incremental Management Compensation will not apply to the issuance of our shares upon the redemption or exchange of OpCo Units. During the year ended December 31, 2021, we recorded general and administrative expense of $0.9 million, related to the Management Agreement.

Additionally, the Manager is entitled to receive incentive compensation ("Incentive Compensation") under which the Manager is targeted to receive 10% of our outstanding Class A Common Stock based on the achievement of certain performance-based measures. The Incentive Compensation consists of five tranches that settle over a five year period beginning in 2024, and each tranche relates to a target number of shares of Class A common stock equal to 2% of the outstanding Class A common stock as of the time such tranche is settled. So long as the Manager continuously provides services to us until the end of the performance period applicable to a tranche, the Manager is entitled to settlement of such tranche with respect to a number of shares of Class A common stock ranging from 0% to 240% of the initial target amount based on the level of achievement with respect to the performance goals applicable to such tranche. During the year ended December 31, 2021, we granted the Performance Stock Units associated with the Incentive Compensation. See NOTE 13 – Incentive Compensation Arrangements for more information.

KKR Funds

From time to time, we may invest in upstream oil and gas assets alongside EIGF II and/or other KKR funds ("KKR Funds") pursuant to the terms of the Management Agreement. In these instances, certain of our consolidated subsidiaries enter into Master Service Agreements ("MSA") with entities owned by KKR Funds, pursuant to which our subsidiaries provide certain services to such KKR Funds, including the allocation of the production and sale of oil, natural gas and NGLs, collection and disbursement of revenues, operating expenses and general and administrative expenses in the respective oil and natural gas properties, and the payment of all capital costs associated with the ongoing operations of the oil and natural gas assets. Our subsidiaries settle balances due to or due from KKR Funds on a monthly basis. The administrative costs associated with these MSAs are allocated by us to KKR Funds based on (i) an actual basis for direct expenses we may incur on their behalf or (ii) an allocation of such charges between the various KKR Funds based on the estimated use of such services by each party. As of December 31, 2021, we had a related party receivable of $3.3 million included within Accounts receivable – affiliates and $7.0 million included within Accounts payable – affiliates on our consolidated balance sheets associated with KKR Funds transactions.

Other Transactions

We paid $1.6 million in fees to KKR Capital Markets LLC, an affiliate of KKR, for services provided as a book-running manager in connection with the issuance of our Senior Notes in May 2021 and recorded as debt issuance costs within Long-term debt on the consolidated balance sheets. Additionally, we paid $0.1 million to KKR Capstone Americas LLC for professional fees support related to insurance and employee benefits due diligence and placement and recorded as General and administrative expense on the combined and consolidated statements of operations. In February 2022, we paid $0.4 million in fees to KKR Capital Markets LLC in connection with the issuance of the New Notes. See NOTE 16 – Subsequent Events.

FDL

On April 1, 2021, certain minority investors, including FDL Operating LLC ("FDL") management, exchanged 100% of their interests in our Barnett basin natural gas assets for 9,508 of our predecessor Class A units, representing 0.77% of our consolidated ownership. Since we already consolidate the results of these assets, this transaction was accounted for as an equity transaction and reflected as a reclassification from noncontrolling interests to members' equity with no gain or loss recognized on the exchange (the "April 2021 Exchange"). As of December 31, 2021, FDL's management owns less than 0.15% of our Class B shares and holds noncontrolling interests in certain of our consolidated subsidiaries.

Certain of our consolidated subsidiaries have entered into an Oil and Natural Gas Property Operating and Services Agreement (the “FDL Agreement”) with FDL. Pursuant to the FDL Agreement, FDL was engaged to manage the day-to-day operations of the business activities of certain of our consolidated subsidiaries, including allocating to us and other interest holders the production and sale of oil, natural gas and natural gas liquids, collection and disbursement of revenues, operating expenses and general and administrative expenses in the respective oil and natural gas properties and the payment of all capital costs associated with the ongoing operations of such properties. As part of the engagement, FDL will then allocate the revenues,

operating expenses, general and administrative expenses and cash collected to us and others as appropriate. We settle balances due to or due from FDL on a monthly basis. As of December 31, 2021, we had a net related party receivable due from FDL totaling $16.9 million and at December 31, 2020, we had a net related party payable due to FDL totaling $7.5 million, included within Accounts receivable – affiliates and Accounts payable – affiliates, respectively, on our consolidated balance sheets. On September 20, 2021 we provided notice that we are terminating the FDL Agreement effective on March 31, 2022. During October 2021, as part of the termination principal terms, we agreed to pay up to $6.5 million in wind down costs and additional severance costs for certain qualifying, dedicated employees, of which any unused portion will be returned to us at the end of the wind down period. During the year ended December 31, 2021, we recorded $3.3 million of expense associated with the termination.

RPM

An affiliate of KKR Group has entered into a Master Management Services Agreement (the “MSA”) with a subsidiary of RPM Energy Management Partnership L.P. (“RPM”) to act as the manager of certain mineral and non-operated assets controlled by our consolidated subsidiaries. Pursuant to the MSA and under management of certain KKR affiliated entities, RPM manages the day-to-day operations of the business activities of certain of our oil and natural gas properties. We reimburse RPM for all reasonable out-of-pocket expenses incurred for fulfilling its obligations under the MSA (“Allocable Overhead Costs”). The Allocable Overhead Costs are charged to us on an actual basis without mark-up or subsidy. As such, the Allocable Overhead Costs approximate reasonable market rates and are representative of the expenses that we would have incurred had we not entered into the MSA. We settle balances due to or due from RPM on a monthly basis.

As of December 31, 2021 and 2020 we had a payable due to RPM of $1.7 million included within Accounts payable - affiliates on our consolidated balance sheets. On December 31, 2021, we terminated our relationship with RPM.

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Earnings Per Share

12 Months Ended

Dec. 31, 2021

Earnings Per Share [Abstract]

Earnings Per Share

Earnings Per Share

We have two classes of common stock in the form of Class A Common Stock and Class B Common Stock. However, only shares of Class A Common Stock are entitled to dividends, and shares of Class B Common Stock do not have rights to participate in dividends or undistributed earnings. We apply the two-class method for purposes of calculating earnings per share (“EPS”). The two-class method determines earnings per share of common stock and participating securities according to dividends or dividend equivalents declared during the period and each security's respective participation rights in undistributed earnings and losses.

As described in NOTE 1 – Organization and Basis of Presentation, our financial statements have been retrospectively recast to reflect the historical accounts of Independence and the Contributed Entities on a combined basis due to the Merger Transactions and Independence Reorganization, respectively. Net income (loss) for periods prior to the Merger Transactions is allocated to our Predecessor as our Predecessor's Class A Units were exchanged for shares of Class B Common Stock in connection with the Merger Transactions. Net income (loss) attributable to Crescent Energy is allocated to Class A Common Stock and Class B Common Stock based on the participation rights of each class to share in undistributed earnings and losses after giving effect to dividends declared during the period, if any.

The following table sets forth the computation of basic and diluted net income (loss) per share:

	Year Ended December 31,
	2021		2020		2019
	(in thousands, except unit and per unit amounts)
Numerator:
Net income (loss)	$	(432,227)	$	(216,124)	$	46,709
Less: net (income) loss attributable to Predecessor	339,168		118,649		(45,839)
Less: net (income) loss attributable to noncontrolling interests	14,922		97,475		(870)
Less: net (income) loss attributable to redeemable noncontrolling interests	58,761		—		—
Net income (loss) attributable to Crescent Energy	$	(19,376)	$	—	$	—
Denominator:
Weighted-average Class A common stock outstanding - basic and diluted (1)	41,954,385
Weighted-average Class B common stock outstanding - basic and diluted	127,536,463
Net income (loss) per share:
Class A common stock - basic and diluted (1)	$	(0.46)
Class B common stock - basic and diluted	$	—

(1)Represents weighted-average Class A common stock outstanding and net loss per share of Class A common stock for the period subsequent to the Merger Transactions.

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Subsequent Events

12 Months Ended

Dec. 31, 2021

Subsequent Events [Abstract]

Subsequent Events

Subsequent Events

Subsequent events have been evaluated through the date of issuance of these financial statements, and there have been no events subsequent to December 31, 2021, other than those items disclosed below, that would require additional adjustments to our disclosure in our financial statements.

$200.0 million Senior Notes Issuance

In February 2022, we issued an additional $200.0 million aggregate principal amount of our 7.250% senior notes due 2026 (the “New Notes”). The New Notes were issued as additional notes pursuant to our $500.0 million issuance in May 2021 as described in NOTE 8 – Debt. The New Notes will be treated as a single series and will vote together as a single class with the Senior Notes, and have identical terms and conditions, other than the issue date, the issue price and the first interest payment, as the Senior Notes.

Uinta Basin Acquisition

In February 2022, Javelin VentureCo, LLC (the “Purchaser”), one of our subsidiaries, and OpCo entered into a Membership Interest Purchase Agreement (the “Purchase Agreement”) with Verdun Oil Company II LLC, a Delaware limited liability company (the “Seller”), pursuant to which the Purchaser agreed to purchase from Seller all of the issued and outstanding membership interests (the “Purchased Interests”) of Uinta AssetCo, LLC, a to-be formed Texas limited liability company which will be a wholly-owned subsidiary of the Seller (“UtahCo”). UtahCo will hold all exploration and production assets of and certain obligations of EP Energy E&P Company, L.P. located in the state of Utah (the “Utah Assets”).

Seller will receive aggregate consideration of approximately $815.0 million in cash and the assumption of certain hedges, subject to certain customary purchase price adjustments set forth in the Purchase Agreement. OpCo has agreed to guarantee Purchaser’s obligation to fund the purchase price at closing, which is expected to occur in the first half of 2022.

In connection with the closing of the transaction, we anticipate entering into an amendment to our Revolving Credit Facility to, among other things, increase the elected commitment amount to $1.3 billion. However, there can be no assurances we will consummate this transaction or that we will enter into such amendment to our Revolving Credit Facility.

Chama

In February 2022, we contributed all the assets and prospects in the Gulf of Mexico formerly owned by Contango to Chama Energy LLC (“Chama”), an entity in which we retain an interest of approximately 9.4%. Such interest is valued at

approximately $3.75 million. John Goff, the Chairman of our Board of Directors, holds an interest of approximately 17.5% in Chama, and the remaining interest is held by other investors. Pursuant to the Limited Liability Company Agreement of Chama, we may be required to fund certain workover costs and we will be required to fund plugging and abandonment costs related to producing assets held by Chama (collectively, “Crescent Contributions”). We will receive 90.0% of cash flows from the producing assets, which amount is increased for any Crescent Contributions.

Dividend

On March 9, 2022, the Board of Directors approved a quarterly cash dividend of $0.12 per share, or $0.48 per share on an annualized basis, to be paid to our shareholders with respect to the fourth quarter of 2021. The quarterly dividend is payable on March 31, 2022 to shareholders of record as of the close of business on March 18, 2022.

The payment of quarterly cash dividends is subject to management’s evaluation of our financial condition, results of operations and cash flows in connection with such payments and approval by our Board of Directors. In light of current economic conditions, management will evaluate any future increases in cash dividends on a quarterly basis.

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Selected Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2021

Quarterly Financial Information Disclosure [Abstract]

Selected Quarterly Financial Data (Unaudited)

Selected Quarterly Financial Data (Unaudited)

Quarterly financial data was as follows for the periods indicated:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(in thousands, except per share amounts)
2021
Revenues	$	317,860	$	330,130	$	365,726	$	463,261
Income (loss) from operations	88,045		100,483		133,604		161,607
Net income (loss)	(166,268)		(272,861)		(162,043)		168,945
Less: net (income) loss attributable to Predecessor	155,629		269,608		160,567		(246,636)
Less: net (income) loss attributable to noncontrolling interests	10,639		3,253		1,476		(446)
Less: net (income) loss attributable to redeemable noncontrolling interests	—		—		—		58,761
Net income (loss) attributable to Crescent Energy	—		—		—		(19,376)
Net income (loss) per share
Class A common stock - basic and diluted	$	—	$	—	$	—	$	(0.46)
Class B common stock - basic and diluted	$	—	$	—	$	—	$	—
2020
Revenues	$	207,848	$	103,509	$	190,612	$	252,252
Income (loss) from operations	3,353		(293,463)		(26,669)		(56,849)
Net income (loss)	466,790		(412,227)		(101,005)		(169,682)
Less: net (income) loss attributable to Predecessor	(320,722)		236,166		69,990		133,215
Less: net (income) loss attributable to noncontrolling interests	(146,068)		176,061		31,015		36,467
Net income (loss) attributable to Crescent Energy	—		—		—		—
Net income (loss) per share
Class A common stock - basic and diluted	$	—	$	—	$	—	$	—
Class B common stock - basic and diluted	$	—	$	—	$	—	$	—

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Supplemental Oil and Natural Gas Disclosures (Unaudited)

12 Months Ended

Dec. 31, 2021

Extractive Industries [Abstract]

Supplemental Oil and Natural Gas Disclosures (Unaudited)

Supplemental Oil and Natural Gas Disclosures (Unaudited)

Geographic Area of Operation

All of the oil and natural gas properties in which we have working interests and mineral and royalty interests are located within the continental U.S., with the majority concentrated in Texas, Rockies and Oklahoma. Therefore, the following disclosures about our costs incurred and proved reserves are presented on a combined and consolidated basis. In addition, we have a 37% ownership in our equity method investment, Exaro, that operates in the Jonah Field in Wyoming.

Oil and Natural Gas Reserve Information

The following table presents our net proved reserves for the years ended December 31, 2021, 2020 and 2019 and the changes in net proved oil, natural gas and NGL reserves during such years. In addition, the net proved reserves for our equity method investment, Exaro, are presented based on our 37% ownership percentage. Because Exaro was acquired in 2021 as part of the Merger Transactions, prior periods are not presented.

Developed and Undeveloped	Oil (MBbls)	Natural Gas (MMcf)	Natural Gas Liquids (MBbls)	Total (MBoe)
Consolidated operations
Net proved reserves at December 31, 2018	202,805	1,189,962	75,780	476,913
Revisions of previous estimates	10,477	20,552	(11,321)	2,581
Extensions, discoveries, and other additions (1)	12,003	24,472	1,855	17,936
Sales of reserves in place	—	—	—	—
Purchases of reserves in place	—	—	—	—
Production	(13,752)	(73,747)	(5,188)	(31,231)
Net proved reserves at December 31, 2019	211,533	1,161,239	61,126	466,199
Revisions of previous estimates (2)	(57,708)	(478,153)	(20,279)	(157,680)
Extensions, discoveries, and other additions	4,088	21,479	603	8,271
Sales of reserves in place	—	—	—	—
Purchases of reserves in place (3)	22,409	196,840	18,952	74,168
Production	(13,132)	(78,541)	(5,078)	(31,300)
Net proved reserves at December 31, 2020	167,190	822,864	55,324	359,658
Revisions of previous estimates (4)	9,147	316,572	16,480	78,389
Extensions, discoveries, and other additions	7,007	17,247	2,093	11,975
Sales of reserves in place	(6,333)	(48,977)	(3,265)	(17,762)
Purchases of reserves in place (5)	46,386	451,702	11,960	133,630
Production	(13,237)	(89,455)	(6,099)	(34,245)
Net proved reserves at December 31, 2021	210,160	1,469,953	76,493	531,645
Equity affiliate
Net proved reserves at December 31, 2020	—	—	—	—
Revisions of previous estimates	—	—	—	—
Extensions, discoveries, and other additions	—	—	—	—
Sales of reserves in place	—	—	—	—
Purchases of reserves in place	205	20,880	—	3,685
Production	(1)	(115)	—	(20)
Net proved reserves at December 31, 2021	204	20,765	—	3,665
Total company
Net proved reserves at December 31, 2019	211,533	1,161,239	61,126	466,199
Net proved reserves at December 31, 2020	167,190	822,864	55,324	359,658
Net proved reserves at December 31, 2021	210,364	1,490,718	76,493	535,310

(1)During the year ended December 31, 2019, we added 17.9 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Eagle Ford and Permian. Approximately 77% of the reserve additions for the year ended December 31, 2019 were crude oil and NGLs.

(2)Revisions of previous estimates include 92.0 MMBoe downward revisions of our PUD reserves. The revisions are primarily due to declining commodity prices which decreased the quantity of reserves recoverable from our proved locations, and also resulted in the removal of certain PUD locations that were uneconomic at year end prices.

(3)Purchases in place of 74.2 MMBoe were primarily related to the Permian and DJ Basins.

(4)Revisions of previous estimates include 92.7 MMBoe upward revision due to pricing and cost changes, offset by 21.1 MMBoe downward revisions of our PUD reserves due to the removal of certain locations that are no longer part of our five-year consolidated development plan following the Merger Transactions.

(5)Purchases in place included 125.6 MMBoe from our Merger Transactions, 5.6 MMBoe from our Central Basin Platform Acquisition and 2.5 MMBoe from our DJ Basin Acquisition.

The following table sets forth our net proved oil, natural gas and NGL reserves for both our consolidated operations and our investment in Exaro as of the years ended December 31, 2021 and 2020, 2019 and 2018:

Proved Developed Reserves	Oil (MBbls)	Natural Gas (MMcf)	Natural Gas Liquids (MBbls)	Total (MBoe)
Consolidated operations
December 31, 2021	158,091	1,404,570	66,402	458,588
December 31, 2020	92,024	748,496	44,307	261,079
December 31, 2019	103,728	870,491	48,997	297,808
Equity affiliate
December 31, 2021	204	20,765	—	3,665
December 31, 2020	—	—	—	—
December 31, 2019	—	—	—	—

Proved Undeveloped Reserves	Oil (MBbls)	Natural Gas (MMcf)	Natural Gas Liquids (MBbls)	Total (MBoe)
Consolidated operations
December 31, 2021	52,069	65,383	10,091	73,057
December 31, 2020	75,166	74,368	11,017	98,579
December 31, 2019	107,805	290,748	12,129	168,391
Equity affiliate
December 31, 2021	—	—	—	—
December 31, 2020	—	—	—	—
December 31, 2019	—	—	—	—

Capitalized Costs Relating to Oil and Gas Producing Activities

The following table summarizes the capitalized costs relating to our oil and natural gas producing activities for both our consolidated operations and our investment in Exaro as of December 31, 2021 and 2020:

	As of December 31,
	2021		2020
	(in thousands)
Consolidated operations
Proved oil and natural gas properties (successful efforts method)	$	6,043,602	$	4,910,059
Unproved oil and natural gas properties	308,721		288,459
Oil and natural gas properties, at cost	6,352,323		5,198,518
Less accumulated depreciation, depletion and amortization	(1,881,933)		(1,666,620)
Net capitalized costs	$	4,470,390	$	3,531,898
Equity affiliate
Proved oil and natural gas properties (successful efforts method)	$	9,043	$	—
Unproved oil and natural gas properties	—		—
Oil and natural gas properties, at cost	9,043		—
Less accumulated depreciation, depletion and amortization	(67)		—
Net capitalized costs	$	8,976	$	—

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

Acquisition costs include costs incurred to purchase, lease or otherwise acquire property. Exploration costs include additions to exploratory wells, including those in progress, and exploration expenses. Development costs include additions to production facilities and equipment and additions to development wells, including those in progress.

The following table summarizes costs incurred related to our oil and natural gas activities for both our consolidated operations and our investment in Exaro for the years ended December 31, 2021, 2020 and 2019:

	Year Ended December 31,
	2021		2020		2019
	(in thousands)
Consolidated operations
Acquisition costs:
Proved	$	1,098,696	$	355,010	$	795
Unproved	41,355		680		7,264
Exploration costs	1,180		—		710
Development	194,828		83,013		318,157
Total costs incurred	$	1,336,059	$	438,703	$	326,926
Equity affiliate
Acquisition costs:
Proved	$	—	$	—	$	—
Unproved	—		—		—
Exploration costs	—		—		—
Development	—		—		—
Total costs incurred	$	—	$	—	$	—

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following information has been developed utilizing procedures prescribed by ASC 932 – Extractive Industries – Oil and Gas and based on crude oil, NGL and natural gas reserves and production volumes estimated by our engineering staff. The estimates were based on a 12-month average for first-day-of-the month commodity prices. The following information may be useful for certain comparative purposes, but should not be solely relied upon in evaluating our performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of our current value.

The future cash flows presented below are based on sales prices and cost rates in existence as of the date of the projections. It is expected that material revisions to some estimates of crude oil, NGL and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.

Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable and possible reserves as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

Future net cash flows were calculated at December 31, 2021, 2020 and 2019 by applying prices, which were the simple average of the first-of-the-month commodity prices, adjusted for location and quality differentials, with consideration of known contractual price changes. The following table provides the average benchmark prices per unit, before location and quality differential adjustments, used to calculate the related reserve category:

	Year Ended December 31,
	2021		2020		2019
Average benchmark price per unit:
Crude oil (Bbl)	$	66.56	$	39.56	$	55.69
Natural gas (MMBtu)	$	3.60	$	1.99	$	2.62

The following table sets forth the standardized measure of discounted future net cash flows for both our consolidated operations and our investment in Exaro from projected production of oil and natural gas reserves, for the years ended December 31, 2021, 2020 and 2019:

	Year Ended December 31,
	2021		2020		2019
	(in thousands)
Consolidated operations
Future cash inflows	$	21,063,117	$	8,232,932	$	15,745,942
Future production costs	(10,194,648)		(4,280,563)		(6,766,410)
Future development costs (1)	(1,477,562)		(1,353,957)		(2,323,420)
Future income taxes	(352,136)		(30,155)		(63,136)
Future net cash flows	9,038,771		2,568,257		6,592,976
Annual discount of 10% for estimated timing	(4,080,471)		(1,240,397)		(3,482,128)
Standardized measure of discounted future net cash flows	$	4,958,300	$	1,327,860	$	3,110,848
Equity affiliate (2)
Future cash inflows	$	99,290	$	—	$	—
Future production costs	(55,371)		—		—
Future development costs	(2,309)		—		—
Future income taxes	(1,730)		—		—
Future net cash flows	39,880		—		—
Annual discount of 10% for estimated timing	(16,702)		—		—
Standardized measure of discounted future net cash flows	$	23,178	$	—	$	—

(1)    Future development costs include future abandonment and salvage costs.

(2)    The average benchmark prices used for the equity affiliate were $66.55 per barrel for crude oil and $3.64 per MMBtu for natural gas.

Changes in standardized measure of discounted future net cash flows

The following table sets forth the changes in the standardized measure of discounted future net cash flows for both our consolidated operations and our investment in Exaro for the years ended December 31, 2021, 2020 and 2019:

	Year Ended December 31,
	2021		2020		2019
	(in thousands)
Consolidated operations
Balance at beginning of period	$	1,327,860	$	3,110,848	$	4,207,347
Net change in prices and production costs	3,330,299		(1,184,939)		(821,874)
Net change in future development costs	117,333		160,465		(59,359)
Sales and transfers of oil and natural gas produced, net of production expenses	(872,521)		(290,053)		(568,665)
Extensions, discoveries, additions and improved recovery, net of related costs	162,657		31,688		182,697
Purchases of reserves in place	1,236,388		176,480		—
Sales of reserves in place	(84,095)		—		—
Revisions of previous quantity estimates	(295,234)		(887,395)		(226,561)
Previously estimated development costs incurred	95,879		32,873		15,676
Net change in taxes	(184,419)		19,350		(19)
Accretion of discount	124,153		283,954		424,278
Changes in timing and other	—		(125,411)		(42,672)
Balance at end of period	$	4,958,300	$	1,327,860	$	3,110,848
Equity affiliate
Balance at beginning of period	$	—	$	—	$	—
Net change in prices and production costs	—		—		—
Net change in future development costs	—		—		—
Sales and transfers of oil and natural gas produced, net of production expenses	(1,246)		—		—
Extensions, discoveries, additions and improved recovery, net of related costs	—		—		—
Purchases of reserves in place	26,154		—		—
Sales of reserves in place	—		—		—
Revisions of previous quantity estimates	—		—		—
Previously estimated development costs incurred	—		—		—
Net change in taxes	(1,730)		—		—
Accretion of discount	—		—		—
Changes in timing and other	—		—		—
Balance at end of period	$	23,178	$	—	$	—

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SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT

12 Months Ended

Dec. 31, 2021

Condensed Financial Information Disclosure [Abstract]

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CRESCENT ENERGY COMPANY

PARENT COMPANY BALANCE SHEETS

	December 31, 2021		December 31, 2020
	(in thousands, except share and unit data)
ASSETS
Investment in subsidiary	$	3,103,176	$	2,893,160
TOTAL ASSETS	$	3,103,176	$	2,893,160
LIABILITIES, REDEEMABLE NONCONTROLLING INTERESTS AND EQUITY
Current liabilities:
Accounts payable – affiliates	$	914	$	—
Accrued liabilities	68		—
Total current liabilities	982		—
Deferred tax liability	82,537		—
Total liabilities	83,519		—
Contingencies (Note 3)
Redeemable noncontrolling interests	2,325,013		—
Equity:
Members’ equity – Class A units, no units and 1,220,421 units outstanding as of December 31, 2021 and 2020, respectively	—		2,716,892
Class A common stock, $0.0001 par value; 1,000,000,000 shares authorized and 43,105,376 shares issued and 41,954,385 shares outstanding as of December 31, 2021; no shares issued and outstanding as of December 31, 2020	4		—
Class B common stock, $0.0001 par value; 500,000,000 shares authorized and 127,536,463 shares issued and outstanding as of December 31, 2021; no shares issued and outstanding as of December 31, 2020	13		—
Preferred stock, $0.0001 par value; 500,000,000 shares authorized and 1,000 Series I preferred shares issued and outstanding as of December 31, 2021; no shares issued and outstanding as of December 31, 2020	—		—
Treasury stock, at cost; 1,150,991 shares of Class A common stock as of December 31, 2021 and no shares of Class A Common Stock as of December 31, 2020	(18,448)		—
Additional paid-in capital	720,016		—
Accumulated deficit	(19,376)		—
Noncontrolling interests	12,435		176,268
Total equity	694,644		2,893,160
TOTAL LIABILITIES, REDEEMABLE NONCONTROLLING INTERESTS AND EQUITY	$	3,103,176	$	2,893,160

SCHEDULE I - CONTINUED

CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CRESCENT ENERGY COMPANY

PARENT COMPANY STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2021		2020		2019
	(in thousands, except per share amounts)
Revenues	$	—	$	—	$	—
Expenses:
General and administrative expense	914		—		—
Total expenses	914		—		—
Income (loss) before taxes and equity in income (losses) of subsidiary	(914)		—		—
Income tax benefit (expense)	867		—		—
Income (loss) before equity in income (losses) of subsidiary	(47)		—		—
Equity in income (losses) of subsidiary, net of tax	(432,180)		(216,124)		46,709
Net income (loss)	(432,227)		(216,124)		46,709
Less: net (income) loss attributable to Predecessor	339,168		118,649		(45,839)
Less: net (income) loss attributable to noncontrolling interests	14,922		97,475		(870)
Less: net loss attributable to redeemable noncontrolling interests	58,761		—		—
Net loss attributable to Crescent Energy	$	(19,376)	$	—	$	—
Net Loss per Share:
Class A common stock - basic and diluted	$	(0.46)
Class B common stock - basic and diluted	$	—
Weighted Average Shares Outstanding:
Class A common stock - basic and diluted	41,954
Class B common stock - basic and diluted	127,536

The accompanying notes to financial statements are an integral part of these condensed financial statements.

SCHEDULE I - CONTINUED

CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CRESCENT ENERGY COMPANY

PARENT COMPANY STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2021		2020		2019
	(in thousands)
Cash flows from operating activities:
Net income (loss)	(432,227)		(216,124)		46,709
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Equity in (income) losses of subsidiary	432,180		216,124		(46,709)
Deferred income taxes (benefit)	(935)		—		—
Changes in operating assets and liabilities:
Accounts payable – affiliates	914		—		—
Accrued liabilities	68		—		—
Net cash provided by operating activities	—		—		—
Net cash provided by investing activities	—		—		—
Net cash provided by financing activities	—		—		—
Net change in cash, cash equivalents and restricted cash	—		—		—
Cash, cash equivalents and restricted cash, beginning of period	—		—		—
Cash, cash equivalents, and restricted cash, end of period	$	—	$	—	$	—

The accompanying notes to financial statements are an integral part of these condensed financial statements.

NOTE 1 – Basis of Presentation

On December 7, 2021, we completed the Merger Transactions, pursuant to which Contango Oil & Gas Company ("Contango") combined with Independence Energy LLC ("Independence") under a new publicly traded holding company named "Crescent Energy Company." Our Class A Common Stock is listed on The New York Stock Exchange under the symbol “CRGY.” The new combined company is structured as an “Up-C,” with all of our assets and operations and those of Contango held by Crescent Energy Company ("Crescent"), which is the sole managing member of Crescent Energy OpCo LLC ("OpCo"). We are a holding company that conducts substantially all of our business through our consolidated subsidiary, OpCo. Our sole material asset consists of units of OpCo ("OpCo Units"). As the sole managing member of OpCo, we are responsible for all operational, management and administrative decisions related to OpCo’s business. Because the unit holders of OpCo lack the characteristics of a controlling financial interest, OpCo was determined to be a variable interest entity. Crescent is considered the primary beneficiary of OpCo as it has both the power to direct OpCo and the right to receive benefits from OpCo. As a result, we consolidate the financial results of OpCo and its subsidiaries, including Crescent Energy Finance LLC. Former Contango shareholders now own shares of Crescent Class A Common Stock, which have both voting and economic rights with respect to Crescent. The former owners of our predecessor, Independence Energy LLC, now own economic, non-voting OpCo Units and corresponding shares of Crescent Class B Common Stock, which have voting (but no economic) rights with respect to Crescent. OpCo is owned approximately 25% by Crescent and approximately 75% by holders of our redeemable noncontrolling interests representing former owners of Independence.

The Isla Merger, whereby Independence merged with and into OpCo on December 7, 2021 in connection with the Merger Transactions, was accounted for as a reorganization of entities under common control. As required by GAAP, the contribution of Independence was accounted for as a reorganization of entities under common control, in a manner similar to a pooling of interests, with all assets and liabilities transferred to us at their carrying amounts. Because the Isla Merger resulted in a change in the reporting entity, and in order to furnish comparative financial information prior to the Merger Transactions, our financial statements have been retrospectively recast to reflect the historical accounts of Independence, our accounting predecessor (the "Predecessor").

These condensed parent company financial statements reflect the activity of Crescent as the parent company to OpCo and have been prepared in accordance with Rules 5-04 and 12-04 of Regulation S-X, as the restricted net assets of OpCo and its consolidated subsidiaries exceed 25% of the consolidated net assets of Crescent. This information should be read in conjunction with the combined and consolidated financial statements of Crescent included in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report.

NOTE 2 – Income Taxes

For details regarding income taxes, see NOTE 10 - Income Taxes, to the combined and consolidated financial statements of Crescent included in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report.

NOTE 3 – ContingenciesFor details regarding contingencies related to litigation, see NOTE 12 - Commitments and Contingencies, to the combined and consolidated financial statements of Crescent included in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

Basis of Presentation

Basis of PresentationOur combined and consolidated financial statements (the “financial statements”) include the accounts of the Company and its subsidiaries after the elimination of intercompany transactions and balances and are presented in accordance with U.S. general accepted accounting principles (“GAAP”). We have no elements of other comprehensive income for the periods presented.

Basis of Consolidation

Basis of PresentationOur combined and consolidated financial statements (the “financial statements”) include the accounts of the Company and its subsidiaries after the elimination of intercompany transactions and balances and are presented in accordance with U.S. general accepted accounting principles (“GAAP”). We have no elements of other comprehensive income for the periods presented.

Use of Estimates

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make use of estimates and assumptions that affect the reported amount of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We use historical experience and various other assumptions and information that are believed to be reasonable under the circumstances in developing our estimates and judgments. Estimates and assumptions about future events and their effects cannot be predicted with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. While we believe that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results may differ from these estimates. Our significant estimates include the fair value of acquired assets and liabilities, oil and natural gas reserves, impairment of proved and unproved oil and natural gas properties and valuation of derivative instruments.

Cash and Cash Equivalents

Cash and Cash Equivalents

Cash and cash equivalents consist of cash deposited in commercial bank accounts and highly liquid investments purchased with an original maturity of three months or less at the date of purchase. Cash and cash equivalents are maintained with major financial institutions in the U.S. Deposits with these financial institutions may exceed the amount of insurance provided on such deposits; however, the financial stability of the financial institutions is regularly monitored, and we believe that we do not have exposure to any significant default risk.

Restricted Cash

Restricted Cash

Restricted cash consists of funds earmarked for a special purpose and therefore not available for immediate and general use. The majority of our restricted cash is comprised of cash that is contractually required to be restricted to pay for the future

abandonment of certain wells in California. Restricted cash is included in other current assets and other assets on our balance sheets.

Accounts Receivable

Accounts Receivable

We routinely assess the recoverability of our accounts receivable, which primarily comprise amounts due from (i) purchasers of our oil, natural gas and NGL production and (ii) joint interest owners on properties that we operate. We monitor our exposure to credit risk primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s creditworthiness. Generally, our oil and natural gas receivables are collected within 45 to 60 days of production. Our joint interest billings are collected within the month after they are billed, and we have the ability to withhold future revenue distributions to recover any nonpayment of our joint interest billings.

As a result of adopting ASU 2016-13, Measurement of Credit Losses on Financial Instruments, we establish allowances for credit losses equal to the estimable portions of accounts receivable for which failure to collect is expected to occur primarily based on a historical loss rate analysis. We estimate uncollectible amounts based on the length of time that the accounts receivables have been outstanding, historical collection experience and current and future economic and market conditions. We consider forecasts of future economic conditions in the estimate of our expected credit losses, in particular whether there is an increase in the probability that our counterparties will be unable to pay their obligations when due, and adjust our allowance for expected credit losses, when necessary.

Restricted Investment Securities

Restricted Investment Securities

We hold U.S. Treasury securities, which are contractually required to be set aside to pay for the future abandonment of certain wells in California. Due to this restriction, we report these investment securities as noncurrent and include them within other assets on our consolidated balance sheets.

We classify our investment in these debt securities at the acquisition date and re-evaluate the classification at each balance sheet date. We classify debt securities purchased with the positive intent and ability to hold until their maturity date as held-to-maturity investments (“HTM”) and carry these investments at amortized cost. Premiums and discounts on purchases are amortized over the remaining time to maturity of the security and the amortization is recorded as an adjustment to interest income.

Oil and Natural Gas Properties

Oil and Natural Gas PropertiesOil and natural gas producing activities are accounted for under the successful efforts method of accounting. Under this method, exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. Costs that are associated with the drilling of successful exploration wells are capitalized if proved reserves are found. Capitalized costs attributed to the properties are charged as an operating expense through depreciation, depletion and amortization (“DD&A”). Dry hole costs associated with developing proved fields are capitalized. Costs associated with the drilling of exploratory wells that do not find proved reserves, geological and geophysical costs and costs of certain nonproducing leasehold costs are expensed once evaluated and determined to be a dry hole.

Delay and surface rentals are charged to expense as incurred. The costs to acquire mineral interests in oil and natural gas properties and lease acquisition costs are capitalized when incurred. If proved reserves are found on an undeveloped property, leasehold costs are transferred to proved properties.

The capitalized costs of producing oil and natural gas properties are depleted on a field-by-field basis using the units-of-production method based on the ratio of current production to estimated total net proved oil, natural gas and NGL reserves. Proved developed reserves are used in computing depletion rates for drilling and development costs and total proved reserves are used for depletion rates of leasehold costs.

Upon the sale of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated DD&A are removed from the property accounts and any gain or loss is recognized.

Estimated dismantlement and abandonment costs for oil and natural gas properties are capitalized at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. See discussion of Asset Retirement Obligations below for additional discussion.

Other Property, Plant, and Equipment

Other Property, Plant and Equipment

We have other property, plant, and equipment that consists principally of gathering and processing facilities, vehicles, computer hardware and software, office furniture and equipment, buildings and leasehold improvements. Other property, plant, and equipment is recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the respective assets which range from three to thirty years. Leasehold improvements are amortized over the shorter of their economic lives or the lease term. The cost of maintenance and repairs are expensed in the period incurred. Expenditures that extend the life or improve existing property and equipment are capitalized.

Impairment

Impairment

Proved and unproved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. When a triggering event is identified, we compare the carrying amount of our oil and natural gas properties to the estimated undiscounted cash flows our oil and natural gas properties will generate to determine if the carrying amount is recoverable. We perform this analysis on a field-by-field basis. If the carrying amount exceeds the estimated undiscounted cash flows, we will write-down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, and discount rates commensurate with the risk associated with realizing the projected cash flows.

Drilling Advances

Drilling AdvancesWe pay advances for certain D&C costs on our non-operated properties, as required by our joint operating agreements.

Equity Method Investments

Equity Method Investments

If an entity is organized as a limited partnership or limited liability company and maintains separate ownership accounts, we generally account for our investment using the equity method if our ownership interest is between 3% and 50%, unless our interest is so minor that we have virtually no influence over the investee’s operating and financial policies. For all other types of investments, we generally apply the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the investee’s operating and financial policies. We eliminate our proportionate share of

profits and losses from transactions with equity affiliates to the extent such amounts remain on our consolidated balance sheets (or those of our equity affiliates).

Under the equity method, our proportionate share of each investees' net income increases the balance of our investment, while a net loss or receipt of dividends decreases the balance of our investment. Our proportionate share of net income from our equity affiliates are reported as a single line item within income (loss) from equity method investments in our combined and consolidated statements of operations.

Other Long-Term Assets

Other Long-Term Assets

We acquired certain long-term joint interest receivables that are settled through the underlying oil and natural gas interests of certain joint interest owners. The outstanding balance of these long-term receivables was $1.2 million and $1.3 million as of December 31, 2021 and 2020. We recognized write-offs of acquired long-term joint interest receivables totaling $3.8 million within operating expense in the combined and consolidated statement of operations for the year ended December 31, 2019.

Redeemable Noncontrolling Interests

Redeemable Noncontrolling InterestsIn connection with the Merger Transactions, 127.5 million OpCo Units were issued to the former owners of Independence. The former owners of Independence also own all outstanding shares of our Class B Common Stock. Pursuant to the OpCo LLC Agreement, holders of OpCo Units, other than the Company, may redeem all or a portion of their OpCo Units, together with a corresponding number of shares of Class B Common Stock, for either (a) shares of Class A Common Stock or (b) an approximately equivalent amount of cash as determined pursuant to the terms of the OpCo LLC Agreement, at the election of the Company. In connection with the exercise of such redemption, a corresponding number of shares of Class B Common Stock will be cancelled. The redemption election is not considered to be within the control of the Company because the holders of Class B Common Stock and their affiliates control the Company through direct representation on the Board of Directors. As a result, we present the noncontrolling interests in OpCo as redeemable noncontrolling interests outside of permanent equity. Redeemable noncontrolling interest is recorded at the greater of the carrying value or redemption amount with a corresponding adjustment to additional paid-in capital.

Stockholders' Equity

Stockholders' Equity

Class A and Class B Common Stock

As of December 31, 2021, we had 41,954,385 and 127,536,463 shares of Class A Common Stock and Class B Common Stock outstanding, respectively. Our Class A Common Stock is publicly traded, while our Class B Common Stock is 100% owned by the former owners of Independence.

As a result of the Merger Transactions, (a) former owners of Independence own 100% of the total outstanding Class B Common Stock and approximately 75% of the total outstanding Class A Common Stock and Class B Common Stock taken

together, and (b) former stockholders of Contango own Class A Common Stock that represents approximately 25% of the outstanding Class A Common Stock and Class B Common Stock, taken together.

Treasury stock

Treasury stock shares represent shares we withheld associated with the payroll tax withholding obligations due from employees upon the vesting of stock awards. We include the shares withheld as treasury stock on our consolidated balance sheets and separately pay the payroll tax obligation. These retained shares are not part of a publicly announced program to repurchase shares of our Class A Common Stock and are accounted for at cost. We do not have a publicly announced program to repurchase shares of our Class A Common Stock.

Predecessor members' equity

Prior to the Merger Transactions, Independence had two classes of equity in the form of Class A Units and Class B Units. Both Class A Units and Class B Units were considered common units, and distributions were made pro rata in accordance with each unit’s respective ownership percentage. At the time of the Merger Transactions, only Class A Units were issued and outstanding. As a result of the Merger Transactions, all Class A Units were exchanged for our Class B Common Stock and no Class A Units or Class B Units remain issued or outstanding.

Noncontrolling interest

We record noncontrolling interest associated with third party ownership interests in our subsidiaries. Income or loss associated with these interests is classified as net income (loss) attributable to noncontrolling interest on our combined and consolidated statements of operations.

In April 2021, certain minority investors exchanged 100% of their interests in our Barnett Basin natural gas assets for 9,508 of our Predecessor's Class A Units ("April 2021 Exchange"). Since we already consolidate the results of these assets, this transaction was accounted for as an equity transaction and reflected as a reclassification from noncontrolling interests to members’ equity with no gain or loss recognized on exchange.

In December 2020, certain other minority owners of our consolidated subsidiaries elected to exchange 100% of their interests in those individual consolidated subsidiaries for 220,421 of our Predecessor's Class A Units (“December 2020 Exchange”). Since we already consolidate the results of these subsidiaries, this transaction was accounted for as a reclassification of $657.4 million from noncontrolling interest to members’ equity with no gain or loss recognized on the exchange.

In August 2020, in connection with the Independence Reorganization, certain interests in our consolidated subsidiaries owned by a third-party investor were not contributed to the Predecessor. These interests were reclassified from members’ equity to noncontrolling interest as of the date of the Independence Reorganization and all income and loss attributable to these interests is recorded as net income (loss) attributable to noncontrolling interests from the date of the Independence Reorganization. In May 2021, these noncontrolling equity interests were redeemed in exchange for the third-party investor’s proportionate share of the underlying oil and natural gas interests held by its consolidated subsidiaries ("Noncontrolling Interest Carve-out"). Additionally, the third-party investor contributed cash of approximately $35.5 million to repay its proportionate share of the underlying debt outstanding under our Prior Credit Agreements and other liabilities. The percentage ownership of these certain consolidated subsidiaries owned by the third-party investor ranges from 2.21% to 7.38%.

Debt Issuance Costs

Debt Issuance Costs

We capitalize costs incurred in connection with obtaining financing associated with our revolving credit facilities and amortize such costs as additional interest expense over the life of the underlying indebtedness. These costs include fees paid to financial institutions and legal fees and are included in other assets in our consolidated balance sheets.

Revenue Recognition

Revenue Recognition

Oil, Gas and NGL Revenues

We hold operated and non-operated working interests and mineral and royalty interests in producing assets that function as follows:

Operated working interests: We are responsible for the day-to-day management and operation of the field as well as negotiations required for post-production transportation, gathering, processing and marketing; we remit proceeds from sales of resulting hydrocarbons to third parties back to non-operators less costs as agreed in the applicable joint operating agreement.

Non-operated working interests: An operator of these assets is responsible for the day-to-day management and operation of the field as well as negotiations required for post-production transportation, gathering, processing, and marketing; the operator then remits proceeds from sales of resulting hydrocarbons to third parties back to non-operators less costs as agreed in the applicable joint operating agreement.

Mineral and royalty interests: Ownership of a percentage of production or production revenues produced from leased acreage. The owner of this share of production does not bear any of the cost of exploration, drilling, producing, operating or any other expense associated with drilling and producing an oil and gas well. Mineral and royalty interests may be burdened by some or all of the post-production costs related to gathering, processing and marketing.

We sell oil production at the lease and collect an agreed-upon index price, net of pricing differentials.

Under our natural gas contracts, we deliver natural gas to a midstream processor at a contractually specified delivery point. The midstream processor gathers and processes the natural gas and then markets and remits proceeds to us for the resulting sale of the residue gas and NGLs.

Our non-operated production is marketed by operators, after which the operators remit net proceeds from the sale of our share of production to us. Proceeds reflect post-production expenses such as gathering, processing and other expenses incurred in marketing of that production.

Performance Obligations

Under product sales contracts, each unit of product generally represents a separate performance obligation. We record revenue for our product sales contracts at the point-in-time control of a commodity is transferred to the customer. However, settlement statements from non-operated working interests may not be received for 30 to 60 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the customer and the net commodity price that will be received for the sale of these commodity products.

At the end of the reporting period, we did not have any unsatisfied performance obligations. Our contracts with customers typically include variable consideration based on monthly pricing tied to local indices and volumes delivered in the current month. The nature of our contracts with customers does not require us to constrain variable consideration for accounting purposes.

Revenue is recognized to the extent it is determined that it is probable that a significant reversal will not occur. We record the differences between our revenue estimates and the actual amounts received in the month that payment is received from the operator.

Incentive Compensation Arrangements

Incentive Compensation Arrangements

Incentive compensation includes share-based payment awards and incentive cash bonus plans that are issued to employees and non-employees in exchange for services provided to us. Equity-classified share-based payment awards are recognized at fair value on the grant date, and amortized over the life of the award. Liability-classified share-based payment awards are remeasured at fair value until settlement. For awards with service-based vesting conditions only, we recognize compensation cost using straight-line attribution. For awards that contain market or performance conditions we use accelerated attribution. Our policy is to recognize forfeitures as they occur. Certain of our consolidated subsidiaries have also issued incentive awards that are accounted for similar to cash bonus plans, whereby compensation cost is measured based on the present value of probable expected benefits to be paid and recognized over the period services are provided. Incentive awards similar to cash bonus plans may also have market-based or time-based vesting conditions and are included in accounts payable and accrued liabilities on our consolidated balance sheets.

Incentive compensation cost is presented as general and administrative expense on our combined and consolidated statements of operations.

Defined Contribution Plan

Defined Contribution Plan

In conjunction with the Merger Transactions we will begin offering our employees a defined contribution 401(k) Plan (the “401(k) Plan”) for the benefit of substantially all of our employees. The 401(k) Plan allows eligible employees to make tax-deferred contributions, not to exceed annual limits established by the Internal Revenue Service. The Company matches contributions of 100% of employee contributions, up to 5% of compensation with immediate vesting for existing employees. The Company did not make any contributions to the 401(k) Plan for the years ended December 31, 2021, 2020 and 2019 since the plan's inception began in January 2022 in conjunction with the start of the benefit plan year; however, the Company expects to make contributions to the plan in 2022.

Business Combinations

Business Combinations

We recognize the identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values. Fair value is the price that would be received to sell an asset or would be paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value measurement is based on the assumptions of market participants and not those of the reporting entity. Therefore, entity-specific intentions do not impact the measurement of fair value. These fair values are accounted for at the date of acquisition and included in our consolidated balance sheets as of December 31, 2021 and 2020. The results of operations of an acquired business are included in our combined and consolidated statements of operations from the date of the acquisition.

Credit and Concentration Risk

Credit and Concentration Risk

We sell a significant amount of our oil, natural gas and NGL production to a limited number of purchasers. This concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our purchasers may be similarly affected by changes in economic, industry or other conditions. If these counterparties were to fail to pay amounts due to us, our financial position and results of operations could be materially affected.

Risks and Uncertainties

Risks and Uncertainties

Our future financial condition, results of operations and cash flows are dependent on the demand and prices received for oil, natural gas and NGL production. These prices historically have been volatile, and we expect such volatility to continue in the future, as they are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for oil, natural gas and NGL, market uncertainty and a variety of additional factors beyond our control. These factors include weather conditions, government regulations and taxes, the price and availability of alternative fuels and overall economic conditions. A decline in oil, natural gas or NGL prices may adversely affect our financial position, cash flows and results of operations. Lower oil, natural gas or NGL prices also may reduce the amount of oil, natural gas and NGL that can be produced economically.

Our revenues are derived principally from uncollateralized sales to numerous companies in the oil and natural gas industry; therefore, our customers may be similarly affected by changes in economic and other conditions within the industry.

Risk Management

Risk Management

We periodically enter into derivative contracts to manage our exposure to commodity price and interest rate changes. These derivative contracts may take the form of forward contracts, futures contracts, swaps, swaptions, collars or other options. We do not use derivative contracts for speculative purposes and have not designated any derivative instruments as hedging instruments for accounting purposes. As such, unrealized gains and losses from changes in the valuation of our unsettled derivative contracts, as well as realized gains and losses on the settlement of derivative contracts, are reported in gain (loss) on derivatives in our combined and consolidated statements of operations.

Such derivative instruments are initially recorded at fair value on the date on which a derivative contract is entered into and are subsequently remeasured at fair value at each reporting date. Derivatives are carried as assets when the fair value is positive or as liabilities when the fair value is negative and are classified as current and long term based on the delivery periods of the financial instruments. If the right of offset exists and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on our consolidated balance sheets.

Contingencies

Contingencies

Certain conditions may exist as of the date our financial statements are issued, which may result in a loss to us but which will only be resolved when one or more future events occur or fail to occur. In the preparation of our financial statements, management assesses the need for accounting recognition or disclosure of these contingencies, if any, and such assessment inherently involves an exercise in judgment. In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in such proceedings, our management and legal counsel evaluate the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.

When applicable, we will accrue an undiscounted liability for contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum amount within the range is accrued. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when it is believed to be only reasonably possible or remote.

For contingencies where an unfavorable outcome is reasonably possible and the impact would be material, we disclose the nature of the contingency and, if feasible, an estimate of the possible loss or range of loss. Loss contingencies considered remote are generally not disclosed.

Income Taxes

Income Taxes

Crescent is a holding company of which our sole material assets are OpCo Units. OpCo is a partnership and is generally not subject to U.S. federal and certain state taxes. Crescent is subject to U.S. federal and certain state taxes on our allocable share of any taxable income of OpCo. Taxable income or loss generated by OpCo is generally allocated and passed through to Crescent at our proportionate share of OpCo unit ownership, except for activity related to items contributed by Contango with a pre-contribution gain which are allocated solely to Crescent.

The amount of income taxes we record requires interpretations of complex rules and regulations of various tax jurisdictions throughout the United States. We recognize deferred tax assets and liabilities for temporary differences, operating losses and tax credit carryforwards. Temporary differences arise when there are differences between the financial statement carrying amount and the tax basis of existing assets and liabilities as these differences create taxable or tax-deductible amounts for future periods. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized. For additional information regarding income taxes, see NOTE 10 – Income Taxes.

ASC 740, Income Taxes, specifies the accounting for uncertainty in income taxes by prescribing a minimum recognition threshold for a tax position to be reflected in the financial statements. If recognized, the tax benefit is measured as the largest amount of tax benefit that is more likely than not to be realized upon ultimate settlement. Management has considered the amounts and the probabilities of the outcomes that could be realized upon ultimate settlement and believes that it is more likely than not that the Company's recorded income tax benefits will be fully realized, or recognizes a valuation allowance against deferred tax assets in cases where we do not forecast sufficient future income to recognize the deferred tax asset.

Goodwill

Goodwill

Goodwill represents the excess of the consideration transferred for business combinations over the fair value of the identifiable net assets acquired. We test goodwill for impairment annually or more frequently if events or changes in circumstances indicate that the asset might be impaired.

Asset Retirement Obligations

Asset Retirement Obligations

An ARO represents the legal obligation associated with the future abandonment of tangible assets, such as wells, service assets, pipelines, and other facilities. We record an ARO and capitalize the asset retirement cost in oil and natural gas properties in the period in which the ARO is incurred based upon the estimated fair value of the obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO liability is accreted to its future estimated value using an estimated credited-adjusted risk-free rate and the capitalized asset retirement cost is depleted on a unit-of-production basis. Both the accretion expense and the depletion expense are included in depreciation, depletion and amortization expense on our combined and consolidated statements of operations.

Measuring the future ARO requires management to make estimates, assumptions and judgments inherent in the present value calculation including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the related asset. If the ARO is settled for an amount other than the recorded amount, a gain or loss is recognized at settlement.

Environmental Expenditures

Environmental Expenditures

In addition to ARO, management also reviews our estimates of the cleanup costs of various sites on an annual basis. When it is probable that obligations have been incurred, and where a reasonable estimate of the cost of compliance or remediation can be determined, the applicable amount is accrued. For other potential liabilities, the timing of accruals coincides with the related

ongoing site assessments. We do not discount any of these liabilities. Recoveries for environmental remediation costs from third parties, which are probable of realization, are separately recorded and are not offset against the related environmental liability.

Recent Accounting Standards

Recent Accounting Standards

In February 2016, the FASB issued ASU 2016-02, Leases, ("ASC Topic 842") which establishes comprehensive accounting and financial reporting requirements for leasing arrangements. ASC Topic 842 requires lessees to recognize substantially all lease assets and lease liabilities on the balance sheets. Additional disclosures about an entity’s lease transactions will also be required. ASC Topic 842 defines a lease as “a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment (an identified asset) for a period of time in exchange for consideration.” Lessees and lessors can elect to recognize and measure leases as of the date of adoption using a modified retrospective approach. We adopted ASC Topic 842 effective January 1, 2021. Adoption of ASC Topic 842 resulted in the recognition of additional lease assets and liabilities on our consolidated balance sheets as well as additional disclosures. The adoption did not have a material impact to our combined and consolidated financial statements.

In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848) - Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”). ASU 2020-04 provides optional guidance, for a limited period of time, to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. The amendments in ASU 2020-04 provide optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by reference rate reform if certain criteria are met. The amendments in this ASU apply only to contracts, hedging relationships and other transactions that reference LIBOR, or another reference rate, expected to be discontinued because of reference rate reform. The guidance was effective beginning March 12, 2020 and can be applied prospectively through December 31, 2022. In January 2021, the FASB issued ASU 2021-01, Reference Rate Reform - Scope, which clarified the scope and application of the original guidance. The Company is currently assessing the potential impact of ASU 2020-04 on its consolidated financial statements.

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

Schedule of Cash and Cash Equivalents

The following table provides a reconciliation of cash and restricted cash presented on our balance sheets to amounts shown in the statements of cash flows:

	As of December 31,
	2021		2020		2019
	(in thousands)
Cash and cash equivalents	$	128,578	$	36,861	$	19,894
Restricted cash – current	—		—		3,932
Restricted cash – noncurrent	6,539		4,559		3,595
Total cash, cash equivalents and restricted cash	$	135,117	$	41,420	$	27,421

Schedule of Restricted Cash and Restricted Cash Equivalents

The following table provides a reconciliation of cash and restricted cash presented on our balance sheets to amounts shown in the statements of cash flows:

	As of December 31,
	2021		2020		2019
	(in thousands)
Cash and cash equivalents	$	128,578	$	36,861	$	19,894
Restricted cash – current	—		—		3,932
Restricted cash – noncurrent	6,539		4,559		3,595
Total cash, cash equivalents and restricted cash	$	135,117	$	41,420	$	27,421

Schedule of Redeemable Noncontrolling Interest

From the date of the Merger Transactions through December 31, 2021, we recorded adjustments to the value of our redeemable noncontrolling interests as shown below:

	Redeemable Noncontrolling Interest
	(in thousands)
Balance as of December 7, 2021	$	2,353,977
Net loss attributable to redeemable noncontrolling interests	(58,761)
Accrued OpCo distribution	(2,706)
Equity-based compensation, net of withholding taxes	16,412
Cancellation of OpCo Units associated with repurchase of treasury stock	16,091
Balance as of December 31, 2021	$	2,325,013

Schedule of Effects of Changes in Ownership

The following table discloses the effects on equity of changes in our ownership interest in our subsidiaries related to transactions with holders of noncontrolling interests:

	Year Ended December 31,
	2021		2020		2019
	(in thousands)
Net income (loss) attributable to Crescent Energy and its Predecessor	$	(358,544)	$	(118,649)	$	45,839
Transfers (to) from noncontrolling interest
Decrease in Predecessor members’ equity related to the Independence Reorganization	—		(101,926)		—
Increase in Predecessor members’ equity related to the December 2020 Exchange	—		657,370		—
Increase in Predecessor members’ equity related to the April 2021 Exchange	62,051		—		—
Net transfers (to) from noncontrolling interest	62,051		555,444		—
Changes from net income (loss) attributable to Crescent Energy and its Predecessor and transfers (to) from noncontrolling interest	$	(296,493)	$	436,795	$	45,839

Schedules of Concentration of Risk by Revenue

The below purchasers represented greater than 10% of our revenues during the years ended December 31, 2021, 2020 and 2019:

	2021		2020		2019
SN EF Maverick, LLC	*		15.5	%	20.0	%
Eighty Eight Oil	*		11.7	%	*
Shell Trading US Company	18.3	%	10.4	%	*
Cokinos Energy Corporation	*		*		18.1	%
BP Products North America	*		*		13.1	%

*Purchaser did not account for greater than 10% of revenue for the year

Schedule of Supplemental Cash Flow

The following are our supplemental cash flow disclosures for the years ended December 31, 2021, 2020 and 2019:

	Year Ended December 31,
	2021		2020		2019
	(in thousands)
Supplemental cash flow disclosures:
Interest paid, net of amounts capitalized	$	35,055	$	33,902	$	49,397
Income taxes paid	562		14		28
Non-cash investing and financing activities:
Capital expenditures included in accounts payable and accrued liabilities	47,173		12,267		28,305
Equity consideration for acquisitions, net of cash acquired	647,579		454,599		—
Right-of-use assets obtained in exchange for leases	8,573		—		—
April 2021 Exchange and December 2020 Exchange	62,051		657,370		—
Noncontrolling Interest Carve-out	(121,872)		—		—
Capitalized non-cash equity-based compensation	3,373		—		—

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Acquisitions and Divestitures (Tables)

12 Months Ended

Dec. 31, 2021

Business Combination and Asset Acquisition [Abstract]

Schedule of Pro Forma Information

The following table summarizes our unaudited pro forma financial information for the years ended December 31, 2021 and 2020 as if the Contango acquisition occurred on January 1, 2020 (unaudited):

	Year Ended December 31,
	2021		2020
	(in thousands)
Revenues	$	1,943,741	$	970,921
Net loss	$	(432,328)	$	(507,837)

Schedule of Consideration Transferred

The following table summarizes the consideration transferred and the estimated fair value of identified assets acquired and liabilities assumed for the Contango and Titan business combinations:

	Contango		Titan
	(in thousands)
Consideration transferred:
Equity consideration	$	654,616	$	461,983
Total	$	654,616	$	461,983
Assets acquired and liabilities assumed:
Cash and cash equivalents	$	14,202	$	482
Accounts receivable, net	145,727		29,044
Derivative assets – current	—		12,000
Prepaid and other current assets	8,275		49,079
Oil and natural gas properties - proved	1,002,165		375,014
Field and other property and equipment	6,955		30,232
Derivative assets – noncurrent	—		114
Goodwill	76,564		—
Investment in equity affiliates	15,047		—
Other assets	3,514		—
Accounts payable and accrued liabilities	(186,689)		(6,539)
Derivative liabilities – current	(44,002)		(4,550)
Long-term debt	(140,000)		—
Deferred tax liability	(83,250)		—
Derivative liabilities – noncurrent	(14,592)		(1,484)
Asset retirement obligations	(142,100)		(21,409)
Other liabilities	(7,200)		—
Fair value of net assets acquired	$	654,616	$	461,983

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed

The following table summarizes the consideration transferred and the estimated fair value of identified assets acquired and liabilities assumed for the Contango and Titan business combinations:

	Contango		Titan
	(in thousands)
Consideration transferred:
Equity consideration	$	654,616	$	461,983
Total	$	654,616	$	461,983
Assets acquired and liabilities assumed:
Cash and cash equivalents	$	14,202	$	482
Accounts receivable, net	145,727		29,044
Derivative assets – current	—		12,000
Prepaid and other current assets	8,275		49,079
Oil and natural gas properties - proved	1,002,165		375,014
Field and other property and equipment	6,955		30,232
Derivative assets – noncurrent	—		114
Goodwill	76,564		—
Investment in equity affiliates	15,047		—
Other assets	3,514		—
Accounts payable and accrued liabilities	(186,689)		(6,539)
Derivative liabilities – current	(44,002)		(4,550)
Long-term debt	(140,000)		—
Deferred tax liability	(83,250)		—
Derivative liabilities – noncurrent	(14,592)		(1,484)
Asset retirement obligations	(142,100)		(21,409)
Other liabilities	(7,200)		—
Fair value of net assets acquired	$	654,616	$	461,983

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2021

Property, Plant and Equipment [Abstract]

Schedule of Other Property, Plant and Equipment

The following table summarizes our oil and natural gas properties as of December 31, 2021 and 2020:

	As of December 31,
	2021		2020
	(in thousands)
Proved oil and natural gas properties (successful efforts method)	$	6,043,602	$	4,910,059
Unproved oil and natural gas properties	308,721		288,459
Oil and natural gas properties, at cost	6,352,323		5,198,518
Less accumulated depreciation, depletion, amortization and impairment	(1,881,934)		(1,633,664)
Oil and natural gas properties, net	$	4,470,389	$	3,564,854

Other Property

The following table summarizes other property, plant and equipment as of December 31, 2021 and 2020:

	Estimated useful life	As of December 31,
		2021		2020
	(years)	(in thousands)
Gathering and pipeline system	30	$	106,023	$	108,777
Vehicles	3-5	10,836		7,273
Computers, furniture, and equipment	3-10	7,175		6,812
Buildings and improvements	5-30	6,641		6,797
Land		5,467		5,700
Financing right of use asset		5,249		—
Field inventory		2,927		3,012
Total field and other property and equipment, at cost		144,318		138,371
Less: accumulated depreciation, amortization and impairment		(59,594)		(61,078)
Total field and other property and equipment, net		$	84,724	$	77,293

Schedule of Capitalized Exploratory Well Costs

Capitalized exploratory well costs are included in unproved oil and natural gas properties. The following table reflects the net changes in capitalized exploratory well costs for the years ended December 31, 2021 and 2020:

	As of December 31,
	2021		2020
	(in thousands)
Balance at beginning of period	$	—	$	—
Additions pending the determination of proved reserves	—		—
Reclassifications to proved properties	—		—
Cost charged to expense	—		—
Balance at end of period	$	—	$	—

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Derivatives (Tables)

12 Months Ended

Dec. 31, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments

The following table details our net volume positions by commodity as of December 31, 2021:

Production Period	Volumes	Weighted Average Fixed Price			Fair Value
	(in thousands)				(in thousands)
Crude oil swaps (Bbls):
WTI
2022	10,464	$60.63			$	(121,508)
2023	7,627	$58.50			(59,395)
2024	2,975	$57.35			(16,542)
Brent
2022	500	$56.36			(9,258)
2023	527	$52.52			(9,103)
2024	189	$63.71			(766)
Natural gas swaps (MMBtu):
2022	84,527	$2.77			(76,861)
2023	56,728	$2.54			(47,722)
2024	454	$2.94			(82)
NGL swaps (Bbls):
2022	2,983	$22.23			(38,596)
Crude oil basis swaps (Bbls):
2022	5,843	$(0.11)			(4,403)
Natural gas basis swaps (MMBtu):
2022	26,061	$(0.17)			(3,243)
CMA roll swaps (Bbls):
2022	1,468	$1.08			563
Natural gas collars (MMBtu):
2022	510	$3.00	-	$3.41	(220)
2023	550	$2.63	-	$3.01	(469)
2024	9,150	$3.00		$3.87	1,187
Total					$	(386,418)

Schedule of Offsetting Assets

The following table shows the effects of master netting arrangements on the fair value of our derivative contracts at December 31, 2021 and 2020:

	Gross Fair Value		Effect of Counterparty Netting		Net Carrying Value
	(in thousands)
December 31, 2021
Assets:
Derivative assets – current	$	2,983	$	(2,983)	$	—
Derivative assets – noncurrent	4,834		(4,255)		579
Total assets	$	7,817	$	(7,238)	$	579
Liabilities:
Derivative liabilities – current	$	(256,508)	$	2,983	$	(253,525)
Derivative liabilities – noncurrent	(137,726)		4,255		(133,471)
Total liabilities	$	(394,234)	$	7,238	$	(386,996)

	Gross Fair Value		Effect of Counterparty Netting		Net Carrying Value
	(in thousands)
December 31, 2020
Assets:
Derivative assets – current	$	52,833	$	(21,907)	$	30,926
Derivative assets – noncurrent	34,257		(11,905)		22,352
Total assets	$	87,090	$	(33,812)	$	53,278
Liabilities:
Derivative liabilities – current	$	(48,299)	$	21,907	$	(26,392)
Derivative liabilities – noncurrent	(35,863)		11,905		(23,958)
Total liabilities	$	(84,162)	$	33,812	$	(50,350)

Schedule of Offsetting Liabilities

The following table shows the effects of master netting arrangements on the fair value of our derivative contracts at December 31, 2021 and 2020:

	Gross Fair Value		Effect of Counterparty Netting		Net Carrying Value
	(in thousands)
December 31, 2021
Assets:
Derivative assets – current	$	2,983	$	(2,983)	$	—
Derivative assets – noncurrent	4,834		(4,255)		579
Total assets	$	7,817	$	(7,238)	$	579
Liabilities:
Derivative liabilities – current	$	(256,508)	$	2,983	$	(253,525)
Derivative liabilities – noncurrent	(137,726)		4,255		(133,471)
Total liabilities	$	(394,234)	$	7,238	$	(386,996)

	Gross Fair Value		Effect of Counterparty Netting		Net Carrying Value
	(in thousands)
December 31, 2020
Assets:
Derivative assets – current	$	52,833	$	(21,907)	$	30,926
Derivative assets – noncurrent	34,257		(11,905)		22,352
Total assets	$	87,090	$	(33,812)	$	53,278
Liabilities:
Derivative liabilities – current	$	(48,299)	$	21,907	$	(26,392)
Derivative liabilities – noncurrent	(35,863)		11,905		(23,958)
Total liabilities	$	(84,162)	$	33,812	$	(50,350)

Schedule of Derivative Contracts on Operations

The amount of gain (loss) recognized in gain (loss) on derivatives in our combined and consolidated statements of operations was as follows for the years ended December 31, 2021, 2020 and 2019:

	Years ended December 31,
	2021		2020		2019
	(in thousands)
Derivatives not designated as hedging instruments:
Realized gain (loss) on oil positions	$	(180,572)	$	149,713	$	(44,265)
Realized loss on early settlement of certain oil positions	(198,688)		—		—
Realized gain (loss) on natural gas positions	(80,253)		32,638		4,245
Realized gain (loss) on NGL positions	(68,766)		14,458		13,033
Realized gain (loss) on interest hedges	(7,373)		(12,435)		(2,189)
Total realized gain (loss)	(535,652)		184,374		(29,176)
Unrealized gain (loss) on commodity hedges	(337,715)		8,836		(94,766)
Unrealized gain (loss) on interest hedges	7,347		2,074		(3,260)
Total unrealized gain (loss)	(330,368)		10,910		(98,026)
Total gain (loss) on derivatives	$	(866,020)	$	195,284	$	(127,202)

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2021

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis

The following table presents the location and fair value of our derivative assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2021 and 2020, by level within the fair value hierarchy:

	Fair Value Measurement Using
	Level 1		Level 2		Level 3		Total
	(in thousands)
December 31, 2021
Financial assets:
Derivative assets	$	—	$	7,817	$	—	$	7,817
Financial Liabilities:
Derivative liabilities	$	—	$	(394,234)	$	—	$	(394,234)
December 31, 2020
Financial assets:
Derivative assets	$	—	$	87,090	$	—	$	87,090
Financial Liabilities:
Derivative liabilities	$	—	$	(84,162)	$	—	$	(84,162)

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Accounts Payable and Accrued Liabilities (Tables)

12 Months Ended

Dec. 31, 2021

Payables and Accruals [Abstract]

Schedule of Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities consisted of the following as of December 31, 2021 and 2020:

	As of December 31,
	2021		2020
	(in thousands)
Accounts payable and accrued liabilities:
Accounts payable	$	87,336	$	15,019
Accrued lease operating expense	46,231		20,126
Accrued asset operating expense	8,997		3,591
Accrued capital expenditure	60,647		12,267
Accrued general and administrative	12,193		9,549
Accrued transportation expense	19,684		8,399
Accrued deficiency fees	955		5,050
Accrued revenue and royalties payable	75,827		2,142
Accrued interest and other	26,011		4,545
Total accounts payable and accrued liabilities	$	337,881	$	80,688

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Debt (Tables)

12 Months Ended

Dec. 31, 2021

Debt Disclosure [Abstract]

Schedule of Debt Balances

The following table summarizes our debt balances as of December 31, 2021 and 2020:

	As of December 31, 2021
	Debt Outstanding		Letters of Credit Issued		Borrowing Base		Maturity
	(in thousands)
Revolving Credit Facility	$	543,000	$	20,653	$	1,300,000	5/6/2025
7.25% Senior Notes due 2026	500,000		—		—		5/1/2026
Less: Unamortized discount and issuance costs	(12,594)
Total long-term debt	$	1,030,406

	As of December 31, 2020
	Debt Outstanding		Letters of Credit Issued		Borrowing Base		Maturity
	(in thousands)
Independence Upstream Holdings LLC	$	32,500	$	—	$	100,000	6/7/2022
Independence Minerals Holdings LLC	15,000		—		37,000		10/25/2024
KNR Resource Investors LP	5,565		250		12,000		6/7/2022
Renee Acquisition LLC	101,310		5,667		145,000		1/31/2023
Newark Acquisition I LP	135,400		6,280		190,000		5/31/2023
Bridge Energy Holdings LLC	35,800		5,574		50,000		7/21/2022
Venado EF LP	156,500		—		160,000		3/10/2022
VOG Palo Verde LP	269,000		—		320,000		2/28/2023
Total long-term debt	$	751,075

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2021

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligations

The following table summarizes activity related to our ARO liabilities for the years ended December 31, 2021 and 2020:

	Year Ended December 31,
	2021		2020
	(in thousands)
Balance at beginning of period	$	109,616	$	83,141
Additions(1)	156,201		21,860
Retirements	(1,252)		(881)
Accretion expense	7,121		5,694
Revisions	—		(198)
Noncontrolling Interest Carve-out	(3,810)		—
Sale	(1,869)		—
Balance at end of period	266,007		109,616
Less: current portion	(7,905)		(3,213)
Balance at end of period, noncurrent portion	$	258,102	$	106,403

(1)During the year ended December 31, 2021, our ARO additions related to properties acquired in our 2021 acquisitions. During the year ended December 31, 2020, our ARO additions primarily related to properties acquired in the Titan Acquisition. See NOTE 3 – Acquisitions and Divestitures for additional information.

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2021

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Provisions

Details of income tax provisions and deferred income taxes are provided in the following tables:

	Year Ended December 31,
	2021		2020		2019
Federal income tax provision (benefit)	(in thousands)
Current	$	—	$	—	$	—
Deferred	(935)		—		—
State income tax provision (benefit)
Current	629		14		28
Deferred	—		—		—
Total income tax provision (benefit)	$	(306)	$	14	$	28

Schedule of Effective Income Tax Rate Reconciliation

The difference between the statutory federal income tax rate and the Company's effective income tax rate is explained as follows:

	Year Ended December 31,
	2021		2020		2019
Federal income taxes statutory rate	21.0	%	—	%	—	%
Increase (decrease) in rate as a result of:
State current income tax provision, net of federal benefit	(0.1)	%	—	%	—	%
Permanent adjustments (1)	(1.7)	%	—	%	—	%
Income attributable to Predecessor that was not subject to corporate income tax (2)	(18.4)	%	—	%	—	%
Income attributable to noncontrolling interests	(0.7)	%	—	%	—	%
Effective income tax rate	0.1	%	—	%	—	%

(1)During the year ended December 31, 2021, the permanent items primarily related to disallowed officer compensation under Section 162(m) of the Internal Revenue Code.

(2)    During the year ended December 31, 2021, the income attributable to Predecessor was not subject to corporate income tax as we were organized as limited liability companies and limited partnerships that were treated as flow-through entities for U.S federal income tax purposes prior to the Merger Transactions.

Schedule of Deferred Tax Assets and Liabilities

Significant components of the Company's deferred income taxes were as follows:

	Year Ended December 31,
	2021		2020
Deferred tax liabilities	(in thousands)
Outside Basis in OpCo	$	98,079	$	—
Deferred tax assets
Federal and state NOL (1)	38,317		—
Federal and state NOL valuation allowance	(30,567)		—
Recognized built-in loss carryforward	6,872		—
Other	920		—
Total deferred tax assets, net of valuation allowance	15,542		—
Net deferred income tax liability	$	82,537	$	—

(1)We have Federal NOLs of $1.9 million, net of tax, that have expiration dates beginning in 2026. We also have NOLs of $36.4 million, net of tax, that were generated after 2017 and have indefinite lives but are limited to offsetting 80% of taxable income in a given tax year.

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Leases (Tables)

12 Months Ended

Dec. 31, 2021

Leases [Abstract]

Schedule of Leases in Statement of Financial Position

The following tables show the presentation of the right-of-use assets and lease liabilities within our combined and consolidated financial statements:

	As of December 31, 2021
	(in thousands)
Field and other property and equipment, at cost
Financing right-of-use asset	$	5,249
Other assets
Operating right-of-use asset	2,299
Other current liabilities
Short-term operating lease liability	(1,292)
Other liabilities
Long-term operating lease liability	(1,007)

Schedule of Lease Cost

	Year Ended December 31, 2021
	(in thousands)
Lease cost included in combined and consolidated statement of operations
Operating lease cost	$	939
Financing lease cost - amortization of ROU assets	20
Financing lease cost - interest on lease liabilities	131
Administrative lease cost (1)	100
Short-term lease cost (2)	876
Total lease cost	$	2,066

(1)     Costs related primarily to office equipment and IT solutions with lease terms of more than one month and less than one year.

(2)     Costs related primarily to generators, compressors and vehicle agreements with lease terms of more than one month and less than one year.

Lease term and discount rate related to our leases are as follows:

	As of December 31, 2021
	Operating	Financing
Weighted-average remaining lease term (years)	2.3	3.1
Weighted-average discount rate	4.50%	4.50%

Schedule of Maturities of Operating Lease Liabilities

As of December 31, 2021, the maturity analysis for our lease liabilities under the scope of ASC 842 is as follows:

	As of December 31, 2021
	Operating		Financing
Year Ended December 31,	(in thousands)
2022	$	1,292	$	1,606
2023	666		1,887
2024	412		1,370
2025	18		633
2026	18		16
After 2026	24		—
Less: interest	(131)		(394)
Present value of lease liabilities	$	2,299	$	5,118

Schedule of Maturities of Financing Lease Liabilities

As of December 31, 2021, the maturity analysis for our lease liabilities under the scope of ASC 842 is as follows:

	As of December 31, 2021
	Operating		Financing
Year Ended December 31,	(in thousands)
2022	$	1,292	$	1,606
2023	666		1,887
2024	412		1,370
2025	18		633
2026	18		16
After 2026	24		—
Less: interest	(131)		(394)
Present value of lease liabilities	$	2,299	$	5,118

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2021

Commitments and Contingencies Disclosure [Abstract]

Schedule of Future Commitments

The following table summarizes our future commitments related to these oil and natural gas transportation and gathering agreements as of December 31, 2021:

	As of December 31, 2021
	(in thousands)
2022	$	105,606
2023	80,340
2024	65,848
2025	61,346
2026	32,652
Thereafter	62,957
Total minimum future commitments	$	408,749

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Incentive Compensation Arrangements (Tables)

12 Months Ended

Dec. 31, 2021

Share-based Payment Arrangement [Abstract]

Schedule of Equity-Based Compensation Expense

The following table summarizes compensation expense we recognized in connection with our incentive compensation awards for the years indicated:

	Year Ended December 31,
	2021		2020		2019
	(in thousands)
ASC 710 profits interest awards	$	—	$	—	$	—
ASC 718 liability-classified profits interest awards	(2,043)		(797)		(2,721)
ASC 718 equity-classified profits interest awards	1,563		—		—
ASC 718 equity-classified PSU awards	1,120		—		—
ASC 718 equity-classified Contango PSU awards	39,279		—		—
Total expense (income)	$	39,919	$	(797)	$	(2,721)

Schedule of Transactions Involving Unvested Units

Transactions involving all of our unvested liability-classified stock-based compensation profits interest awards is summarized below:

	Year Ended December 31,
	2021	2020	2019
	(units in thousands)
Beginning Balance	888	1,215	1,163
Granted	708	—	285
Vested	(110)	(203)	(233)
Forfeited	(778)	(125)	—
Ending Balance	708	888	1,215

Transactions involving all of our unvested equity-classified profits interest awards, including weighted average grant date fair values, are summarized below:

	Units	Weighted average grant date fair value
	(in thousands)
Unvested at December 31, 2020	—	$	—
Granted	477	10.98
Vested	(25)	10.61
Forfeited	(253)	11.02
Unvested at December 31, 2021	200	—

Transactions involving all of our unvested units, including weighted average grant date fair values, are summarized below:

	Target Class A Shares	Weighted average grant date fair value
	(in thousands)
Unvested at December 31, 2020	—	$	—
Granted	4,195	17.33
Vested	—	—
Forfeited	—	—
Unvested at December 31, 2021	4,195	17.33

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Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2021

Earnings Per Share [Abstract]

Schedule of Computation of Basic and Diluted Net Income (Loss) per Share

The following table sets forth the computation of basic and diluted net income (loss) per share:

	Year Ended December 31,
	2021		2020		2019
	(in thousands, except unit and per unit amounts)
Numerator:
Net income (loss)	$	(432,227)	$	(216,124)	$	46,709
Less: net (income) loss attributable to Predecessor	339,168		118,649		(45,839)
Less: net (income) loss attributable to noncontrolling interests	14,922		97,475		(870)
Less: net (income) loss attributable to redeemable noncontrolling interests	58,761		—		—
Net income (loss) attributable to Crescent Energy	$	(19,376)	$	—	$	—
Denominator:
Weighted-average Class A common stock outstanding - basic and diluted (1)	41,954,385
Weighted-average Class B common stock outstanding - basic and diluted	127,536,463
Net income (loss) per share:
Class A common stock - basic and diluted (1)	$	(0.46)
Class B common stock - basic and diluted	$	—

(1)Represents weighted-average Class A common stock outstanding and net loss per share of Class A common stock for the period subsequent to the Merger Transactions.

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Selected Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2021

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Data

Quarterly financial data was as follows for the periods indicated:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(in thousands, except per share amounts)
2021
Revenues	$	317,860	$	330,130	$	365,726	$	463,261
Income (loss) from operations	88,045		100,483		133,604		161,607
Net income (loss)	(166,268)		(272,861)		(162,043)		168,945
Less: net (income) loss attributable to Predecessor	155,629		269,608		160,567		(246,636)
Less: net (income) loss attributable to noncontrolling interests	10,639		3,253		1,476		(446)
Less: net (income) loss attributable to redeemable noncontrolling interests	—		—		—		58,761
Net income (loss) attributable to Crescent Energy	—		—		—		(19,376)
Net income (loss) per share
Class A common stock - basic and diluted	$	—	$	—	$	—	$	(0.46)
Class B common stock - basic and diluted	$	—	$	—	$	—	$	—
2020
Revenues	$	207,848	$	103,509	$	190,612	$	252,252
Income (loss) from operations	3,353		(293,463)		(26,669)		(56,849)
Net income (loss)	466,790		(412,227)		(101,005)		(169,682)
Less: net (income) loss attributable to Predecessor	(320,722)		236,166		69,990		133,215
Less: net (income) loss attributable to noncontrolling interests	(146,068)		176,061		31,015		36,467
Net income (loss) attributable to Crescent Energy	—		—		—		—
Net income (loss) per share
Class A common stock - basic and diluted	$	—	$	—	$	—	$	—
Class B common stock - basic and diluted	$	—	$	—	$	—	$	—

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Supplemental Oil and Natural Gas Disclosures (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2021

Extractive Industries [Abstract]

Schedule of Oil and Natural Gas Reserve Information

The following table presents our net proved reserves for the years ended December 31, 2021, 2020 and 2019 and the changes in net proved oil, natural gas and NGL reserves during such years. In addition, the net proved reserves for our equity method investment, Exaro, are presented based on our 37% ownership percentage. Because Exaro was acquired in 2021 as part of the Merger Transactions, prior periods are not presented.

Developed and Undeveloped	Oil (MBbls)	Natural Gas (MMcf)	Natural Gas Liquids (MBbls)	Total (MBoe)
Consolidated operations
Net proved reserves at December 31, 2018	202,805	1,189,962	75,780	476,913
Revisions of previous estimates	10,477	20,552	(11,321)	2,581
Extensions, discoveries, and other additions (1)	12,003	24,472	1,855	17,936
Sales of reserves in place	—	—	—	—
Purchases of reserves in place	—	—	—	—
Production	(13,752)	(73,747)	(5,188)	(31,231)
Net proved reserves at December 31, 2019	211,533	1,161,239	61,126	466,199
Revisions of previous estimates (2)	(57,708)	(478,153)	(20,279)	(157,680)
Extensions, discoveries, and other additions	4,088	21,479	603	8,271
Sales of reserves in place	—	—	—	—
Purchases of reserves in place (3)	22,409	196,840	18,952	74,168
Production	(13,132)	(78,541)	(5,078)	(31,300)
Net proved reserves at December 31, 2020	167,190	822,864	55,324	359,658
Revisions of previous estimates (4)	9,147	316,572	16,480	78,389
Extensions, discoveries, and other additions	7,007	17,247	2,093	11,975
Sales of reserves in place	(6,333)	(48,977)	(3,265)	(17,762)
Purchases of reserves in place (5)	46,386	451,702	11,960	133,630
Production	(13,237)	(89,455)	(6,099)	(34,245)
Net proved reserves at December 31, 2021	210,160	1,469,953	76,493	531,645
Equity affiliate
Net proved reserves at December 31, 2020	—	—	—	—
Revisions of previous estimates	—	—	—	—
Extensions, discoveries, and other additions	—	—	—	—
Sales of reserves in place	—	—	—	—
Purchases of reserves in place	205	20,880	—	3,685
Production	(1)	(115)	—	(20)
Net proved reserves at December 31, 2021	204	20,765	—	3,665
Total company
Net proved reserves at December 31, 2019	211,533	1,161,239	61,126	466,199
Net proved reserves at December 31, 2020	167,190	822,864	55,324	359,658
Net proved reserves at December 31, 2021	210,364	1,490,718	76,493	535,310

(1)During the year ended December 31, 2019, we added 17.9 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Eagle Ford and Permian. Approximately 77% of the reserve additions for the year ended December 31, 2019 were crude oil and NGLs.

(2)Revisions of previous estimates include 92.0 MMBoe downward revisions of our PUD reserves. The revisions are primarily due to declining commodity prices which decreased the quantity of reserves recoverable from our proved locations, and also resulted in the removal of certain PUD locations that were uneconomic at year end prices.

(3)Purchases in place of 74.2 MMBoe were primarily related to the Permian and DJ Basins.

(4)Revisions of previous estimates include 92.7 MMBoe upward revision due to pricing and cost changes, offset by 21.1 MMBoe downward revisions of our PUD reserves due to the removal of certain locations that are no longer part of our five-year consolidated development plan following the Merger Transactions.

(5)Purchases in place included 125.6 MMBoe from our Merger Transactions, 5.6 MMBoe from our Central Basin Platform Acquisition and 2.5 MMBoe from our DJ Basin Acquisition.

The following table sets forth our net proved oil, natural gas and NGL reserves for both our consolidated operations and our investment in Exaro as of the years ended December 31, 2021 and 2020, 2019 and 2018:

Proved Developed Reserves	Oil (MBbls)	Natural Gas (MMcf)	Natural Gas Liquids (MBbls)	Total (MBoe)
Consolidated operations
December 31, 2021	158,091	1,404,570	66,402	458,588
December 31, 2020	92,024	748,496	44,307	261,079
December 31, 2019	103,728	870,491	48,997	297,808
Equity affiliate
December 31, 2021	204	20,765	—	3,665
December 31, 2020	—	—	—	—
December 31, 2019	—	—	—	—

Proved Undeveloped Reserves	Oil (MBbls)	Natural Gas (MMcf)	Natural Gas Liquids (MBbls)	Total (MBoe)
Consolidated operations
December 31, 2021	52,069	65,383	10,091	73,057
December 31, 2020	75,166	74,368	11,017	98,579
December 31, 2019	107,805	290,748	12,129	168,391
Equity affiliate
December 31, 2021	—	—	—	—
December 31, 2020	—	—	—	—
December 31, 2019	—	—	—	—

Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities

The following table summarizes the capitalized costs relating to our oil and natural gas producing activities for both our consolidated operations and our investment in Exaro as of December 31, 2021 and 2020:

	As of December 31,
	2021		2020
	(in thousands)
Consolidated operations
Proved oil and natural gas properties (successful efforts method)	$	6,043,602	$	4,910,059
Unproved oil and natural gas properties	308,721		288,459
Oil and natural gas properties, at cost	6,352,323		5,198,518
Less accumulated depreciation, depletion and amortization	(1,881,933)		(1,666,620)
Net capitalized costs	$	4,470,390	$	3,531,898
Equity affiliate
Proved oil and natural gas properties (successful efforts method)	$	9,043	$	—
Unproved oil and natural gas properties	—		—
Oil and natural gas properties, at cost	9,043		—
Less accumulated depreciation, depletion and amortization	(67)		—
Net capitalized costs	$	8,976	$	—

Schedule of Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

The following table summarizes costs incurred related to our oil and natural gas activities for both our consolidated operations and our investment in Exaro for the years ended December 31, 2021, 2020 and 2019:

	Year Ended December 31,
	2021		2020		2019
	(in thousands)
Consolidated operations
Acquisition costs:
Proved	$	1,098,696	$	355,010	$	795
Unproved	41,355		680		7,264
Exploration costs	1,180		—		710
Development	194,828		83,013		318,157
Total costs incurred	$	1,336,059	$	438,703	$	326,926
Equity affiliate
Acquisition costs:
Proved	$	—	$	—	$	—
Unproved	—		—		—
Exploration costs	—		—		—
Development	—		—		—
Total costs incurred	$	—	$	—	$	—

Schedule of Average First-Day-of-the-Month Price for Oil, Natural Gas and Natural Gas Liquids

The following table provides the average benchmark prices per unit, before location and quality differential adjustments, used to calculate the related reserve category:

	Year Ended December 31,
	2021		2020		2019
Average benchmark price per unit:
Crude oil (Bbl)	$	66.56	$	39.56	$	55.69
Natural gas (MMBtu)	$	3.60	$	1.99	$	2.62

Schedule of Standardized Measure Discounted Future Net Cash Flows

The following table sets forth the standardized measure of discounted future net cash flows for both our consolidated operations and our investment in Exaro from projected production of oil and natural gas reserves, for the years ended December 31, 2021, 2020 and 2019:

	Year Ended December 31,
	2021		2020		2019
	(in thousands)
Consolidated operations
Future cash inflows	$	21,063,117	$	8,232,932	$	15,745,942
Future production costs	(10,194,648)		(4,280,563)		(6,766,410)
Future development costs (1)	(1,477,562)		(1,353,957)		(2,323,420)
Future income taxes	(352,136)		(30,155)		(63,136)
Future net cash flows	9,038,771		2,568,257		6,592,976
Annual discount of 10% for estimated timing	(4,080,471)		(1,240,397)		(3,482,128)
Standardized measure of discounted future net cash flows	$	4,958,300	$	1,327,860	$	3,110,848
Equity affiliate (2)
Future cash inflows	$	99,290	$	—	$	—
Future production costs	(55,371)		—		—
Future development costs	(2,309)		—		—
Future income taxes	(1,730)		—		—
Future net cash flows	39,880		—		—
Annual discount of 10% for estimated timing	(16,702)		—		—
Standardized measure of discounted future net cash flows	$	23,178	$	—	$	—

(1)    Future development costs include future abandonment and salvage costs.

(2)    The average benchmark prices used for the equity affiliate were $66.55 per barrel for crude oil and $3.64 per MMBtu for natural gas.

Schedule of Changes in the Standardized Measure of Discounted Future Net Cash Flows

The following table sets forth the changes in the standardized measure of discounted future net cash flows for both our consolidated operations and our investment in Exaro for the years ended December 31, 2021, 2020 and 2019:

	Year Ended December 31,
	2021		2020		2019
	(in thousands)
Consolidated operations
Balance at beginning of period	$	1,327,860	$	3,110,848	$	4,207,347
Net change in prices and production costs	3,330,299		(1,184,939)		(821,874)
Net change in future development costs	117,333		160,465		(59,359)
Sales and transfers of oil and natural gas produced, net of production expenses	(872,521)		(290,053)		(568,665)
Extensions, discoveries, additions and improved recovery, net of related costs	162,657		31,688		182,697
Purchases of reserves in place	1,236,388		176,480		—
Sales of reserves in place	(84,095)		—		—
Revisions of previous quantity estimates	(295,234)		(887,395)		(226,561)
Previously estimated development costs incurred	95,879		32,873		15,676
Net change in taxes	(184,419)		19,350		(19)
Accretion of discount	124,153		283,954		424,278
Changes in timing and other	—		(125,411)		(42,672)
Balance at end of period	$	4,958,300	$	1,327,860	$	3,110,848
Equity affiliate
Balance at beginning of period	$	—	$	—	$	—
Net change in prices and production costs	—		—		—
Net change in future development costs	—		—		—
Sales and transfers of oil and natural gas produced, net of production expenses	(1,246)		—		—
Extensions, discoveries, additions and improved recovery, net of related costs	—		—		—
Purchases of reserves in place	26,154		—		—
Sales of reserves in place	—		—		—
Revisions of previous quantity estimates	—		—		—
Previously estimated development costs incurred	—		—		—
Net change in taxes	(1,730)		—		—
Accretion of discount	—		—		—
Changes in timing and other	—		—		—
Balance at end of period	$	23,178	$	—	$	—

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Organization and Basis of Presentation (Details)	12 Months Ended
	Dec. 31, 2021 state segment $ / shares	Dec. 07, 2021	Dec. 31, 2020 $ / shares
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Number of states in which entity operates | state	48
Number of reportable segments | segment	1
Preferred stock, par value (in USD per share) | $ / shares	$ 0.0001		$ 0.0001
OpCo
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Ownership of outstanding shares (as a percent)	25.00%
OpCo | Independence Minerals Holdings LLC And Crescent Energy Finance LLC
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Ownership of outstanding shares (as a percent)	75.00%
Crescent Energy | Class A and Class B | Independence Minerals Holdings LLC
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Ownership interest by noncontrolling owners (as a percent)		75.00%
Crescent Energy | Class A and Class B | Contango
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Ownership interest by noncontrolling owners (as a percent)		25.00%
Crescent Energy | Class B | Independence Minerals Holdings LLC
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Ownership interest by noncontrolling owners (as a percent)		100.00%

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Summary of Significant Accounting Policies - Cash and Restricted Cash (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Accounting Policies [Abstract]
Cash and cash equivalents	$ 128,578	$ 36,861	$ 19,894
Restricted cash – current	0	0	3,932
Restricted cash – noncurrent	6,539	4,559	3,595
Total cash, cash equivalents and restricted cash	$ 135,117	$ 41,420	$ 27,421	$ 23,256

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Summary of Significant Accounting Policies - Narrative (Details)	1 Months Ended			11 Months Ended	12 Months Ended
	Apr. 30, 2021 shares	Dec. 30, 2020 USD ($) shares	May 31, 2020	Dec. 06, 2021 equity_class	Dec. 31, 2021 USD ($) class shares	Dec. 31, 2020 USD ($) shares	Dec. 31, 2019 USD ($)	Dec. 07, 2021
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Credit loss expense/ bad debt expense on accounts receivable					$ 0	$ 0	$ 0
Off-balance sheet credit exposure					0
Restricted investment securities - HTM					5,300,000	8,500,000
Exploration expense					1,180,000	486,000	469,000
Depletion expense					300,000,000	364,700,000	300,900,000
Impairment expense of oil and natural gas properties					0	247,215,000	0
Drilling advances					200,000	38,892,000
Equity method investments					15,415,000	0
Outstanding balance of long-term joint interest receivables					$ 1,200,000	1,300,000
Write-offs of acquired long-term joint interest receivables							3,800,000
Number of classes of equity | class					2
Reclassification for exchange					$ 0	0
Noncontrolling interest contributions					$ 35,460,000	$ 0	$ 250,000
Employer matching contribution rate of employee contributions (as a percent)					100.00%
Employer matching contribution, proportion of employees' gross pay (as a percent)					5.00%
Exaro
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Ownership interest in equity method investment (as a percent)					37.00%
Equity method investments					$ 4,700,000
Lost Creek
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Ownership interest in equity method investment (as a percent)					65.00%
Equity method investments					$ 10,700,000
Members' Equity
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Stock issued in merger transactions (in shares) | shares					(1,230,000)
Number of shares issued in transaction (in shares) | shares						380,000
Stock issued in exchange (in shares) | shares	9,508	220,421			10,000	220,000
Reclassification for exchange		$ 657,400,000			$ 62,051,000	$ 657,370,000
Independence Minerals Holdings LLC
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Number of classes of equity | equity_class				2
Barnett Basin Natural Gas Assets | Members' Equity
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Ownership interest exchanged (as a percent)	100.00%
Consolidated Subsidiaries | Members' Equity
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Ownership interest exchanged (as a percent)						100.00%
Class A and Class B | Crescent Energy | Independence Minerals Holdings LLC
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Ownership interest by noncontrolling owners (as a percent)								75.00%
Class A and Class B | Crescent Energy | Contango
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Ownership interest by noncontrolling owners (as a percent)								25.00%
Class A
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Common stock outstanding (in shares) | shares					41,954,385	0
Class A | Common Stock
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Stock issued in merger transactions (in shares) | shares					43,105,000
Class B
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Common stock outstanding (in shares) | shares					127,536,463	0
Class B | Common Stock
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Stock issued in merger transactions (in shares) | shares					127,536,000
Class B | Crescent Energy | Independence Minerals Holdings LLC
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Ownership interest by noncontrolling owners (as a percent)								100.00%
Minimum | Certain Subsidiaries | Third-Party Investors
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Ownership interest by investor (as a percent)			2.21%
Maximum | Certain Subsidiaries | Third-Party Investors
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Ownership interest by investor (as a percent)			7.38%
Other Capitalized Property Plant and Equipment | Minimum
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Estimated useful life					3 years
Other Capitalized Property Plant and Equipment | Maximum
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Estimated useful life					30 years

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Summary of Significant Accounting Policies - Adjustments to Redeemable Noncontrolling Interests (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended				12 Months Ended
	Dec. 31, 2021	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Increase (Decrease) in Temporary Equity [Roll Forward]
Balance as of December 7, 2021	$ 2,353,977				$ 0	$ 0
Net loss attributable to redeemable noncontrolling interests	(58,761)	$ (58,761)	$ 0	$ 0	$ 0	(58,761)	$ 0	$ 0
Accrued OpCo distribution						(2,706)
Equity-based compensation, net of withholding taxes	16,412
Cancellation of OpCo Units associated with repurchase of treasury stock	16,091
Balance as of December 31, 2021	$ 2,325,013	$ 2,325,013				$ 2,325,013	$ 0

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Summary of Significant Accounting Policies - Effects of Changes in Ownership (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Accounting Policies [Abstract]
Net income (loss)	$ (358,544)	$ (118,649)	$ 45,839
Decrease in Predecessor members’ equity related to the Independence Reorganization	0	(101,926)	0
Increase in Predecessor members’ equity related to the December 2020 Exchange	0	657,370	0
Increase in Predecessor members’ equity related to the April 2021 Exchange	62,051	0	0
Net transfers (to) from noncontrolling interest	62,051	555,444	0
Changes from net income (loss) attributable to Crescent Energy and its Predecessor and transfers (to) from noncontrolling interest	$ (296,493)	$ 436,795	$ 45,839

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Summary of Significant Accounting Policies - Revenue from Contracts with Customers (Details) - Revenue from Contract with Customer Benchmark - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
SN EF Maverick, LLC
Disaggregation of Revenue [Line Items]
Concentration risk (as a percent)		15.50%	20.00%
Eighty Eight Oil
Disaggregation of Revenue [Line Items]
Concentration risk (as a percent)		11.70%
Shell Trading US Company
Disaggregation of Revenue [Line Items]
Concentration risk (as a percent)	18.30%	10.40%
Cokinos Energy Corporation
Disaggregation of Revenue [Line Items]
Concentration risk (as a percent)			18.10%
BP Products North America
Disaggregation of Revenue [Line Items]
Concentration risk (as a percent)			13.10%

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Summary of Significant Accounting Policies - Supplemental Cash Flow Disclosures (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Supplemental cash flow disclosures:
Interest paid, net of amounts capitalized	$ 35,055	$ 33,902	$ 49,397
Income taxes paid	562	14	28
Non-cash investing and financing activities:
Capital expenditures included in accounts payable and accrued liabilities	47,173	12,267	28,305
Equity consideration for acquisitions, net of cash acquired	647,579	454,599	0
Right-of-use assets obtained in exchange for leases	8,573	0	0
April 2021 Exchange and December 2020 Exchange	62,051	657,370	0
Noncontrolling Interest Carve-out	(121,872)	0	0
Capitalized non-cash equity-based compensation	$ 3,373	$ 0	$ 0

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Acquisitions and Divestitures - Acquisitions Narrative (Details) - USD ($)	1 Months Ended			12 Months Ended
	Dec. 31, 2021	Dec. 31, 2021	Mar. 31, 2021	Dec. 31, 2021	Aug. 31, 2021	Dec. 31, 2020	Aug. 31, 2020
Business Acquisition [Line Items]
Repurchase of treasury shares (in shares)				1,150,991
Goodwill	$ 76,564,000	$ 76,564,000		$ 76,564,000		$ 0
Central Basin Platform
Business Acquisition [Line Items]
Cash consideration paid for asset acquisition		60,400,000
Additional proved oil and natural gas properties recorded as part of asset acquisition	73,700,000	73,700,000		73,700,000
ARO asset recorded as part of asset acquisition	12,600,000	12,600,000		12,600,000
DJ Basin Acquisition
Business Acquisition [Line Items]
Cash consideration paid for asset acquisition			$ 60,800,000
Purchase price allocation, proved oil and gas properties, percentage			35.60%
Purchase price allocation, unproved oil and gas properties, percentage			64.40%
Contango
Business Acquisition [Line Items]
Fair value of consideration transferred		654,616,000
Goodwill	76,564,000	76,564,000		76,564,000
Goodwill expected to be deductible for tax purposes	0	0		0
Revenue of acquiree since acquisition date	36,400,000
Net income of acquiree since acquisition date	$ 5,600,000
Acquisition related costs				12,900,000
Consideration transferred, equity interests issued and issuable		$ 654,616,000
Contango | Class A
Business Acquisition [Line Items]
Consideration transferred, equity interests issued and issuable (in shares)		39,834,461
Stock issued to settle acquiree equity based compensation plans (in shares)		3,270,915
Titan
Business Acquisition [Line Items]
Consideration transferred, equity interests issued and issuable (in shares)						400,000
Fair value of consideration transferred					$ 461,983,000
Goodwill							$ 0
Acquisition related costs						$ 8,700,000
Consideration transferred, equity interests issued and issuable					$ 461,983,000	$ 455,100,000
Additional consideration transferred equity interests issued and issuable				$ 7,200,000
Titan | DJ Basin Erie Hub Gathering System
Business Acquisition [Line Items]
Ownership interest acquired (as a percent)							50.00%

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Acquisitions and Divestitures - Pro Forma Financial Information (Details) - Contango - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Business Acquisition [Line Items]
Revenues	$ 1,943,741	$ 970,921
Net loss	$ (432,328)	$ (507,837)

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Acquisitions and Divestitures - Estimated Fair Value of Identified Assets Acquired and Liabilities Assumed (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Dec. 31, 2021	Aug. 31, 2021	Dec. 31, 2020	Aug. 31, 2020
Assets acquired and liabilities assumed:
Goodwill	$ 76,564		$ 0
Contango
Consideration transferred:
Equity consideration	654,616
Total	654,616
Assets acquired and liabilities assumed:
Cash and cash equivalents	14,202
Accounts receivable, net	145,727
Derivative assets – current	0
Prepaid and other current assets	8,275
Oil and natural gas properties - proved	1,002,165
Field and other property and equipment	6,955
Derivative assets – noncurrent	0
Goodwill	76,564
Investment in equity affiliates	15,047
Other assets	3,514
Accounts payable and accrued liabilities	(186,689)
Derivative liabilities – current	(44,002)
Long-term debt	(140,000)
Deferred tax liability	(83,250)
Derivative liabilities – noncurrent	(14,592)
Asset retirement obligations	(142,100)
Other liabilities	(7,200)
Fair value of net assets acquired	$ 654,616
Titan
Consideration transferred:
Equity consideration		$ 461,983	$ 455,100
Total		$ 461,983
Assets acquired and liabilities assumed:
Cash and cash equivalents				$ 482
Accounts receivable, net				29,044
Derivative assets – current				12,000
Prepaid and other current assets				49,079
Oil and natural gas properties - proved				375,014
Field and other property and equipment				30,232
Derivative assets – noncurrent				114
Goodwill				0
Investment in equity affiliates				0
Other assets				0
Accounts payable and accrued liabilities				(6,539)
Derivative liabilities – current				(4,550)
Long-term debt				0
Deferred tax liability				0
Derivative liabilities – noncurrent				(1,484)
Asset retirement obligations				(21,409)
Other liabilities				0
Fair value of net assets acquired				$ 461,983

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Acquisitions and Divestitures - Divestitures Narrative (Details) - USD ($) $ in Thousands	1 Months Ended					12 Months Ended
	Dec. 31, 2021	May 31, 2021	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on sale of assets						$ 8,794	$ 0	$ 22
Proceeds from the sale of oil and natural gas properties						25,723	$ 9,362	15,798
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Claiborne Parish Divestiture
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash consideration, net of closing adjustments	$ 4,300
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Arkoma Basin Divestiture
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash consideration, net of closing adjustments		$ 22,100
Gain on sale of assets		$ 8,800
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Midland and Ector County Divestiture
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from the sale of oil and natural gas properties			$ 3,900	$ 4,000
Value of property sold			$ 7,900
Consideration received on disposition				$ 7,900				$ 7,900
Primary term of agreement				4 years
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Eagle Ford Divestiture
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from the sale of oil and natural gas properties					$ 15,200
Post-closing settlement consideration receivable					$ 1,800
Post-closing settlement consideration						$ 1,200

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Property, Plant and Equipment - Oil and Natural Gas Properties (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Oil and Gas Property, Successful Effort Method, Net [Abstract]
Proved oil and natural gas properties (successful efforts method)	$ 6,043,602	$ 4,910,059
Unproved oil and natural gas properties	308,721	288,459
Oil and natural gas properties at cost, successful efforts method	6,352,323	5,198,518
Less accumulated depreciation, depletion, amortization and impairment	(1,881,934)	(1,633,664)
Oil and natural gas properties, net	$ 4,470,389	$ 3,564,854

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Property, Plant and Equipment - Other Property, Plant and Equipment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Financing right of use asset	$ 5,249	$ 0
Total property, plant and equipment	6,496,641	5,336,889
Less: accumulated depreciation, amortization and impairment	(1,941,528)	(1,694,742)
Property, plant and equipment, net	4,555,113	3,642,147
Field and other property, plant and equipment
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	144,318	138,371
Less: accumulated depreciation, amortization and impairment	(59,594)	(61,078)
Property, plant and equipment, net	$ 84,724	77,293
Gathering and pipeline system
Property, Plant and Equipment [Line Items]
Estimated useful life	30 years
Property, plant and equipment, gross	$ 106,023	108,777
Vehicles
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 10,836	7,273
Vehicles | Minimum
Property, Plant and Equipment [Line Items]
Estimated useful life	3 years
Vehicles | Maximum
Property, Plant and Equipment [Line Items]
Estimated useful life	5 years
Computers, furniture, and equipment
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 7,175	6,812
Computers, furniture, and equipment | Minimum
Property, Plant and Equipment [Line Items]
Estimated useful life	3 years
Computers, furniture, and equipment | Maximum
Property, Plant and Equipment [Line Items]
Estimated useful life	10 years
Buildings and improvements
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 6,641	6,797
Buildings and improvements | Minimum
Property, Plant and Equipment [Line Items]
Estimated useful life	5 years
Buildings and improvements | Maximum
Property, Plant and Equipment [Line Items]
Estimated useful life	30 years
Land
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 5,467	5,700
Field inventory
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 2,927	$ 3,012

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Property, Plant and Equipment - Capitalized Exploratory Well Costs (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Balance at beginning of period	$ 0	$ 0
Additions pending the determination of proved reserves	0	0
Reclassifications to proved properties	0	0
Cost charged to expense	0	0
Balance at end of period	$ 0	$ 0

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Derivatives - Net Volume Positions by Commodity (Details) bbl in Thousands, MMBTU in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2021 USD ($) MMBTU $ / bbl $ / MMBTU bbl
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Fair Value	$ (386,418)
2022 | Swap | Crude Oil
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volumes (Bbls) | bbl	1,468
Weighted Average Fixed Price (in USD per unit) | $ / bbl	1.08
Fair Value	$ 563
2022 | Swap | Crude Oil | WTI
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volumes (Bbls) | bbl	10,464
Weighted Average Fixed Price (in USD per unit) | $ / bbl	60.63
Fair Value	$ (121,508)
2022 | Swap | Crude Oil | Brent
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volumes (Bbls) | bbl	500
Weighted Average Fixed Price (in USD per unit) | $ / bbl	56.36
Fair Value	$ (9,258)
2022 | Swap | Natural Gas
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volumes (MBtu) | MMBTU	84,527
Weighted Average Fixed Price (in USD per unit) | $ / MMBTU	2.77
Fair Value	$ (76,861)
2022 | Swap | Natural gas liquids
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volumes (Bbls) | bbl	2,983
Weighted Average Fixed Price (in USD per unit) | $ / bbl	22.23
Fair Value	$ (38,596)
2022 | Basis Swap | Crude Oil
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volumes (Bbls) | bbl	5,843
Weighted Average Fixed Price (in USD per unit) | $ / bbl	(0.11)
Fair Value	$ (4,403)
2022 | Basis Swap | Natural Gas
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volumes (MBtu) | MMBTU	26,061
Weighted Average Fixed Price (in USD per unit) | $ / MMBTU	(0.17)
Fair Value	$ (3,243)
2022 | Collar | Natural Gas
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volumes (MBtu) | MMBTU	510
Fair Value	$ (220)
2022 | Collar | Minimum | Natural Gas
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Fixed Price (in USD per unit) | $ / MMBTU	3.00
2022 | Collar | Maximum | Natural Gas
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Fixed Price (in USD per unit) | $ / MMBTU	3.41
2023 | Swap | Crude Oil | WTI
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volumes (Bbls) | bbl	7,627
Weighted Average Fixed Price (in USD per unit) | $ / bbl	58.50
Fair Value	$ (59,395)
2023 | Swap | Crude Oil | Brent
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volumes (Bbls) | bbl	527
Weighted Average Fixed Price (in USD per unit) | $ / bbl	52.52
Fair Value	$ (9,103)
2023 | Swap | Natural Gas
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volumes (MBtu) | MMBTU	56,728
Weighted Average Fixed Price (in USD per unit) | $ / MMBTU	2.54
Fair Value	$ (47,722)
2023 | Collar | Natural Gas
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volumes (MBtu) | MMBTU	550
Fair Value	$ (469)
2023 | Collar | Minimum | Natural Gas
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Fixed Price (in USD per unit) | $ / MMBTU	2.63
2023 | Collar | Maximum | Natural Gas
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Fixed Price (in USD per unit) | $ / MMBTU	3.01
2024 | Swap | Crude Oil | WTI
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volumes (Bbls) | bbl	2,975
Weighted Average Fixed Price (in USD per unit) | $ / bbl	57.35
Fair Value	$ (16,542)
2024 | Swap | Crude Oil | Brent
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volumes (Bbls) | bbl	189
Weighted Average Fixed Price (in USD per unit) | $ / bbl	63.71
Fair Value	$ (766)
2024 | Swap | Natural Gas
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volumes (MBtu) | MMBTU	454
Weighted Average Fixed Price (in USD per unit) | $ / MMBTU	2.94
Fair Value	$ (82)
2024 | Collar | Natural Gas
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volumes (MBtu) | MMBTU	9,150
Fair Value	$ 1,187
2024 | Collar | Minimum | Natural Gas
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Fixed Price (in USD per unit) | $ / MMBTU	3.00
2024 | Collar | Maximum | Natural Gas
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Fixed Price (in USD per unit) | $ / MMBTU	3.87

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Derivatives - Narrative (Details) $ in Millions	Dec. 31, 2020 USD ($)
Interest Rate Swap
Derivative Instruments, Gain (Loss) [Line Items]
Aggregate unrealized loss on derivatives	$ 7.0

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Derivatives - Netting Arrangements (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Assets:
Gross Fair Value	$ 7,817	$ 87,090
Effect of Counterparty Netting	(7,238)	(33,812)
Net Carrying Value	579	53,278
Liabilities:
Gross Fair Value	(394,234)	(84,162)
Effect of Counterparty Netting	7,238	33,812
Net Carrying Value	(386,996)	(50,350)
Derivative assets – current
Assets:
Gross Fair Value	2,983	52,833
Effect of Counterparty Netting	(2,983)	(21,907)
Net Carrying Value	0	30,926
Derivative assets – noncurrent
Assets:
Gross Fair Value	4,834	34,257
Effect of Counterparty Netting	(4,255)	(11,905)
Net Carrying Value	579	22,352
Derivative liabilities – current
Liabilities:
Gross Fair Value	(256,508)	(48,299)
Effect of Counterparty Netting	2,983	21,907
Net Carrying Value	(253,525)	(26,392)
Derivative liabilities – noncurrent
Liabilities:
Gross Fair Value	(137,726)	(35,863)
Effect of Counterparty Netting	4,255	11,905
Net Carrying Value	$ (133,471)	$ (23,958)

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Derivatives - Gain (Loss) on Derivatives Included in Statement of Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivatives	$ (866,020)	$ 195,284	$ (127,202)
Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss) on derivatives	(535,652)	184,374	(29,176)
Unrealized gain (loss) on derivatives	(330,368)	10,910	(98,026)
Gain (loss) on derivatives	(866,020)	195,284	(127,202)
Interest Hedges | Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss) on derivatives, cash settled	(7,373)	(12,435)	(2,189)
Unrealized gain (loss) on derivatives	7,347	2,074	(3,260)
Commodity Hedges | Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on derivatives	(337,715)	8,836	(94,766)
Oil | Energy Hedges | Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss) on derivatives, cash settled	(180,572)	149,713	(44,265)
Realized gain (loss) on derivatives, early settlement	(198,688)	0	0
Natural Gas | Energy Hedges | Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss) on derivatives, cash settled	(80,253)	32,638	4,245
Natural gas liquids | Energy Hedges | Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss) on derivatives, cash settled	$ (68,766)	$ 14,458	$ 13,033

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Fair Value Measurements - Schedule of Fair Value of Assets and Liabilities Measured on Recurring Basis (Details) - Fair Value, Recurring - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Financial assets:
Derivative assets	$ 7,817	$ 87,090
Financial Liabilities:
Derivative liabilities	(394,234)	(84,162)
Level 1
Financial assets:
Derivative assets	0	0
Financial Liabilities:
Derivative liabilities	0	0
Level 2
Financial assets:
Derivative assets	7,817	87,090
Financial Liabilities:
Derivative liabilities	(394,234)	(84,162)
Level 3
Financial assets:
Derivative assets	0	0
Financial Liabilities:
Derivative liabilities	$ 0	$ 0

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Fair Value Measurements - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Impairment expense of oil and natural gas properties	$ 0	$ 247,215	$ 0
Fair value based on quoted market prices	$ 521,500

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Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Payables and Accruals [Abstract]
Accounts payable	$ 87,336	$ 15,019
Accrued lease operating expense	46,231	20,126
Accrued asset operating expense	8,997	3,591
Accrued capital expenditure	60,647	12,267
Accrued general and administrative	12,193	9,549
Accrued transportation expense	19,684	8,399
Accrued deficiency fees	955	5,050
Accrued revenue and royalties payable	75,827	2,142
Accrued interest and other	26,011	4,545
Total accounts payable and accrued liabilities	$ 337,881	$ 80,688

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Debt - Senior Notes (Details) - USD ($)		1 Months Ended	12 Months Ended
	May 06, 2021	Feb. 28, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Debt Instrument [Line Items]
Proceeds from issuance of the Senior Notes, net of discount			$ 490,625,000	$ 0	$ 0
7.25% Senior Notes due 2026 | Senior Notes
Debt Instrument [Line Items]
Face amount of debt instrument	$ 500,000,000
7.25% Senior Notes due 2026 | Senior Notes | Subsequent Event
Debt Instrument [Line Items]
Face amount of debt instrument		$ 200,000,000
Stated interest rate (as a percent)		7.25%
Proceeds from issuance of the Senior Notes, net of discount		$ 200,000,000
7.25% Senior Notes due 2026 | Senior Notes | On or After May 1, 2023
Debt Instrument [Line Items]
Percentage of principal amount redeemable (as a percent)	40.00%
Redemption price, percentage (as a percent)	107.25%
7.25% Senior Notes due 2026 | Senior Notes | Prior to May 1, 2023
Debt Instrument [Line Items]
Redemption price, percentage (as a percent)	100.00%
7.25% Senior Notes due 2026 | Senior Notes | Independence Energy Finance LLC
Debt Instrument [Line Items]
Face amount of debt instrument	$ 500,000,000
Stated interest rate (as a percent)	7.25%

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Debt - Revolving Credit Facility (Details) - Line of Credit - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Sep. 01, 2021	May 06, 2021
Revolving Credit Facility
Debt Instrument [Line Items]
Committed amount of credit facility		$ 700,000	$ 500,000
Borrowing base of credit facility	$ 1,300,000	$ 1,300,000	$ 850,000
Borrowings under credit facility	$ 543,000
Minimum mortgage maintenance rate of net present value (as a percent)			85.00%
Discount rate (as a percent)			9.00%
Minimum aggregate purchase price of the effective borrowing base (as a percent)			5.00%
Unused capacity commitment fee (as a percent)	0.50%
Weighted-average interest rate (as a percent)	3.125%
Letter of Credit
Debt Instrument [Line Items]
Letters of credit outstanding	$ 20,653

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Debt - Summary (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Sep. 01, 2021	May 06, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Less: Unamortized discount and issuance costs	$ (12,594)
Total long-term debt	1,030,406			$ 751,075
Revolving Credit Facility | Line of Credit
Debt Instrument [Line Items]
Long-term debt, gross	543,000
Borrowing Base	1,300,000	$ 1,300,000	$ 850,000
Revolving Credit Facility | Line of Credit | Independence Upstream Holdings LLC
Debt Instrument [Line Items]
Total long-term debt				32,500
Borrowing Base				100,000
Revolving Credit Facility | Line of Credit | Independence Minerals Holdings LLC
Debt Instrument [Line Items]
Total long-term debt				15,000
Borrowing Base				37,000
Revolving Credit Facility | Line of Credit | KNR Resource Investors LP
Debt Instrument [Line Items]
Total long-term debt				5,565
Borrowing Base				12,000
Revolving Credit Facility | Line of Credit | Renee Acquisition LLC
Debt Instrument [Line Items]
Total long-term debt				101,310
Borrowing Base				145,000
Revolving Credit Facility | Line of Credit | Newark Acquisition I LP
Debt Instrument [Line Items]
Total long-term debt				135,400
Borrowing Base				190,000
Revolving Credit Facility | Line of Credit | Bridge Energy Holdings LLC
Debt Instrument [Line Items]
Total long-term debt				35,800
Borrowing Base				50,000
Revolving Credit Facility | Line of Credit | Venado EF LP
Debt Instrument [Line Items]
Total long-term debt				156,500
Borrowing Base				160,000
Revolving Credit Facility | Line of Credit | VOG Palo Verde LP
Debt Instrument [Line Items]
Total long-term debt				269,000
Borrowing Base				320,000
Letter of Credit | Line of Credit
Debt Instrument [Line Items]
Letters of Credit Issued	20,653
Letter of Credit | Line of Credit | Independence Upstream Holdings LLC
Debt Instrument [Line Items]
Letters of Credit Issued				0
Letter of Credit | Line of Credit | Independence Minerals Holdings LLC
Debt Instrument [Line Items]
Letters of Credit Issued				0
Letter of Credit | Line of Credit | KNR Resource Investors LP
Debt Instrument [Line Items]
Letters of Credit Issued				250
Letter of Credit | Line of Credit | Renee Acquisition LLC
Debt Instrument [Line Items]
Letters of Credit Issued				5,667
Letter of Credit | Line of Credit | Newark Acquisition I LP
Debt Instrument [Line Items]
Letters of Credit Issued				6,280
Letter of Credit | Line of Credit | Bridge Energy Holdings LLC
Debt Instrument [Line Items]
Letters of Credit Issued				5,574
Letter of Credit | Line of Credit | Venado EF LP
Debt Instrument [Line Items]
Letters of Credit Issued				0
Letter of Credit | Line of Credit | VOG Palo Verde LP
Debt Instrument [Line Items]
Letters of Credit Issued				$ 0
Senior Notes | 7.25% Senior Notes due 2026
Debt Instrument [Line Items]
Long-term debt, gross	$ 500,000
Senior Notes | 7.25% Senior Notes due 2026 | Independence Energy Finance LLC
Debt Instrument [Line Items]
Stated interest rate (as a percent)			7.25%

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Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at beginning of period	$ 109,616	$ 83,141
Additions	156,201	21,860
Retirements	(1,252)	(881)
Accretion expense	7,121	5,694
Revisions	0	(198)
Noncontrolling Interest Carve-out	(3,810)	0
Sale	(1,869)	0
Balance at end of period	266,007	109,616
Less: current portion	(7,905)	(3,213)
Asset retirement obligations	$ 258,102	$ 106,403

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Income Taxes - Income Tax Provisions and Deferred Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Federal income tax provision (benefit)
Current	$ 0	$ 0	$ 0
Deferred	(935)	0	0
State income tax provision (benefit)
Current	629	14	28
Deferred	0	0	0
Total income tax provision (benefit)	$ (306)	$ 14	$ 28

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Income Taxes - Effective Income Tax Rate (Details)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Federal income taxes statutory rate (as a percent)	21.00%	0.00%	0.00%
State current income tax provision, net of federal benefit (as a percent)	(0.10%)	0.00%	0.00%
Permanent adjustments (as a percent)	(1.70%)	0.00%	0.00%
Income attributable to Predecessor that was not subject to corporate income tax (as a percent)	(18.40%)	0.00%	0.00%
Income attributable to noncontrolling interests (as a percent)	(0.70%)	0.00%	0.00%
Effective income tax rate (as a percent)	0.10%	0.00%	0.00%

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Income Taxes - Deferred Income Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Deferred tax liabilities
Outside Basis in OpCo	$ 98,079	$ 0
Deferred tax assets
Federal and state NOL	38,317	0
Federal and state NOL valuation allowance	(30,567)	0
Recognized built-in loss carryforward	6,872	0
Other	920	0
Total deferred tax assets, net of valuation allowance	15,542	0
Net deferred income tax liability	82,537	$ 0
Expiration Dates Beginning In 2026 | Federal
Deferred tax assets
Federal and state NOL	1,900
Generated After 2017
Deferred tax assets
Federal and state NOL	$ 36,400

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Income Taxes - Narrative (Details) - USD ($)	Dec. 31, 2021	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Federal and state NOL valuation allowance	$ 30,567,000	$ 0
Uncertain tax positions	$ 0	$ 0

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Leases - Statement of Financial Position (Details) $ in Thousands	Dec. 31, 2021 USD ($)
Field and other property and equipment, at cost
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Property, Plant, and Equipment and Finance Lease Right-of-Use Asset, after Accumulated Depreciation and Amortization
Financing right-of-use asset	$ 5,249
Other assets
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Other assets
Operating right-of-use asset	$ 2,299
Other current liabilities
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Other current liabilities
Short-term operating lease liability	$ (1,292)
Other liabilities
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Other liabilities
Long-term operating lease liability	$ (1,007)

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Leases - Lease Cost (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2021 USD ($)
Leases [Abstract]
Operating lease cost	$ 939
Financing lease cost - amortization of ROU assets	20
Financing lease cost - interest on lease liabilities	131
Administrative lease cost	100
Short-term lease cost	876
Total lease cost	$ 2,066
Operating
Weighted-average remaining lease term (years)	2 years 3 months 18 days
Weighted-average discount rate (as a percent)	4.50%
Financing
Weighted-average remaining lease term (years)	3 years 1 month 6 days
Weighted-average discount rate (as a percent)	4.50%

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Leases - Maturities of Operating Lease Liabilities (Details) $ in Thousands	Dec. 31, 2021 USD ($)
Operating
2022	$ 1,292
2023	666
2024	412
2025	18
2026	18
After 2026	24
Less: interest	(131)
Present value of lease liabilities	2,299
Financing
2022	1,606
2023	1,887
2024	1,370
2025	633
2026	16
After 2026	0
Less: interest	(394)
Present value of lease liabilities	$ 5,118

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Commitments and Contingencies - Narrative (Details) Mcf in Thousands		12 Months Ended
	Feb. 14, 2022 USD ($)	Dec. 31, 2021 USD ($) purchase_agreement Mcf	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Loss Contingencies [Line Items]
Accrual for environmental loss contingencies			$ 1,400,000
Environmental remediation expense		$ 1,400,000
Number of purchase agreements | purchase_agreement		1
Long-term purchase commitment, minimum daily volume required | Mcf		140
Transportation expense		$ 5,800,000	$ 14,500,000	$ 1,900,000
Subsequent Event
Loss Contingencies [Line Items]
Civil penalty expense	$ 913,200
Whitfield v. Contango Oil & Gas Co.
Loss Contingencies [Line Items]
Loss contingency accrual		$ 0

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Commitments and Contingencies - Future Commitments (Details) - Oil and Natural Gas Transportation and Gathering Commitments $ in Thousands	Dec. 31, 2021 USD ($)
Other Commitments [Line Items]
2022	$ 105,606
2023	80,340
2024	65,848
2025	61,346
2026	32,652
Thereafter	62,957
Total minimum future commitments	$ 408,749

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Incentive Compensation Arrangements - Equity-Based Compensation Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expense (income)	$ 39,919	$ (797)	$ (2,721)
ASC 710 profits interest awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expense (income)	0	0	0
ASC 718 liability-classified profits interest awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expense (income)	(2,043)	(797)	(2,721)
ASC 718 equity-classified profits interest awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expense (income)	1,563	0	0
ASC 718 equity-classified PSU awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expense (income)	1,120	0	0
ASC 718 equity-classified Contango PSU awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expense (income)	$ 39,279	$ 0	$ 0

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Incentive Compensation Arrangements - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
ASC 718 liability-classified profits interest awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of awards vested during period	$ 2.9	$ 7.7
Weighted average recognition period	3 years 10 months 24 days
Cash paid to settle liability for award	$ 0.9	0.0
Noncurrent share-based payment award liabilities	7.1	8.0
Capitalized oil and natural gas properties	1.8
ASC 718 liability-classified profits interest awards, time-based
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost	23.6
ASC 718 liability-classified profits interest awards, performance-based
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost	2.8
ASC 718 equity-classified profits interest awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of awards vested during period	1.8
Unrecognized compensation cost	0.0
Fair value of vested stock-based compensation awards		0.0
Cash used to settle award	0.2	$ 0.0
Additional property capitalized during period	$ 1.6
ASC 718 equity-classified PSU awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance/vesting period	3 years
Unrecognized compensation cost	$ 71.6
Weighted average recognition period	5 years
Target receipt as proportion of common stock issued and outstanding (as a percent)	2.00%
ASC 718 equity-classified Contango PSU awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Value of awards as proportion of common stock value (as a percent)	300.00%
Minimum | ASC 718 liability-classified profits interest awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance/vesting period	1 year
Minimum | ASC 718 equity-classified profits interest awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance/vesting period	1 year
Minimum | ASC 718 equity-classified PSU awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Value of awards as proportion of common stock value (as a percent)	0.00%
Maximum | ASC 718 liability-classified profits interest awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance/vesting period	4 years
Maximum | ASC 718 equity-classified profits interest awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance/vesting period	4 years
Maximum | ASC 718 equity-classified PSU awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Value of awards as proportion of common stock value (as a percent)	240.00%

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Incentive Compensation Arrangements - ASC 718 Stock-based Compensation Awards (Details) - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
ASC 718 liability-classified profits interest awards
Number of Shares
Unvested beginning balance (in shares)	888	1,215	1,163
Granted (in shares)	708	0	285
Vested (in shares)	(110)	(203)	(233)
Forfeited (in shares)	(778)	(125)	0
Unvested ending balance (in shares)	708	888	1,215
ASC 718 equity-classified profits interest awards
Number of Shares
Unvested beginning balance (in shares)	0
Granted (in shares)	477
Vested (in shares)	(25)
Forfeited (in shares)	(253)
Unvested ending balance (in shares)	200	0
Weighted average grant date fair value
Unvested beginning balance (in USD per share)	$ 0
Granted (in USD per share)	10.98
Vested (in USD per share)	10.61
Forfeitures (in USD per share)	11.02
Unvested ending balance (in USD per share)	$ 0	$ 0
ASC 718 equity-classified PSU awards
Number of Shares
Unvested beginning balance (in shares)	0
Granted (in shares)	4,195
Vested (in shares)	0
Forfeited (in shares)	0
Unvested ending balance (in shares)	4,195	0
Weighted average grant date fair value
Unvested beginning balance (in USD per share)	$ 0
Granted (in USD per share)	17.33
Vested (in USD per share)	0
Forfeitures (in USD per share)	0
Unvested ending balance (in USD per share)	$ 17.33	$ 0

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Related Party Transactions (Details) - Affiliated Entity	1 Months Ended			12 Months Ended
	Feb. 28, 2022 USD ($)	May 31, 2021 USD ($)	Apr. 30, 2021 USD ($)	Dec. 31, 2021 USD ($) tranche	Apr. 01, 2021 shares	Dec. 31, 2020 USD ($)
Management Agreement
Related Party Transaction [Line Items]
Agreement initial term (years)				3 years
Agreement additional initial term (years)				3 years
Asset operating expenses				$ 900,000
Management Agreement, Annual Compensation to Manager
Related Party Transaction [Line Items]
Amount of related party transaction				13,500,000
Management Agreement, Ownership of Subsidiary | OpCo
Related Party Transaction [Line Items]
Amount of related party transaction				$ 53,300,000
Management Agreement, Compensation Increase
Related Party Transaction [Line Items]
Related party transaction rate (as a percent)				1.50%
Management Agreement, Incentive Compensation
Related Party Transaction [Line Items]
Incentive target rate (as a percent)				10.00%
Number of tranches | tranche				5
Incentive compensation settled period (years)				5 years
Incentive compensation settled rate (as a percent)				2.00%
Management Agreement, Incentive Compensation | Minimum
Related Party Transaction [Line Items]
Initial target amount (as a percent)				0.00%
Management Agreement, Incentive Compensation | Maximum
Related Party Transaction [Line Items]
Initial target amount (as a percent)				240.00%
Oil and gas investments
Related Party Transaction [Line Items]
Amount due from related party				$ 3,300,000
Amount due to related party				7,000,000
Other Transactions | KKR Capital Markets LLC
Related Party Transaction [Line Items]
Amount of related party transaction				1,600,000
Other Transactions | KKR Capital Markets LLC | Subsequent Event
Related Party Transaction [Line Items]
Amount of related party transaction	$ 400,000
Other Transactions | KKR Capstone Americas LLC
Related Party Transaction [Line Items]
Amount of related party transaction				100,000
FDL - Management Agreement | FDL
Related Party Transaction [Line Items]
Ownership interest exchanged (as a percent)					100.00%
Gain (loss) on exchange transaction			$ 0
Due from (to) related party				$ 16,900,000		$ 7,500,000
FDL - Management Agreement | FDL | Class A
Related Party Transaction [Line Items]
Asset exchange, units issued (in shares) | shares					9,508
Ownership interest (as a percent)				0.15%	0.77%
Oil And Natural Gas Property Operating And Services Agreement, Additional Wind Down Costs | FDL
Related Party Transaction [Line Items]
Amount of related party transaction		$ 6,500,000
Oil And Natural Gas Property Operating And Services Agreement, Termination Costs | FDL
Related Party Transaction [Line Items]
Expenses from transactions with related party				$ 3,300,000
Master Management Services Agreement | RPM
Related Party Transaction [Line Items]
Amount due to related party				$ 1,700,000		$ 1,700,000

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Earnings Per Share - Narrative (Details)	12 Months Ended
	Dec. 31, 2021 class
Earnings Per Share [Abstract]
Number of classes of equity	2

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Earnings Per Share - Summary (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended	3 Months Ended								12 Months Ended
	Dec. 31, 2021	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Numerator:
Net income (loss)		$ 168,945	$ (162,043)	$ (272,861)	$ (166,268)	$ (169,682)	$ (101,005)	$ (412,227)	$ 466,790	$ (432,227)	$ (216,124)	$ 46,709
Less: net (income) loss attributable to Predecessor		(246,636)	160,567	269,608	155,629	133,215	69,990	236,166	(320,722)	339,168	118,649	(45,839)
Less: net (income) loss attributable to noncontrolling interests		(446)	1,476	3,253	10,639	36,467	31,015	176,061	(146,068)	14,922	97,475	(870)
Less: net loss attributable to redeemable noncontrolling interests	$ 58,761	58,761	0	0	0					58,761	0	0
Net loss attributable to Crescent Energy		$ (19,376)	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ (19,376)	$ 0	$ 0
Class A
Denominator:
Weighted-average common stock outstanding - basic (in shares)										41,954,385
Weighted-average Common Stock outstanding - diluted (in shares)										41,954,385
Net income (loss) per share:
Common stock - basic (in USD per share)		$ (0.46)	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ (0.46)
Common stock - diluted (in USD per share)		(0.46)	0	0	0	0	0	0	0	$ (0.46)
Class B
Denominator:
Weighted-average common stock outstanding - basic (in shares)										127,536,463
Weighted-average Common Stock outstanding - diluted (in shares)										127,536,463
Net income (loss) per share:
Common stock - basic (in USD per share)		0	0	0	0	0	0	0	0	$ 0
Common stock - diluted (in USD per share)		$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0

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Subsequent Events (Details) - USD ($) $ / shares in Units, $ in Thousands		6 Months Ended
	Mar. 09, 2022	Jun. 30, 2022	Feb. 28, 2022	Sep. 01, 2021	May 06, 2021
Uinta AssetCo, LLC | Javelin VentureCo, LLC | Forecast
Subsequent Event [Line Items]
Aggregate consideration transferred		$ 815,000
Revolving Credit Facility | Line of Credit
Subsequent Event [Line Items]
Committed amount of credit facility				$ 700,000	$ 500,000
Revolving Credit Facility | Line of Credit | Forecast
Subsequent Event [Line Items]
Committed amount of credit facility		$ 1,300,000
7.25% Senior Notes due 2026 | Senior Notes
Subsequent Event [Line Items]
Face amount of debt instrument					$ 500,000
Subsequent Event
Subsequent Event [Line Items]
Annual common stock dividends per share (in USD per share)	$ 0.48
Common stock dividends declared per share (in USD per share)	$ 0.12
Subsequent Event | Chama
Subsequent Event [Line Items]
Ownership interest by noncontrolling owners (as a percent)			9.40%
Fair value of ownership in noncontrolling interest			$ 3,750
Cash flows from producing assets to be received (as a percent)			90.00%
Subsequent Event | Board of Directors Chairman | Chama
Subsequent Event [Line Items]
Ownership interest by noncontrolling owners (as a percent)			17.50%
Subsequent Event | 7.25% Senior Notes due 2026 | Senior Notes
Subsequent Event [Line Items]
Face amount of debt instrument			$ 200,000
Stated interest rate (as a percent)			7.25%

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Selected Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended	3 Months Ended								12 Months Ended
	Dec. 31, 2021	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Condensed Financial Statements, Captions [Line Items]
Total revenues		$ 463,261	$ 365,726	$ 330,130	$ 317,860	$ 252,252	$ 190,612	$ 103,509	$ 207,848	$ 1,476,977	$ 754,221	$ 1,087,240
Income (loss) from operations		161,607	133,604	100,483	88,045	(56,849)	(26,669)	(293,463)	3,353	483,739	(373,628)	227,114
Net income (loss)		168,945	(162,043)	(272,861)	(166,268)	(169,682)	(101,005)	(412,227)	466,790	(432,227)	(216,124)	46,709
Less: net (income) loss attributable to Predecessor		(246,636)	160,567	269,608	155,629	133,215	69,990	236,166	(320,722)	339,168	118,649	(45,839)
Less: net (income) loss attributable to noncontrolling interests		(446)	1,476	3,253	10,639	36,467	31,015	176,061	(146,068)	14,922	97,475	(870)
Less: net loss attributable to redeemable noncontrolling interests	$ 58,761	58,761	0	0	0					58,761	0	0
Net loss attributable to Crescent Energy		$ (19,376)	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ (19,376)	$ 0	$ 0
Class A
Net income (loss) per share
Common stock - basic (in USD per share)		$ (0.46)	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ (0.46)
Common stock - diluted (in USD per share)		(0.46)	0	0	0	0	0	0	0	(0.46)
Class B
Net income (loss) per share
Common stock - basic (in USD per share)		0	0	0	0	0	0	0	0	0
Common stock - diluted (in USD per share)		$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0

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Supplemental Oil and Natural Gas Disclosures (Unaudited) - Narrative (Details)	Dec. 31, 2021
Exaro
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Ownership interest in equity method investment (as a percent)	37.00%

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Supplemental Oil and Natural Gas Disclosures (Unaudited) - Oil and Natural Gas Reserve Information (Details) bbl in Thousands, Mcf in Thousands, Boe in Thousands	12 Months Ended
	Dec. 31, 2021 Boe Mcf bbl	Dec. 31, 2020 Boe Mcf bbl	Dec. 31, 2019 Boe bbl Mcf
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Net proved reserves at beginning of period | Boe	359,658	466,199
Revisions of previous estimates | Boe	(92,000)
Extensions, discoveries, and other additions | Boe			17,900
Purchases of reserves in place | Boe	125,600
Net proved reserves at end of period | Boe	535,310	359,658	466,199
Additional proved reserves (as a percent)			77.00%
Proved undeveloped reserves, planned development period	5 years
Permian and DJ Basins
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Purchases of reserves in place | Boe	74,200
Central Basin Platform
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Purchases of reserves in place | Boe	5,600
DJ Basin Acquisition
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Purchases of reserves in place | Boe	2,500
MMBoe Upward Revision
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Revisions of previous estimates | Boe	92,700
MMBoe Downward Revision
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Revisions of previous estimates | Boe	(21,100)
Oil
Proved Developed and Undeveloped Reserves [Roll Forward]
Net proved reserves at beginning of period	167,190	211,533
Net proved reserves at end of period	210,364	167,190	211,533
Natural Gas
Proved Developed and Undeveloped Reserves [Roll Forward]
Net proved reserves at beginning of period | Mcf	822,864	1,161,239
Net proved reserves at end of period | Mcf	1,490,718	822,864	1,161,239
Natural gas liquids
Proved Developed and Undeveloped Reserves [Roll Forward]
Net proved reserves at beginning of period	55,324	61,126
Net proved reserves at end of period	76,493	55,324	61,126
Consolidated operations
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Net proved reserves at beginning of period | Boe	359,658	466,199	476,913
Revisions of previous estimates | Boe	78,389	(157,680)	2,581
Extensions, discoveries, and other additions | Boe	11,975	8,271	17,936
Sales of reserves in place | Boe	(17,762)	0	0
Purchases of reserves in place | Boe	133,630	74,168	0
Production | Boe	(34,245)	(31,300)	(31,231)
Net proved reserves at end of period | Boe	531,645	359,658	466,199
Proved Developed Reserves (Energy) | Boe	458,588	261,079	297,808
Proved Undeveloped Reserves (Energy) | Boe	73,057	98,579	168,391
Consolidated operations | Oil
Proved Developed and Undeveloped Reserves [Roll Forward]
Net proved reserves at beginning of period	167,190	211,533	202,805
Revisions of previous estimates	9,147	(57,708)	10,477
Extensions, discoveries, and other additions	7,007	4,088	12,003
Sales of reserves in place	(6,333)	0	0
Purchases of reserves in place	46,386	22,409	0
Production	(13,237)	(13,132)	(13,752)
Net proved reserves at end of period	210,160	167,190	211,533
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved Developed Reserves	158,091	92,024	103,728
Proved Undeveloped Reserves	52,069	75,166	107,805
Consolidated operations | Natural Gas
Proved Developed and Undeveloped Reserves [Roll Forward]
Net proved reserves at beginning of period | Mcf	822,864	1,161,239	1,189,962
Revisions of previous estimates | Mcf	316,572	(478,153)	20,552
Extensions, discoveries, and other additions | Mcf	17,247	21,479	24,472
Sales of reserves in place | Mcf	(48,977)	0	0
Purchases of reserves in place | Mcf	451,702	196,840	0
Production | Mcf	(89,455)	(78,541)	(73,747)
Net proved reserves at end of period | Mcf	1,469,953	822,864	1,161,239
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved Developed Reserves | Mcf	1,404,570	748,496	870,491
Proved Undeveloped Reserves | Mcf	65,383	74,368	290,748
Consolidated operations | Natural gas liquids
Proved Developed and Undeveloped Reserves [Roll Forward]
Net proved reserves at beginning of period	55,324	61,126	75,780
Revisions of previous estimates	16,480	(20,279)	(11,321)
Extensions, discoveries, and other additions	2,093	603	1,855
Sales of reserves in place	(3,265)	0	0
Purchases of reserves in place	11,960	18,952	0
Production	(6,099)	(5,078)	(5,188)
Net proved reserves at end of period	76,493	55,324	61,126
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved Developed Reserves	66,402	44,307	48,997
Proved Undeveloped Reserves	10,091	11,017	12,129
Equity affiliate
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Net proved reserves at beginning of period | Boe	0
Revisions of previous estimates | Boe	0
Extensions, discoveries, and other additions | Boe	0
Sales of reserves in place | Boe	0
Purchases of reserves in place | Boe	3,685
Production | Boe	(20)
Net proved reserves at end of period | Boe	3,665	0
Proved Developed Reserves (Energy) | Boe	3,665	0	0
Proved Undeveloped Reserves (Energy) | Boe	0	0	0
Equity affiliate | Oil
Proved Developed and Undeveloped Reserves [Roll Forward]
Net proved reserves at beginning of period	0
Revisions of previous estimates	0
Extensions, discoveries, and other additions	0
Sales of reserves in place	0
Purchases of reserves in place	205
Production	(1)
Net proved reserves at end of period	204	0
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved Developed Reserves	204	0	0
Proved Undeveloped Reserves	0	0	0
Equity affiliate | Natural Gas
Proved Developed and Undeveloped Reserves [Roll Forward]
Net proved reserves at beginning of period | Mcf	0
Revisions of previous estimates | Mcf	0
Extensions, discoveries, and other additions | Mcf	0
Sales of reserves in place | Mcf	0
Purchases of reserves in place | Mcf	20,880
Production | Mcf	(115)
Net proved reserves at end of period | Mcf	20,765	0
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved Developed Reserves | Mcf	20,765	0	0
Proved Undeveloped Reserves | Mcf	0	0	0
Equity affiliate | Natural gas liquids
Proved Developed and Undeveloped Reserves [Roll Forward]
Net proved reserves at beginning of period	0
Revisions of previous estimates	0
Extensions, discoveries, and other additions	0
Sales of reserves in place	0
Purchases of reserves in place	0
Production	0
Net proved reserves at end of period	0	0
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved Developed Reserves	0	0	0
Proved Undeveloped Reserves	0	0	0

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Supplemental Oil and Natural Gas Disclosures (Unaudited) - Capitalized Costs Relating to Oil and Gas Producing Activities (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Consolidated operations
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved oil and natural gas properties (successful efforts method)	$ 6,043,602	$ 4,910,059
Unproved oil and natural gas properties	308,721	288,459
Oil and natural gas properties, at cost	6,352,323	5,198,518
Less accumulated depreciation, depletion and amortization	(1,881,933)	(1,666,620)
Net capitalized costs	4,470,390	3,531,898
Equity affiliate
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved oil and natural gas properties (successful efforts method)	9,043	0
Unproved oil and natural gas properties	0	0
Oil and natural gas properties, at cost	9,043	0
Less accumulated depreciation, depletion and amortization	(67)	0
Net capitalized costs	$ 8,976	$ 0

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Supplemental Oil and Natural Gas Disclosures (Unaudited) - Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Consolidated operations
Acquisition costs:
Proved	$ 1,098,696	$ 355,010	$ 795
Unproved	41,355	680	7,264
Exploration costs	1,180	0	710
Development	194,828	83,013	318,157
Total costs incurred	1,336,059	438,703	326,926
Equity affiliate
Acquisition costs:
Proved	0	0	0
Unproved	0	0	0
Exploration costs	0	0	0
Development	0	0	0
Total costs incurred	$ 0	$ 0	$ 0

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Supplemental Oil and Natural Gas Disclosures (Unaudited) - Average First-Day-of-the-Month Price for Oil, Natural Gas and Natural Gas Liquids (Details)	12 Months Ended
	Dec. 31, 2021 $ / MMBTU $ / bbl	Dec. 31, 2020 $ / bbl $ / MMBTU	Dec. 31, 2019 $ / bbl $ / MMBTU
Crude Oil
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Average benchmark price (in USD per unit) | $ / bbl	66.56	39.56	55.69
Natural Gas
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Average benchmark price (in USD per unit) | $ / MMBTU	3.60	1.99	2.62

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Supplemental Oil and Natural Gas Disclosures (Unaudited) - Discounted Future Net Cash Flows (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2021 USD ($) $ / MMBTU $ / bbl	Dec. 31, 2020 USD ($) $ / bbl $ / MMBTU	Dec. 31, 2019 USD ($) $ / bbl $ / MMBTU	Dec. 31, 2018 USD ($)
Crude Oil
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Average benchmark price (in USD per unit) | $ / bbl	66.56	39.56	55.69
Crude Oil | Arithmetic Average
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Average benchmark price (in USD per unit) | $ / bbl	66.55
Natural Gas
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Average benchmark price (in USD per unit) | $ / MMBTU	3.60	1.99	2.62
Natural Gas | Arithmetic Average
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Average benchmark price (in USD per unit) | $ / MMBTU	3.64
Consolidated operations
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	$ 21,063,117	$ 8,232,932	$ 15,745,942
Future production costs	(10,194,648)	(4,280,563)	(6,766,410)
Future development costs	(1,477,562)	(1,353,957)	(2,323,420)
Future income taxes	(352,136)	(30,155)	(63,136)
Future net cash flows	9,038,771	2,568,257	6,592,976
Annual discount of 10% for estimated timing	(4,080,471)	(1,240,397)	(3,482,128)
Standardized measure of discounted future net cash flows	4,958,300	1,327,860	3,110,848	$ 4,207,347
Equity affiliate
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	99,290	0	0
Future production costs	(55,371)	0	0
Future development costs	(2,309)	0	0
Future income taxes	(1,730)	0	0
Future net cash flows	39,880	0	0
Annual discount of 10% for estimated timing	(16,702)	0	0
Standardized measure of discounted future net cash flows	$ 23,178	$ 0	$ 0	$ 0

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Supplemental Oil and Natural Gas Disclosures (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Consolidated operations
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward]
Balance at beginning of period	$ 1,327,860	$ 3,110,848	$ 4,207,347
Net change in prices and production costs	3,330,299	(1,184,939)	(821,874)
Net change in future development costs	117,333	160,465	(59,359)
Sales and transfers of oil and natural gas produced, net of production expenses	(872,521)	(290,053)	(568,665)
Extensions, discoveries, additions and improved recovery, net of related costs	162,657	31,688	182,697
Purchases of reserves in place	1,236,388	176,480	0
Sales of reserves in place	(84,095)	0	0
Revisions of previous quantity estimates	(295,234)	(887,395)	(226,561)
Previously estimated development costs incurred	95,879	32,873	15,676
Net change in taxes	(184,419)	19,350	(19)
Accretion of discount	124,153	283,954	424,278
Changes in timing and other	0	(125,411)	(42,672)
Balance at end of period	4,958,300	1,327,860	3,110,848
Equity affiliate
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward]
Balance at beginning of period	0	0	0
Net change in prices and production costs	0	0	0
Net change in future development costs	0	0	0
Sales and transfers of oil and natural gas produced, net of production expenses	(1,246)	0	0
Extensions, discoveries, additions and improved recovery, net of related costs	0	0	0
Purchases of reserves in place	26,154	0	0
Sales of reserves in place	0	0	0
Revisions of previous quantity estimates	0	0	0
Previously estimated development costs incurred	0	0	0
Net change in taxes	(1,730)	0	0
Accretion of discount	0	0	0
Changes in timing and other	0	0	0
Balance at end of period	$ 23,178	$ 0	$ 0

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SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT - Parent Company Balance Sheets (Details) - USD ($) $ / shares in Units, $ in Thousands	Dec. 31, 2021	Dec. 07, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
ASSETS
TOTAL ASSETS	$ 5,157,462		$ 3,907,369
Current liabilities:
Accounts payable – affiliates	8,675		9,019
Total current liabilities	616,125		120,671
Deferred tax liability	82,537		0
Total liabilities	2,137,805		1,014,209
Commitments and contingencies (Note 12)
Redeemable noncontrolling interests	2,325,013	$ 2,353,977	0
Equity:
Members’ equity – Class A units, no units and 1,220,421 units outstanding as of December 31, 2021 and 2020, respectively			2,716,892
Preferred stock, $0.0001 par value; 500,000,000 shares authorized and 1,000 Series I preferred shares issued and outstanding as of December 31, 2021; no shares issued and outstanding as of December 31, 2020	0
Treasury stock, at cost; 1,150,991 shares of Class A common stock as of December 31, 2021 and no shares of Class A Common Stock as of December 31, 2020	(18,448)
Additional paid-in capital	720,016
Accumulated deficit	(19,376)
Noncontrolling interests	12,435
Noncontrolling interests			176,268
Total equity	694,644
Total equity			2,893,160	$ 2,712,066	$ 2,807,844
TOTAL LIABILITIES, REDEEMABLE NONCONTROLLING INTERESTS AND EQUITY	$ 5,157,462		$ 3,907,369
Members’ equity outstanding (in shares)	0		1,220,421
Preferred stock, par value (in USD per share)	$ 0.0001		$ 0.0001
Preferred stock authorized (in shares)	500,000,000		500,000,000
Preferred stock issued (in shares)	1,000		0
Preferred stock outstanding (in shares)	1,000		0
Parent Company
ASSETS
Investment in subsidiary	$ 3,103,176		$ 2,893,160
TOTAL ASSETS	3,103,176		2,893,160
Current liabilities:
Accounts payable – affiliates	914		0
Accrued liabilities	68		0
Total current liabilities	982		0
Deferred tax liability	82,537		0
Total liabilities	83,519		0
Commitments and contingencies (Note 12)
Redeemable noncontrolling interests	2,325,013		0
Equity:
Members’ equity – Class A units, no units and 1,220,421 units outstanding as of December 31, 2021 and 2020, respectively			2,716,892
Preferred stock, $0.0001 par value; 500,000,000 shares authorized and 1,000 Series I preferred shares issued and outstanding as of December 31, 2021; no shares issued and outstanding as of December 31, 2020	0
Treasury stock, at cost; 1,150,991 shares of Class A common stock as of December 31, 2021 and no shares of Class A Common Stock as of December 31, 2020	(18,448)
Additional paid-in capital	720,016
Accumulated deficit	19,376
Noncontrolling interests	12,435
Noncontrolling interests			176,268
Total equity	694,644
Total equity			2,893,160
TOTAL LIABILITIES, REDEEMABLE NONCONTROLLING INTERESTS AND EQUITY	$ 3,103,176		$ 2,893,160
Members’ equity outstanding (in shares)	0		1,220,421
Preferred stock, par value (in USD per share)	$ 0.0001		$ 0.0001
Preferred stock authorized (in shares)	500,000,000		500,000,000
Preferred stock issued (in shares)	1,000		0
Preferred stock outstanding (in shares)	1,000		0
Class A
Equity:
Common stock	$ 4
Common stock, par value (in USD per share)	$ 0.0001		$ 0.0001
Common stock authorized (in shares)	1,000,000,000		1,000,000,000
Common stock issued (in shares)	43,105,376		0
Common stock outstanding (in shares)	41,954,385		0
Treasury stock (in shares)	1,150,991		0
Class A | Parent Company
Equity:
Common stock	$ 4
Common stock, par value (in USD per share)	$ 0.0001		$ 0.0001
Common stock authorized (in shares)	1,000,000,000		1,000,000,000
Common stock issued (in shares)	43,105,376		0
Common stock outstanding (in shares)	41,954,385		0
Treasury stock (in shares)	1,150,991		0
Class B
Equity:
Common stock	$ 13
Common stock, par value (in USD per share)	$ 0.0001		$ 0.0001
Common stock authorized (in shares)	500,000,000		500,000,000
Common stock issued (in shares)	127,536,463		0
Common stock outstanding (in shares)	127,536,463		0
Class B | Parent Company
Equity:
Common stock	$ 13
Common stock, par value (in USD per share)	$ 0.0001		$ 0.0001
Common stock authorized (in shares)	500,000,000		500,000,000
Common stock issued (in shares)	127,536,463		0
Common stock outstanding (in shares)	127,536,463		0

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SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT - Parent Company Statements Of Operations (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended	3 Months Ended								12 Months Ended
	Dec. 31, 2021	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Condensed Income Statements, Captions [Line Items]
Total revenues		$ 463,261	$ 365,726	$ 330,130	$ 317,860	$ 252,252	$ 190,612	$ 103,509	$ 207,848	$ 1,476,977	$ 754,221	$ 1,087,240
Expenses:
General and administrative expense										78,342	16,542	2,357
Total expenses										993,238	1,127,849	860,126
Income tax benefit (expense)										306	(14)	(28)
Equity in income (losses) of subsidiary, net of tax											(216,124)	46,709
Net income (loss)		168,945	(162,043)	(272,861)	(166,268)	(169,682)	(101,005)	(412,227)	466,790	(432,227)	(216,124)	46,709
Less: net (income) loss attributable to Predecessor		(246,636)	160,567	269,608	155,629	133,215	69,990	236,166	(320,722)	339,168	118,649	(45,839)
Less: net (income) loss attributable to noncontrolling interests		(446)	1,476	3,253	10,639	36,467	31,015	176,061	(146,068)	14,922	97,475	(870)
Less: net loss attributable to redeemable noncontrolling interests	$ 58,761	58,761	0	0	0					58,761	0	0
Net loss attributable to Crescent Energy		$ (19,376)	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	(19,376)	0	0
Parent Company
Condensed Income Statements, Captions [Line Items]
Total revenues										0	0	0
Expenses:
General and administrative expense										914	0	0
Total expenses										914	0	0
Income (loss) from operations										(914)	0	0
Income tax benefit (expense)										867	0	0
Income (loss) before equity in income (losses) of subsidiary										(47)	0	0
Equity in income (losses) of subsidiary, net of tax										(432,180)	(216,124)	46,709
Net income (loss)										(432,227)	(216,124)	46,709
Less: net (income) loss attributable to Predecessor										339,168	118,649	(45,839)
Less: net (income) loss attributable to noncontrolling interests										14,922	97,475	(870)
Less: net loss attributable to redeemable noncontrolling interests										58,761	0	0
Net loss attributable to Crescent Energy										$ (19,376)	$ 0	$ 0
Class A
Net Loss per Share:
Common stock - basic (in USD per share)		$ (0.46)	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ (0.46)
Common stock - diluted (in USD per share)		(0.46)	0	0	0	0	0	0	0	$ (0.46)
Weighted Average Shares Outstanding:
Common stock - basic (in shares)										41,954,385
Common stock - diluted (in shares)										41,954,385
Class A | Parent Company
Net Loss per Share:
Common stock - basic (in USD per share)										$ (0.46)
Common stock - diluted (in USD per share)										$ (0.46)
Weighted Average Shares Outstanding:
Common stock - basic (in shares)										41,954,000
Common stock - diluted (in shares)										41,954,000
Class B
Net Loss per Share:
Common stock - basic (in USD per share)		0	0	0	0	0	0	0	0	$ 0
Common stock - diluted (in USD per share)		$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0
Weighted Average Shares Outstanding:
Common stock - basic (in shares)										127,536,463
Common stock - diluted (in shares)										127,536,463
Class B | Parent Company
Net Loss per Share:
Common stock - basic (in USD per share)										$ 0
Common stock - diluted (in USD per share)										$ 0
Weighted Average Shares Outstanding:
Common stock - basic (in shares)										127,536,000
Common stock - diluted (in shares)										127,536,000

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SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT - Parent Company Statements Of Cash Flows (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash flows from operating activities:
Net income (loss)	$ 168,945	$ (162,043)	$ (272,861)	$ (166,268)	$ (169,682)	$ (101,005)	$ (412,227)	$ 466,790	$ (432,227)	$ (216,124)	$ 46,709
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Equity in (income) losses of subsidiary										216,124	(46,709)
Deferred income taxes (benefit)									(935)	0	0
Changes in operating assets and liabilities:
Accounts payable – affiliates									(358)	657	27
Net cash provided by operating activities									233,147	411,028	485,515
Net cash provided by investing activities									(244,595)	(124,940)	(328,158)
Net cash provided by financing activities									105,145	(272,089)	(153,192)
Net change in cash, cash equivalents and restricted cash									93,697	13,999	4,165
Cash, cash equivalents and restricted cash, beginning of period				41,420				27,421	41,420	27,421	23,256
Cash, cash equivalents, and restricted cash, end of period	135,117				41,420				135,117	41,420	27,421
Parent Company
Cash flows from operating activities:
Net income (loss)									(432,227)	(216,124)	46,709
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Equity in (income) losses of subsidiary									432,180	216,124	(46,709)
Deferred income taxes (benefit)									(935)	0	0
Changes in operating assets and liabilities:
Accounts payable – affiliates									914	0	0
Accrued liabilities									68	0	0
Net cash provided by operating activities									0	0	0
Net cash provided by investing activities									0	0	0
Net cash provided by financing activities									0	0	0
Net change in cash, cash equivalents and restricted cash									0	0	0
Cash, cash equivalents and restricted cash, beginning of period				$ 0				$ 0	0	0	0
Cash, cash equivalents, and restricted cash, end of period	$ 0				$ 0				$ 0	$ 0	$ 0

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SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT - Narrative (Details) - OpCo	12 Months Ended
	Dec. 31, 2021
Condensed Income Statements, Captions [Line Items]
Ownership of outstanding shares (as a percent)	25.00%
Parent Company
Condensed Income Statements, Captions [Line Items]
Ownership of outstanding shares (as a percent)	25.00%
Independence Minerals Holdings LLC And Crescent Energy Finance LLC
Condensed Income Statements, Captions [Line Items]
Ownership of outstanding shares (as a percent)	75.00%
Independence Minerals Holdings LLC And Crescent Energy Finance LLC | Parent Company
Condensed Income Statements, Captions [Line Items]
Ownership of outstanding shares (as a percent)	75.00%

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Label	Element	Value
Net Income (Loss), Including Portion Attributable to Nonredeemable Noncontrolling Interest	us-gaap_NetIncomeLossIncludingPortionAttributableToNonredeemableNoncontrollingInterest	$ (339,168,000)
Net Income (Loss), Including Portion Attributable to Nonredeemable Noncontrolling Interest	us-gaap_NetIncomeLossIncludingPortionAttributableToNonredeemableNoncontrollingInterest	(34,298,000)
Noncontrolling Interest [Member]
Net Income (Loss), Including Portion Attributable to Nonredeemable Noncontrolling Interest	us-gaap_NetIncomeLossIncludingPortionAttributableToNonredeemableNoncontrollingInterest	(14,922,000)
Member Units [Member]
Net Income (Loss), Including Portion Attributable to Nonredeemable Noncontrolling Interest	us-gaap_NetIncomeLossIncludingPortionAttributableToNonredeemableNoncontrollingInterest	(339,168,000)
Retained Earnings [Member]
Net Income (Loss), Including Portion Attributable to Nonredeemable Noncontrolling Interest	us-gaap_NetIncomeLossIncludingPortionAttributableToNonredeemableNoncontrollingInterest	$ (19,376,000)