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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 _______________________________________

FORM 10-K

 _______________________________________

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

For the fiscal year ended December 31, 2022

OR

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

Commission file number: 001-34776

Chord Energy Corporation

(Exact name of registrant as specified in its charter)

Delaware	80-0554627
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
1001 Fannin Street, Suite 1500
Houston, Texas	77002
(Address of principal executive offices)	(Zip Code)

(281) 404-9500

(Registrant’s telephone number, including area code)

Securities Registered Pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, par value $0.01 per share	CHRD	The Nasdaq Stock Market LLC

Securities Registered Pursuant to Section 12(g) of the Act:

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ý    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  ý 

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  ý    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  ý   No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or 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 13(a) of the Exchange 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. ☒

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ☐  No  ý

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes  ý   No  ¨

Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter: $2,377,796,568

Number of shares of registrant’s common stock outstanding as of February 24, 2023: 41,626,556

_______________________________________ 

Documents Incorporated By Reference:

Portions of the registrant’s definitive proxy statement for its 2023 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2022, are incorporated by reference into Part III of this report for the year ended December 31, 2022.

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CHORD ENERGY CORPORATION

FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2022

TABLE OF CONTENTS

 

Cautionary Note Regarding Forward-Looking Statements		2
Risk Factors Summary		4
	PART I
Item 1.	Business	6
Item 1A.	Risk Factors	33
Item 1B.	Unresolved Staff Comments	54
Item 2.	Properties	54
Item 3.	Legal Proceedings	55
Item 4.	Mine Safety Disclosures	55
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	56
Item 6.	[Reserved]	58
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	59
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	75
Item 8.	Financial Statements and Supplementary Data	77
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	147
Item 9A.	Controls and Procedures	147
Item 9B.	Other Information	147
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	148
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	149
Item 11.	Executive Compensation	149
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	149
Item 13.	Certain Relationships and Related Transactions, and Director Independence	149
Item 14.	Principal Accountant Fees and Services	149
	PART IV
Item 15.	Exhibits, Financial Statement Schedules	150
Item 16.	Form 10-K Summary	155
Signatures		156
Glossary of Terms		157

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains 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 Securities Exchange Act of 1934, as amended (the “Exchange Act”). These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this Annual Report on Form 10-K, regarding our strategic tactics, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Annual Report on Form 10-K, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, the factors discussed below and detailed under “Item 1A. Risk Factors” could affect our actual results and cause our actual results to differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or implied in such forward-looking statements.

Forward-looking statements may include statements about:

•crude oil, NGL and natural gas realized prices;

•uncertainty regarding the future actions of foreign oil producers and the related impacts such actions have on the balance between the supply of and demand for crude oil, NGLs and natural gas;

•war and political instability in Ukraine and the effect on commodity prices due to the ongoing conflict in Ukraine;

•general economic conditions;

•inflation rates and the impact of associated monetary policy responses, including increased interest rates;

•logistical challenges and supply chain disruptions;

•our business strategy;

•the geographic concentration of our operations;

•estimated future net reserves and present value thereof;

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

•drilling and completion of wells;

•estimated inventory of wells remaining to be drilled and completed;

•costs of exploiting and developing our properties and conducting other operations;

•availability of drilling, completion and production equipment and materials;

•availability of qualified personnel;

•infrastructure for produced and flowback water gathering and disposal;

•gathering, transportation and marketing of crude oil, NGLs and natural gas in the Williston Basin and other regions in the United States;

•the possible shutdown of DAPL;

•property acquisitions and divestitures;

•integration and benefits of property acquisitions or the effects of such acquisitions on our cash position and levels of indebtedness;    

•failing to realize the anticipated benefits or synergies from the Merger (as defined in the “Overview” section of Item 1 below) in the timeframe expected or at all;

•the results of integrating the operations of Oasis and Whiting;

•any litigation relating to the Merger;

•the amount, nature and timing of capital expenditures;

•availability and terms of capital;

•our financial strategic tactics, budget, projections, execution of business plan and operating results;

•cash flows and liquidity;

•our ability to return capital to stockholders;

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•our ability to utilize net operating loss carryforwards or other tax attributes in future periods;

•our ability to comply with the covenants under our credit agreement and other indebtedness;

•operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;

•interruptions in service and fluctuations in tariff provisions of third-party connecting pipelines;

•potential effects arising from cyber threats, terrorist attacks and any consequential or other hostilities;

•compliance with, and, changes in environmental, safety and other laws and regulations, including the Inflation Reduction Act of 2022 (the “IRA”);

•execution of our ESG initiatives;

•effectiveness of risk management activities;

•competition in the oil and gas industry;

•counterparty credit risk;

•incurring environmental liabilities;

•developments in the global economy as well as the public health crisis related to the COVID-19 pandemic and resulting demand and supply for crude oil, NGLs and natural gas;

•governmental regulation and the taxation of the oil and gas industry;

•developments in crude oil-producing and natural gas-producing countries;

•technology;

•the effects of accounting pronouncements issued periodically during the periods covered by forward-looking statements;

•uncertainty regarding future operating results;

•our ability to successfully forecast future operating results and manage activity levels with ongoing macroeconomic uncertainty;

•plans, objectives, expectations and intentions contained in this report that are not historical; and

•certain factors discussed elsewhere in this Form 10-K.

All forward-looking statements speak only as of the date of this Annual Report on Form 10-K. We disclaim any obligation to update or revise these statements unless required by securities law, and you should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Annual Report on Form 10-K are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. Some of the key factors which could cause actual results to vary from our expectations include changes in crude oil, NGL and natural gas prices, climatic and environmental conditions, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, inflation, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed under “Part I, Item 1A. Risk Factors” and “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Annual Report on Form 10-K, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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Risk Factors Summary

The following is a summary of some of the principal risks that could materially adversely affect our business, financial condition and results of operations. You should read this summary together with the more detailed description of each risk factor contained in “Part I, Item 1A. Risk Factors.”

Risks related to the oil and gas industry and our business

•A substantial or extended decline in commodity prices, for crude oil and, to a lesser extent, NGLs and natural gas, may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

•The ability or willingness of OPEC+ to set and maintain production levels has a significant impact on oil prices.

•Drilling for and producing crude oil and natural gas are high-risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations. We use some of the latest available horizontal drilling and completion techniques, which involve risk and uncertainty in their application.

•Our estimated net proved reserves are based on many assumptions that may turn out to be inaccurate.

•The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services or the unavailability of sufficient transportation for our production could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.

•Substantially all of our producing properties and operations are located in the Williston Basin.

•We depend upon a limited number of midstream providers for a large portion of our midstream services, and our failure to obtain and maintain access to the necessary infrastructure from these providers to successfully deliver crude oil, natural gas and NGLs to market may adversely affect our earnings, cash flows and results of operations.

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

•Drilling locations are scheduled to be drilled over several years and may not yield crude oil, NGLs or natural gas in commercially viable quantities.

•Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage, the primary term is extended through continuous drilling provisions or the leases are renewed. Failure to drill sufficient wells in order to hold acreage will result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.

•We are not the operator of all of our drilling locations, and, therefore, we may not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated assets.

•Our operations are subject to federal, state and local laws and regulations related to environmental and natural resources protection and occupational health and safety which may expose us to significant costs and liabilities and result in increased costs and additional operating restrictions or delays.

•Failure to comply with federal, state and local laws and regulations could adversely affect our ability to produce, gather and transport our crude oil, NGLs and natural gas and may result in substantial penalties.

•We expect to consider from time to time further strategic opportunities that may involve acquisitions, dispositions, investments in joint ventures, partnerships, and other strategic alternatives that may enhance stockholder value, any of which may result in the use of a significant amount of our management resources or significant costs, and we may not be able to fully realize the potential benefit of such transactions.

•Increasing stakeholder and market attention to ESG matters may impact our business and ability to secure financing.

•Our operations are subject to a series of risks arising out of the threat of climate change.

•Outbreak of infectious diseases could materially adversely affect our business.

•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 crude oil and natural gas wells and adversely affect our production.

•Laws and regulations pertaining to the protection of threatened and endangered species or to critical habitat, wetlands and natural resources could delay, restrict or prohibit our operations and cause us to incur substantial costs that may have a material adverse effect on our development and production of reserves.

•Our ability to produce crude oil, NGLs and natural gas economically and in commercial quantities could be impaired by challenges related to water acquisition and disposal.

•Competition in the oil and gas industry is intense, making it more difficult for us to acquire properties, market crude oil, NGLs and natural gas and secure and retain trained personnel.

•Seasonal weather conditions adversely affect our ability to conduct drilling activities in some of the areas where we operate.

•We may be subject to risks in connection with acquisitions because of integration difficulties, uncertainties in evaluating recoverable reserves, well performance and potential liabilities and uncertainties in forecasting crude oil, NGL and natural gas prices and future development, production and marketing costs.

•We may incur losses as a result of title defects in the properties in which we invest.

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•Disputes or uncertainties may arise in relation to our royalty obligations.

Risks related to our financial position

•Increased costs of capital could adversely affect our business.

•Our revolving credit facility and the indentures governing our senior unsecured notes contain operating and financial restrictions that may restrict our business and financing activities.

•Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our estimated net crude oil, NGL and natural gas reserves.

•We may maintain material balances of cash and cash equivalents for extended periods of time at commercial banks in excess of amounts insured by government agencies such as the FDIC.

•Changes in tax laws or the interpretation thereof or the imposition of new or increased taxes or fees may adversely affect our operations and cash flows.

•We may not be able to utilize all or a portion of our net operating loss carryforwards or other tax benefits to offset future taxable income for U.S. federal or state tax purposes, which could adversely affect our financial position, results of operations and cash flows.

•The enactment of derivatives legislation and regulation could have an adverse effect on our ability to use derivative instruments to reduce the negative effect of commodity price changes, interest rate and other risks associated with our business. Our derivative activities could also result in financial losses or could reduce our income.

•The cost of servicing, and the ability to generate enough cash flows to meet, our current or future debt obligations could adversely affect our business. Those risks could increase if we incur more debt.

Risks related to our common stock

•Our ability to declare and pay dividends is subject to certain considerations and limitations.

•Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals.

•The exercise of all or any number of outstanding warrants or the issuance of stock-based awards may dilute your holding of shares of our common stock.

Risks related to the Merger

•We may not realize anticipated benefits and synergies expected from the Merger.

•The failure to integrate our businesses and operations with those of Whiting successfully in the expected time frame may adversely affect the combined business’ future results.

•The future results of the combined company following the Merger will suffer if the combined company does not effectively manage its expanded operations.

General risk factors

•Involvement in legal, governmental and regulatory proceedings could result in substantial liabilities.

•Our profitability may be negatively impacted by inflation in the cost of labor, materials and services and general economic, business or industry conditions.

•Global geopolitical tensions may create heightened volatility in oil, gas and NGL prices and could adversely affect our business, financial condition and results of operations.

•Terrorist attacks or cyber-attacks could have a material adverse effect on our business, financial condition or results of operations and could result in information theft or data corruption.

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PART I

Item 1. Business

Overview

Chord Energy Corporation (together with our consolidated subsidiaries, the “Company,” “Chord,” “we,” “us,” or “our”), a Delaware corporation, is an independent exploration and production (“E&P”) company with quality and sustainable long-lived assets in the Williston Basin. Chord, formerly known as Oasis Petroleum Inc. (“Oasis”), was established on July 1, 2022 upon completion of the combination of Oasis and Whiting Petroleum Corporation (“Whiting”) in a merger of equals transaction (the “Merger”). Our mission is to responsibly produce hydrocarbons while exercising capital discipline, operating efficiently, improving continuously and providing a rewarding environment for our employees. We are ideally positioned to enhance return of capital and generate strong free cash flow, while being responsible stewards of the communities and environment where we operate.

As of December 31, 2022, we had 963,009 net leasehold acres in the Williston Basin, of which approximately 99% is held by production. We are currently exploiting significant resource potential from the Middle Bakken and Three Forks formations, which are present across a substantial portion of our acreage. We believe the locations, size and concentration of our acreage in the Williston Basin creates an opportunity for us to achieve cost, recovery and production efficiencies through the development of our project inventory. Our management team has a proven record of accomplishment in identifying, acquiring and executing large, repeatable development drilling programs and has substantial experience in the Williston Basin.

As of December 31, 2022, we had 3,583 gross (2,742.8 net) operated producing wells, including 2,558.6 net operated producing wells in the Williston Basin. Our working interest for producing wells averaged 46% in total and 77% in the wells we operate. During the year ended December 31, 2022, we had average daily production of 119,785 net Boepd, including average daily production of 171,880 net Boepd for the period subsequent to the Merger (with crude oil production of 95,992 Bopd). As of December 31, 2022, Netherland, Sewell & Associates, Inc. (“NSAI”), our independent reserve engineers, estimated our net proved reserves to be 655.6 MMBoe, of which 77% were classified as proved developed and 58% were crude oil. Effective July 1, 2022, we elected to report crude oil, NGLs and natural gas separately on a three-stream basis. Accordingly, our reported production volumes and reserve estimates as of and subsequent to July 1, 2022 are reported on a three-stream basis, while periods prior to July 1, 2022 were reported on a two-stream basis with NGLs combined with the natural gas stream.

Business Strategy

Our operational and financial strategy is focused on rigorous capital discipline and generating significant, sustainable free cash flow by executing on the following strategic priorities:

•Maximize returns. We intend to maximize returns through efficiently executing our development program and optimizing our capital allocation, while evaluating our performance and focusing on continuous improvement. As part of our efforts to maximize returns, we have established a rigorous capital allocation framework with the objective of balancing stockholder returns and reinvestment of capital. We are focused on conservative capital allocation, delivering low reinvestment rates and returning significant capital to stockholders. Since our inaugural dividend in February 2021, we have declared cash dividends to our stockholders of $37.46 per share of common stock.

We materially enhanced our scale in the Williston Basin as a result of the Merger and have high-quality assets that generate significant, sustainable cash flow to support the priority we place on stockholder returns. We expect that our business strategy will continue to provide sizable cash flow generation which will enable us to return capital to our stockholders and continue to pursue acquisitions that add to our inventory, while maintaining a strong balance sheet. In August 2022, we introduced a return of capital program designed to provide peer-leading, sustainable stockholder returns. The return of capital plan includes a base dividend of $1.25 per share per quarter ($5.00 per share annualized) and a $300 million share-repurchase program. As of December 31, 2022, we had $272.9 million remaining under this share-repurchase program. We plan to return capital through a mix of base and variable dividend payouts, supplemented by opportunistic share repurchases.

We expect to return a certain percentage of adjusted free cash flow (“Adjusted FCF”) each quarter, with the targeted percentage based on free cash flow generated during the previous quarter and leverage under the following framework:

•Below 0.5x leverage:	75%+ of Adjusted FCF
•Below 1.0x leverage:	50%+ of Adjusted FCF
•>1.0x leverage:	Base dividend+ ($5.00 per share annualized)

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The variable dividend will be calculated using the framework noted above to establish the minimum percentage of free cash flow to be returned less share repurchases completed during the quarter and the base dividend.

•Financial strength. Our management team is focused on maintaining a solid risk management process to preserve our strong balance sheet and protect our cash generation capabilities. Recognizing the oil and gas industry is cyclical, our business is designed to navigate challenging environments while preserving sufficient liquidity in an effort to be opportunistic in low commodity price cycles.

As of December 31, 2022, we had $1.6 billion of liquidity available, including $593.2 million of cash and cash equivalents and $993.6 million of unused borrowing capacity available under the Credit Facility (defined in “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”).

•Commitment to excellence. We are focused on creating a durable organization that generates strong financial returns and sustainable free cash flow through commodity cycles. We believe we have an attractive inventory that is resilient to commodity price fluctuations, which supports the sustainable generation of free cash flow. Our management team is focused on the continuous improvement of our operations and overall cost structure and has significant experience in successfully operating cost-efficient development programs. The magnitude and concentration of our acreage within the Williston Basin allows us to capture economies of scale, including the ability to drill multiple wells from a single drilling pad into multiple formations, the ability to drill longer lateral lengths for developmental wells, the ability to utilize centralized production and crude oil, natural gas and water fluid handling facilities and infrastructure, and reduce the time and cost of rig mobilization.

We have extensive engineering, operational, geologic and subsurface technical knowledge. Our technical team has access to an abundance of digital well log, seismic, completion, production and other subsurface information, which is analyzed in order to accurately and efficiently characterize the anticipated performance of our oil and gas reservoirs. We leverage many technologies in support of data gathering, information analysis and production optimization. Data management and reporting practices improve the availability, accuracy and analysis of our information in a cycle of continuous improvement. Emerging technologies are evaluated on a regular basis, ensuring we are implementing the best technologies for our business needs.

Our team is focused on employing leading drilling and completions techniques to optimize overall project economics. We continuously evaluate our internal drilling and completions results and monitor the results of other operators to improve our operating practices. We continue to optimize our completion designs based on geology and well spacing.

We foster a culture of innovation and continuous improvement, constantly looking for ways to strengthen our organizational agility and adaptability. Management, with oversight from the Board of Directors, is focused on enterprise risk management (“ERM”), which seeks to establish guidelines and policies for appropriate risk assessment and risk management, including exposure to safety risk, financial risk, commodity price risk and cybersecurity risk. The Audit and Reserves Committee of our Board of Directors reviews our cybersecurity guidelines and policies and receives updates on cybersecurity matters at least annually. In addition, we have established cybersecurity best practices aligned with the National Institute of Standards and Technology, require quarterly cybersecurity training of our employees and receive an annual audit and penetration assessment by a third party. Our ERM program allows us to have a better enterprise-view of risks, improve our risk response and preparedness and better incorporate risk mitigation around existing and emerging risks into our strategic plans.

•Responsible stewards. We are committed to our established ESG initiatives and seek to maintain a culture of continuous improvement in ESG practices. We strive to provide safe, reliable and affordable energy in a responsible manner against the backdrop of an evolving energy landscape. The key tenets of our ESG philosophy are to always put safety first, minimize our environmental impact, reduce our emissions intensity, promote a diverse and inclusive culture, align executive compensation with long-term value creation and stockholder interests, and support programs that benefit the communities in which we operate.

From a safety standpoint, our corporate, field and environmental, health and safety teams are enhancing best practices and training to minimize the likelihood of safety incidents among employees and contractors. We owe it to our employees, our service providers and stakeholders to do all we can to create an environment where everyone on a Chord location is safe. We hold ourselves to always put safety first, to be diligent and never complacent. We expect the same of any service provider or partner that works with us.

We remain focused on reducing Scope 1 GHG emissions, and in particular methane emissions. We are establishing a carbon management program that includes a team focused on gas capture, flare management and replacement or retrofit of gas pneumatics. In addition, we plan to increase transparency by reporting full Scope 1 and Scope 2 operated emissions while continuing to align our disclosures towards the Sustainability Accounting Standards Board (“SASB”) and Task Force on Climate-Related Financial Disclosures (“TCFD”) frameworks. We

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also are proficient in capturing the natural gas that we produce, and, as of December 31, 2022, we were capturing substantially all of our natural gas production in North Dakota.

We provide leadership training and educational and professional development programs for employees at every level of the organization. We have also made meaningful investments in safety training programs that benefit our employees and contractors. We are deeply involved in the communities in which we work and deploy our financial resources, time and talent to support a number of charitable organizations.

We have a short tenured and highly capable Board of Directors that is comprised of diverse and experienced energy industry professionals. Our Board of Directors is 80% independent and 63% of our independent directors are women. As part of our ongoing effort to enhance our ESG practices, the Board of Directors has established the Environmental, Social and Governance Committee, which is charged with overseeing our ESG strategies, policies and goals. For more information about our ESG and corporate responsibility efforts, please see the “Sustainability” page of our website and the Proxy Statement that we will file for our 2023 Annual Meeting of Stockholders.

Competitive Strengths

We have a number of competitive strengths that we believe will help us successfully execute our business strategies:

•Substantial leasehold position and existing production in one of North America’s leading unconventional crude oil resource plays. We believe that our Williston Basin acreage represents a premier position in a top oil basin in the United States that will continue to provide significant free cash flow generation. As of December 31, 2022, we had 963,009 net leasehold acres in the Williston Basin, which is the largest acreage position of any operator in the Williston Basin. Of our 963,009 net leasehold acres, 954,566 net acres were held by production and 58% of our 655.6 MMBoe estimated net proved reserves were comprised of crude oil. We believe we have a large project inventory of potential drilling locations that we have not yet drilled, the majority of which are operated by us.

•Operating control over the majority of our portfolio. In order to maintain control over our asset portfolio, we have established a leasehold position comprised primarily of properties that we expect to operate. As of December 31, 2022, 96% of our estimated net proved reserves were attributable to properties that we operate. In 2023, we plan to complete approximately 90 to 94 gross operated wells with an average working interest of approximately 73%. Controlling operations enables us to optimize capital allocation and control the pace of development of our assets to manage our reinvestment rates in line with our broader strategic objectives. Additionally, operational control allows us to materially benefit from proactively managing our cost structure across our portfolio. We believe that maintaining operational control over the majority of our acreage allows us to better pursue our strategies of enhancing returns through operational, cost and capital efficiencies, and allows us to better manage infrastructure investment to drive down operating costs and optimize price realizations.

•Best-in-class balance sheet. We believe our strong balance sheet will allow us to generate significant, sustainable free cash flow and corporate-level returns. We have no near-term debt maturities, are focused on rigorous capital discipline and have a hedging program to minimize downside risk.

•Incentivized management team with proven operating and acquisition skills. Our senior management team has extensive expertise in the oil and gas industry with an average of more than 25 years of industry experience. We believe our management and technical team is one of our principal competitive strengths relative to our industry peers due to our team’s proven record of accomplishment in identification, acquisition and execution of large, repeatable development drilling programs. In addition, a substantial majority of our executive officers’ overall compensation is in long-term equity-based incentive awards, and we have implemented best-in-class management compensation practices aligned with stockholders, which we believe provides our executive officers with significant incentives to grow the value of our business and return capital to stockholders.

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Exploration and Production Operations

Estimated net proved reserves

Our estimated net proved reserves and related PV-10 at December 31, 2022 are based on reports independently prepared by NSAI, our independent reserve engineers. Our estimated net proved reserves and related PV-10 at December 31, 2021 and 2020 were based on reports independently prepared by DeGolyer and MacNaughton, our previous independent reserve engineers. Our current and previous independent reserve engineers evaluated 100% of the reserves and discounted values at December 31, 2022, 2021 and 2020 in accordance with the rules and regulations of the SEC applicable to companies involved in crude oil, NGL and natural gas producing activities. Our estimated net proved reserves and related standardized measure of discounted future net cash flows (“Standardized Measure”) and PV-10 do not include probable or possible reserves and were determined using the preceding 12 month unweighted arithmetic average of the first-day-of-the-month index prices for crude oil and natural gas (the “SEC Price”), which were held constant throughout the life of the properties. See “Item 8. Financial Statements and Supplementary Data—Note 26.—Supplemental Oil and Gas Reserve Information — Unaudited” for additional information about our estimated net proved reserves.

The following table summarizes our estimated net proved reserves based upon the SEC Price:

	At December 31,
	2022			2021			2020
Estimated proved reserves:
Crude oil (MMBbls)	381.3			174.3			119.8
NGLs (MMBbls)(1)	138.5			—			—
Natural gas (Bcf)	814.9			459.3			376.2
Total estimated proved reserves (MMBoe)	655.6			250.9			182.5
Percent crude oil	58		%	69		%	66		%
Estimated proved developed reserves:
Crude oil (MMBbls)	272.5			114.0			85.4
NGLs (MMBbls)(1)	115.2			—			—
Natural gas (Bcf)	689.7			361.8			262.7
Total estimated proved developed reserves (MMBoe)	502.7			174.3			129.2
Percent proved developed	77		%	69		%	71		%
Estimated proved undeveloped reserves:
Crude oil (MMBbls)	108.8			60.3			34.3
NGLs (MMBbls)(1)	23.2			—			—
Natural gas (Bcf)	125.3			97.4			113.5
Total estimated proved undeveloped reserves (MMBoe)	152.9			76.5			53.3
Standardized Measure (GAAP) (in millions)(2)	$	11,494.5		$	2,696.9		$	948.9
PV-10 (Non-GAAP) (in millions)(3):
Proved developed PV-10	$	11,460.3		$	2,474.5		$	936.9
Proved undeveloped PV-10	2,991.9			640.9			178.1
Total PV-10 (Non-GAAP)	$	14,452.2		$	3,115.4		$	1,115.0

__________________ 

(1)At December 31, 2021 and 2020, we reported crude oil and natural gas reserves on a two-stream basis, with NGLs combined with the natural gas stream. At December 31, 2022, NGL reserves are reported separately from the natural gas stream on a three-stream basis. This change impacts the comparability of the periods presented.

(2)Standardized Measure represents the present value of estimated future net cash flows from proved crude oil and natural gas reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows.

(3)PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable financial measure under GAAP, because it does not include the effect of income taxes on discounted future net cash flows. See “Reconciliation of Standardized Measure to PV-10” below.

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Reconciliation of Standardized Measure to PV-10

PV-10 is derived from Standardized Measure, which is the most directly comparable financial measure under GAAP. PV-10 is equal to Standardized Measure at the applicable date, before deducting future income taxes, discounted at 10%. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies without regard to the specific tax characteristics of such entities. We use this measure when assessing the potential return on investment related to our oil and gas properties. PV-10, however, is not a substitute for Standardized Measure. Our PV-10 measure and Standardized Measure do not purport to represent the fair value of our crude oil and natural gas reserves.

The following table provides a reconciliation of Standardized Measure to PV-10:

	At December 31,
	2022		2021		2020
			(In millions)
Standardized Measure of discounted future net cash flows	$	11,494.5	$	2,696.9	$	948.9
Add: present value of future income taxes discounted at 10%	2,957.7		418.5		166.1
PV-10	$	14,452.2	$	3,115.4	$	1,115.0

Independent petroleum engineers

Our estimated net proved reserves and PV-10 at December 31, 2022 are based on reports independently prepared by NSAI, our independent reserve engineers, by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revised June 2019) (the “Estimating and Auditing Standards”) and definitions and current guidelines established by the SEC. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699.

Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Richard B. Talley, Jr. and Mr. Edward C. Roy III. Mr. Talley, a Licensed Professional Engineer in the State of Texas (No. 102425), has been practicing as a petroleum engineering consultant at NSAI since 2004 and has over 5 years of prior industry experience. He graduated from University of Oklahoma in 1998 with a Bachelor of Science degree in Mechanical Engineering and from Tulane University in 2001 with a Master of Business Administration degree. Mr. Roy, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 2364), has been practicing as a petroleum geoscience consultant at NSAI since 2008 and has over 11 years of prior industry experience. He graduated from Texas Christian University in 1992 with a Bachelor of Science degree in Geology and from Texas A&M University in 1998 with a Master of Science degree in geology. Both technical principals meet or exceed the education, training and experience requirements set forth in the Estimating and Auditing Standards. In addition, both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations, as well as applying SEC and other industry reserves definitions and guidelines.

Our estimated net proved reserves and PV-10 at December 31, 2021 and 2020 were based on reports independently prepared by DeGolyer and MacNaughton, by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the Estimated and Auditing Standards and definitions and current guidelines established by the SEC. DeGolyer and MacNaughton is a Delaware corporation with offices in Dallas, Houston, Moscow, Astana, Buenos Aires, Baku and Algiers. The firm’s more than 180 professionals include engineers, geologists, geophysicists, petrophysicists and economists engaged in the appraisal of oil and gas properties, evaluation of hydrocarbon and other mineral prospects, basin evaluations, comprehensive field studies and equity studies related to the domestic and international energy industry. DeGolyer and MacNaughton has provided such services for over 85 years. The Senior Vice President at DeGolyer and MacNaughton that was primarily responsible for overseeing the preparation of the reserve estimates is a Registered Professional Engineer in the State of Texas, is a member of the Society of Petroleum Engineers and has over 10 years of experience in crude oil and natural gas reservoir studies and reserve evaluations. He graduated with a Bachelor of Science degree in Petroleum Engineering from Istanbul Technical University in 2003, a Master of Science degree in Petroleum Engineering from Texas A&M University in 2005 and a Doctor of Philosophy degree in Petroleum Engineering from Texas A&M University in 2010. DeGolyer and MacNaughton restricts its activities exclusively to consultation; it does not accept contingency fees, nor does it own operating interests in any crude oil, natural gas or mineral properties, or securities or notes of clients. The firm subscribes to a code of professional conduct, and its employees actively support their related technical and professional societies. The firm is a Texas Registered Engineering Firm.

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Technology used to establish proved reserves

In accordance with rules and regulations of the SEC applicable to companies involved in crude oil and natural gas producing activities, proved reserves are those quantities of crude oil and natural 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. The term “reasonable certainty” means deterministically, the quantities of crude oil and/or natural gas are much more likely to be achieved than not, and probabilistically, there should be at least a 90% probability of recovering volumes equal to or exceeding the estimate. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by using 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.

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the Estimating and Auditing Standards. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data and production history.

Based on the current stage of field development, production performance, the development plans provided by us to NSAI and the analyses of areas offsetting existing wells with test or production data, reserves were classified as proved.

A performance-based methodology integrating the appropriate geology and petroleum engineering data was utilized for the evaluation of all reserves categories. Performance-based methodology primarily includes (i) production diagnostics, (ii) decline-curve analysis and (iii) model-based analysis (if necessary, based on the availability of data). Production diagnostics include data quality control, identification of flow regimes and characteristic well performance behavior. Analysis was performed for all well groupings (or type-curve areas).

Characteristic rate-decline profiles from diagnostic interpretation were translated to modified hyperbolic rate profiles, including one or multiple b-exponent values followed by an exponential decline. Based on the availability of data, model-based analysis may be integrated to evaluate long-term decline behavior, the impact of dynamic reservoir and fracture parameters on well performance and complex situations sourced by the nature of unconventional reservoirs. The methodology used for the analysis was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, production history and appropriate reserves definitions.

Internal controls over reserves estimation process

We employ NSAI as the independent preparer for 100% of our reserves. We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with the independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished for the reserves estimation process. Our Managing Director, Corporate Planning & Reserves is responsible for overseeing the preparation of the reserves estimates under the supervision of our Senior Vice President, Planning & Investor Relations. Our Managing Director, Corporate Planning & Reserves has more than 12 years of broad reservoir engineering experience in the oil and gas industry, focused across conventional and unconventional evaluation and development projects, including corporate reserves estimations. He holds a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines and is a member of the Society of Petroleum Engineers.

Throughout each fiscal year, our technical team meets with the independent reserve engineers to review properties and discuss evaluation methods and assumptions used in the proved reserves estimates, in accordance with our prescribed internal control procedures. Our internal controls over the reserves estimation process include verification of input data into our reserves evaluation software as well as management review, such as, but not limited to the following:

•Comparison of historical expenses from the lease operating statements and workover authorizations for expenditure to the operating costs input in our reserves database;

•Review of working interests and net revenue interests in our reserves database against our well ownership system;

•Review of historical realized prices and differentials from index prices as compared to the differentials used in our reserves database;

•Review of updated capital costs prepared by our operations team;

•Review of internal reserve estimates by well and by area by our internal reservoir engineers;

•Discussion of material reserve variances among our internal reservoir engineers;

•Review of the reserves report by members of our senior management team, including our President & Chief Executive Officer; Executive Vice President & Chief Operating Officer; Executive Vice President & Chief

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Financial Officer; Senior Vice President, Planning & Investor Relations and Managing Director, Corporate Planning & Reserves; and

•Review of our reserves estimation process and the reserves report by our Audit and Reserves Committee and NSAI on an annual basis.

Production, price and cost history

We produce and market crude oil, NGLs and natural gas, which are commodities. The prices that we receive for the crude oil, NGLs and natural gas we produce is largely a function of market supply and demand. Demand is impacted by general economic conditions, access to markets, weather and other seasonal conditions, including hurricanes and tropical storms. Over or under supply of crude oil, NGLs or natural gas can result in substantial price volatility. Historically, commodity prices have been volatile, and we expect that volatility to continue in the future. Please see “Item 1A. Risk Factors—Risks related to the oil and gas industry and our business” for additional information on risks associated with commodity prices. Please also see “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—Market Conditions” for additional information on market demand.

The following table sets forth information regarding our crude oil, NGL and natural gas production, realized prices and production costs for the periods presented. References to “Successor” relate to our results of operations subsequent to our emergence from bankruptcy on November 19, 2020. References to “Predecessor” relate to our results of operations through and including our emergence from bankruptcy on November 19, 2020.

In addition, the Merger was accounted for as of July 1, 2022. Accordingly, the results of operations presented herein report the results of legacy Oasis prior to the closing of the Merger on July 1, 2022 and the results of Chord (including legacy Whiting) from July 1, 2022 through December 31, 2022. For additional information on price calculations, please see information set forth in “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

	Successor						Predecessor
	Year Ended December 31,				Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020
	2022		2021
Net production volumes:
Crude oil (MBbls)	25,457		13,489		1,593		14,226
NGLs (MBbls)(1)	7,026		—		—		—
Natural gas (MMcf)(1)	67,428		46,157		5,008		42,199
Oil equivalents (MBoe)	43,722		21,182		2,428		21,258
Average daily production (Boepd)	119,785		58,032		57,809		65,612
Average sales prices:
Crude oil, without derivative settlements (per Bbl)	$	92.98	$	67.49	$	43.36	$	36.75
Crude oil, with derivative settlements(2) (per Bbl)	73.50		48.55		43.36		48.13
NGL, without derivative settlements(1) (per Bbl)	26.23		—		—		—
NGL, with derivative settlements(1)(2) (per Bbl)	26.94		—		—		—
Natural gas, without derivative settlements(1) (per Mcf)	6.30		6.28		3.41		1.86
Natural gas, with derivative settlements(1)(2) (per Mcf)	5.26		5.96		3.40		1.86
Average costs (per Boe):
Lease operating expenses	10.14		9.63		9.27		7.55
Gathering, processing and transportation expenses	3.24		5.79		5.44		5.55
Production taxes	5.25		3.63		2.45		2.14

__________________ 

(1)For periods prior to July 1, 2022, we reported crude oil and natural gas on a two-stream basis, and NGLs were combined with the natural gas stream when presenting our production data and average sales prices. As of July 1, 2022, NGLs were reported separately from the natural gas stream on a three-stream basis. This prospective change impacts the comparability of the periods presented.

(2)Our commodity derivatives do not qualify for or were not designated as hedging instruments for accounting purposes. The effect of derivative settlements includes the gains or losses on commodity derivatives for contracts ending within the periods presented.

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Acreage

The following table sets forth certain information regarding the developed and undeveloped acreage in which we own a working interest as of December 31, 2022. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary.

	Gross	Net
Developed acres	1,323,520	935,748
Undeveloped acres	134,769	76,088
Total acres	1,458,289	1,011,836

Our total net leasehold position shown in the table above includes 963,009 net leasehold acres in the Williston Basin, which is the largest acreage position of any operator in the Williston Basin. At December 31, 2022, our total acreage that is held by production increased to 996,187 net acres from 487,254 net acres at December 31, 2021.

The following table sets forth the number of gross and net undeveloped acres as of December 31, 2022 that will expire over the next three years unless production is established on the acreage prior to the expiration dates:

	Undeveloped acres expiring
	Gross	Net
Year ending December 31,
2023	2,110	1,539
2024	2,353	1,934
2025	405	405

We have not assigned any PUD reserves to locations scheduled to be drilled after lease expiration.

Productive wells

All of our productive wells are crude oil wells. Gross wells are the number of wells, operated and non-operated, in which we own a working interest, and net wells are the total of our working interests owned in gross wells. The following table presents the total and operated gross and net productive wells as of December 31, 2022:

	Total wells		Operated wells
	Gross	Net	Gross	Net
Horizontal wells	6,534	3,025.2	3,579	2,740.1
Other	40	9.0	4	2.7
Total wells	6,574	3,034.2	3,583	2,742.8

Our total producing wells shown in the table above includes 2,758.7 total net producing wells and 2,558.6 operated net producing wells in the Williston Basin.

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Drilling and completion activity

The following table summarizes the number of gross and net wells completed during the periods presented, regardless of when drilling was initiated.

	Year ended December 31,
	2022		2021		2020
	Gross	Net	Gross	Net	Gross	Net
Development wells:
Oil	67	41.3	49	23.3	69	34.6
Gas	—	—	—	—	—	—
Dry	—	—	—	—	—	—
Total development wells	67	41.3	49	23.3	69	34.6
Exploratory wells:
Oil	—	—	—	—	—	—
Gas	—	—	—	—	—	—
Dry	—	—	—	—	—	—
Total exploratory wells	—	—	—	—	—	—
Total wells	67	41.3	49	23.3	69	34.6

As of December 31, 2022, we had 45 gross (27.4 net) wells in the process of being drilled or completed, which includes 36 gross operated wells waiting on completion and 7 gross non-operated wells drilling or completing.

As of December 31, 2022, we had three operated rigs running, and we expect to run four operated rigs for the majority of 2023.

Description of properties

As of December 31, 2022, our operations were focused in the North Dakota and Montana areas of the Williston Basin targeting the Middle Bakken and Three Forks formations. We are one of the top producers in the Williston Basin, and we have the largest acreage position of any operator in the Williston Basin. As a result of the Merger, we significantly enhanced our scale in our acreage position, reserves and production. We focus our operations in the Williston Basin because of its high oil content, multiple producing horizons, substantial resource potential and management’s previous professional history in the basin. The Williston Basin also generally has established infrastructure and access to materials and services.

Marketing

We principally sell our crude oil, NGL and natural gas production to refiners, marketers and other purchasers that have access to nearby pipeline and rail facilities. In an effort to improve price realizations, we manage our commodities marketing activities in-house, which enables us to market and sell our crude oil, NGL and natural gas to a broad array of potential purchasers. We sell a significant amount of our crude oil production through bulk sales at delivery points on crude oil gathering systems to a variety of purchasers at prevailing market prices under short-term contracts that normally provide for us to receive a market-based price, which incorporates regional differentials that include, but are not limited to, transportation costs. These gathering systems, which typically originate at the wellhead and are connected to multiple pipeline and rail facilities, reduce the need to transport barrels by truck from the wellhead, helping remove trucks from local highways and reduce greenhouse gas emissions. As of December 31, 2022, substantially all of our gross operated crude oil and natural gas production were connected to gathering systems. In addition, from time to time we may enter into third-party purchase and sales transactions to, among other things, improve price realizations, optimize transportation costs, blend to meet pipeline specifications or to cover production shortfalls. We also enter into various sales contracts for a portion of our portfolio at fixed differentials. We believe that the loss of any individual purchaser would not have a long-term material adverse impact on our financial position or results of operations, as alternative customers and markets for the sale of our products are readily available in the areas in which we operate.

Our marketing of crude oil, NGL and natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted. For a description of some of these factors, please see “Item 1A. Risk Factors—Risks related to the oil and gas industry and our business.”

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Delivery commitments

As of December 31, 2022, we had certain agreements with an aggregate requirement to deliver or transport a minimum quantity of approximately 44.7 MMBbl of crude oil, 17.0 MMBbl of NGLs, 494.2 Bcf of natural gas and 1.6 MMBbl of water, prior to any applicable volume credits, within specified timeframes, the majority of which are ten years or less. We are required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments under certain agreements. We believe that for the substantial majority of these agreements, our future production will be adequate to meet our delivery commitments or that we can purchase sufficient volumes of crude oil, NGLs and natural gas from third parties to satisfy our minimum volume commitments.

Midstream Transactions

On February 1, 2022, we completed the merger of Oasis Midstream Partners LP (“OMP”) and OMP GP LLC, OMP’s general partner (“OMP GP”) with and into a subsidiary of Crestwood Equity Partners LP (“Crestwood”) and, in exchange, received $160.0 million in cash and 20,985,668 common units representing limited partner interests of Crestwood (the “OMP Merger”). Prior to the completion of the OMP Merger, OMP was a consolidated subsidiary and we owned approximately 70% of OMP’s issued and outstanding common units. We had provided OMP acreage dedications pursuant to several long-term, fee-based contractual arrangements for midstream services, including (i) natural gas gathering, compression, processing and gas lift supply services, (ii) crude oil gathering, terminaling and transportation services, (iii) produced and flowback water gathering and disposal services and (iv) freshwater distribution services. These contracts were assigned to Crestwood upon completion of the OMP Merger, and we now depend on Crestwood for a large portion of our midstream services.

Competition

There is a high degree of competition in the oil and gas industry for acquiring properties, obtaining investment capital, securing oil field goods and services, marketing oil, NGLs and natural gas products and attracting and retaining qualified personnel. Certain of our competitors possess and employ financial, technical and personnel resources greater than ours, which can be particularly important in the areas in which we operate. Those companies may be able to pay more for productive oil and gas properties and exploratory prospects, better sustain production in periods of low commodity prices and evaluate, bid for and purchase a greater number of properties and prospects than our resources permit. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation or regulation enacted by state, local and U.S. government bodies and their associated agencies, especially with regard to environmental protection and climate-related policies. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or the resultant effects on our future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing oil, NGLs and natural gas and our larger competitors may be able to better absorb the burden of such legislation and regulation, which would also adversely affect our competitive position. See “Regulation” below as well as Item 1A. within this Annual Report on Form 10-K for more information on and the potential associated risks resulting from existing and future legislation and regulation of our industry.

Additionally, the unavailability or high cost of drilling rigs, completion crews or other equipment and services could delay or adversely affect our development and exploration operations. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to obtain necessary capital as well as evaluate and select suitable properties and to consummate transactions in a highly competitive environment. See “Item 1A. Risk Factors—Risks related to the oil and gas industry and our business—Competition in the oil and gas industry is intense, making it more difficult for us to acquire properties, market crude oil, NGLs and natural gas and secure and retain trained personnel.”

In addition, the oil and gas industry as a whole competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. The price and availability of alternative energy sources, such as wind, solar, nuclear, coal, hydrogen and biofuels as well as the emerging impact of climate change activism, fuel conservation measures and governmental requirements for renewable energy sources, could adversely affect our revenues. See “Item 1A. Risk Factors—Our operations are subject to a series of risks arising out of the threat of climate change, energy conservation measures or initiatives that stimulate demand for alternative forms of energy that could result in increased operating costs, restrictions on drilling and reduced demand for the crude oil and natural gas that we produce.”

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Title to Properties

As is customary in the oil and gas industry, we initially conduct a preliminary review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant title defects. 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 general industry standards. Prior to completing an acquisition of producing crude oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of the properties, we may obtain a title opinion or review previously obtained title opinions. Our oil and gas properties are subject to customary royalty and other interests, liens to secure borrowings under the Credit Facility, liens for current taxes and other burdens, which we believe do not materially interfere with the use or affect our carrying value of the properties. Please see “Item 1A. Risk Factors—Risks related to the oil and gas industry and our business—We may incur losses as a result of title defects in the properties in which we invest.”

Seasonality

Winter weather conditions and lease stipulations can limit or temporarily halt our drilling, completion and producing activities and other oil and gas operations. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operating and capital costs. Such seasonal anomalies can also pose challenges for meeting our drilling objectives and may increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay or temporarily halt our operations.

Regulation

Our E&P operations are substantially affected by federal, tribal, regional, state and local laws and regulations. In particular, crude oil and natural gas production is, or has been, subject to price controls, taxes and numerous laws and regulations. All of the jurisdictions in which we own or operate properties for crude oil and natural gas production have statutory provisions regulating the exploration for and production of crude oil and natural gas or the gathering, transportation and processing of those commodities, including provisions related to permits for the drilling of wells or processing of natural gas, bonding requirements to drill or operate producing or injection wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled or processing plants are constructed, sourcing and disposal of water used in the drilling and completion process and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in an area, the siting of processing plants, disposal wells and gathering or transportation lines, and the unitization or pooling of crude oil and natural gas wells, as well as regulations that generally discourage the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Historically, our compliance costs with applicable laws and regulations have not had a material adverse effect on our financial position, cash flows and results of operations; however, new laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement may occur and, thus, there can be no assurance that such costs will not be material in the future. Additionally, environmental incidents such as spills or other releases may occur or past non-compliance with environmental laws or regulations may be discovered, any of which may require us to install new or modified controls on equipment or processes, incur longer permitting timelines, and incur increased capital or operating expenditures, the costs of which may be material. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission (“FERC”), the U.S. Environmental Protection Agency (“EPA”) and the courts. We cannot predict when or whether any such proposals may be finalized and become effective.

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Regulation of transportation and sales of crude oil

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

Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of crude oil by common carrier pipelines is also subject to rate and access regulation. FERC regulates interstate crude oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate crude oil 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. Effective January 1, 1995, FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for crude oil pipelines that allows a pipeline to increase its rates annually up to prescribed ceiling levels that are tied to changes in the Producer Price Index, without making a cost of service filing. Many existing pipelines utilize the FERC crude oil index to change transportation rates annually every July 1. Every five years, FERC reviews the appropriateness of the index level in relation to changes in industry costs. On December 17, 2020, FERC established a new price index for the five-year period commencing July 1, 2021 and ending June 30, 2026, in which common carriers charging indexed rates were permitted to adjust their indexed ceiling annually by Producer Price Index plus 0.78%. The Commission received requests for rehearing of its December 17, 2020 order and on January 20, 2022, in Docket No. RM20-14, granted rehearing and modified the oil index (“January 2022 Order”). Specifically, for the five-year period commencing July 1, 2021 and ending June 30, 2026, common carriers charging indexed rates are permitted to adjust their indexed ceilings annually by Producer Price Index minus 0.21%. FERC directed oil pipelines to recompute their ceiling levels for July 1, 2021 through June 30, 2022 based on the new index level. Where an oil pipeline’s filed rates exceed its ceiling levels, FERC ordered such oil pipelines to reduce the rate to bring it into compliance with the recomputed ceiling level to be effective March 1, 2022.

On February 22, 2022, several shippers filed for a Request for Clarification, or in the alternative, Rehearing of the January 2022 Order (“Request for Rehearing”). Additionally, during February and March 2022, shippers filed timely petitions for review of the January 2022 Order with the D.C. Circuit and the 5th Circuit. The petitions for review filed with the D.C. Circuit were transferred to the 5th Circuit. On May 6, 2022, the FERC issued an order on rehearing in which it denied the Request for Rehearing. On May 11, 2022, the 5th Circuit transferred the challenge to the D.C. Circuit. Additional petitions for review were timely filed with the D.C. Circuit in June 2022. The appeal remains pending before the D.C. Circuit.

Intrastate crude oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate crude oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate crude 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 crude oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

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

We sell a significant amount of our crude oil production through gathering systems connected to rail facilities. Due to several crude oil train derailments in the past decade, transportation safety regulators in the United States and Canada have examined the adequacy of transporting crude oil by rail, with an emphasis on the safe transport of Bakken crude oil by rail, following findings by the U.S. Pipeline and Hazardous Materials Safety Administration (“PHMSA”) that Bakken crude oil tends to be more volatile and flammable than certain other crude oils, and thus poses an increased risk for a significant accident.

Since 2011, all new railroad tank cars built to transport crude oil or other petroleum type fluids, including ethanol, have been built to more stringent safety standards. In 2015, PHMSA adopted a final rule that includes, among other things, additional requirements to enhance tank car standards for certain trains carrying crude oil and ethanol, a classification and testing program for crude oil, new operational protocols for trains transporting large volumes of flammable liquids and a requirement that older DOT-111 tank cars be phased out beginning in late 2017 if they are not already retrofitted to comply with new tank car design standards. In 2016, PHMSA released a final rule mandating a phase-out schedule for all DOT-111 tank cars used to transport Class 3 flammable liquids, including crude oil and ethanol, between 2018 and 2029, and in early 2019, PHMSA published a final rule requiring railroads to develop and submit comprehensive oil spill response plans for specific route segments traveled by a single train carrying 20 or more loaded tanks of liquid petroleum oil in a continuous block or a single train carrying 35 or more loaded tank cars of liquid petroleum oil throughout the train. Additionally, the 2019 final rule requires railroads to establish geographic response zones along various rail routes, ensure that both personnel and equipment are staged and prepared to respond in the event of an accident, and share information about high-hazard flammable train operations with state and tribal emergency response commissions.

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In addition, a number of states proposed or enacted laws in recent years that encourage safer rail operations, urge the federal government to strengthen requirements for these operations or otherwise seek to impose more stringent standards on rail transport of crude oil. For example, in the absence of a current federal standard on the vapor pressure of crude oil transported by rail, the State of Washington passed a law that became effective in July 2019, prohibiting the loading or unloading of crude oil from a rail car in the state unless the crude oil vapor pressure is lower than 9 pounds per square inch. In response, the States of North Dakota and Montana filed a preemption application with PHMSA in July 2019 and in May 2020, PHMSA published a Notice of Administrative Determination of Preemption, finding that the federal Hazardous Material Transportation Law preempts Washington State’s vapor pressure limit.

One or more of these federal or state safety improvements or updates relating to rail tank cars and rail crude oil-related operational practices imposed by PHMSA since 2015 could drive up the cost of transportation and lead to shortages in availability of tank cars. We do not currently own or operate rail transportation facilities or rail cars. However, we cannot assure that costs incurred by the railroad industry to comply with these enhanced standards resulting from PHMSA’s final rules or that restrictions on rail transport of crude oil due to state crude oil volatility standards, if not preempted by PHMSA, will not increase our costs of doing business or limit our ability to transport and sell our crude oil at favorable prices, the consequences of which could be material to our business, financial condition or results of operations. However, we believe that any such consequences would not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

More stringent regulatory initiatives have likewise been pursued in Canada to assess and address risks from the transport of crude oil by rail. For example, since 2014, Transport Canada has issued requirements prohibiting crude oil shippers from using certain DOT-111 tank cars and imposed a phase out schedule for other tank cars that do not meet specified safety requirements, imposed a 50 mile per hour speed limit on trains carrying hazardous materials and required all crude oil shipments in Canada to have an emergency response plan. Also, at or near the same time that PHMSA released its 2015 rule, Canada’s Minister of Transport announced Canada’s new tank car standards, which largely align with the requirements in the PHMSA rule. Likewise, Transport Canada’s rail car retrofitting and phase out timeline largely aligned with the requirements in the PHMSA rule and issued retrofitting and phase out timelines similar to those introduced by PHMSA. Transport Canada also introduced new requirements that railways carry minimum levels of insurance depending on the quantity of crude oil or dangerous goods that they transport as well as a final report recommending additional practices for the transportation of dangerous goods.

Historically, our hazardous materials transportation compliance costs have not had a material adverse effect on our results of operations; however, any new laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement regarding hazardous material transportation may occur in the future, which could directly and indirectly increase our operation, compliance and transportation costs and lead to shortages in availability of tank cars. We cannot assure that costs incurred to comply with PHMSA and Transport Canada standards and regulations emerging from these existing and any future rulemakings will not be material to our business, financial condition or results of operations. In addition, any derailment of crude oil from the Williston Basin involving crude oil that we have sold or are shipping may result in claims being brought against us that may involve significant liabilities. Although we believe that we are adequately insured against such events, we cannot assure you that our insurance policies will cover the entirety of any damages that may arise from such an event. Nonetheless, we believe that any such consequences would 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 natural gas

Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by FERC under the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 (“NGPA”) and regulations issued under those statutes. 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 market prices, 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 all price controls affecting wellhead sales of natural gas effective January 1, 1993.

FERC regulates interstate natural gas transportation rates, and terms and conditions of service, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, FERC issued a series of orders, beginning with Order No. 636, to implement its open access policies. As a result, the interstate pipelines’ traditional role of providing the sale and transportation of natural gas as a single service has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

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In 2000, FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 revised FERC’s pricing policy by waiving price ceilings for short-term released capacity for a two-year experimental period, and effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. The natural gas industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that the less stringent regulatory approach established by FERC under Order No. 637 will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.

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 sales of energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the Commodity Futures Trading Commission (“CFTC”) and the Federal Trade Commission (“FTC”). Please see below the discussion of “Other federal laws and regulations affecting our industry—Energy Policy Act of 2005.” 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. In addition, pursuant to Order No. 704, some of our operations may be required to annually report to FERC on May 1 of each year for the previous calendar year. Order No. 704 requires certain natural gas market participants to report information regarding their reporting of transactions to price index publishers and their blanket sales certificate status, as well as certain information regarding their wholesale, physical natural gas transactions for the previous calendar year depending on the volume of natural gas transacted. Please see below the discussion of “Other federal laws and regulations affecting our industry—FERC market transparency rules.”

Gathering services, which occur upstream of FERC jurisdictional transmission services, are regulated by the states onshore and in state waters. Although FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, FERC’s determinations as to the classification of facilities is done on a case by case basis. State regulation of natural gas gathering facilities generally includes various 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.

Intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by FERC. 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. Insofar 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.

Regulation of production

The production of crude oil, NGLs and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. We own and operate properties in North Dakota and Montana, which have regulations governing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum allowable rates of production from crude oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of crude oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, both states impose a production or severance tax with respect to the production and sale of crude oil, NGLs and natural gas within their jurisdictions.

The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

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Other federal laws and regulations affecting our industry

Energy Policy Act of 2005

The Energy Policy Act of 2005 (“EPAct 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, EPAct 2005 amends the NGA to add an anti-manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. EPAct 2005 provides FERC with the power to assess civil penalties of up to $1,496,035 per day, adjusted annually for inflation, for violations of the NGA and increases FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1,496,035 per violation per day, adjusted annually for inflation. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-manipulation provision of EPAct 2005, and subsequently denied rehearing. The rule makes it unlawful for any entity, directly or indirectly, 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, to (1) use or employ any device, scheme or artifice to defraud; (2) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) engage in any act, practice or course of business that operates as a fraud or deceit upon any person. The new anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but do apply to activities of gas pipelines and storage companies that provide interstate services, such as Section 311 service, 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 No. 704, as described below. The anti-manipulation rules and enhanced civil penalty authority increased FERC’s NGA enforcement authority. Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

FERC market transparency rules

On December 26, 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing, or Order No. 704. Under Order No. 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors, natural gas marketers and natural gas producers, are 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 No. 704. Order No. 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.

Effective November 4, 2009, pursuant to the Energy Independence and Security Act of 2007, the FTC issued a rule prohibiting market manipulation in the petroleum industry. The FTC rule prohibits any person, directly or indirectly, in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale from: (a) knowingly engaging in any act, practice or course of business, including the making of any untrue statement of material fact, that operates or would operate as a fraud or deceit upon any person; or (b) intentionally failing to state a material fact that under the circumstances renders a statement made by such person misleading, provided that such omission distorts or is likely to distort market conditions for any such product. A violation of this rule may result in civil penalties of up to $1,426,319 per day per violation, adjusted annually for inflation, in addition to any applicable penalty under the Federal Trade Commission Act.

North Dakota Industrial Commission crude oil and natural gas rules

The North Dakota Industrial Commission (“NDIC”) regulates the drilling and production of crude oil and natural gas in North Dakota. Beginning in 2012 and continuing thereafter, the NDIC has adopted more stringent rules relating to production activities, including with respect to financial assurance for wells and underground gathering pipelines, waste discharges and storage, hydraulic fracturing and associated public disclosure on the FracFocus chemical disclosure registry, site construction, underground gathering pipelines and spill containment, which new requirements are now in effect. These requirements have increased or will increase the well costs incurred by us and similarly situated crude oil and natural gas E&P operators, and we expect to continue to incur these increased costs as well as any added costs arising from new NDIC legal requirements laws and regulations applicable to the drilling and production of crude oil and natural gas that may be issued in the future.

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Furthermore, the NDIC regulates natural gas flaring and over the past decade has issued orders limiting flaring emissions. These requirements were further revised in 2020. Please see below the discussion of “Environmental protection and natural gas flaring initiatives” for more information on the natural gas flaring program. In addition, the NDIC has adopted rules that improve the safety of transporting Bakken crude oil by establishing operating standards for conditioning equipment to properly separate production fluids, limits to the vapor pressure of produced crude oil, and parameters for temperatures and pressures associated with the production equipment.

Pipeline safety regulation

Certain of our pipelines are subject to regulation by PHMSA under the Hazardous Liquids Pipeline Safety Act (“HLPSA”) with respect to crude oil and condensates and the Natural Gas Pipeline Safety Act (“NGPSA”) with respect to natural gas. The HLPSA and NGPSA govern the design, installation, testing, construction, operation, replacement and management of hazardous liquid and gas pipeline facilities. These laws have resulted in the adoption of rules by PHMSA, that, among other things, require transportation pipeline operators to develop and implement integrity management programs to comprehensively evaluate certain relatively higher risk areas, known as high consequence areas (“HCA”) and moderate consequence areas (“MCA”) along pipelines and take additional safety measures to protect people and property in these areas. The HCAs for natural gas pipelines are predicated on high-population areas (which, for natural gas transmission pipelines, may include Class 3 and Class 4 areas) whereas HCAs for crude oil, NGL and condensate pipelines are based on high-population areas, certain drinking water sources and unusually sensitive ecological areas. An MCA is attributable to natural gas pipelines and is based on high-population areas as well as certain principal, high-capacity roadways, though it does not meet the definition of a natural gas pipeline HCA. In addition, states have adopted regulations similar to existing PHMSA regulations for certain intrastate gas and hazardous liquid pipelines, which regulations may impose more stringent requirements than found under federal law. Historically, our pipeline safety compliance costs have not had a material 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 costs will not have a material adverse effect on our business and operating results. New pipeline safety laws or regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause us to incur increased capital and operating costs and operational restrictions, delays or cancellations.

Legislation in the past decade has resulted in more stringent mandates for pipeline safety and has charged PHMSA with developing and adopting regulations that impose increased pipeline safety requirements on pipeline operators. In particular, the HLPSA and NGPSA were amended by the Pipeline, Safety, Regulatory Certainty and Job Creation Act of 2011 (the “2011 Pipeline Safety Act”) and the Protecting Our Infrastructure of Pipelines and Enhancing Safety (“PIPES”) Act of 2016 and, most recently, the PIPES Act of 2020. Each of these laws imposed increased pipeline safety obligations on pipeline operators. The 2011 Pipeline Safety Act increased the penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of safety issues that could result in the adoption of new regulatory requirements by PHMSA for existing pipelines. The PIPES Act of 2020 reauthorized PHMSA through fiscal year 2023 and directed the agency to move forward with several regulatory initiatives, including obligating operators of nonrural 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.

Following the adoption of the 2011 Pipeline Safety Act, the PIPES Act of 2016 and the PIPES Act of 2020, PHMSA issued a series of significant rulemakings imposing more stringent regulations on certain types of pipelines. In October 2019, PHMSA published a final rule imposing numerous requirements on onshore gas transmission pipelines relating to maximum allowable operating pressure (“MAOP”) reconfirmation and exceedance reporting, the integrity assessment of additional pipeline mileage found in MCAs and non-HCA Class 3 and Class 4 areas by 2033, and the consideration of seismicity as a risk factor in integrity management. PHMSA published a second final rule in October 2019 for hazardous liquid transmission and gathering pipelines that significantly extends and expands the reach of certain of its integrity management requirements, requires accommodation of in-line inspection tools by 2039 unless the pipeline cannot be modified to permit such accommodation, increased annual, accident and safety-related conditional reporting requirements, and expanded the use of leak detection systems beyond HCAs. PHMSA also published final rules during February and July 2020 that amended the minimum safety issues related to natural gas storage facilities, including wells, wellbore tubing and casing, as well as added applicable reporting requirements. In November 2021, PHMSA issued a final rule that imposed safety regulations on approximately 400,000 miles of previously unregulated onshore gas gathering lines that, among other things, imposed criteria for inspection and repair of fugitive emissions, extend reporting requirements to all gas gathering operators and applied a set of minimum safety requirements to certain gas gathering pipelines with large diameters and high operating pressures. More recently, in August 2022, PHMSA issued a final rule that established more stringent standards for management of change, integrity management, corrosion control, and inspection criteria to help identify and mitigate potential failures and worst-case scenarios. Separately, in June 2021, PHMSA issued an Advisory Bulletin advising pipeline and pipeline facility operators of applicable requirements to update their inspection and maintenance plans for the elimination of hazardous leaks and minimization of natural gas released from pipeline facilities. PHMSA, together with state regulators, inspected these plans throughout 2022.

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These new regulatory actions or any future regulations adopted by PHMSA may impose more stringent requirements applicable to integrity management programs or other pipeline safety aspects of our operations, which could cause us to incur increased capital and operating costs and operational delays. In the absence of PHMSA pursuing any legal requirements, state agencies, to the extent authorized, may pursue state standards, including standards for rural gathering lines.

Environmental and occupational health and safety regulation

Our exploration, development and production operations are subject to stringent federal, tribal, regional, state and local laws and regulations governing occupational health and safety, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may, among other things, require the acquisition of permits to conduct drilling; govern the amounts and types of substances that may be released into the environment; limit or prohibit construction or drilling activities in environmentally-sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered species; require investigatory and remedial actions to mitigate pollution conditions; impose obligations to reclaim and abandon well sites and pits; and impose specific criteria addressing worker protection. Certain environmental laws impose strict, joint and several liability for costs required to remediate and restore sites where hydrocarbons, materials or wastes have been stored or released. 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 action obligations or the incurrence of capital expenditures, the occurrence of restrictions, delays or cancellations in the permitting, development or expansion of projects 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 crude 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.

The trend in environmental regulation is to place more restrictions and limitations on, and enhanced disclosures of, activities that may affect the environment, and thus, any new laws or regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement that result in more stringent and costly well construction, drilling, operating conditions, monitoring and reporting obligations, water management or completion activities, or waste handling, storage, transport, disposal or remediation requirements could 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. We may also experience a delay in obtaining or be unable to obtain required permits, which may interrupt our operations and limit our growth and revenues, which in turn could affect our profitability. Moreover, accidental spills or other releases may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such spills or releases, including any third-party claims for damage to property, natural resources or persons. While, historically, our compliance costs with environmental laws and regulations have not had a material adverse effect on our financial position, cash flows and results of operations, there can be no assurance that such costs will not be material in the future as a result of such existing laws and regulations or any new laws and regulations, or that such future compliance will not have a material adverse effect on our business and operating results. Some or all of such increased compliance costs may not be recoverable from insurance.

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

Hazardous substances and wastes

The Comprehensive Environmental Response, Compensation, and Liability Act (“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 who are considered to be responsible for the release of a “hazardous substance” into the environment. These classes of persons include current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances released at the site. Under CERCLA, these “responsible persons” may be subject to strict, joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. 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 or other pollutants into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances.

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We are also subject to the requirements of the Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. RCRA imposes strict requirements on the generation, storage, treatment, transportation, disposal and cleanup of hazardous and nonhazardous wastes. Under the authority of the EPA, most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. In the course of our operations, we generate ordinary industrial wastes that may be regulated as hazardous wastes. RCRA currently exempts certain drilling fluids, produced waters and other wastes associated with exploration, development and production of crude oil and natural gas from regulation as hazardous wastes. These wastes are instead regulated under RCRA’s less stringent nonhazardous waste provisions, state laws or other federal laws. There have been efforts from time to time to remove this exclusion, which removal could significantly increase our and our customers operating costs, and it is possible that certain crude oil and natural gas E&P wastes now classified as non-hazardous could be classified as hazardous waste in the future.

We currently own or lease, and have in the past owned or leased, properties that have been used for numerous years to explore and produce crude oil and natural gas. Although we have utilized operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons, hazardous substances and wastes may have been released on, under or from the properties owned or leased by us or on, under or from, other locations where these petroleum hydrocarbons and wastes have been taken for recycling or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons, hazardous substances and wastes were not under our control. These properties and the substances disposed or released thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) and to perform remedial plugging or pit closure operations to prevent future contamination.

Air emissions

The federal Clean Air Act (the “CAA”) and comparable state laws and regulations restrict the emission of various air pollutants from many sources through air emissions standards, construction and operating permitting programs and the imposition of other monitoring and reporting 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. Obtaining permits has the potential to restrict, delay or cancel the development or expansion of crude 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 2015, the EPA under the Obama Administration issued a final rule under the CAA, making the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone more stringent. Since that time, the EPA has issued area designations with respect to ground-level ozone, and, on December 31, 2020, published a notice of final action to retain the 2015 ozone NAAQS without revision on a going-forward basis. However, several groups have filed litigation over this December 2020 decision, and in October 2021 the EPA announced plans to reconsider the December 2020 decision. The EPA has indicated that it expects to complete its reconsideration efforts by the end of 2023. If the EPA were to adopt more stringent NAAQS for ground-level ozone as a result of its reconsideration of the December 2020 decision, state implementation of the revised standard or any other new legal requirements could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, significantly increase our capital expenditures and operating costs and reduce demand for the crude oil and natural gas that we produce, which one or more developments could adversely impact our E&P business.

Environmental protection and natural gas flaring initiatives

We attempt to conduct our operations in a manner that protects the health, safety and welfare of the public, our employees and the environment. We recognize the environmental and financial risks associated with air emissions, particularly with respect to flaring of natural gas from our operated well sites and are focused on reducing these emissions, consistent with applicable requirements.

We believe that one of the leading causes of natural gas flaring from the Bakken and Three Forks formations is a historical lack of sufficient natural gas gathering infrastructure in the Williston Basin, which translates into the inability of operators to promptly connect their wells to natural gas processing and gathering infrastructure. External factors impacting such inability that are out of the control of the operator include, for example, the granting of right-of-way access by land owners, investment from third parties in the development of gas gathering systems and processing facilities, and the development and adoption of regulations. We have allocated significant resources to connect our wells to natural gas infrastructure. The substantial majority of our operated wells are connected to gas gathering systems, which reduces our flared volumes of natural gas.

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The NDIC has issued orders and pursued other regulatory initiatives to implement legally enforceable “gas capture percentage goals” targeting the capture of natural gas produced in the state, commencing in 2014. As of November 1, 2020, the enforceable gas capture percentage goal is 91%. The NDIC requires operators to develop and implement Gas Capture Plans to maintain consistency with the agency’s gas capture percentage goals, but it maintains the flexibility to exclude certain gas volumes from consideration in calculating compliance with the state’s gas capture percentage goals. Wells must continue to meet or exceed the NDIC’s gas capture percentage goals on a statewide, county, per-field, or per-well basis. Failure of an operator to comply with the applicable goal at maximum efficiency rate may result in the imposition of monetary penalties and restrictions on production from subject wells. In September 2020, the NDIC revised the gas capture policy to allow several additional exceptions for companies that flare natural gas under certain circumstances, such as gas plant outages or delays in securing a right-of-way for pipeline construction. As of December 31, 2022, we were capturing substantially all of our natural gas production in North Dakota. While we were satisfying the applicable gas capture percentage goals as of December 31, 2022, there is no assurance that we will remain in compliance in the future or that such future satisfaction of such goals will not have a material adverse effect on our business and results of operations.

Climate change

The threat of climate change continues to attract considerable attention in the United States and around the world. Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, climate-related disclosure obligations, and regulations that directly limit GHG emissions from certain sources. Moreover, President Biden highlighted addressing climate change as a priority of his administration, issued several Executive Orders related to climate change, and recommitted the United States to long-term international goals to reduce emissions. In recent years the U.S. Congress has considered legislation to reduce emissions of GHGs, including methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas. While it presently appears unlikely that comprehensive climate change legislation will be passed by Congress in the near future, energy legislation and other regulatory initiatives are expected to be proposed that may be relevant to GHG emissions issues. For example, the IRA, which appropriates significant federal funding for renewable energy initiatives and, for the first time ever, imposes a fee on GHG emissions from certain facilities, was signed into law in August 2022. The excess methane emissions fee provision of the IRA takes effect in 2024. The provision applies to methane leaks from certain oil and gas facilities and begins at $900 per metric ton of leaked methane in 2024 and rises to $1,200 in 2025, and $1,500 for 2026 and thereafter. The emissions fee and funding provisions of the law could increase operating costs within the oil and gas industry and accelerate the transition away from fossil fuels, which could in turn adversely affect our business and results of operations.

In addition, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted rules and regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and gas system sources, and impose new standards reducing methane emissions from oil and gas operations through limitations on venting and flaring and the implementation of enhanced emission leak detection and repair requirements. The EPA also works together with the Department of Transportation (“DOT”) to implement GHG emissions limits on vehicles manufactured for operation in the United States.

In recent years, there has been considerable uncertainty surrounding regulation of methane emissions. During 2020, the former Trump Administration finalized two sets of amendments to the 2016 Subpart OOOO performance standards for methane, volatile organic compound (“VOC”) and sulfur dioxide emissions to lessen the impact of those standards and remove the transmission and storage segments from the source category for certain regulations. The first, known as the “2020 Technical Rule,” reduced the 2016 rule’s fugitive emissions monitoring requirements and expanded exceptions to pneumatic pump requirements, among other changes. The second, known as the “2020 Policy Rule,” rescinded the methane-specific requirements for certain oil and natural gas sources in the production and processing segments. However, shortly after taking office in 2021, President Biden issued an executive order calling on the EPA to revisit federal regulations regarding methane and establish new or more stringent standards for existing or new sources in the oil and gas sector, including the transmission and storage segments. The U.S. Congress also passed, and President Biden signed into law, a resolution under the Congressional Review Act (“CRA”) that revoked the 2020 Policy Rule. The CRA resolution did not address the 2020 Technical Rule. In response to President Biden’s executive order, in November 2021, the EPA issued a proposed rule that, if finalized, would make the existing regulations in Subpart OOOOa more stringent and establish Subpart OOOOb to expand emissions reduction requirements for new, modified and reconstructed oil and gas sources, including certain source types not previously regulated under Subpart OOOOa. In addition, the proposed rule would create a new Subpart OOOOc which would require states to develop plans to reduce methane and VOC emissions from existing sources that must be at least as effective as presumptive standards set by the EPA. This proposed rule would apply to upstream and midstream facilities at oil and natural gas well sites, natural gas gathering and boosting compressor stations, natural gas processing plants, and transmission and storage facilities. Owners or operators of affected emission units or processes would have to comply with specific standards of performance that may include leak detection using optical gas imaging and subsequent repair requirements, reduction of

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emissions by 95% through capture and control systems, zero-emission requirements, operations and maintenance requirements, and so-called green well completion requirements. The EPA issued a supplemental proposed rule in November 2022, which updated, strengthened, and expanded the standards provided in the November 2021 proposed rule. The supplemental proposed rule requires states to develop their compliance plan for existing sources under Subpart OOOOc within eighteen months of final publication. The EPA is currently seeking comments on the supplemental proposed rule, and like each of EPA’s previous methane emission regulations, any adopted final rule is likely to face immediate legal challenges. Separately, the Bureau of Land Management (“BLM”) has also proposed rules to limit venting, flaring, and methane leaks for oil and gas operations on federal lands. While we cannot predict the final scope or compliance costs of these proposed regulatory requirements, any such requirements have the potential to increase our operating costs and thus may adversely affect our financial results and cash flows.

At the international level, the United Nations (“UN”) -sponsored Paris agreement (“Paris Agreement”) requires member states to submit non-binding, individually determined reduction goals known as Nationally Determined Contributions every five years after 2020. President Biden has recommitted the United States to the Paris Agreement and, in April 2021, announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. Additionally, at the UN Climate Change Conference of Parties (“COP26”), held in November 2021, the United States and the European Union jointly announced the launch of a Global Methane Pledge, an initiative committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including “all feasible reductions” in the energy sector. COP26 concluded with the finalization of the Glasgow Climate Pact, which stated long-term global goals (including those in the Paris Agreement) to limit the increase in the global average temperature and emphasized reductions in GHG emissions. These goals were reaffirmed at the November 2022 Conference of Parties (“COP27”). At COP27, the US also announced, in conjunction with the European Union and other partner countries, that it would develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas. Moreover, various state and local governments have also publicly committed to furthering the goals of the Paris Agreement. The full impact of these actions, and any legislation or regulation promulgated to fulfill the United States’ commitments thereunder, is uncertain at this time, and it is unclear what additional initiatives may be adopted or implemented that may have adverse effects on our operations.

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. President Biden has issued several executive orders focused on addressing climate change, including items that may impact 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 eliminating subsidies provided to the fossil fuel industry, reducing non-CO2 GHG emissions, and increasing the emphasis on climate-related risks across government agencies and economic sectors. The Biden Administration has also called for revisions and restrictions to the leasing and permitting programs for oil and gas development on federal lands and, for a time, suspended federal oil and gas leasing activities. The Department of Interior’s (“DOI’s”) comprehensive review of the federal leasing program resulted in a reduction in the volume of onshore land held for lease and an increased royalty rate. Other actions adversely affecting the oil and gas industry that may be pursued by the Biden Administration include limiting hydraulic fracturing by banning new oil and gas permitting on federal lands and waters, potentially eliminating certain tax deductions and relief available to the oil and gas industry, and imposing restrictions on pipeline infrastructure and LNG export facilities. Litigation risks are also increasing, as a number of states, municipalities and other plaintiffs have sought to bring suit against various oil and gas companies in state or federal court, alleging, among other things, that such energy companies created public nuisances by producing fuels that contributed to climate change and its effects, such as rising sea levels, and therefore, are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts. The Company is not currently a defendant in any of these lawsuits, but it could be named in actions in the future making similar allegations. Should the Company be targeted by any such litigation, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to causation or contribution to the asserted damage, or to other mitigating factors. Involvement in such a case could have adverse reputational impacts and an unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.

Additionally, our access to capital may be impacted by climate change policies. Stockholders and bondholders currently invested in fossil fuel energy companies concerned about the potential effects of climate change may elect in the future to shift some or all of their investments into non-fossil fuel energy related sectors. Institutional investors who provide financing to fossil fuel energy companies also have become more attentive to sustainable lending and investment practices that favor “clean” power sources, such as wind and solar, making those sources more attractive, and some of them may elect not to provide funding for fossil fuel energy companies. Many of the largest U.S. banks have made “net zero” carbon emission commitments and have announced that they will be assessing financed emissions across their portfolios and taking steps to quantify and reduce those emissions. At COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”), a coalition of over 550 firms

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around the world, announced it had 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. These and other developments in the financial sector could lead to some lenders restricting access to capital for or divesting from certain industries or companies, including the oil and natural gas sector, or requiring that borrowers take additional steps to reduce their GHG emissions. Additionally, there is the possibility that financial institutions may be pressured or required to adopt policies that limit funding for fossil fuel energy companies. In late 2020, the Federal Reserve announced that it had joined the Network for Greening the Financial System (“NGFS”), a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Then, 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. More recently, in January 2023, the Federal Reserve published instructions for its pilot climate scenario analysis exercise, which the six largest U.S. banks are required to complete by July 31, 2023. While we cannot predict what policies may result from these announcements, a material reduction in the capital available to the fossil fuel industry could make it more difficult to secure funding for exploration, development, production, transportation, and processing activities, which could impact our business and operations. Additionally, in March 2022, the SEC issued a proposed rule that would mandate extensive disclosure of climate risks, including financial impacts, physical and transition risks, related climate-related governance and strategy, and GHG emissions, for all U.S.-listed public companies. Although the final form and substance of this rule and its requirements are not yet known and its ultimate impact on our business is uncertain, compliance with the proposed rule, if finalized, will result in additional legal, accounting and financial compliance costs which may be significant. In addition, enhanced climate disclosure requirements could accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon-intensive sectors. Separately, the SEC has also announced that it is scrutinizing existing climate-change related disclosures in public filings, increasing the potential for enforcement if the SEC were to allege an issuer’s existing climate disclosures misleading or deficient.

Finally, increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods, rising sea levels and other climatic events, as well as chronic shifts in temperature and precipitation patterns. These climatic developments have the potential to cause physical damage to our assets or disrupt our supply chains and thus could have an adverse effect on our exploration and production operations through, for example, water use curtailments in response to extended drought conditions. Additionally, changing meteorological conditions, particularly temperature, may result in changes to the amount, timing, or location of demand for energy or its production. While our consideration of changing climatic conditions and inclusion of safety factors in design is intended to reduce the uncertainties that climate change and other events may potentially introduce, our ability to mitigate the adverse impacts of these events depends in part on the effectiveness of our facilities and our disaster preparedness and response and business continuity planning, which may not have considered or be prepared for every eventuality.

Water discharges

The Federal Water Pollution Control Act (the “Clean Water Act” or “CWA”) and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The CWA also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit, and there continues to be uncertainty on the federal government’s applicable jurisdictional reach over waters of the United States (“WOTUS”), including wetlands. The EPA and U.S. Army Corps of Engineers (the “Corps”) under the Obama, Trump and Biden Administrations have pursued multiple rulemakings since 2015 in an attempt to determine the scope of such reach. While the EPA and Corps under the Trump Administration issued a final rule in April 2020 narrowing federal jurisdictional reach over WOTUS, the rule was later vacated by two federal district court decisions, resulting in a return to protections that were in place prior to the 2015 rulemaking revisions under the Obama Administration. President Biden had also previously issued an executive order to further review and assess these regulations consistent with the new administration’s policy objectives. The EPA and the Corps have since published a final rule, which will take effect on March 20, 2023, defining WOTUS according to the broader pre-2015 standards with additional updates to incorporate existing U.S. Supreme Court decisions and agency guidance regarding regional and geographic differences. However, the new rule has already been challenged, with the State of Texas and industry groups filing separate suits in federal court in Texas on January 18, 2023. Moreover, the EPA and the Corps have announced an intent to develop a subsequent rule further revising the definition of WOTUS. The U.S. Supreme Court is also expected to rule in mid-2023 on certain aspects of the definition. Therefore, the future substance of the WOTUS definition and its impacts on the scope of the CWA remain

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uncertain at this time. In addition, in an April 2020 decision, the U.S. Supreme Court held that, in certain cases, discharges from a point source to groundwater could fall within the scope of the CWA and require a permit. The Court rejected the EPA’s and Corps’ assertion that groundwater should be totally excluded from the CWA. To the extent any new rule or judicial determination expands the scope of the CWA’s jurisdiction in areas where we conduct operations, such developments could delay, restrict or halt permitting or development of projects, result in longer permitting timelines, or increase compliance expenditures or mitigation costs for our operations, which may reduce our rate of production of crude oil or natural gas.

The Oil Pollution Act of 1990 (the “OPA”) amends the CWA and sets minimum standards for prevention, containment and cleanup of crude oil spills. The OPA applies to vessels, offshore facilities and onshore facilities, including E&P facilities that may affect WOTUS. Under the OPA, responsible parties including owners and operators of onshore facilities may be held strictly liable for crude oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from crude oil spills. The OPA also requires owners or operators of certain onshore facilities to prepare Facility Response Plans for responding to a worst-case discharge of crude oil into WOTUS.

Operations associated with our production and development activities generate drilling muds, produced waters and other waste streams, some of which may be disposed of by means of injection into underground wells situated in non-producing subsurface formations. These injection wells are regulated pursuant to the federal Safe Drinking Water Act (the “SDWA”) Underground Injection Control (the “UIC”) program and analogous state laws. The UIC program requires permits from the EPA or analogous state agency for disposal wells that we operate, establishes minimum standards for injection well operations and restricts the types and quantities of fluids that may be injected. Any leakage from the subsurface portions of the injection wells may cause degradation of fresh water, potentially resulting in cancellation of operations of a well, imposition of fines and penalties from governmental agencies, incurrence of expenditures for remediation of affected resources and imposition of liability by landowners or other parties claiming damages for alternative water supplies, property damages and personal injuries. Moreover, any changes in the laws or regulations or the inability to obtain permits for new injection wells in the future may affect our ability to dispose of produced waters and ultimately increase the cost of our operations, which costs could be material.

In response to seismic events near underground injection wells used for the disposal of produced water from crude oil and natural gas activities, federal and some state agencies have investigated, and continue to investigate, whether such wells have caused increased seismic activity. In 2016, the United States Geological Survey identified six states, though not North Dakota or Montana, with areas of increased rates of induced seismicity that could be attributed to fluid injection or crude oil and natural gas extraction. In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. Another consequence of seismic events may be lawsuits alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells by us or our customers.

Hydraulic fracturing activities

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from unconventional formations, including shales. The process involves the injection of water, sand or other proppants and chemical additives under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing techniques in many of our drilling and completion programs.

The hydraulic fracturing process is typically regulated by state crude oil and natural gas commissions or similar agencies, but federal agencies have asserted regulatory authority over certain aspects of the process. While hydraulic fracturing is generally exempt from regulation under the SDWA’s UIC program, the EPA has published permitting guidance for certain hydraulic fracturing activities involving the use of diesel fuel and issued a final regulation under the CWA prohibiting discharges to publicly owned treatment works of wastewater from onshore unconventional oil and gas extraction facilities. In late 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 circumstances. These reports or any future studies could spur initiatives to further regulate hydraulic fracturing and ultimately make it more difficult or costly for the Company to perform fracturing activities. Moreover, in 2016, the BLM under the Obama Administration published a final rule imposing more stringent standards on hydraulic fracturing activities on federal lands, including requirements for chemical disclosure, wellbore integrity and handling of flowback water. However, in late 2018, the BLM under the Trump Administration published a final rule rescinding the 2016 final rule. Since that time, litigation challenging the BLM's 2016 final rule and the 2018 final rule has resulted in rescission in federal courts of both the 2016 and 2018 rules but appeals to those decisions are on-going.

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From time to time Congress has considered, but has not adopted, legislation to provide for federal regulation of hydraulic fracturing. The Biden Administration has issued executive orders, could issue additional executive orders and could pursue other legislative and regulatory initiatives that restrict hydraulic fracturing activities on federal lands. For example, the Biden Administration issued an order in January 2021 suspending the issuance of new leases on federal lands and waters pending review and reconsideration of federal oil and gas leasing and permitting practices. The suspension of these federal leasing activities prompted legal action by several states against the Biden Administration, resulting in the issuance of an injunction by a federal district judge in Louisiana, effectively halting implementation of the leasing suspension within the thirteen plantiff states, including Montana. Further constraints may be adopted by the Biden Administration in the future.

In addition, some states, including North Dakota and Montana where we primarily operate, have adopted, and other states may adopt, legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. For example, both North Dakota and Montana require operators to disclose chemical ingredients and water volumes used in hydraulic fracturing activities, subject to certain trade-secret exceptions. States could elect to adopt certain prohibitions on hydraulic fracturing, following the approach already taken by several states. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Nevertheless, if new or more stringent federal, state or local legal restrictions or bans relating to the hydraulic fracturing process are adopted in areas where we operate, or in the future plan to operate, we could incur potentially significant added costs to comply with such requirements, experience restrictions, delays or curtailment in the pursuit of exploration, development or production activities and perhaps even be limited or precluded from drilling wells or limited in the volume that we are ultimately able to produce from our reserves.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to, and litigation concerning, crude oil and natural gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to added delays, restrictions or cancellations in the pursuit of our operations or increased operating costs in our production of crude oil and natural gas. We may not be insured for, or our insurance may be inadequate to protect us against, these risks.

Endangered Species Act considerations

The federal Endangered Species Act (the “ESA”) and comparable state laws may restrict exploration, development and production activities that may affect endangered and threatened species or their habitats. The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered in the United States and prohibits the taking of endangered species. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”) and to bald and golden eagles under the Bald and Golden Eagle Protection Act. The U.S. Fish and Wildlife Service (the “FWS”) under the Trump Administration issued a final rule on January 7, 2021, which notably clarifies that criminal liability under the MBTA will apply only to actions “directed at” migratory birds, their nests or their eggs; however, the FWS under the Biden Administration has since published a final rule in October 2021 revoking the January 2021 rule and affirmatively stating that the MBTA prohibits incidental takes of migratory birds. Federal agencies are required to ensure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed or endangered species or modify their critical habitats. Some of our operations are located in areas that are designated as habitat for endangered or threatened species, and our development plans have been impacted on occasion by certain endangered or threatened species, including the Dakota Skipper and the Golden Eagle. If endangered or threatened species are located in areas of the underlying properties where we want to conduct seismic surveys, development activities or abandonment operations, such work could be prohibited or delayed by seasonal or permanent restrictions or require the performance of extensive studies or implementation of costly mitigation practices.

Moreover, the FWS may make determinations on the listing of species as endangered or threatened under the ESA and litigation with respect to the listing or non-listing of certain species as endangered or threatened may result in more fulsome protections for non-protected or lesser-protected species pursuant to specific timelines. The issuance of more stringent conservation measures or land, water, or resource use restrictions could result in operational delays and decreased production and revenue for us.

Operations on federal lands

Performance of crude oil and natural gas E&P activities on federal lands, including Indian lands and lands administered by the BLM, are subject to detailed federal regulations and orders that regulate, among other matters, drilling and operations on lands covered by these leases and calculation and disbursement of royalty payments to the federal government. For example, these regulations require the plugging and abandonment of wells and removal of production facilities by current and former operators, including corporate successors of former operators. These requirements may result in significant costs associated with the removal of tangible equipment and other restorative actions. Additionally, under certain circumstances, the BLM may require operations on federal leases to be suspended or terminated.

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Oil, NGL, and natural gas operations on federal lands are subject to increasing regulatory attention. The Biden Administration has explored various means to curtail oil and natural gas activities on federal lands. For example, in January 2021, President Biden issued an executive order that instructed the Secretary of the DOI to pause new oil and natural gas leases on public lands, but not existing operations under valid leases or on tribal lands which the federal government merely holds in trust, pending completion of a comprehensive review and reconsideration of federal oil and natural gas permitting and leasing practices. A federal district court issued a preliminary injunction against the order in June 2021 that was subsequently vacated and remanded back to the district court by Fifth U.S. Circuit Court of Appeals in August 2022. The district court then issued a permanent injunction against the order, though limited in scope to the thirteen plaintiff states, including Montana. Meanwhile, the DOI released a report on the federal oil and natural gas leasing program in November 2021 which included several recommendations for how to reform the program. Some of the report’s recommendations, including an increased royalty rate and a significant reduction in total available acreage, have been incorporated in recent lease sales. While most of the Biden Administration’s changes to federal lands regulations have focused on new leases, future regulatory efforts could shift focus to existing lease operations. For example, the BLM issued a proposed rule in November 2022 to reduce natural gas waste from venting, flaring, and leaks associated with exploration and production activities on federal and tribal lands. The outcome of litigation surrounding the Biden Administration’s Social Cost of Carbon (“SCC”) metric may also impact future regulatory decision-making. In February 2022, a district court blocked the Biden Administration’s use of its interim SCC value in agency decision-making. In March 2022, the Fifth Circuit stayed the order while the government’s appeal remains in progress. The ultimate result of this litigation may impact the character of new regulations on certain federal oil and gas leases or oil and gas infrastructure on federal lands, which in turn could impact our future operations.

Additionally, oil and natural gas operations and related infrastructure projects on federal lands may be impacted by recent changes to the National Environmental Policy Act (“NEPA”) implementing regulations. NEPA requires federal agencies, including the BLM and the federal Bureau of Indian Affairs (“BIA”), to evaluate major agency actions, such as the issuance of permits that have the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. On July 16, 2020, the Council on Environmental Quality (the “CEQ”) under the Trump Administration published a final rule modifying NEPA. The 2020 rule established a time limit of two years for preparation of environmental impact statements and one year for the preparation of environmental assessments. The 2020 rule also limited the scope of review to the direct effects of a proposed project on the environment. However, in April 2022 the CEQ under the Biden Administration introduced a new ‘Final Rule’ that reversed several parts of the 2020 rule, including the scope limitations. The 2022 Final Rule requires NEPA reviews to incorporate consideration of indirect and cumulative impacts of the proposed project, including effects on climate change and GHGs, consistent with pre-2020 requirements. The new rule also allows agencies to create stricter NEPA rules as they see fit but left in place the 2020 rule two-year time limit to complete environmental impact statements. More recently, in January 2023 the CEQ released updated guidance for agency consideration of GHG emissions and climate change impacts in environmental reviews, which includes, among other recommendations, best practices for analyzing and communicating climate change effects.

In addition to administrative and policy risks, operations on federal lands also face litigation risks. For example, in January 2022, a federal district court in Washington, DC, vacated the results of the federal government’s Lease Sale 257, effectively canceling the sale, on the grounds that the federal government failed to consider foreign consumption of oil and natural gas in its GHG emissions analysis. Lease Sale 257 was reinstated as part of the IRA, but litigation remains ongoing as to whether the lease sale was properly vacated. More recently, a June 2022 settlement approved by a federal district court in Washington, DC, obligates BLM to repeat its environmental reports under NEPA for all oil and gas leases sold between 2015 and 2020. The settlement stems from a 2016 lawsuit alleging that BLM was not properly accounting for the cumulative climate impacts of its federal leasing program. However, the settlement does not require the BLM to rescind affected leases nor does it prohibit the agency from approving applications for permits to drill.

Depending on any mitigation strategies recommended in such environmental assessments or environmental impact statements, we could incur added costs, which could be material, and be subject to delays, limitations or prohibitions in the scope of crude oil and natural gas projects or performance of midstream services. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt our or our customers’ E&P activities. Approximately 8% of our net acreage position in the Williston Basin is federal mineral acreage, which is spread across our acreage position, and any portion of a well on federal land requires a permit. However, we believe that the vast majority of our future drilling locations would not be affected by any subsequent need to obtain a federal permit.

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Employee health and safety

We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the U.S. Occupational Safety and Health Administration hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state regulations require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens.

Human Capital Resources

Our mission is to responsibly produce hydrocarbons while exercising capital discipline, operating efficiently, improving continuously and providing a rewarding environment for our employees. We, as a company and as individuals, seek to foster a culture of innovation and continuous improvement, constantly looking for ways to strengthen our organizational agility and adaptability.

To execute our strategy in the highly competitive oil and gas industry we need to attract, develop and retain a highly effective and diverse workforce. Our ability to do so depends on a number of factors, including an available pool of qualified talent, compelling compensation and benefits plans and an energizing environment committed to helping employees develop and grow. As of February 22, 2023, we employed 531 full-time employees and we utilize independent contractors to perform various field and corporate services as needed. As part of the Merger, an organizational review was completed to identify synergies across the legacy organizations. Staff reductions in connection with the Merger have occurred, and corporate functions are expected to transfer to our corporate headquarters in Houston, Texas by June 30, 2023. Our current hiring plans focus on advancing talent attraction in our primary operating locations of Houston, Texas and Williston, North Dakota. We believe that the knowledge transfer plans we have in place are appropriate, and that we will continue to have the human capital necessary to operate our business safely while executing on our strategic priorities. Additionally, we are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees to be satisfactory.

Health and safety

We are committed to protecting the health and safety of our employees, our contractors and the communities in which we operate. We seek to improve our procedures to maintain our safety culture. For example, our environmental, health and safety teams regularly monitor and update our recommended safety practices with feedback and input from our field personnel under a management of change process framework. We operate our worksites under a stop work authority program pursuant to which every person on our worksites is empowered to halt operations to address a potential safety issue. We have developed a comprehensive safety management system that includes recurring risk assessment, hazard recognition and mitigation and emergency response preparedness training, protective measures including adequate personal protective equipment, life-saving rules, onboarding processes, contractor safety management, partner surveys, comprehensive audits, semi-annual safety summits, executive-level reviews of incidents and ad-hoc safety stand-downs. In addition, safety training is provided to all employees, and, in order to reinforce accountability, safety performance is integrated into our annual compensation program. We seek to partner only with contractors and vendors who share our commitment to safety.

Compensation and benefits

The goal of our total rewards program is to provide a transparent, thoughtful framework for decisions on employee compensation and benefits. Our total rewards program considers goals in addition to financial benefits and aims to increase employee focus on key performance goals, improve overall happiness and well-being and deepen commitment to our collective success. We do this by ensuring employees at Chord are fairly compensated and feel valued, which enables us to attract, motivate and retain high level talent while delivering strong performance to achieve our business strategy. Our intent is to ensure the compensation and benefits provided as part of our total rewards program are fair and equitable across positions and locations, market competitive, based on merit, consistent with our values and transparent to our employees.

The core elements of our compensation program include base pay, short-term incentives and long-term incentive opportunity for employees at all levels of the Company. In addition, we provide benefits that include retirement plan dollar matching, health insurance for employees and their families, income protection and disability coverage, paid time off, flexible work schedules, financial wellness tools and resources and emotional well-being services, such as an employee Life Assistance Program.

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Training, development and career opportunities

Our team of talented employees possess a broad set of skills including engineering, geology, production, marketing, land, supply chain, health and human safety, human resources, finance, accounting, information technology and legal. Many of our employees work in disciplines that require highly specialized skills and subject-matter expertise, underpinning our ability to deliver on our strategic priorities. We are committed to the personal and professional development of our employees, with the belief that a greater level of knowledge, skill and ability benefits the employee and fosters a more creative, innovative, efficient and therefore competitive organization. We empower our employees to develop the skills they need to perform in their current jobs while also developing skills and experiences to support their longer-term growth. We provide our employees with programs that support their learning and development, which are designed to build and strengthen employees’ abilities, including leadership trainings, development of professional competencies, safety trainings and information and technology trainings. We are also proud to sponsor training and scholarships to support growth in our communities, such as: serving as corporate sponsor to the Bakken Area Skills Center, which provides high school students hands on training in various technical trades; sponsoring engineering college scholarships in North Dakota and Montana; volunteering at Habitat for Humanity to build homes for families in need of safe and affordable housing; and supporting and promoting OneGoal and Junior Achievement in Houston, which provide access to college scholarships and classroom mentorship opportunities for students across our community.

Finally, we have in place a robust approach to succession planning for key personnel by assessing the competencies, experience, leadership capabilities and development opportunities of identified succession candidates. We will continue to build a pipeline of talent for the future through our new graduate and intern hiring programs, which brings fresh perspectives and new ideas to the organization to help us continually challenge the status-quo.

Diversity, equity and inclusion

We believe a diverse workforce provides the best opportunity to obtain unique perspectives, experiences and ideas to help our business succeed, and we are committed to creating an environment where every employee is valued and heard. We regularly seek ways to increase the diversity of our workforce, and we embrace an approach to talent attraction and promotion that enables each and every individual to be evaluated based on merit. Our Compensation and Human Resources Committee reviews the Company’s development, implementation and effectiveness of our human resources and human capital management practices, policies, strategies and goals, including those related to the recruitment, development and retention of personnel, talent management, diversity, equity and inclusion and other employment practices. Similarly, our Environmental Social and Governance Committee provides oversight, guidance and perspective to management and the Board of Directors regarding the Company’s policies, programs and initiatives related to the promotion of diversity. As of February 22, 2023, approximately 25% of our employees are either women or members of a minority group. In addition, the Board of Directors believes it is important for directors to possess a diverse array of backgrounds, skills and achievements. When considering new candidates, the Nominating and Governance Committee, with input from the Board of Directors, takes these factors into account as set forth in its charter. As of February 22, 2023, 63% of our independent directors are women.

We are an equal opportunity employer and do not discriminate on the basis of race, religion, color, national origin, sex, gender, gender expression, sex (including pregnancy, sexual orientation and gender identity), age, marital status, socioeconomic background, veteran status or disability status. We engage with individuals with disabilities to provide reasonable accommodations that may allow them to participate in the job application or interview process, to perform essential job functions and to receive other benefits and privileges of employment.

In addition, we seek to work with business partners who do not engage in prohibited discrimination in hiring or in their employment practices, and who make decisions about hiring, salary, benefits, training opportunities, work assignments, advancement, discipline, termination, retirement and other employment decisions based on job and business-related criteria. To sustain and promote a diverse, equitable and inclusive workforce, we maintain a robust compliance program supported by annual certification by all employees to our Code of Business Conduct and Ethics Policy, as well as training programs on equal employment opportunity.

Offices

Our principal corporate office is located in Houston, Texas at 1001 Fannin Street. We also have a corporate office in Denver, Colorado at 1700 Lincoln Street. We also own field offices in the North Dakota communities of Williston, Ray, New Town and Watford City.

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Available Information

We are required to file annual, quarterly and current reports, proxy statements and other information with the SEC. Our filings with the SEC are available to the public from commercial document retrieval services and at the SEC’s website at http://www.sec.gov.

We make available on our website at http://www.chordenergy.com all of the documents that we file with the SEC, free of charge, as soon as reasonably practicable after we electronically file such material with the SEC. Information contained on our website is not incorporated by reference into this Annual Report on Form 10-K.

Other information, such as presentations, the charters of the Audit and Reserves Committee, Compensation and Human Resources Committee and Environmental, Social and Governance Committee, and the Code of Business Conduct and Ethics Policy, are available on our website, http://www.chordenergy.com, under “Investors — Corporate Governance” and in print to any stockholders who provide a written request to the Corporate Secretary at 1001 Fannin Street, Suite 1500, Houston, Texas 77002.

Our Code of Business Conduct and Ethics Policy applies to all directors, officers and employees, including the Chief Executive Officer and Chief Financial Officer. Within the time period required by the SEC and The Nasdaq Stock Market LLC, as applicable, we will post on our website any modification to the Code of Business Conduct and Ethics Policy and any waivers applicable to senior officers who are defined in the Code of Business Conduct and Ethics, as required by the Sarbanes-Oxley Act of 2002.

We also make available Sustainability Reports and other sustainability documents on our website, which contain various performance highlights relating to ESG and human capital measures. Information contained in our Sustainability Reports, and other documents, are not incorporated by reference into, and do not constitute a part of, this Annual Report on Form 10-K.

References to the Company’s website in this Form 10-K are provided as a convenience and do not constitute, and should not be deemed, an incorporation by reference of the information contained on, or available through, the website, and such information should not be considered part of this Form 10-K.

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Item 1A. Risk Factors

Our business involves a high degree of risk. If any of the following risks, or any risk described elsewhere in this Annual Report on Form 10-K, actually occurs, our business, financial condition, results of operations or cash flows could suffer. The risks described below are not the only ones facing us. Additional risks not presently known to us or which we currently consider immaterial also may adversely affect us.

Risks related to the oil and gas industry and our business

A substantial or extended decline in commodity prices, for crude oil and, to a lesser extent, NGLs and natural gas, may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The prices we receive for our crude oil and, to a lesser extent, NGLs and natural gas, heavily influence our revenue, profitability, cash flow from operations, access to capital and future rate of growth. Crude oil, NGLs and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for crude oil, NGLs and natural gas have been volatile, and these markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:

•worldwide and regional economic and political conditions impacting the global supply and demand for crude oil, NGLs and natural gas;

•the actions of OPEC+ countries, including Russia;

•the price and quantity of imports of foreign crude oil, NGLs and natural gas;

•political conditions in or affecting other crude oil, NGL and natural gas producing countries, including the current conflicts in and among the Middle East and conditions in South America, China, India and Russia;

•the level of global exploration and production;

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

•events that impact global market demand, including impacts from wars, such as the ongoing conflict between Russia and Ukraine, conflicts and global health epidemics and concerns such as the COVID-19 pandemic;

•localized supply and demand fundamentals and regional, domestic and international transportation availability;

•weather conditions and natural disasters;

•domestic and foreign governmental laws, regulations and policies, including, among others, the IRA, environmental requirements and the discouragement of the use of fuels that emit GHGs and encouragement of the use of alternative energy sources;

•speculation as to future commodity prices and the speculative trading of crude oil, NGL and natural gas futures contracts;

•changing consumer or market preferences, stockholder activism or activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and production of crude oil, NGLs and natural gas and related infrastructure;

•price and availability of competitors’ supplies of crude oil, NGLs and natural gas;

•technological advances affecting energy consumption; and

•the price and availability of alternative fuels.

Substantially all of our crude oil and natural gas production is sold to purchasers under short-term (less than 12-month) contracts at market-based prices, and our NGL production is sold to purchasers under long-term (more than 12-month) contracts at market-based prices. Low crude oil, NGL and natural gas prices will reduce our cash flows, borrowing ability, the present value of our reserves and our ability to develop future reserves. See below “Risks related to our financial position—Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our estimated net crude oil, NGL and natural gas reserves.” Low crude oil, NGL and natural gas prices may also reduce the amount of crude oil, NGLs and natural gas that we can produce economically and may affect our proved reserves. See also “Our estimated net proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves” below.

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The ability or willingness of OPEC+ to set and maintain production levels has a significant impact on oil prices.

OPEC is an intergovernmental organization that seeks to manage the price and supply of oil on the global energy market. Actions or inaction of OPEC+ members have a significant impact on global oil supply and pricing. For example, OPEC+ nations have previously agreed to take measures, including production cuts and increases, in an effort to achieve certain global supply or demand targets or to achieve certain crude oil price outcomes. There can be no assurance that OPEC+ members will continue to agree to future production cuts, moderating future production or other actions to support and stabilize oil prices, and they may take actions that have the effect of reducing oil prices. Uncertainty regarding future actions to be taken by OPEC+ members could lead to increased volatility in the price of oil, which could adversely affect our business, financial condition, results of operations and cash flows.

Drilling for and producing crude oil and natural gas are high-risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations. We use some of the latest available horizontal drilling and completion techniques, which involve risk and uncertainty in their application.

Our future financial condition and results of operations will depend on the success of our exploitation, exploration, development and production activities. Our crude oil and natural gas E&P activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable crude oil, NGL or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit drilling locations or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “Our estimated net proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves” below. Our cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in planned expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

•shortages of or delays in obtaining equipment and qualified personnel;

•facility or equipment malfunctions and/or failure;

•unexpected operational events, including accidents;

•pressure or irregularities in geological formations;

•adverse weather or climatic conditions, such as blizzards, ice storms, wildfires, floods and prolonged drought conditions;

•reductions in crude oil, NGL and natural gas prices;

•inflation in exploration and drilling costs;

•disruptions in our supply chain for raw materials, chemicals and equipment;

•delays imposed by or resulting from compliance with regulatory requirements, including permits;

•proximity to and capacity of transportation facilities;

•contractual disputes;

•title problems; and

•limitations in the market for crude oil, NGLs and natural gas.

Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers in order to maximize cumulative recoveries and therefore generate the highest possible returns. Risks that we face while drilling include, but are not limited to, the following:

•spacing of wells to maximize production rates and recoverable reserves;

•landing the wellbore in the desired drilling zone;

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

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

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

Risks that we face while completing our wells include, but are not limited to, 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;

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

•protecting nearby producing wells from the impact of fracture stimulation.

Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and limited takeaway capacity or otherwise, and/or crude oil, NGL and natural gas prices decline, the return on our investment for certain projects may not be as attractive as we anticipate. Further, as a result of any of these developments, we could incur material write-downs of our oil and gas properties and the value of our undeveloped acreage could decline in the future.

Our estimated net proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating crude oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K. See “Item 1. Business—Exploration and Production Operations” and “Item 8. Financial Statements and Supplementary Data—Note 26—Supplemental Oil and Gas Reserve Information — Unaudited” for additional information about our estimated crude oil and natural gas reserves and the PV-10 and Standardized Measure as of December 31, 2022, 2021 and 2020.

In order to prepare our estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as crude oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Although the reserve information contained herein is reviewed by our independent reserve engineers, estimates of crude oil, NGL and natural gas reserves are inherently imprecise.

Actual future production, crude oil, NGL and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K. In addition, we may adjust estimates of net proved reserves to reflect production history, results of exploration and development, prevailing crude oil and natural gas prices and other factors, many of which are beyond our control. Due to the limited production history of our undeveloped acreage, the estimates of future production associated with such properties may be subject to greater variance to actual production than would be the case with properties having a longer production history.

You should not assume that the present value of future net revenues from our estimated net proved reserves is the current market value of our estimated net crude oil and natural gas reserves. In accordance with SEC requirements, we based the estimated discounted future net revenues from our estimated net proved reserves on the unweighted arithmetic average of the first-day-of-the-month price for the preceding 12 months without giving effect to derivative transactions. Actual future net revenues from our oil and gas properties will be affected by factors such as:

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

•actual cost of development and production expenditures;

•the amount and timing of actual production; 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 oil and gas properties will affect the timing and amount of actual future net revenues from estimated net proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues 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 industry in general.

Actual future prices and costs may differ materially from those used in the present value estimates included in this Annual Report on Form 10-K. Any significant future price changes will have a material effect on the quantity and present value of our estimated net proved reserves.

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If crude oil, NGL and natural gas prices decline, or for an extended period of time remain at depressed levels, we may be required to take write-downs of the carrying values of our oil and gas properties.

We review our proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. In addition, we assess our unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and gas properties, which may result in a decrease in the amount available under the Credit Facility. During the period from January 1, 2020 through November 19, 2020 (Predecessor), we recorded impairment charges of $4.4 billion to reduce the carrying value of our proved oil and gas properties to their estimated fair values. There were no impairment charges to our oil and gas properties during the period from November 20, 2020 through December 31, 2020 (Successor) or for the years ended December 31, 2021 (Successor) or 2022 (Successor).

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services or the unavailability of sufficient transportation for our production could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.

Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs of rigs, equipment, supplies and personnel are substantially greater and their availability to us may be limited. Additionally, these services may not be available on commercially reasonable terms.

Shortages or the high cost of drilling rigs, equipment, supplies, personnel or oilfield services or the unavailability of sufficient transportation for our production could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital plan, which could have a material adverse effect on our business, financial condition or results of operations. Additionally, compliance with new or emerging legal requirements that affect midstream operations in North Dakota or Montana may reduce the availability of transportation for our production. For example, the NDIC adopted regulations in 2013 that impose more rigorous pipeline development standards on midstream operators, some of whom we rely on to construct and operate pipeline infrastructure to transport the crude oil, NGLs and natural gas we produce.

Substantially all of our producing properties and operations are located in the Williston Basin, making us vulnerable to risks associated with operating in a concentrated geographic area.

Our producing properties are geographically concentrated in the Williston Basin in northwestern North Dakota and northeastern Montana. As a result, we may be disproportionately exposed to the impact of economics in the Williston Basin or delays or interruptions of production from those wells caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of crude oil, NGLs or natural gas produced from the wells in those areas. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic crude oil and natural gas producing areas such as the Williston Basin, which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Our crude oil, NGLs and natural gas are sold in a limited number of geographic markets and each has a generally fixed amount of storage and processing capacity. As a result, if such markets become oversupplied with crude oil, NGLs and/or natural gas, it could have a material negative effect on the prices we receive for our products and therefore an adverse effect on our financial condition and results of operations. Variances in quality may also cause differences in the value received for our products.

Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. The impact of regional economics or delays or interruptions of production in an area could have a material adverse effect on our financial condition and results of operations.

Our operations on the Fort Berthold Indian Reservation of the Three Affiliated Tribes in North Dakota are subject to various federal, state, local and tribal regulations and laws, any of which may increase our costs and have an adverse impact on our ability to effectively conduct our operations.

Various federal agencies within the U.S. Department of the Interior (the “Department of the Interior”), particularly the BIA and the Office of Natural Resource Revenue, along with the Three Affiliated Tribes of the Fort Berthold Indian Reservation (“MHA Nation”), promulgate and enforce regulations pertaining to operations on the Fort Berthold Indian Reservation. In addition, the MHA Nation is a sovereign nation having the right to enforce laws and regulations independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees, approvals and other conditions that apply to lessees, operators and contractors conducting operations on the Fort Berthold Indian Reservation. Lessees and operators conducting operations on tribal lands may be subject to the MHA Nation’s court system. On February 4, 2022, the Department

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of the Interior issued an official opinion stating that the minerals beneath the Missouri River riverbed located on the Fort Berthold Indian Reservation belong to the MHA Nation and not the state of North Dakota, overturning a 2020 Trump-agency decision that gave the state of North Dakota ownership. One or more of these factors may increase our costs of doing business on the Fort Berthold Indian Reservation and may have an adverse impact on our ability to effectively transport products within the Fort Berthold Indian Reservation or to conduct our operations on such lands.

We depend upon a limited number of midstream providers for a large portion of our midstream services, and our failure to obtain and maintain access to the necessary infrastructure from these providers to successfully deliver crude oil, natural gas and NGLs to market may adversely affect our earnings, cash flows and results of operations.

Our delivery of oil, NGLs and natural gas depends upon the availability, proximity and capacity of pipelines, other transportation facilities and gathering and processing facilities primarily owned by a limited number of midstream service providers. The capacity of transmission, gathering and processing facilities may be insufficient to accommodate potential production from existing and new wells, which may result in substantial discounts in the prices we receive for our oil, NGLs and natural gas or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Our ability to secure access to pipeline infrastructure on favorable economic terms could affect our competitive position. In addition, midstream service providers could change or impose more stringent specifications on the quality of our production they are willing to accept, including the gravity and sulphur content of our crude oil and the Btu content of our natural gas. If the total mix of product fails to meet the applicable product quality specification, these midstream service providers may refuse to accept all or a part of the production we deliver, or we may be required to deliver production to meet such quality specifications that yields a lower realized price.

Historically our ownership interest in and control of OMP allowed us to exercise significant control over the development of midstream infrastructure to service a portion of our operations. However, as a result of the OMP Merger, we no longer control those operations and facilities and are dependent on a limited number of midstream providers for these services. Access to midstream assets may be unavailable due to market conditions or mechanical or other reasons. A lack of access to needed infrastructure, or an extended interruption of access to or service from our or a midstream provider’s pipelines and facilities for any reason, including vandalism, sabotage or cyber-attacks on such pipelines and facilities or service interruptions, could result in adverse consequences to us, such as delays in producing and selling our crude oil, NGLs and natural gas.

Our dependence on midstream service providers for transmission, gathering and processing services makes us dependent on them in order to get our crude oil, NGLs and natural gas to market. To the extent these services are delayed or unavailable, we would be unable to realize revenue from wells served by such facilities until suitable arrangements are made to market our production. Our failure to obtain these services on acceptable terms could materially harm our business.

Legal and regulatory challenges to transportation may impact our ability to move volume.

The impact of pending and future legal proceedings on the systems, pipelines and facilities that we rely on can affect our ability to market our products and have a negative impact on realized pricing. In July 2020, the operator of DAPL was ordered by a U.S. District court to halt oil flow and empty the pipeline within 30 days while an environmental impact study (“EIS”) is completed. Also, in July 2020, the U.S. Court of Appeals for the District of Columbia Circuit issued a temporary administrative stay while the court considers the merits of a longer-term emergency stay order through the appeals process. On January 26, 2021, the U.S. Court of Appeals for the District of Columbia Circuit upheld the U.S. District court’s ruling that an EIS is needed and also reaffirmed its earlier decision which allows DAPL to operate through the EIS process. The owners of DAPL appealed the lower court decision to the U.S. Supreme Court in September 2021; however, the appeal was rejected on February 22, 2022. The Corps continues to conduct the EIS, a draft of which is estimated to be completed and available for public comments in the Spring of 2023. Once the EIS is completed, the Corps will determine whether DAPL is safe to operate or must be shut down. We regularly use DAPL in addition to other outlets to market our crude oil to end markets. Our risk is not concentrated at DAPL as we have alternative outlets to sell our crude oil production using multiple modes of transportation. In the event DAPL were to cease operating, we would anticipate Williston Basin crude oil prices to weaken materially before improving as the market adapts to rail transportation.

A portion of our crude oil and NGL production is transported to market centers by rail. Potential crude oil or NGL train derailments or crashes as well as state or federal restrictions on the vapor pressure of crude oil transported by, or loaded on or unloaded from, railcars could also impact our ability to market and deliver our products and cause significant fluctuations in our realized prices due to tighter safety regulations imposed on crude-by-rail transportation and interruptions in service. See “Item 1. Business—Regulation—Regulation of transportation and sales of crude oil” for more information about the regulations relating to the transport of crude oil by rail.

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Limited takeaway capacity can result in significant discounts to our realized prices.

The crude oil business environment has historically been characterized by periods when crude oil production has surpassed local transportation and refining capacity, resulting in substantial discounts in the price received for crude oil versus prices quoted for NYMEX West Texas Intermediate (“NYMEX WTI”) crude oil. In the past, there have been periods when this discount has substantially increased due to the production of crude oil in the area increasing to a point that it temporarily surpasses the available pipeline transportation, rail transportation and refining capacity in the area. Expansions of both rail and pipeline facilities have reduced the prior constraint on crude oil transportation out of the Williston Basin and improved basin differentials received at the lease. See “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for information about our realized crude oil prices and average price differentials relative to NYMEX WTI for the years ended December 31, 2022, 2021 and 2020.

Additionally, the refining capacity in the U.S. Gulf Coast is insufficient to refine all of the light sweet crude oil being produced in the United States. The United States imports heavy crude oil and exports light crude oil to utilize the U.S. Gulf Coast refineries that have more heavy refining capacity. If light sweet crude oil production remains at current levels or continues to increase, demand for our light crude oil production could result in widening price discounts to the world crude oil prices and potential shut-in or reduction of production due to a lack of sufficient markets despite the lift on prior restrictions on the exporting of crude oil and natural gas from the United States.

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

Approximately 23% of our estimated net proved reserves were classified as PUD as of December 31, 2022. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. The future development of our PUD reserves is dependent on future commodity prices, costs and economic assumptions that align with our internal forecasts as well as access to liquidity sources, such as capital markets, the Credit Facility and derivative contracts. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the PV-10 of our estimated PUD reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved reserves as unproved reserves.

Unless we replace our crude oil, NGL and natural gas reserves, our reserves and production will decline, which could adversely affect our business, financial condition and results of operations.

Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our estimated net proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future crude oil, NGL and natural gas reserves and production, and therefore our cash flows and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire additional reserves to replace our current and future production at acceptable costs. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations could be adversely affected.

Our business is subject to operating risks that could result in substantial losses or liability claims, and we may not be insured for, or our insurance may be inadequate to protect us against these risks.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our E&P activities are subject to all the operating risks associated with drilling for and producing crude oil and natural gas, including the possibility of:

•environmental hazards, such as natural gas leaks, crude oil and produced water spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials and unauthorized discharges of brine, well stimulation and completion fluids, toxic gas, such as hydrogen sulfide, or other pollutants into the environment;

•abnormally pressured formations;

•shortages of, or delays in, obtaining water for hydraulic fracturing activities;

•supply chain disruptions which could delay or halt our development projects;

•mechanical difficulties, such as stuck oilfield drilling and service tools and casing failure;

•personal injuries and death; and

•natural disasters.

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:

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•injury or loss of life;

•damage to and destruction of property, natural resources and equipment;

•pollution and other environmental damage;

•regulatory investigations and penalties;

•suspension of our operations; and

•repair and remediation costs.

Insurance against all operational risk is not available to us. We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Also, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

Drilling locations are scheduled to be drilled over several years and may not yield crude oil, NGLs or natural gas in commercially viable quantities.

Our drilling locations are in various stages of evaluation, ranging from a location which is ready to drill to a location that will require substantial additional interpretation. There is no way to predict in advance of drilling and testing whether any particular location will yield crude oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether crude oil or natural gas will be present or, if present, whether crude oil, NGLs or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of crude oil, NGLs or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from the well or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. We cannot assure you that the analogies we draw from available data from other wells, more fully explored locations or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or other operators in the Williston Basin may not be indicative of future or long-term production rates. In sum, the cost of drilling, completing and operating any well is often uncertain, and new wells may not be productive.

Our potential drilling locations are scheduled to be drilled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Our management has identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These potential drilling locations, including those without PUD reserves, represent a significant part of our execution strategy. Our ability to drill and develop these locations is subject to a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, crude oil, NGL and natural gas prices, costs and drilling results. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill a substantial portion of our potential drilling locations. See also “Risks related to our financial position—Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our estimated net crude oil, NGL and natural gas reserves.”

Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce crude oil, NGLs or natural gas from these or any other potential drilling locations. Pursuant to existing SEC rules and guidance, subject to limited exceptions, PUD reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. These rules and guidance may limit our potential to book additional PUD reserves as we pursue our drilling program.

Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage, the primary term is extended through continuous drilling provisions or the leases are renewed. Failure to drill sufficient wells in order to hold acreage will result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.

As of December 31, 2022, approximately 99% of our total net acreage in the Williston Basin was held by production. The leases for our net acreage not held by production will expire at the end of their primary term unless production is established in paying quantities under the units containing these leases, the leases are held beyond their primary terms under continuous drilling provisions or the leases are renewed. In the Williston Basin, our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. Unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will

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expire. As of December 31, 2022, we had an aggregate of 321 net acres expiring in 2023, 1,934 net acres expiring in 2024 and 405 net acres expiring in 2025 in the Williston Basin. The cost to renew such leases may increase significantly and we may not be able to renew such leases on commercially reasonable terms or at all. In addition, on certain portions of our acreage, third-party leases become immediately effective if our leases expire. Our ability to drill and develop these locations depends on a number of uncertainties, including crude oil, NGL 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 and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business. During the period from January 1, 2020 through November 19, 2020 (Predecessor), we recorded non-cash impairment charges of $401.1 million on our unproved properties due to expiring leases, periodic assessments and drilling plan uncertainty on certain acreage of our unproved properties. We did not record any impairment charges on unproved properties during the years ended December 31, 2022 and 2021 (Successor) or the period from November 20, 2020 through December 31, 2020 (Successor).

We are not the operator of all of our drilling locations, and, therefore, we may not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated assets.

We may enter into arrangements with respect to existing or future drilling locations that result in a greater proportion of our locations being operated by others. As a result, we may have limited ability to exercise influence over the operations of the drilling locations operated by our partners. Dependence on the operator could prevent us from realizing our target returns for those locations. The success and timing of exploration and 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;

•approval of other participants in drilling wells;

•selection of technology; and

•the rate of production of reserves, if any.

This limited ability to exercise control over the operations of some of our drilling locations may cause a material adverse effect on our results of operations and financial condition.

Our operations are subject to federal, state and local laws and regulations related to environmental and natural resources protection and occupational health and safety which may expose us to significant costs and liabilities and result in increased costs and additional operating restrictions or delays.

Our operations are subject to stringent federal, tribal, regional, state and local laws and regulations governing occupational health and safety, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to our operations and services. The trend of more expansive and stringent environmental and occupational health and safety legislation and regulations applied to the oil and gas industry could continue, resulting in material increases in our costs of doing business and consequently affecting profitability. See “Item 1. Business—Regulation—Environmental and occupational health and safety regulation” for more discussion on these environmental and occupational health and safety matters. Compliance with existing environmental and occupational safety and health laws, regulations, executive orders and other regulatory initiatives, or any other such new legal requirements, could, among other things, require us or our customers to install new or modified emission controls on equipment or processes, incur longer permitting timelines, and incur significantly increased capital or operating expenditures, which costs may be material. One or more of these developments that impact us, our service providers or our customers could have a material adverse effect on our business, results of operations and financial condition and reduce demand for our products.

Failure to comply with federal, state and local laws and regulations could adversely affect our ability to produce, gather and transport our crude oil, NGLs and natural gas and may result in substantial penalties.

Our operations are substantially affected by federal, state and local laws and regulations, particularly as they relate to the regulation of crude oil, NGL and natural gas production and transportation. These laws and regulations include regulation of crude oil, NGL and natural gas exploration and production and related operations, including a variety of activities related to the drilling of wells, and the interstate transportation of crude oil, NGLs and natural gas by federal agencies such as FERC, as well as state agencies. We may incur substantial costs in order to maintain compliance with these laws and regulations. Due to recent incidents involving the release of crude oil, NGLs and natural gas and fluids as a result of drilling activities in the United States, there have been a variety of regulatory initiatives at the federal and state levels to restrict crude oil, NGL and natural gas drilling operations in certain locations. Any increased regulation or suspension of crude oil, NGL and natural gas exploration and

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production, or revision or reinterpretation of existing laws and regulations, that arise out of these incidents or otherwise could result in delays and higher operating costs. Such costs or significant delays could have a material adverse effect on our business, financial condition and results of operations. With regard to our physical purchases and sales of energy commodities, we must also comply with anti-market manipulation laws and related regulations enforced by FERC, the CFTC and the FTC. To the lesser extent we are a shipper on interstate pipelines, we must comply with the FERC-approved tariffs of such pipelines and with federal policies related to the use of interstate capacity. Should we fail to comply with all applicable statutes, rules, regulations and orders of FERC, the CFTC or the FTC, we could be subject to substantial penalties and fines.

We expect to consider from time to time further strategic opportunities that may involve acquisitions, dispositions, investments in joint ventures, partnerships, and other strategic alternatives that may enhance stockholder value, any of which may result in the use of a significant amount of our management resources or significant costs, and we may not be able to fully realize the potential benefit of such transactions.

We expect to continue to consider acquisitions, dispositions, investments in joint ventures, partnerships, and other strategic alternatives with the objective of maximizing stockholder value. Our Board of Directors and our management may from time to time be engaged in evaluating potential transactions and other strategic alternatives. In addition, from time to time, we may engage financial advisors, enter into non-disclosure agreements, conduct discussions, and undertake other actions that may result in one or more transactions. Although there would be uncertainty that any of these activities or discussions would result in definitive agreements or the completion of any transaction, we may devote a significant amount of our management resources to analyzing and pursuing such a transaction, which could negatively impact our operations, and may impair our ability to retain and motivate key personnel. In addition, we may incur significant costs in connection with seeking such transactions or other strategic alternatives regardless of whether the transaction is completed. In the event that we consummate an acquisition, disposition, partnership or other strategic transaction in the future, we cannot be certain that we would fully realize the potential benefit of such a transaction and cannot predict the impact that such strategic transaction might have on our operations or stock price. Any potential transaction would be dependent upon a number of factors that may be beyond our control, including, among other factors, market conditions, industry trends, regulatory limitations and the interest of third parties in us and our assets. There can be no assurance that the exploration of strategic alternatives will result in any specific action or transaction. Further, any such strategic alternative may not ultimately lead to increased stockholder value. We do not undertake to provide updates or make further comments regarding the evaluation of strategic alternatives, unless otherwise required by law.

Increasing stakeholder and market attention to ESG matters may impact our business and ability to secure financing.

Businesses across all industries are facing increasing scrutiny from stakeholders related to their ESG practices. Businesses that do not adapt to or comply with investor or stakeholder expectations and standards, which are continuing to evolve, or businesses that are perceived to have not responded appropriately to the growing concern for ESG issues, regardless of whether there is a legal requirement to do so, may suffer from reputational damage and the business, financial condition, and/or stock price of such business entity could be materially and adversely affected. Increasing attention to climate change, societal expectations on companies to address climate change, investor and societal expectations regarding voluntary ESG related disclosures, increasing mandatory ESG disclosures, and consumer demand for alternative forms of energy may result in increased costs, reduced demand for our products, reduced profits, increased legislative and judicial scrutiny, investigations and litigation, reputational damage, and negative impacts on our access to capital markets. To the extent that societal pressures or political or other factors are involved, it is possible that the Company could be subject to additional governmental investigations, private litigation or activist campaigns as stockholders may attempt to effect changes to the Company’s business or governance practices.

As part of our ongoing effort to enhance our ESG practices, our Board of Directors has established the Environmental, Social and Governance Committee, which is charged with overseeing our ESG policies. Committee members are expected to review the implementation and effectiveness of our ESG programs and policies. Additionally, to help strengthen our ESG performance, we have implemented compensation practices focused on value creation and aligned with stockholders’ interests. Additionally, while we may elect to seek out various voluntary ESG targets in the future, 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 as a result of unforeseen costs or technical difficulties associated with achieving such results. To the extent we elected to pursue such targets and were able to achieve the desired target levels, such achievement may have been accomplished as a result of entering into various contractual arrangements, including the purchase of various environmental credits or offsets that may be deemed to mitigate our ESG impact instead of actual changes in our ESG performance. However, even in those cases we cannot guarantee that the environmental credits or offsets we do purchase will not subsequently be determined to have failed to result in GHG emission reductions for reasons out of our control. In addition, voluntary disclosures regarding ESG matters, as well as any ESG disclosures currently required or required in the future, could result in private litigation or government investigation or enforcement action regarding the sufficiency or validity of such disclosures. Moreover, failure or a perception (whether or not valid) of failure to implement ESG strategies or achieve ESG goals or commitments, including any GHG emission reduction or

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carbon intensity goals or commitments, could result in private litigation and damage our reputation, cause investors or consumers to lose confidence in us, and negatively impact our operations. Notwithstanding our election to pursue aspirational ESG-related targets in the future, 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 sentiment toward the Company, our customers, and our industry and to the diversion of investment to other industries, which could have a negative impact on the Company and our access to and costs of capital. Furthermore, while we may participate in various voluntary frameworks and certification programs to improve the ESG profile of our operations and services, we cannot guarantee that such participation or certification will have the intended results on our ESG profile.

Also, institutional lenders may, of their own accord, decide not to provide funding for fossil fuel energy companies or related infrastructure projects based on climate or other ESG-related concerns, which could affect our access to capital for potential growth projects.

See “Item 1. Business—Regulation—Environmental and occupational health and safety regulation” for more discussion on ESG and climate-related concerns.

Our operations are subject to a series of risks arising out of the threat of climate change, energy conservation measures or initiatives that stimulate demand for alternative forms of energy that could result in increased operating costs, restrictions on drilling and reduced demand for the crude oil and natural gas that we produce.

The threat of climate change continues to attract considerable attention in the United States and foreign countries. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. As a result, our operations are subject to a series of regulatory, political, litigation and financial risks associated with the production and processing of fossil fuels and emissions of GHGs. See “Item 1. Business—Regulation—Environmental and occupational health and safety regulation” for more discussion on the threat of climate change, restriction of GHG emissions and related legal and policy developments. The adoption and implementation of any international, federal, regional or state legislation, executive actions, regulations or other regulatory and policy initiatives that impose more stringent standards for GHG emissions from the oil and gas industry or otherwise restrict the areas in which this industry may produce crude oil and natural gas or generate GHG emissions, or require enhanced disclosure of such GHG emissions and other climate-related information, could result in increased compliance costs, which if passed on to the customer could result in increased fossil fuels consumption costs and thereby reduce demand for crude oil and natural gas. Similarly, international, federal, state, and local laws and policy initiatives supporting, incentivizing, or preferring alternative forms of energy to fossil fuels could result in increased competition or reduce demand for our products. Additionally, political, financial and litigation risks may result in us restricting, delaying or canceling production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing the ability to continue to operate in an economic manner. The occurrence of one or more of these developments could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Outbreak of infectious diseases could materially adversely affect our business.

We face risks related to pandemics, epidemics, outbreaks or other public health events that are outside of our control and could significantly disrupt our operations and adversely affect our business and financial condition. For example, the global outbreak of COVID-19 during 2020 negatively impacted demand for crude oil and natural gas because of reduced global and national economic activity levels. There have been wide-ranging actions taken by international, federal, state and local public health and governmental authorities to contain and combat the outbreak and spread of COVID-19 in regions across the United States and the world. To the extent COVID-19 continues or worsens, governments may impose additional similar restrictions.

In addition, the resurgence of COVID-19 or other public health events may adversely affect our operations or the health of our workforce and the workforces of our customers and service providers by rendering employees or contractors unable to work or access the appropriate facilities for an indefinite period of time. There can be no assurance that our personnel will not be impacted by these pandemic diseases or ultimately lead to a reduction in our workforce productivity or increased medical costs or insurance premiums as a result of these health risks.

Any further impact from COVID-19 will depend on future developments and new information that may emerge regarding the continued severity of COVID-19 and any new variants, the actions taken by authorities to contain it or treat its impact, and the availability and acceptance of vaccines, all of which are beyond our control. These potential impacts, while uncertain and difficult to predict, may negatively affect our business, including, without limitation, our operating results, financial position

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and liquidity, the duration of any potential disruption of our business, how and the degree to which the pandemic may impact our customers, supply chain and distribution network, the health of our employees, the productivity and sustainability of our workforce, our insurance premiums, costs attributable to our emergency measures, payments from customers and uncollectible accounts, limitations on travel, the availability of industry experts and qualified personnel and the market for our securities.

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 crude oil and natural gas wells and adversely affect our production.

Hydraulic fracturing continues to be controversial in certain parts of the United States, resulting in increased scrutiny and regulation of the hydraulic fracturing process, including by federal and state agencies and local municipalities. See “Item 1. Business—Regulation—Environmental and occupational health and safety regulation” for more discussion on these hydraulic fracturing matters. The adoption of any federal, state or local laws or the implementation of regulations or issuance of executive orders restricting hydraulic fracturing activities or locations or suspending or delaying the performance of hydraulic fracturing on federal properties or other locations could potentially result in an increase in our compliance costs, and a decrease in the completion rate of our new crude oil and natural gas wells, which could have a material adverse effect on our liquidity, results of operations, and financial condition. Restrictions, delays or bans on hydraulic fracturing could also reduce the amount of crude oil, NGLs and natural gas that we are ultimately able to produce in commercial quantities, which adversely impacts our revenues and profitability.

Laws and regulations pertaining to the protection of threatened and endangered species or to critical habitat, wetlands and natural resources could delay, restrict or prohibit our operations and cause us to incur substantial costs that may have a material adverse effect on our development and production of reserves.

The federal ESA and comparable state laws were established to protect endangered and threatened species. Under the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the MBTA.

See “Item 1. Business—Regulation—Environmental and occupational health and safety regulation” for more discussion on endangered species protection regulations. Some of our operations are conducted in areas where protected species or their habitats are known to exist, including those of the Dakota Skipper and Golden Eagle, and from time to time our development plans have been impacted in these areas. We may be obligated to develop and implement plans to avoid potential adverse effects to protected species and their habitats, and we may be delayed, restricted or prohibited from conducting operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on the species. Additionally, the designation of previously unprotected species or the re-designation of under-protected species as threatened or endangered in areas where we conduct operations could cause us to incur increased costs arising from species protection measures or could result in delays, restrictions or prohibitions on our development and production activities that could have a material adverse effect on our ability to develop and produce reserves.

Our ability to produce crude oil, NGLs and natural gas economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling and completion operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.

Water is an essential component of shale crude oil, NGL and natural gas production during both the drilling and hydraulic fracturing processes. Our access to water to be used in these processes may be adversely affected due to reasons such as periods of extended drought, private, third-party competition for water in localized areas or the implementation of local or state governmental programs to monitor or restrict the beneficial use of water subject to their jurisdiction for hydraulic fracturing to assure adequate local water supplies. The occurrence of these or similar developments may result in limitations being placed on allocations of water due to needs by third-party businesses with more senior contractual or permitting rights to the water. Our inability to locate or contractually acquire and sustain the receipt of sufficient amounts of water could adversely impact our E&P operations and have a corresponding adverse effect on our business, financial condition and results of operations. Additionally, operations associated with our production and development activities generate drilling muds, produced waters and other waste streams, some of which may be disposed of by means of injection into underground wells situated in non-producing subsurface formations. These injection wells are regulated pursuant to the UIC program established under the SDWA. See “Item 1. Business—Regulation—Environmental and occupational health and safety regulation” for more discussion on seismicity matters. Compliance with current and future environmental laws, executive orders, regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing activities, the injection of waste streams into disposal wells, or any inability to secure transportation and access to disposal wells with sufficient capacity to accept all of our flowback and produced water on economic terms may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted but that could be materially adverse to our business and results of operations.

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Competition in the oil and gas industry is intense, making it more difficult for us to acquire properties, market crude oil, NGLs and natural gas and secure and retain trained personnel.

Our ability to acquire additional drilling locations and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, market crude oil, NGLs and natural gas and secure equipment and trained personnel. Also, there is substantial competition for capital available for investment in the oil and gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and gas properties and exploratory drilling locations or to identify, evaluate, bid for and purchase a greater number of properties and locations than our financial or personnel resources permit. Furthermore, these companies may also be better able to withstand the financial pressures of unsuccessful drilling attempts, sustained periods of volatility in financial markets and generally adverse global and industry-wide economic conditions, and may be better able to absorb the burdens resulting from changes in relevant laws and regulations, which would adversely affect our competitive position. In addition, companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased in recent years due to competition and may increase substantially in the future. We may also see corporate consolidations among our competitors, which could significantly alter industry conditions and competition within the industry.

Further, the COVID-19 pandemic that began in early 2020 provides an illustrative example of how a pandemic or epidemic can also impact our operations and business by affecting the health of these qualified or trained personnel and rendering them unable to work or travel. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining qualified personnel and raising additional capital, which could have a material adverse effect on our business.

The loss of senior management or technical personnel could adversely affect our operations.

To a large extent, we depend on the services of our senior management and technical personnel. The loss of the services of our senior management or technical personnel could have a material adverse effect on our operations. The public health concerns posed by COVID-19 could pose a risk to our personnel and may render our personnel unable to work or travel. The extent to which COVID-19 may impact our personnel, and subsequently our business, cannot be predicted at this time. We continue to monitor impacts of COVID-19, have actively implemented policies and practices to address COVID-19, and may adjust our current policies and practices as more information and guidance become available. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.

Seasonal weather conditions adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Our crude oil, NGL and natural gas operations are adversely affected by seasonal weather conditions. In the Williston Basin, drilling and other crude oil, NGL and natural gas activities cannot be conducted as effectively during the winter months. Severe winter weather conditions limit and may temporarily halt our ability to operate during such conditions. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operating and capital costs. See “Item 1. Business—Regulation—Environmental and occupational health and safety regulation” for more discussion on the threat of climate change and the resulting impacts to weather patterns and conditions.

We may be subject to risks in connection with acquisitions because of integration difficulties, uncertainties in evaluating recoverable reserves, well performance and potential liabilities and uncertainties in forecasting crude oil, NGL and natural gas prices and future development, production and marketing costs.

We periodically evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of producing properties requires an assessment of several factors, including:

•recoverable reserves;

•future crude oil, NGL and natural gas prices and their appropriate differentials;

•development and operating costs;

•potential for future drilling and production;

•validity of the seller’s title to the properties, which may be less than expected at the time of signing the purchase agreement; and

•potential environmental and other liabilities, together with associated litigation of such matters.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or

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potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities or title defects in excess of the amounts claimed by us before closing and acquire properties on an “as is” basis. Indemnification from the sellers will generally be effective only during a limited time period after the closing and subject to certain dollar limitations and minimums. We may not be able to collect on such indemnification because of disputes with the sellers or their inability to pay. Moreover, there is a risk that we could ultimately be liable for unknown obligations related to acquisitions, which could materially adversely affect our financial condition, results of operations or cash flows.

Significant acquisitions and other strategic transactions may involve other risks, including:

•diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;

•the challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of our operations while carrying on our ongoing business;

•difficulty associated with coordinating geographically separate organizations;

•an inability to secure, on acceptable terms, sufficient financing that may be required in connection with expanded operations and unknown liabilities; and

•the challenge of attracting and retaining personnel associated with acquired operations.

The process of integrating assets could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer. The success of an acquisition will depend, in part, on our ability to realize anticipated opportunities from combining the acquired assets or operations with those of ours. Even if we successfully integrate the assets acquired, it may not be possible to realize the full benefits we may expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition or realize these benefits within the expected time frame. Anticipated benefits of an acquisition may be offset by operating losses relating to changes in commodity prices, in oil and gas industry conditions, by risks and uncertainties relating to the exploratory prospects of the combined assets or operations, failure to retain key personnel, an increase in operating or other costs or other difficulties. If we fail to realize the benefits we anticipate from an acquisition, our results of operations and stock price may be adversely affected.

We may incur losses as a result of title defects in the properties in which we invest.

It is our practice in acquiring crude oil and natural gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we rely upon the judgment of crude oil and natural gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest.

Prior to the drilling of a crude oil or natural gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in the title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may adversely impact our ability in the future to increase production and reserves. There is no assurance that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

Disputes or uncertainties may arise in relation to our royalty obligations.

Our production is subject to royalty obligations which may be prescribed by government regulation or by contract. These royalty obligations may be subject to changes in interpretation as business circumstances change and the law in jurisdictions in which we operate continues to evolve. For example, in 2019, the Supreme Court of North Dakota issued an opinion indicating a change in its interpretation of how certain gas royalty payments are calculated under North Dakota law with respect to certain state leases, which may require us to make additional royalty payments and reduce our revenues. Such changes in interpretation could have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, such changes in interpretation could result in legal or other proceedings. Please see “Involvement in legal, governmental and regulatory proceedings could result in substantial liabilities” for a discussion of risks related to such proceedings.

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Risks related to our financial position

Increased costs of capital could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates to combat inflation or a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned operating results.

Our revolving credit facility and the indentures governing our senior unsecured notes contain operating and financial restrictions that may restrict our business and financing activities.

Our revolving credit facility and the indentures governing our senior unsecured notes contains a number of restrictive covenants that impose significant operating and financial restrictions on us, including restrictions on our ability to, among other things:

•sell assets, including equity interests in our subsidiaries;

•pay distributions on, redeem or repurchase our common stock or redeem or repurchase our debt;

•make investments;

•incur or guarantee additional indebtedness or issue preferred stock;

•create or incur certain liens;

•make certain acquisitions and investments;

•redeem or prepay other debt;

•enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;

•consolidate, merge or transfer all or substantially all of our assets;

•engage in transactions with affiliates;

•create unrestricted subsidiaries;

•enter into sale and leaseback transactions; and

•engage in certain business activities.

As a result of these covenants, we are limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.

Our ability to comply with some of the covenants and restrictions contained in our revolving credit facility and the indentures governing our senior unsecured notes may be affected by events beyond our control. If market or other economic conditions deteriorate or if crude oil, NGL and natural gas prices decline substantially or for an extended period of time from their current levels, our ability to comply with these covenants may be impaired. A failure to comply with the covenants, ratios or tests in our revolving credit facility, our senior unsecured notes or any future indebtedness could result in an event of default under which, if not cured or waived, could have a material adverse effect on our business, financial condition and results of operations.

If an event of default occurs and remains uncured, the lenders under our revolving credit facility:

•would not be required to lend any additional amounts to us;

•could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable;

•may have the ability to require us to apply all of our available cash to repay these borrowings; or

•may prevent us from making debt service payments under our other agreements.

A payment default or an acceleration under our revolving credit facility could result in an event of default and an acceleration under the indentures for our senior unsecured notes. If the indebtedness under our senior unsecured notes were to be accelerated, there can be no assurance that we would have, or be able to obtain, sufficient funds to repay such indebtedness in full. Our obligations under our revolving credit facility are collateralized by perfected first priority liens and security interests on substantially all of our oil and gas assets, including mortgage liens on oil and gas properties having at least 85% of the

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reserve value as determined by reserve reports, and if we are unable to repay our indebtedness under the revolving credit facility, the lenders could seek to foreclose on our assets.

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

To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of crude oil, NGLs and natural gas, we currently, and may in the future, enter into derivative arrangements for a portion of our crude oil, NGL and natural gas production, including collars and fixed-price swaps. We have not designated any of our derivative instruments as hedges for accounting purposes and record all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments are recognized in earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments.

Derivative arrangements also expose us to the risk of financial loss in some circumstances, including when:

•production is less than the volume covered by the derivative instruments;

•the counterparty to the derivative instrument defaults on its contract obligations; or

•there is an increase in the differential between the underlying price in the derivative instrument and actual price received.

In addition, some of these types of derivative arrangements limit the benefit we would receive from increases in the prices for crude oil and natural gas.

Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our estimated net crude oil, NGL and natural gas reserves.

Our exploration and development activities are capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of crude oil, NGL and natural gas reserves. Based upon our anticipated five-year development plan and current costs, we project that we will incur capital costs of approximately $2.2 billion to develop our PUD reserves. Please see “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for more information about our capital expenditures. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, inflation in costs, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments.

We intend to finance our future capital expenditures primarily through cash flows provided by operating activities; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of additional debt or equity securities or the sale of non-strategic assets. The issuance of additional debt or equity may require that a portion of our cash flows provided by operating activities be used for the payment of principal and interest on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions or to pay dividends. The issuance of additional equity securities could have a dilutive effect on the value of our common stock. In addition, upon the issuance of certain debt securities (other than on a borrowing base redetermination date), our borrowing base under our revolving credit facility will be automatically reduced by an amount equal to 25% of the aggregate principal amount of such debt securities.

Our cash flows provided by operating activities and access to capital are subject to a number of variables, including:

•our estimated net proved reserves;

•the level of crude oil, NGLs and natural gas we are able to produce from existing wells and new projected wells;

•the prices at which our crude oil, NGLs and natural gas are sold;

•the costs of developing and producing our crude oil and natural gas production;

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

•the ability and willingness of our banks to lend; and

•our ability to access the equity and debt capital markets.

If the borrowing base under our revolving credit facility or our revenues decrease as a result of low crude oil, NGL or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or cash available under the revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our drilling locations, which in turn could lead to a possible expiration of our leases and a

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decline in our estimated net proved reserves, and could adversely affect our business, financial condition and results of operations.

We may maintain material balances of cash and cash equivalents for extended periods of time at commercial banks in excess of amounts insured by government agencies such as the FDIC.

We may maintain material balances of cash and cash equivalents for extended periods of time at commercial banks in excess of amounts insured by government agencies such as the FDIC. A failure of our commercial banks could result in us losing any funds we have deposited in excess of amounts insured by the FDIC. Any losses we sustain on our cash deposits could materially adversely affect our financial position.

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

Our principal exposures to credit risk are through receivables resulting from the sale of our crude oil, NGL and natural gas production, which we market to energy marketing companies, other producers, power generators, local distribution companies, refineries and affiliates, and joint interest receivables.

We are subject to credit risk due to the concentration of our crude oil, NGL and natural gas receivables with several significant customers. This concentration of customers may impact our overall credit risk since these entities may be similarly affected by changes in economic and other conditions. We do not require all of our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. See “Part II. Item 8.—Financial Statements and Supplementary Data—Note 22—Significant Concentrations” for additional information on significant concentrations with major customers.

Joint interest receivables arise from billing entities who own a partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we choose to drill. We have limited ability to control participation in our wells. For the year ended December 31, 2022, changes in our estimate of expected credit losses was not material.

In addition, our crude oil, NGL and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. Derivative assets and liabilities arising from derivative contracts with the same counterparty are reported on a net basis, as all counterparty contracts provide for net settlement. At December 31, 2022, we had commodity derivatives in place with eleven counterparties and a total net commodity derivative liability of $328.9 million.

Changes in tax laws or the interpretation thereof or the imposition of new or increased taxes or fees may adversely affect our operations and cash flows.

From time to time, U.S. federal and state level legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including to certain key U.S. federal and state income tax provisions currently available to oil and natural gas exploration and development companies. Such legislative changes have included, but have not been limited to, (i) the elimination of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) an extension of the amortization period for certain geological and geophysical expenditures, (iv) the elimination of certain other tax deductions and relief previously available to oil and natural gas companies and (v) an increase in the U.S. federal income tax rate applicable to corporations such as us. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. Additionally, states in which we operate or own assets may impose new or increased taxes or fees on oil and natural gas extraction. The passage of any legislation as a result of these proposals and other similar changes in U.S. federal income tax laws or the imposition of new or increased taxes or fees on natural gas and oil extraction could adversely affect our operations and cash flows.

The IRA includes, among other things, a corporate alternative minimum tax (the “CAMT”). Under the CAMT, a 15% minimum tax will be imposed on certain financial statement income of “applicable corporations.” The CAMT generally treats a corporation as an applicable corporation in any taxable year in which the “average annual adjusted financial statement income” of the corporation and certain of its subsidiaries and affiliates for a three-taxable-year period ending prior to such taxable year exceeds $1 billion.

Based on our current interpretation of the IRA and the CAMT and a number of operational, economic, accounting and regulatory assumptions, we do not anticipate being an applicable corporation in 2023, but we may become an applicable corporation in a subsequent tax year. If we become an applicable corporation and our CAMT liability is greater than our regular U.S. federal income tax liability for any particular tax year, the CAMT liability would effectively accelerate our future U.S. federal income tax obligations, reducing our cash flows in that year, but provide an offsetting credit against our regular U.S. federal income tax liability in future tax years. The foregoing analysis is based upon our current interpretation of the provisions contained in the IRA and the CAMT. In the future, the U.S. Department of the Treasury and the Internal Revenue Service are

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expected to release regulations and interpretive guidance relating to the CAMT, and any significant variance from our current interpretation could result in a change in the expected application of the CAMT to us and adversely affect our operations and cash flows.

Additionally, the IRA introduced a one percent non-deductible excise tax on the fair market value of applicable stock repurchases after December 31, 2022, with the fair market value of such repurchased stock reduced by the fair market value of certain stock issued by such corporation during the same taxable year. The impact of this provision will be dependent on the extent of any share repurchases made by the Company in future periods and could adversely affect the Company’s future financial condition and cash flows. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for additional information on our share repurchase program.

We may not be able to utilize all or a portion of our net operating loss carryforwards or other tax benefits to offset future taxable income for U.S. federal or state tax purposes, which could adversely affect our financial position, results of operations and cash flows.

We may be limited in the portion of our net operating loss carryforwards (“NOLs”) that we can use in the future to offset taxable income for U.S. federal and state income tax purposes. Utilization of these NOLs depends on many factors, including our future taxable income, which cannot be assured.

Under Section 382 (“Section 382”) of the Internal Revenue Code of 1986, as amended (the “Code”), if a corporation experiences an “ownership change,” any NOLs, losses or deductions attributable to a “net unrealized built-in loss” and other tax attributes (“Tax Benefits”) could be substantially limited, and timing of the usage of such Tax Benefits could be substantially delayed. A corporation generally will experience an ownership change if one or more stockholders (or group of stockholders) who are each deemed to own at least 5% of the corporation’s stock increase their ownership by more than 50 percentage points over their lowest ownership percentage within a testing period (generally, a rolling three-year period). Determining the limitations under Section 382 is technical and highly complex, and no assurance can be given that upon further analysis our ability to take advantage of our NOLs or other Tax Benefits may be limited to a greater extent than we currently anticipate.

We experienced an ownership change as a result of the Merger with Whiting. In addition, Whiting experienced an ownership change as a result of a prior restructuring under Chapter 11 of the Bankruptcy Code. Accordingly, our ability to utilize our NOLs and other Tax Benefits (including Whiting’s NOLs and other Tax Benefits) is subject to a limitation under Section 382. Additionally, we may experience ownership changes in the future as a result of subsequent shifts in our stock ownership that we cannot predict or control that could result in further limitations being placed on our ability to utilize our NOLs and other Tax Benefits. Any such ownership changes and resulting limitations under Section 382 may result in us paying more taxes than if we were able to utilize our NOLs and other Tax Benefits, which could adversely affect our financial position, results of operations and cash flows.

The enactment of derivatives legislation and regulation could have an adverse effect on our ability to use derivative instruments to reduce the negative effect of commodity price changes, interest rate and other risks associated with our business.

In 2010, new comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), was enacted that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In its rulemaking under the Dodd-Frank Act, the CFTC has proposed new regulations to set position limits for certain futures, options and swap contracts in designated physical commodities, including, among others, crude oil, NGLs and natural gas. The Dodd-Frank Act and CFTC rules have also designated certain types of swaps (thus far, only certain interest rate swaps and credit default swaps) for mandatory clearing and exchange trading, and may designate other types of swaps for mandatory clearing and exchange trading in the future. To the extent that we engage in such transactions or transactions that become subject to such rules in the future, we will be required to comply with the clearing and exchange trading requirements or to take steps to qualify for an exemption to such requirements. In addition, certain banking regulators and the CFTC have adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for the non-financial end-user exception from margin requirements for swaps to other market participants, such as swap dealers, these rules may change the cost and availability of the swaps we use for hedging. If any of our swaps do not qualify for the non-financial end-user exception, we could be required to post initial or variation margin, which would impact liquidity and reduce our cash. This would in turn reduce our ability to execute hedges to reduce risk and protect cash flows. Other regulations to be promulgated under the Dodd-Frank Act also remain to be finalized. As a result, it is not possible at this time to predict with certainty the full effects of the Dodd-Frank Act and CFTC rules on us and the timing of such effects. The Dodd-Frank Act and regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our

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results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Further, to the extent our revenues are unhedged, they could be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our financial position, results of operations and cash flows. In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations.

The cost of servicing, and the ability to generate enough cash flows to meet, our current or future debt obligations could adversely affect our business. Those risks could increase if we incur more debt.

As of December 31, 2022, we had no outstanding borrowings and $6.4 million of outstanding letters of credit under our revolving credit facility and $400.0 million of 6.375% senior unsecured notes outstanding. Our ability to pay interest and principal on our indebtedness and to satisfy our other obligations will depend on our future operating performance, our financial condition and the availability of refinancing indebtedness, which will be affected by prevailing economic conditions and financial, business and other factors, many of which are beyond our control. If crude oil, NGL and natural gas prices decline substantially or for an extended period of time from their current levels, we may not be able to generate sufficient cash flows to pay the interest on our debt and future working capital, and borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.

In the future, we may incur significant indebtedness in order to make future acquisitions or to develop our properties. If we were to take on additional future debt, a substantial decrease in our operating cash flow or an increase in our expenses could make it difficult for us to meet debt service requirements and could require us to modify our operations, including by selling assets, reducing or delaying capital investments, seeking to raise additional capital or refinancing or restructuring our debt. We may or may not be able to complete any such steps on satisfactory terms. In addition, the revolving credit facility borrowing base is subject to periodic redeterminations. We could be forced to repay a portion of our bank borrowings under the revolving credit facility due to redeterminations of our borrowing base. If we are forced to do so, we may not have sufficient funds to make such repayments. Any ability to generate sufficient cash flows to satisfy our debt obligations or contractual commitments, or to refinance our debt on commercially reasonable terms, could materially and adversely affect our financial condition and results of operations.

A negative shift in investor sentiment regarding the oil and gas industry could adversely affect our ability to raise debt and equity capital.

Certain segments of the investor community have developed negative sentiment towards investing in the oil and gas industry. Historic equity returns in this sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. In addition, some investors, including investment advisors and certain sovereign wealth funds, pension funds, university endowments and family foundations, have adopted policies to divest holdings in the oil and gas sector based on social and environmental considerations. Certain other stakeholders have also pressured commercial and investment banks to stop financing oil and gas production and related infrastructure projects.

Such developments, including environmental activism and initiatives aimed at limiting climate change and reducing air pollution, could result in downward pressure on the stock prices of oil and gas companies, including ours. This may also potentially result in a reduction of available capital funding for potential acquisitions or development projects, impacting our future financial results.

Risks related to our common stock

Our ability to declare and pay dividends is subject to certain considerations and limitations.

Any payment of future dividends will be at the discretion of our Board of Directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applicable to the payment of dividends and other considerations that our Board of Directors deems relevant. Cash dividend payments in the future may only be made out of legally available funds and, if we experience substantial losses, such funds may not be available. Certain covenants in our revolving credit facility may limit our ability to pay dividends. We can provide no assurance that we will continue to pay dividends at the current rate or at all.

Our amended and restated certificate of incorporation, as amended, and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

Our amended and restated certificate of incorporation, as amended, authorizes our Board of Directors to issue preferred stock without stockholder approval. If our Board of Directors elects to issue preferred stock, it could be more difficult for a third

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party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

•advance notice provisions for stockholder proposals and nominations for elections to the Board of Directors to be acted upon at meetings of stockholders; and

•limitations on the ability of our stockholders to call special meetings.

Delaware law prohibits us from engaging in any business combination with any “interested stockholder,” meaning generally that a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unless various conditions are met, such as approval of the transaction by our Board of Directors.

The exercise of all or any number of outstanding warrants or the issuance of stock-based awards may dilute your holding of shares of our common stock.

As of December 31, 2022, we had 4,979,513 outstanding warrants to purchase shares of our common stock and 1,291,761 outstanding stock–based awards. In addition, as of December 31, 2022, a total of 2,072,139 shares of common stock were available for future issuance under our equity incentive plans, including 1,016,613 shares of common stock reserved for future issuance under the Oasis Petroleum Inc. 2020 Long Term Incentive Plan (the “2020 LTIP”) and 1,055,526 shares of common stock reserved for future issuance under the Whiting Petroleum Corporation 2020 Equity Incentive Plan, which we assumed in connection with the Merger. The exercise of stock–based awards, including any stock options that we may grant in the future, warrants, and the sale of shares of our common stock underlying any such options or warrants, could have an adverse effect on the market for our common stock, including the price that an investor could obtain for their shares.

In connection with the Merger, we assumed certain pre-petition general unsecured claims of Whiting which remain subject to the jurisdiction of the United States Bankruptcy Court for the Southern District of Texas. As of December 31, 2022, we had reserved 1,224,840 shares of common stock for potential future distribution to settle such general unsecured claims.

The market price of our common stock is subject to volatility.

The liquidity for our common shares has been below historical levels, and the market price of our common stock could be subject to wide fluctuations. If there is a thin trading market or “float” for our stock, the market price for our common stock may fluctuate significantly more than the stock market as a whole. Without a large float, our common stock would be less liquid than the stock of companies with broader public ownership and, as a result, the trading prices of our common stock may be more volatile. In addition, in the absence of an active public trading market, investors may be unable to liquidate their investment in us. The market price of our common stock can be affected by, numerous factors, many of which are beyond our control. These factors include, among other things, actual or anticipated variations in our operating results and cash flow, the nature and content of our earnings releases, announcements or events that impact our products or services, customers, competitors or markets, business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions, such as an economic slowdown or recession, and other factors that may affect our future results.

Risks related to the Merger

We may not realize anticipated benefits and synergies expected from the Merger.

Achieving the expected benefits of the Merger depends in part on successfully consolidating the Company’s and Whiting’s functions and integrating their operations and procedures in a timely and efficient manner, as well as being able to realize the anticipated growth opportunities and synergies from combining the companies’ businesses and operations. We may fail to realize the anticipated benefits and synergies expected from the Merger, which could adversely affect our business, financial condition and operating results. The Merger could also result in difficulties in being able to hire, train or retain qualified personnel to manage and operate the Company’s properties.

Achieving the expected benefits of the Merger requires, among other things, realization of the targeted synergies expected from the Merger, and there can be no assurance that we will be able to successfully integrate Whiting’s assets or otherwise realize the expected benefits of the Merger. The anticipated benefits of the Merger may not be realized fully or at all or may take longer to realize than expected. Difficulties in integrating Whiting’s assets and operations may result in the Company performing differently than expected, or in operational challenges or failures to realize anticipated efficiencies. Potential difficulties in realizing the anticipated benefits of the Merger include:

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•disruptions of relationships with customers, distributors, suppliers, vendors, landlords and other business partners as a result of uncertainty associated with the Merger;

•difficulties integrating the Company’s business with the business of Whiting in a manner that permits us to achieve the full revenue and cost savings anticipated from the transaction;

•complexities associated with managing a larger and more complex business, including difficulty addressing possible inconsistencies in, standards, controls or operational philosophies and the challenge of integrating complex systems, technology, networks and other assets of each of the companies in a seamless manner that minimizes any adverse impact on customers, suppliers, employees and other constituencies;

•difficulties realizing anticipated synergies;

•difficulties integrating personnel, vendors and business partners;

•loss of key employees who are critical to our future operations due to uncertainty about their roles within the Company following the Merger or other concerns regarding the Merger;

•potential unknown liabilities and unforeseen expenses;

•performance shortfalls at one or more of the companies as a result of the diversion of management’s attention to integration efforts; and

•disruption of, or the loss of momentum in, the Company’s ongoing business.

We have also incurred a number of costs associated with the Merger. The elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the two companies, may not initially offset integration-related costs or achieve a net benefit in the near term, or at all. Matters relating to the Merger (including integration planning) require substantial commitments of time and resources by our management, which may result in the distraction of management from ongoing business operations and pursuing other opportunities that could have been beneficial to us.

Our future success will depend, in part, on our ability to manage our expanded business by, among other things, integrating our assets, operations and personnel in an efficient and timely manner; consolidating systems and management controls and successfully integrating relationships with customers, vendors and business partners. Failure to successfully manage the combined company may have an adverse effect on our business, reputation, financial condition and results of operations.

The failure to integrate our businesses and operations with those of Whiting successfully in the expected time frame may adversely affect the combined business’ future results.

The Merger involved the combination of two companies that previously operated as independent public companies. It is possible that the process of integrating the two businesses following the Merger could result in the loss of key employees, the disruption of either or both companies’ ongoing businesses, inconsistencies in standards, controls, procedures and policies, potential unknown liabilities, unforeseen expenses or delays or higher-than-expected integration costs and an overall post-completion integration process that takes longer than originally anticipated.

The future results of the combined company following the Merger will suffer if the combined company does not effectively manage its expanded operations.

Following the Merger, the size of the business of the combined company increased significantly. The combined company’s future success will depend, in part, upon its ability to manage this expanded business, which will pose substantial challenges for management, including challenges related to the management and monitoring of new operations and associated increased costs and complexity. There can be no assurances that the combined company will be successful or that it will realize the expected operating efficiencies, cost savings, revenue enhancements or other benefits currently anticipated from the Merger.

General risk factors

Involvement in legal, governmental and regulatory proceedings could result in substantial liabilities.

Like other similarly-situated oil and gas companies, we are from time to time involved in various legal, governmental and regulatory proceedings in the ordinary course of business including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, regulatory compliance matters, disputes with tax authorities and other matters. The outcome of such matters often cannot be predicted with certainty. If our efforts to defend ourselves in legal, governmental and regulatory matters are not successful, it is possible the outcome of one or more such proceedings could result in substantial liability, penalties, sanctions, judgments, consent decrees or orders requiring a change in our business practices, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. Judgments and estimates to determine accruals related to legal, governmental and regulatory proceedings could change from period to period, and such changes could be material.

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Our profitability may be negatively impacted by inflation in the cost of labor, materials and services and general economic, business or industry conditions.

The U.S. economy has experienced significant increases in inflation rates since 2021 from, among other things, supply chain disruptions and governmental stimulus or fiscal policies adopted in response to the COVID-19 pandemic. Although U.S. inflation rates have shown signs of moderating, we cannot predict any future trends in the rate of inflation. Rising interest rates and the state of the general economy have brought unprecedented uncertainty to the near-term economic outlook. Continued high levels of inflation would further raise our costs for labor, materials and services, due to a combination of factors, including: (i) global supply chain disruptions resulting in limited availability of certain materials and equipment (including drill pipe, casing and tubing), (ii) increased demand for fuel and steel, (iii) increased demand for services coupled with a limited availability of service providers and (iv) labor shortages, which would negatively impact our profitability and cash flows. We seek to mitigate these inflationary impacts by reviewing our pricing agreements on a regular basis and entering into agreements with our service providers to manage costs and availability of certain services that are utilized in our operations. It is difficult to predict whether such inflationary pressures will have a materially negative impact to our overall financial and operating results in 2023; however, such inflationary pressures are not expected to materially impact our overall liquidity position, cash requirements or financial position, or the ability to conduct our day-to-day drilling, completion and production activities.

Concerns over global economic conditions, energy costs, geopolitical issues, inflation and the availability and cost of credit in the European, Asian and U.S. markets contribute to economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil, NGL and natural gas, volatility in consumer confidence and job markets, may result in an economic slowdown or recession. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which oil, NGL and natural gas from our properties are sold, affect the ability of vendors, suppliers and customers associated with our properties to continue operations and ultimately adversely impact our business, results of operations and financial condition.

Global geopolitical tensions may create heightened volatility in oil, gas and NGL prices and could adversely affect our business, financial condition and results of operations.

On February 24, 2022, Russian military forces commenced a military operation in Ukraine and the sustained conflict and disruption in the region that has occurred since this date is expected to continue. Although the length, impact and outcome of the ongoing military conflict in Ukraine is highly unpredictable, this conflict could continue to lead to significant market and other disruptions, including significant volatility in commodity prices and supply of energy resources, instability in financial markets, supply chain interruptions, political and social instability, changes in consumer or purchaser preferences, as well as increases in cyber-attacks and espionage.

Although NGL prices increased during the second half of 2022 due to increased demand around the globe, particularly in Europe, stemming from lower Russian natural gas supply as a result of economic sanctions and other self-sanctioning of Russian commodities, it is not possible at this time to predict or determine the ultimate consequences of the conflict in Ukraine, which could include, among other things, additional sanctions, greater regional instability, embargoes, geopolitical shifts and other material and adverse effects on macroeconomic conditions, supply chains, financial markets and hydrocarbon price volatility. The ongoing conflict between Russia and Ukraine and its broader impacts could have a lasting impact in the short- and long-term on the operations and financial condition of our business and the global economy.

Terrorist attacks or cyber-attacks could have a material adverse effect on our business, financial condition or results of operations and could result in information theft or data corruption.

The oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations. For example, software programs are used to manage gathering and transportation systems and for compliance reporting. The use of mobile communication devices has increased rapidly. Industrial control systems such as supervisory control and data acquisition (“SCADA”) now control large scale processes that can include multiple sites and long distances, such as crude oil and natural gas pipelines. We depend on digital technology, including information systems and related infrastructure as well as third-party cloud applications and services, to process and record financial and operating data and to communicate with our employees and business partners. Our business partners, including vendors, service providers and financial institutions, are also dependent on digital technology.

Terrorist attacks or cyber-attacks may significantly affect the energy industry, including our operations and those of our potential customers, as well as general economic conditions, consumer confidence and spending and market liquidity. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States. A cyber-attack could include gaining unauthorized access to our or third-party digital systems or data for purposes of misappropriating assets or sensitive information, corrupting data or causing operational disruption. SCADA-based systems are potentially vulnerable to targeted cyber-attacks due to their critical role in operations. We, or our business partners, may rely upon outdated

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information technology or software systems that may be at a higher risk of error, failure and cyber breach. Techniques used in cyber-attacks often range from highly sophisticated efforts to electronically circumvent network security to more traditional intelligence gathering and social engineering aimed at obtaining information necessary to gain access. Cyber-attacks may also be performed in a manner that does not require gaining unauthorized access, such as by causing denial-of-service attacks. In addition, certain cyber incidents, such as unauthorized surveillance or a data breach, may remain undetected for an extended period.

A cyber incident or technological failure involving our information systems or data and related infrastructure, or that of our business partners, including any vendor or service provider, could disrupt our business plans and negatively impact our operations in the following ways, among others:

•supply chain disruptions, which could delay or halt development of additional infrastructure, effectively delaying the start of cash flows from the project;

•delays in delivering or failure to deliver product at the tailgate of our facilities, resulting in a loss of revenues;

•operational disruption resulting in loss of revenues;

•events of non-compliance that could lead to regulatory fines or penalties; and

•business interruptions that could result in expensive remediation efforts, distraction of management, damage to our reputation or a negative impact on the price of our units.

Our implementation of various controls and processes to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure is costly and labor intensive. Moreover, despite our or our third-party partners’ security measures there can be no assurance that such measures will be sufficient to protect our information technology systems from hacking, ransomware attacks, employee error, malfeasance, system error, faulty password management or other irregularities.

Moreover, as the sophistication and volume of cyber-attacks continue to increase, we may be required to expend significant additional resources to further enhance our digital security and information technology infrastructure or to remediate vulnerabilities, and we may face difficulties in fully anticipating or implementing adequate preventive measures or mitigating potential harm. These costs may include making organizational changes, deploying additional personnel and protection technologies, training employees, and engaging third party experts and consultants. These efforts may come at the potential cost of revenues and human resources that could be utilized to continue to enhance our product offerings, and such increased costs and diversion of resources may adversely affect our operating margins. A cyber incident could ultimately result in liability under data privacy laws, regulatory penalties, damage to our reputation or additional costs for remediation and modification or enhancement of our information systems to prevent future occurrences, all of which could have a material adverse effect on our financial condition, liquidity or results of operations or the integrity of the systems, processes and data needed to run our business.

Destructive forms of protests and opposition by extremists and other disruptions, including acts of sabotage or eco-terrorism, against crude oil, NGL and natural gas development and production or midstream processing or transportation activities could potentially result in damage or injury to persons, property or the environment or lead to extended interruptions of our operations. Our insurance may not protect us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.

Ineffective internal controls could impact our business and financial results.

Our internal controls over financial reporting may not prevent or detect misstatements because of its inherent limitations, including the possibility of human error, the circumvention or overriding of controls, or fraud. Even effective internal controls can provide only reasonable assurance with respect to the preparation and fair presentation of financial statements. If we fail to maintain the adequacy of our internal controls, including any failure to implement required new or improved controls, or if we experience difficulties in their implementation, our business and financial results could be harmed and we could fail to meet our financial reporting obligations.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

The information required by Item 2. is contained in Item 1. Business.

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Item 3. Legal Proceedings

See “Part II, Item 8. Financial Statements and Supplementary Data—Note 23—Commitments and Contingencies,” which is incorporated herein by reference, for a discussion of material legal proceedings.

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

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

Market for Registrant’s Common Equity. Our common stock is listed on the Nasdaq under the symbol “CHRD”.

Dividends. In 2022, we paid an aggregate amount of cash dividends of $27.03 per share of common stock, including base dividends of $3.67 per share of common stock, variable dividends of $8.36 per share of common stock and a special cash dividend of $15.00 per share of common stock. On February 22, 2023, we declared a base plus variable dividend of $4.80 per share of common stock. These dividends will be payable on March 21, 2023 to stockholders of record as of March 7, 2023.

In August 2022, we introduced a return of capital plan that includes a base dividend of $1.25 per share per quarter ($5.00 per share annualized) and a $300 million share-repurchase program. See “Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments” for additional information on the return of capital plan.

Future dividend payments will depend on our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applicable to the payment of dividends and other considerations that our Board of Directors deems relevant. See “Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Dividends” for more information.

Holders. As of February 24, 2023, the number of record holders of our common stock was 311. Based on inquiry, management believes that the number of beneficial owners of our common stock as of February 24, 2023 was approximately 93,847.

On February 24, 2023, the last sale price of our common stock, as reported on the Nasdaq, was $136.18 per share.

Unregistered Sales of Securities. There were no sales of unregistered securities during the year ended December 31, 2022.

Securities Authorized for Issuance Under Equity Compensation Plans. Information concerning securities authorized for issuance under our equity compensation plans will be disclosed in our definitive proxy statement for our 2023 Annual Meeting of Stockholders.

Issuer Purchases of Equity Securities. The following table contains information about our acquisition of equity securities during the three months ended December 31, 2022:

Period	Total Number of Shares Exchanged(1)(2)	Average Price Paid per Share		Total Number of  Shares Purchased as Part of Publicly Announced Plans or Programs(2)(3)	Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs(2)
October 1 – October 31, 2022	21,438	$	153.81	—	$	300,000,000
November 1 – November 30, 2022	8,251	156.25		—	300,000,000
December 1 – December 31, 2022	206,063	133.45		203,314	272,898,821

___________________ 

(1)During the fourth quarter of 2022, we withheld 32,438 shares of common stock to satisfy tax withholding obligations upon vesting of certain equity-based awards.

(2)During the fourth quarter of 2022, we repurchased 203,314 shares of common stock at a weighted average price of $133.30 per common share for a total cost of $27.1 million as part of our publicly announced share repurchase program.

(3)On August 3, 2022, we announced our new share repurchase program, in which our Board of Directors authorized share repurchases of up to $300 million of our common stock.

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Stock Performance Graph. The following performance graph and related information is “furnished” with the SEC and shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent that we specifically request that such information be treated as “soliciting material” or specifically incorporate such information by reference into such a filing.

The performance graph shown below compares the cumulative total return to our common stockholders as compared to the cumulative total returns on the Standard and Poor’s 500 Index (“S&P 500”) and the Standard and Poor’s 500 Oil & Gas Exploration & Production Index (“S&P 500 O&G E&P”) for the period of November 20, 2020 (the date we emerged from bankruptcy and our common stock commenced trading) through December 31, 2022. The comparison was prepared based upon the following assumptions:

1.$100 was invested in our common stock, the S&P 500 and the S&P 500 O&G E&P on November 20, 2020 at the closing price on such date; and

2.Dividends were reinvested.

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Item 6. [Reserved]

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this Annual Report on Form 10-K. The Consolidated Balance Sheets and Consolidated Statements of Operations have been recast from prior periods to reflect the OMP Merger (defined below) as a discontinued operation. Refer to “Part II, Item 8. Financial Statements and Supplementary Data—Note 13—Discontinued Operations.” In addition, the following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results, and the differences can be material. See “Cautionary Note Regarding Forward-Looking Statements” at the beginning of this report for an explanation of these types of statements.

For discussion related to changes in financial condition and results of operations for the year ended December 31, 2021 (Successor) compared to the period from November 20, 2020 through December 31, 2020 (Successor) and the period from January 1, 2020 through November 19, 2020 (Predecessor), refer to “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2021, filed with the SEC on February 25, 2022.

Overview

We are an independent E&P company with quality and sustainable long-lived assets in the North Dakota and Montana regions of the Williston Basin. Our mission is to responsibly produce hydrocarbons while exercising capital discipline, operating efficiently, improving continuously and providing a rewarding environment for our employees. We are ideally positioned to enhance return of capital and generate strong free cash flow, while being responsible stewards of the communities and environment where we operate.

Recent Developments

Return of Capital Plan

On August 3, 2022, we introduced a return of capital plan designed to provide peer-leading, sustainable stockholder returns. The return of capital plan includes a base dividend of $1.25 per share per quarter ($5.00 per share annualized) and a $300 million share-repurchase program. We plan to return capital through a mix of base and variable dividend payouts, supplemented by opportunistic share repurchases.

We expect to return a certain percentage of adjusted free cash flow (“Adjusted FCF”) each quarter, with the targeted percentage based on free cash flow generated during the previous quarter and leverage under the following framework:

•Below 0.5x leverage:	75%+ of Adjusted FCF
•Below 1.0x leverage:	50%+ of Adjusted FCF
•>1.0x leverage:	Base dividend+ ($5.00 per share annualized)

The variable dividend will be calculated using the framework noted above to establish the minimum percentage of Adjusted FCF to be returned less share repurchases completed during the quarter and the base dividend.

Whiting Merger

On March 7, 2022, we entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Whiting to combine in a merger of equals transaction. Whiting was an independent oil and gas company engaged in the development, production and acquisition of crude oil, NGLs and natural gas primarily in the Rocky Mountains region of the United States. The Merger was unanimously approved by the respective Boards of Directors of both companies, and the proposals relating to the Merger were approved by the stockholders of both companies on June 28, 2022. The Merger was completed on July 1, 2022, and in connection therewith, we changed our name from Oasis Petroleum Inc. to Chord Energy Corporation.

Under the terms of the Merger Agreement, holders of Whiting common stock, par value $0.001 per share, were entitled to receive 0.5774 shares of Chord common stock, par value $0.01 per share, and $6.25 per share in cash in exchange for each share of Whiting common stock. Upon completion of the Merger on July 1, 2022, we issued 22,671,871 shares of Chord common stock and paid $245.4 million in cash to Whiting stockholders.

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Also in connection with the Merger, on June 16, 2022, the Board of Directors of Oasis declared a special dividend of $15.00 per share of common stock (the “Special Dividend”) that was paid on July 8, 2022 to stockholders of record as of June 29, 2022.

OMP Merger

On February 1, 2022, we completed the merger of Oasis Midstream Partners LP (“OMP”) and OMP GP LLC, OMP’s general partner (“OMP GP”) with and into a subsidiary of Crestwood Equity Partners LP (“Crestwood”) and, in exchange for the interests in OMP and OMP GP owned by us, we received $160.0 million in cash and 20,985,668 common units representing limited partner interests of Crestwood (the “OMP Merger”). In connection with the closing of the OMP Merger, we executed a director nomination agreement with Crestwood, pursuant to which we designated two directors to the Board of Directors of Crestwood Equity GP LLC, a Delaware limited liability company and the general partner of Crestwood (“Crestwood GP”).

On September 12, 2022, we sold an aggregate 16,000,000 common units of Crestwood in separate transactions and received pre-tax net proceeds of $428.2 million. On September 15, 2022, in connection with such transactions and pursuant to the terms of the previously executed director nomination agreement, both of our director designees resigned from the Board of Directors of Crestwood GP.

The OMP Merger represented a strategic shift for us and qualified for reporting as a discontinued operation. See “Item 8. Financial Statements and Supplementary Data—Note 12—Divestitures” for additional information.

Market Conditions

Our revenue, profitability and ability to return cash to stockholders depend substantially on factors beyond our control, such as economic, political and regulatory developments as well as competition from other sources of energy. Prices for crude oil, NGLs and natural gas have experienced significant fluctuations in recent years and may continue to fluctuate widely in the future. Commodity prices increased during 2022 due to a combination of factors, including disruptions to global commodity markets resulting from the Russian invasion of Ukraine, continued restraint of supply by OPEC+ and domestic oil and gas producers in the United States and higher demand as a result of increased global economic activity levels due to easing of restrictions associated with the COVID-19 pandemic.

While our operating and financial results in 2022 were positively impacted by higher commodity prices, this was partially offset by an increase in the costs of labor, materials and services due to a combination of factors, including supply chain disruptions, a tight labor market and an increase in the demand for drilling and completion services relative to available supply (see “Item 7A. —Quantitative and Qualitative Disclosures about Market Risk—Inflation risks” for additional information on inflationary impacts). In an effort to reduce inflationary pressures, central banks aggressively raised interest rates in 2022 and have continued to raise interest rates in 2023. Higher interest rates generally reduce economic activity levels, which could result in lower commodity prices due to reduced demand for crude oil, NGLs and natural gas. The uncertainties resulting from potential economic outcomes of monetary policy decisions of central banks, coupled with geopolitical risks associated with the continued Russian invasion of Ukraine make it difficult to predict future impacts to commodity prices.

In addition, while we are unable to predict future commodity prices, we do not believe that an impairment of our oil and gas properties is reasonably likely to occur in the near future at current price levels; however, we would evaluate the recoverability of the carrying value of our oil and gas properties as a result of a future material or extended decline in the price of crude oil, NGLs or natural gas or a material increase in the costs of labor, materials or services. See “Part I, Item 1A. Risk Factors—If crude oil, NGL and natural gas prices decline, or for an extended period of time remain at depressed levels, we may be required to take write-downs of the carrying values of our oil and gas properties” for additional information.

In an effort to improve price realizations from the sale of our crude oil, NGLs and natural gas, we manage our commodities marketing activities in-house, which enables us to market and sell our crude oil, NGLs and natural gas to a broader array of potential purchasers. We enter into crude oil, NGL and natural gas sales contracts with purchasers who have access to transportation capacity, utilize derivative financial instruments to manage our commodity price risk and enter into physical delivery contracts to manage our price differentials. Due to the availability of other markets and pipeline connections, we do not believe that the loss of any single customer would have a material adverse effect on our results of operations or cash flows. Please see “Part I, Item 1. Business—Exploration and Production Operations—Marketing.”

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Our average net realized crude oil prices and average price differentials are shown in the tables below for the periods presented:

	2022												Year ended December 31, 2022
	Q1			Q2			Q3			Q4
Average Realized Crude Oil Prices ($/Bbl)(1)	$	95.34		$	111.79		$	93.13		$	83.74		$	92.98
Average Price Differential ($/Bbl)(2)	$	1.22		$	2.82		$	1.63		$	0.99		$	1.52
Average Price Differential Percentage(2)	1.3		%	2.5		%	1.8		%	1.2		%	1.6		%

	2021												Year ended December 31, 2021
	Q1			Q2			Q3			Q4
Average Realized Crude Oil Prices ($/Bbl)(1)	$	56.09		$	65.53		$	70.11		$	76.37		$	67.49
Average Price Differential ($/Bbl)(2)	$	1.58		$	0.61		$	0.43		$	0.24		$	0.70
Average Price Differential Percentage(2)	2.8		%	0.9		%	0.6		%	0.3		%	1.0		%

__________________ 

(1)Realized crude oil prices do not include the effect of derivative contract settlements.

(2)Price differential reflects the difference between our realized crude oil prices and NYMEX WTI.

We sell a significant amount of our crude oil production through gathering systems connected to multiple pipeline and rail facilities. These gathering systems, which originate at the wellhead, reduce the need to transport barrels by truck from the wellhead, helping remove trucks from local highways and reduce greenhouse gas emissions. As of December 31, 2022, substantially all of our gross operated crude oil production was connected to gathering systems. Our market optionality on these crude oil gathering systems allows us to shift volumes between pipeline and rail markets in order to optimize price realizations. Expansions of both rail and pipeline facilities in the Williston Basin has reduced prior constraints on crude oil takeaway capacity and improved our price differentials received at the lease.

Results of Operations

Comparability of Financial Statements

The results of operations presented below relate to the periods ended December 31, 2022 and 2021. The Merger was accounted for as of July 1, 2022. Accordingly, the results of operations presented herein report the results of legacy Oasis prior to the closing of the Merger on July 1, 2022 and the results of Chord (including legacy Whiting) from July 1, 2022 through December 31, 2022, unless otherwise noted.

As of the completion of the Merger on July 1, 2022, we elected to report crude oil, NGLs and natural gas separately on a three-stream basis. For the periods prior to July 1, 2022, we reported crude oil and natural gas, which included NGLs, on a two-stream basis. This change impacts the comparability with prior periods.

In addition, the OMP Merger qualified for reporting as a discontinued operation. Accordingly, the results of operations of OMP have been classified as discontinued operations in the Consolidated Statement of Operations for the period from January 1, 2022 to February 1, 2022 (the closing date of the OMP Merger). Prior periods have been recast so that the basis of presentation is consistent with that of the 2022 consolidated financial statements. See “Item 8. Financial Statements and Supplementary Data—Note 13—Discontinued Operations” for additional information.

For discussion related to changes in financial condition and results of operations for the year ended December 31, 2021 (Successor) compared to the period from November 20, 2020 through December 31, 2020 (Successor) and the period from January 1, 2020 through November 19, 2020 (Predecessor), refer to “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2021, filed with the SEC on February 25, 2022.

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Operational and Financial Highlights

During the year ended December 31, 2022:

•Production volumes averaged 119,785 Boepd (58% oil), including average daily production of 171,880 Boepd for the period subsequent to the Merger.

•Lease operating expenses were $10.14 per Boe, including $9.88 per Boe for the period subsequent to the Merger.

•E&P and other capital expenditures were $503.1 million, including $394.1 million for the period subsequent to the Merger.

•Estimated net proved reserves were 655.6 MMBoe as of December 31, 2022, with a Standardized Measure of $11.5 billion and PV-10 of $14.5 billion.

•TIL’d 73 gross (54 net) operated wells.

Revenues

Our crude oil, NGL and natural gas revenues are derived from the sale of crude oil, NGL and natural gas production. These revenues do not include the effects of derivative instruments and may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. Our revenues for the year ended December 31, 2022 increased primarily due to the Merger, which significantly expanded our operations in the Williston Basin. Our purchased oil and gas sales are derived from the sale of crude oil and natural gas purchased through our marketing activities primarily to optimize transportation costs, for blending to meet pipeline specifications or to cover production shortfalls. Revenues and expenses from crude oil and natural gas sales and purchases are generally recorded on a gross basis, as we act as a principal in these transactions by assuming control of the purchased crude oil or natural gas before it is transferred to the counterparty. In certain cases, we enter into sales and purchases with the same counterparty in contemplation of one another, and these transactions are recorded on a net basis.

The following table summarizes our revenues for the periods presented:

	Year Ended December 31,
	2022		2021
	(In thousands)
Revenues
Crude oil revenues	$	2,366,995	$	910,381
NGL revenues(1)	184,288		—
Natural gas revenues(1)	425,013		289,875
Purchased oil and gas sales	670,174		378,983
Other services revenues	324		687
Total revenues	$	3,646,794	$	1,579,926

__________________

(1)For periods prior to July 1, 2022, we reported crude oil and natural gas on a two-stream basis, and NGLs were combined with the natural gas stream when reporting revenues, production data and average sales prices. As of July 1, 2022, NGLs are reported separately from the natural gas stream on a three-stream basis. This prospective change impacts the comparability of the periods presented.

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The following table summarizes the changes in production and average realized prices for the periods presented:

	Year Ended December 31,
	2022		2021
Production data
Crude oil (MBbls)	25,457		13,489
NGLs (MBbls)(1)	7,026		—
Natural gas (MMcf)(1)	67,428		46,157
Oil equivalents (MBoe)	43,722		21,182
Average daily production (Boepd)	119,785		58,032
Average daily crude oil production (Bopd)	69,746		36,956
Average sales prices
Crude oil (per Bbl)
Average sales price	$	92.98	$	67.49
Effect of derivative settlements(2)	(19.48)		(18.94)
Average realized price after the effect of derivative settlements(2)	$	73.50	$	48.55
NGLs (per Bbl)(1)
Average sales price	$	26.23	$	—
Effect of derivative settlements(2)	0.71		—
Average realized price after the effect of derivative settlements(2)	$	26.94	$	—
Natural gas (per Mcf)(1)
Average sales price	$	6.30	$	6.28
Effect of derivative settlements(2)	(1.04)		(0.32)
Average realized price after the effect of derivative settlements(2)	$	5.26	$	5.96

__________________

(1)For periods prior to July 1, 2022, we reported crude oil and natural gas on a two-stream basis, and NGLs were combined with the natural gas stream when reporting revenues, production data and average sales prices. As of July 1, 2022, NGLs are reported separately from the natural gas stream on a three-stream basis. This prospective change impacts the comparability of the periods presented.

(2)The effect of derivative settlements includes the cash received or paid for the cumulative gains or losses on our commodity derivatives settled in the periods presented but does not include proceeds from derivative liquidations or payments for derivative modifications. Our commodity derivatives do not qualify for or were not designated as hedging instruments for accounting purposes.

Crude oil revenues. Our crude oil revenues increased $1.5 billion to $2.4 billion for the year ended December 31, 2022. This increase was primarily driven by a $852.8 million increase due to our expanded operations after the Merger. Excluding the impacts attributable to the Merger, our crude oil revenues increased $603.8 million due to an increase of $389.8 million due to higher crude oil realized prices and $214.0 million due to higher crude oil production volumes sold year-over-year. Average crude oil sales prices, without derivative settlements, increased by $25.49 per barrel year-over-year to an average of $92.98 per barrel for the year ended December 31, 2022. Crude oil production volumes of 69,746 Bopd for the year ended December 31, 2022 included 43,041 Bopd from legacy Oasis assets and 95,992 Bopd for the period subsequent to the Merger. Crude oil production volumes increased 6,085 Bopd year-over-year on our legacy Oasis assets due primarily to an increase in TILs.

Our crude oil production volumes in 2022 were negatively impacted by winter storms in the Williston Basin in April 2022 and December 2022, which resulted in a temporary curtailment of a portion of our production, delays in drilling and completion of wells, and other operational constraints. We subsequently restored our production and resumed normal operations.

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NGL and natural gas revenues. Our NGL and natural gas revenues increased $319.4 million to $609.3 million for the year ended December 31, 2022 primarily driven by a $184.8 million increase due to our expanded operations after the Merger. Excluding the impacts attributable to the Merger, our natural gas and NGL sales increased $134.7 million due to an increase of $126.8 million due to higher natural gas and NGL sales volumes year-over-year, coupled with an increase of $7.9 million due to higher natural gas and NGL prices year-over-year. Natural gas production volumes of 184,735 Mcfpd for the year ended December 31, 2022 included 126,341 Mcfpd from legacy Oasis assets and 226,205 Mcfpd for the period subsequent to the Merger. Our NGL sales volumes are reported on a prospective basis upon the conversion to three-stream reporting and were 38,187 Bpd for the period from July 1, 2022 through December 31, 2022. For the year ended December 31, 2022, on a barrel of oil equivalent basis, our natural gas and NGL production volumes were 30,048 Boepd on our legacy Oasis assets compared to 21,076 Boepd for the year ended December 31, 2021. This increase was primarily due to an increase in TILs year-over-year. Our NGL and natural gas production volumes were also negatively impacted by the winter storms that occurred during 2022 discussed above.

During the year ended December 31, 2022, average natural gas sales prices, without derivative settlements, were $6.30 per Mcf and average NGL sales prices, without derivative settlements, were $26.23 per barrel. During the year ended December 31, 2021, average natural gas sales prices, without derivative settlements, were $6.28 per Mcf. Effective July 1, 2022 we elected to report crude oil, NGLs and natural gas separately on a three-stream basis. Prior to this, we reported on a two-stream basis and NGLs were reported with the natural gas stream. Accordingly, the natural gas sales prices for the periods prior to three-stream reporting were higher compared to the periods subsequent to three-stream reporting since the natural gas sales price included the value of NGLs. The conversion to three-stream reporting did not impact our total reported revenues.

Purchased oil and gas sales. Purchased oil and gas sales increased $291.2 million to $670.2 million for the year ended December 31, 2022. This increase was primarily due to higher crude oil prices year-over-year and an increase in crude oil volumes purchased and then subsequently sold.

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Expenses and other income (expense)

The following table summarizes our operating expenses, gain on sale of assets, net other expenses, income tax benefit, net income from continuing operations, income from discontinued operations attributable to Chord, net of income tax and net income attributable to Chord for the years presented:

	Year Ended December 31,
	2022		2021
	(In thousands, except per Boe of production)
Operating expenses
Lease operating expenses	$	443,373	$	203,933
Other services expenses	187		47
Gathering, processing and transportation expenses	141,644		122,614
Purchased oil and gas expenses	671,935		379,972
Production taxes	229,571		76,835
Depreciation, depletion and amortization	369,659		126,436
Exploration and impairment	2,204		2,763
General and administrative expenses	209,299		80,688
Total operating expenses	2,067,872		993,288
Gain on sale of assets, net	4,867		222,806
Operating income	1,583,789		809,444
Other income (expense)
Net loss on derivative instruments	(208,128)		(589,641)
Net gain from investment in unconsolidated affiliate	34,366		—
Interest expense, net of capitalized interest	(29,349)		(30,806)
Other income (expense)	2,901		(1,010)
Total other expense, net	(200,210)		(621,457)
Income from continuing operations	1,383,579		187,987
Income tax benefit	46,884		973
Net income from continuing operations	1,430,463		188,960
Income from discontinued operations attributable to Chord, net of income tax	425,696		130,642
Net income attributable to Chord	$	1,856,159	$	319,602
Costs and expenses (per Boe of production)
Lease operating expenses	$	10.14	$	9.63
Gathering, processing and transportation expenses	3.24		5.79
Production taxes	5.25		3.63

Lease operating expenses. Lease operating expenses (“LOE”) increased $239.4 million to $443.4 million for the year ended December 31, 2022 as compared to the year ended December 31, 2021. This increase was primarily due to a $169.3 million increase from our expanded operations after the Merger. Excluding the effects of the Merger, LOE increased $70.1 million primarily due to higher fixed costs of $45.2 million, higher workover costs of $24.6 million and an increase in non-operated LOE of $7.9 million, partially offset by $11.6 million of LOE costs incurred during the year ended December 31, 2021 on properties in the Permian Basin that were divested in June 2021. LOE per Boe increased $0.51 per Boe to $10.14 per Boe for the year ended December 31, 2022 primarily due to higher costs.

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Gathering, processing and transportation expenses. Gathering, processing and transportation (“GPT”) expenses increased $19.0 million to $141.6 million for the year ended December 31, 2022 as compared to the year ended December 31, 2021. GPT expenses increased $10.0 million from our expanded operations after the Merger, which included a $7.3 million non-cash gain attributable to the change in fair value of certain transportation derivative contracts acquired in the Merger that we did not elect the “normal purchase normal sale” exclusion. See “Item 8. Financial Statements and Supplementary Data—Note 7—Derivative Instruments” for additional information. Excluding the effects of the Merger, GPT expenses increased $9.0 million primarily due to higher crude oil gathering and transportation expenses of $14.4 million driven by an increase in volumes transported on DAPL, partially offset by lower natural gas gathering and processing expenses of $4.9 million and $2.5 million of GPT expenses incurred during the year ended December 31, 2021 on properties in the Permian Basin that were divested in June 2021. GPT expenses per Boe decreased $2.55 per Boe to $3.24 per Boe for the year ended December 31, 2022 due to higher production volumes and other decreases described above.

Purchased oil and gas expenses. Purchased oil and gas expenses increased $292.0 million to $671.9 million for the year ended December 31, 2022 as compared to the year ended December 31, 2021 primarily due to higher crude oil prices year-over-year and an increase in crude oil volumes purchased.

Production taxes. Production taxes increased $152.7 million to $229.6 million for the year ended December 31, 2022 as compared to the year ended December 31, 2021. This increase was primarily due to an $82.6 million increase from our expanded operations after the Merger. Excluding the effects of the Merger, production taxes increased $70.1 million due to increased crude oil sales year-over-year, coupled with an increase in the crude oil extraction tax in North Dakota from 5% to 6% from June 1, 2022 to November 30, 2022 due to a crude oil price trigger adjustment. The production tax rate as a percentage of crude oil, NGL and natural gas sales was 7.7% for the year ended December 31, 2022, compared to 6.5% for the year ended December 31, 2021. This increase was primarily due to the impact of divesting properties in the Permian Basin in June 2021, which were subject to lower production tax rates in Texas, as compared to North Dakota.

Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) expenses increased $243.2 million to $369.7 million for the year ended December 31, 2022 as compared to the year ended December 31, 2021. The increase was primarily due to a $153.1 million increase in DD&A expenses attributable to our expanded operations after the Merger. Excluding the effects of the Merger, depletion expense increased $101.3 million driven by a $109.8 million increase in the Williston Basin attributable to an increase in production and a higher depletion rate year-over-year, partially offset by $8.5 million of depletion expense incurred during the year ended December 31, 2021 on properties in the Permian Basin that were divested in June 2021. The depletion rate increased $3.11 per Boe to $8.10 per Boe for the year ended December 31, 2022 due to higher costs attributable to the oil and gas properties acquired in the Merger. Fixed DD&A expense decreased $11.2 million primarily due to well service equipment that has been fully depreciated.

Exploration and impairment expenses. Exploration and impairment expenses were $2.2 million for the year ended December 31, 2022, which was consistent with the year ended December 31, 2021.

General and administrative expenses. Our general and administrative (“G&A”) expenses increased $128.6 million to $209.3 million for the year ended December 31, 2022 as compared to the year ended December 31, 2021. This increase was primarily due to $97.7 million of merger-related costs, including $39.7 million of costs related to employee severance benefits, $33.5 million of advisory, legal and other transaction-related costs and $17.8 million attributable to the acceleration of equity-based compensation expenses due to terminations of certain officers upon closing of the Merger. The remaining $30.8 million increase in G&A year-over-year was primarily attributable to increased compensation and other costs associated with a larger organization.

Gain on sale of assets, net. For the year ended December 31, 2022, we recognized a net $4.9 million gain on the sale of certain non-core assets. For the year ended December 31, 2021, we recognized a $222.8 million gain on sale of assets primarily related to the divestiture of upstream assets in the Permian Basin. See “Item 8. Financial Statements and Supplementary Data—Note 12—Divestitures” for additional information.

Derivative instruments. We recorded a $208.1 million net loss on derivative instruments for the year ended December 31, 2022, which included a net loss of $224.2 million associated with our contracts to manage commodity price risk, offset by an unrealized gain of $16.1 million associated with an embedded derivative related to the contingent consideration included within the 2021 agreement to sell our upstream assets in the Permian Basin. The net loss of $224.2 million associated with our contracts to manage commodity price risk was comprised of a loss of $561.1 million from settled contracts, partially offset by an unrealized gain of $336.9 million. During the year ended December 31, 2021, we recorded a $589.6 million net loss on derivative instruments, which included a loss of $601.6 million associated with our contracts to manage commodity price risk, offset by an unrealized gain of $12.0 million associated with an embedded derivative related to the contingent consideration included within the 2021 agreement to sell our upstream assets in the Permian Basin. The loss of $601.6 million associated with

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our contracts to manage commodity price risk was comprised of an unrealized loss of $331.5 million and a loss of $270.1 million from settled contracts.

Investment in unconsolidated affiliate. We recorded a $34.4 million net gain related to our investment in Crestwood for the year ended December 31, 2022, including a gain of $43.9 million due to cash distributions received from Crestwood during the year and a gain of $43.0 million attributable to the sale of 16,000,000 common units in September 2022, partially offset by an unrealized loss of $52.5 million due to a decrease in the fair value of the investment during the year. As of December 31, 2022, we owned less than 5% of Crestwood’s issued and outstanding common units.

Interest expense, net of capitalized interest. Interest expense was $29.3 million for the year ended December 31, 2022, which was consistent with the year ended December 31, 2021. Interest capitalized during the year ended December 31, 2022 and 2021 was $4.6 million and $2.1 million, respectively. For the year ended December 31, 2022, the weighted average interest rate incurred on borrowings under the Credit Facility was 4.6%, compared to 4.2% for the year ended December 31, 2021.

Other income (expense). For the year ended December 31, 2022, we recognized $2.9 million of other income compared to $1.0 million of other expense for the year ended December 31, 2021. This $3.9 million increase in other income was primarily due to an increase in interest income year-over-year associated with higher balances in certain of our money market accounts.

Income tax benefit. Our income tax benefit was recorded at (3.4)% of pre-tax income from continuing operations for the year ended December 31, 2022 and (0.5)% of pre-tax income from continuing operations for the year ended December 31, 2021. Our effective tax rate for the year ended December 31, 2022 was lower than the effective tax rate for the year ended December 31, 2021 primarily due to the impact of releasing a substantial majority of the valuation allowance on our net deferred tax assets in 2022, coupled with 2021 restructuring impacts.

Income from discontinued operations attributable to Chord, net of income tax. Income from discontinued operations attributable to Chord, net of income tax for the year ended December 31, 2022 represents income from OMP for the period prior to the completion of the OMP Merger on February 1, 2022. We recorded income from discontinued operations attributable to Chord, net of income tax of $425.7 million for the year ended December 31, 2022. This was primarily comprised of a gain on sale of $518.9 million and midstream revenues of $23.3 million, offset by income tax expense of $101.1 million, midstream expenses of $13.2 million and interest expense of $3.7 million. Income from discontinued operations attributable to Chord, net of income tax was $130.6 million for the year ended December 31, 2021, which included midstream revenues of $254.2 million, offset by midstream expenses of $122.0 million.

Liquidity and Capital Resources

As of December 31, 2022, we had $1,586.8 million of liquidity available, including $593.2 million in cash and cash equivalents and $993.6 million of aggregate unused borrowing capacity available under our senior secured revolving credit facility. Our primary sources of liquidity are cash on hand, cash flows from operations, the sale of non-core or non-strategic assets and available borrowing capacity under our senior secured revolving credit facility.

Our primary liquidity requirements consist of capital expenditures for the development of oil and gas properties, dividend payments, share repurchases, cash payments associated with the Merger and working capital requirements. We believe we have adequate liquidity to fund our capital expenditures and to meet our obligations during the next 12 months and the foreseeable future.

Our cash flows depend on many factors, including the price of crude oil, NGL and natural gas and the success of our development and exploration activities as well as future acquisitions. We actively manage our exposure to commodity price fluctuations by executing derivative transactions to mitigate the impact of changes in crude oil, NGL and natural gas prices on our production, which mitigates our exposure to crude oil, NGL and natural gas price declines; however, these transactions may also limit our cash flow in periods of rising crude oil, NGL and natural gas prices. For example, during the year ended December 31, 2022, crude oil, NGL and natural gas prices generally increased relative to the strike price in our outstanding commodity derivative contracts, thus resulting in a net cash outflow for the settlement of these contracts.

In connection with the Merger, Whiting’s commodity derivative contracts were novated to us. These contracts included fixed-price swaps and two-way collars to mitigate price risk associated with a certain portion of our crude oil, NGL and natural gas production. In addition, we were novated natural gas basis swap contracts which provide for a fixed differential between the NYMEX Henry Hub price index and the Northern Natural Gas Ventura price index. See “Item 8. Financial Statements and Supplementary Data—Note 9—Derivative Instruments” for additional information.

As of December 31, 2022, our commodity derivative contracts cover 14,106 MBbls of our crude oil production, 7,560 gallons of our NGL production and 10,599 MMBtu of our natural gas production for 2023. In addition, as of December 31, 2022, we had outstanding natural gas basis swaps that cover notional volumes of 5,920 MMBtu for 2023. As of December 31, 2022, we did not have any commodity derivative contracts that cover production volumes in 2024. See “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” as well as “Part I, Item 1A. Risk Factors” for additional information.

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Whiting Merger

In connection with the consummation of the Merger on July 1, 2022, we paid cash consideration of $245.4 million, or $6.25 per share of Whiting common stock, to Whiting stockholders. In addition, we paid the Special Dividend on July 8, 2022 to stockholders of record as of June 29, 2022.

We incurred certain costs directly attributable to the Merger for advisory, legal, severance and other third-party fees which were recorded to general and administrative expenses on the Consolidated Statements of Operations. For the year ended December 31, 2022, we recognized total merger-related costs of $97.7 million, including $39.7 million related to employee severance benefits, transaction costs of $33.5 million and $17.8 million related to the acceleration of unamortized stock compensation expense as a result of certain officer terminations upon completion of the Merger. At December 31, 2022, we had a remaining liability of $21.3 million for the payment of employee severance benefits which was included in accrued liabilities on the Consolidated Balance Sheet.

Whiting had a reserves-based credit facility with a syndicate of banks. Upon consummation of the Merger, the Whiting credit facility was terminated, and the Company paid the remaining outstanding accrued interest and other fees of approximately $2.2 million to satisfy and discharge in full all such outstanding obligations that were owed under the Whiting credit facility.

OMP Merger

Upon closing of the OMP Merger on February 1, 2022, OMP’s outstanding 8.00% senior unsecured notes due April 1, 2029 were assumed by Crestwood, and OMP’s senior secured revolving credit facility was paid in full by Crestwood. As a result, we no longer have access to these liquidity sources as of December 31, 2022; however, we do not expect the loss of these liquidity sources to materially impact our liquidity or financial position due to our ability to generate cash flows from operations and our strong balance sheet.

Material cash requirements

Our material cash requirements from known obligations include repayment of outstanding borrowings and interest payment obligations related to our long-term debt, obligations to plug, abandon and remediate our oil and gas properties at the end of their productive lives, payment of income taxes, severance benefits payable to employees terminated in connection with the Merger, obligations associated with outstanding commodity derivative contracts that settle in a loss position, obligations to pay dividends on vested equity awards that include dividend equivalent rights and obligations associated with our leases. In addition, we have announced a return of capital plan pursuant to which we intend to return capital to stockholders through a mix of base and variable dividend payouts, supplemented by opportunistic share repurchases. There were no borrowings outstanding under the Credit Facility (defined below) as of December 31, 2022; however, on a quarterly basis, we pay a commitment fee on the average amount of borrowing base capacity not utilized during the quarter and fees calculated on the average amount of letter of credit balances outstanding during the quarter.

We also have contracts which include provisions for the delivery, transport or purchase of a minimum volume of crude oil, NGLs, natural gas and water within specified time frames, the majority of which are ten years or less. Under the terms of these contracts, if we fail to deliver, transport or purchase the committed volumes we will be required to pay a deficiency payment for the volumes not tendered over the duration of the contract. The estimable future commitments under these agreements (excluding deliveries from future production and applicable volume credits) were $519.5 million as of December 31, 2022. We believe that for the substantial majority of these agreements, our future production will be adequate to meet our delivery commitments or that we can purchase sufficient volumes of crude oil, NGLs and natural gas from third parties to satisfy our minimum volume commitments.

Long-term debt

Our long-term debt consists of a senior secured revolving line of credit that is generally used to support our working capital requirements and $400.0 million of 6.375% senior unsecured notes.

Senior secured revolving line of credit. We have a senior secured revolving credit facility (the “Credit Facility”) with a borrowing base of $2.75 billion and elected commitments of $1.0 billion that is due July 1, 2027. As of December 31, 2022, we had no borrowings outstanding and $6.4 million of outstanding letters of credit, resulting in an unused borrowing capacity of $993.6 million.

On July 1, 2022, we entered into the Amended and Restated Credit Agreement to, among other things: (i) increase the aggregate maximum credit amount to $3.0 billion, (ii) increase the borrowing base to $2.0 billion, (iii) increase the aggregate amount of elected commitments to $800.0 million, (iv) extend the maturity date to July 1, 2027, (v) reduce the margin on outstanding borrowings by 125 basis points and (vi) increase the consolidated total leverage ratio financial covenant to 3.50x.

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On August 8, 2022, we entered into the First Amendment to the Amended and Restated Credit Agreement to provide additional flexibility for SOFR borrowings. In addition, on October 31, 2022, we completed the semi-annual borrowing base redetermination and entered into our Second Amendment to Amended and Restated Credit Agreement to increase the aggregate amount of elected commitments to $1.0 billion and increase the borrowing base to $2.75 billion. We expect the next semi-annual redetermination to be completed in or around April 2023.

For the year ended December 31, 2022, the weighted average interest rate incurred on borrowings under the Credit Facility was 4.6%, compared to 4.2% for the year ended December 31, 2021.

We were in compliance with the financial covenants in the Credit Facility at December 31, 2022. See “Item 8. Financial Statements and Supplementary Data—Note 15—Long-Term Debt” for additional information.

Senior unsecured notes. As of December 31, 2022, we had $400.0 million of 6.375% senior unsecured notes (the “Senior Notes”) that mature on June 1, 2026. Interest on the senior unsecured notes is payable semi-annually on June 1 and December 1 of each year. See “Item 8. Financial Statements and Supplementary Data—Note 15—Long-Term Debt” for more information.

Cash flows

The Consolidated Statements of Cash Flows have not been recast for discontinued operations, therefore the discussion below concerning cash flows from operating activities, investing activities and financing activities includes the results of both continuing operations and discontinued operations. See “Item 8. Financial Statements and Supplementary Data—Note 13—Discontinued Operations” for disclosure of cash flow impacts attributable to discontinued operations. For a discussion on cash flows for the year ended December 31, 2021 (Successor) compared to the period from November 20, 2020 through December 31, 2020 (Successor) and the period from January 1, 2020 through November 19, 2020 (Predecessor), refer to “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2021 Annual Report on Form 10-K filed with the SEC on February 25, 2022 under the subheading “Cash flows.”

The following table summarizes our change in cash flows:

	Year Ended December 31,
	2022		2021
	(In thousands)
Net cash provided by operating activities	$	1,924,026	$	914,136
Net cash used in investing activities	(682,562)		(920,769)
Net cash provided by (used in) financing activities	(823,096)		161,190
Increase in cash and cash equivalents	$	418,368	$	154,557

Cash flows provided by operating activities

Net cash provided by operating activities was $1,924.0 million for the year ended December 31, 2022. The increase in net cash provided by operating activities of $1,009.9 million from the year ended December 31, 2021 was due primarily to higher revenues from crude oil, NGL and natural gas sales due to higher commodity prices and our expanded operations following the Merger. See “Results of Operations” above for additional information on the impact of volumes and prices on revenues and for additional information on increases and decreases in certain expenses between periods.

Working capital. Our working capital fluctuates primarily as a result of changes in commodity prices and production volumes, capital spending to fund development of our oil and gas properties and the settlement of outstanding commodity derivative contracts. At December 31, 2022, we had a working capital surplus of $121.2 million, compared to a working capital surplus of $60.6 million at December 31, 2021 (excluding current assets/liabilities held for sale).

We believe we have adequate liquidity to meet our working capital requirements. The Credit Facility includes a requirement that the Company maintain a Current Ratio (as defined in the Credit Facility) of no less than 1.0 to 1.0 as of the last day of any fiscal quarter. For purposes of the Current Ratio, the Credit Facility’s definition of total current assets includes unused commitments under the Credit Facility, which were $993.6 million as of December 31, 2022, and excludes current hedge assets, which were $23.7 million as of December 31, 2022. For purposes of the Current Ratio, the Credit Facility’s definition of total current liabilities excludes current hedge liabilities, which were $341.5 million as of December 31, 2022.

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Cash flows used in investing activities

Net cash used in investing activities was $682.6 million for the year ended December 31, 2022. The decrease in net cash used in investing activities of $238.2 million from the year ended December 31, 2021 was primarily due to a decrease of (i) $442.0 million related to acquisitions, which included cash consideration of $585.8 million for the acquisition of oil and gas properties in the Williston Basin from Diamondback Energy Inc. in 2021 compared to $245.4 million of cash consideration paid to Whiting stockholders in connection with the Merger in 2022, and (ii) $220.9 million associated with payments to modify the terms of outstanding derivative contracts in 2021. In addition, we received $428.2 million in proceeds from the sale of our investment in Crestwood in September 2022 and cash distributions for our ownership of Crestwood common units of $43.9 million during the year ended December 31, 2022. These reductions to net cash used in investing activities were offset by an increase of (i) $362.9 million for cash payments to settle commodity derivative contracts and (ii) $318.5 million in capital expenditures related to the development of our oil and gas properties. In addition, there was a decrease of $206.9 million in proceeds from divested assets whereby we received net proceeds from divestitures of $376.1 million during the year ended December 31, 2021 primarily related to the sale of our upstream assets in the Permian Basin, compared to $160.0 million in connection with the completion of the OMP Merger in February 2022. See “Capital expenditures” below for additional information on our capital expenditures in 2022 and our outlook for 2023.

Cash flows provided by (used in) financing activities

Net cash used in financing activities of $823.1 million for the year ended December 31, 2022 was primarily attributable to dividends paid to stockholders of $654.7 million, payments of $152.0 million to repurchase common stock and payments of $41.8 million for income tax withholdings on vested equity-based compensation awards. These uses of cash were partially offset by proceeds of $19.8 million from the exercise of outstanding warrants. Net cash provided by financing activities for the year ended December 31, 2021 of $161.2 million was primarily attributable to OMP’s issuance of $450.0 million in aggregate principal amount of senior notes, coupled with our issuance of the Senior Notes in June 2021.

Capital expenditures

Expenditures for the acquisition and development of oil and gas properties are the primary use of our capital resources. Our capital expenditures are summarized in the following table (in thousands):

	Successor						Predecessor
	Year Ended December 31,				Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020
	2022		2021
Capital expenditures
E&P	$	495,947	$	168,189	$	14,839	$	194,004
Other capital expenditures(1)	11,771		2,277		179		7,071
Total E&P and other capital expenditures	507,718		170,466		15,018		201,075
Acquisitions(2)	(2,275)		586,030		—		—
Total capital expenditures from continuing operations	505,443		756,496		15,018		201,075
Discontinued operations(3)	3,396		49,123		3,054		24,266
Total capital expenditures(4)	$	508,839	$	805,619	$	18,072	$	225,341

__________________ 

(1)Other capital expenditures includes items such as infrastructure capital, administrative capital and capitalized interest. Capitalized interest totaled $4.6 million for the year ended December 31, 2022 (Successor), $2.1 million for the year ended December 31, 2021 (Successor), $0.1 million for the period from November 20, 2020 through December 31, 2020 (Successor) and $6.4 million for the period from January 1, 2020 through November 19, 2020 (Predecessor).

(2)Excludes amounts attributable to the Merger.

(3)Represents capital expenditures attributable to our midstream assets that were classified as discontinued operations. See “Recent Developments—OMP Merger” for additional information.

(4)Total capital expenditures (including acquisitions) reflected in the table above differs from the amounts for capital expenditures and acquisitions shown in the statements of cash flows in our consolidated financial statements because amounts reflected in the table include changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the statements of cash flows are presented on a cash basis.

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In 2022, our total E&P and other capital expenditures were $507.7 million, an increase of $337.3 million as compared to 2021. The increase was primarily due to an increase of $223.7 million associated with capital expenditures on assets acquired in the Merger, including capital expenditures of $189.2 million on drilling and completion activities and $28.4 million on workover activities from July 1, 2022 through December 31, 2022. On our legacy assets, our E&P capital expenditures were $278.3 million, which was an increase of $110.1 million as compared to 2021. This increase was primarily driven by an increase in capital expenditures of $88.6 million on drilling and completion activities and $21.4 million on workover activities. The increase in capital expenditures for drilling and completion activities on our legacy assets was primarily due to an increase in net operated well completions and higher costs associated with drilling longer lateral lengths on our operated wells. We completed 26.8 net operated wells associated with our legacy assets in 2022, compared to 22.3 net operated wells in 2021. Additionally, the increase in capital expenditures for workover activities was primarily due to an increase in the number of workover projects year-over-year. Our capital expenditures were also impacted as a result of inflationary impacts. See “Item 7A. Quantitative and Qualitative Disclosures about Market Risk—Inflation risks” for additional information on inflationary impacts.

Our planned 2023 E&P capital expenditures are expected to be approximately $825 million to $865 million. We expect to run four operated rigs during 2023 and plan to complete 90 to 94 gross operated wells with an average working interest of approximately 73%.

The ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling and operations results as the year progresses. Our capital plan may further be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If crude oil prices decline substantially or for an extended period of time, we could defer a significant portion of our planned capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control. Furthermore, we actively review acquisition opportunities on an ongoing basis. If we acquire additional acreage, our capital expenditures may be higher than planned. However, our ability to make significant acquisitions for cash may require us to obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us or at all.

Dividends

During the year ended December 31, 2022, we declared base plus variable cash dividends of $12.03 per share of common stock, or $373.0 million in aggregate, and a special cash dividend of $15.00 per share of common stock, or $307.4 million in aggregate. On February 22, 2023, we declared a base cash dividend of $1.25 per share of common stock and a variable cash dividend of $3.55 per share of common stock. The dividends will be payable on March 21, 2023 to shareholders of record as of March 7, 2023. As of December 31, 2022, we had dividends payable of $30.6 million related to dividend equivalent rights accrued on equity-based compensation awards, including $5.9 million that was recorded under accrued liabilities and $24.8 million that was recorded under other liabilities on the Consolidated Balance Sheet.

During the year ended December 31, 2021, we declared base cash dividends of $1.625 per share of common stock or $32.3 million in aggregate and a special cash dividend of $4.00 per share of common stock, or $80.0 million in aggregate.

See “Recent Developments—Return of Capital Plan” for additional information regarding our strategy on future dividend payments. Future dividend payments will depend on our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applicable to the payment of dividends and other considerations that the Board of Directors deems relevant.

Share Repurchase Program

In February 2022, our Board of Directors authorized a share-repurchase program covering up to $150.0 million of our common stock, which replaced the $100.0 million share repurchase program that was fully utilized in 2021. We repurchased $124.8 million of shares of common stock under this program in 2022.

In August 2022, our Board of Directors authorized a new share-repurchase program covering up to $300.0 million of our common stock, which resulted in the expiration of the $150.0 million share-repurchase program. We repurchased $27.1 million shares of common stock under this program in 2022.

In total, we repurchased 1,378,070 shares of common stock at a weighted average price of $110.24 per common share for a total cost of $151.9 million under both of these programs in 2022.

See “Recent Developments—Return of Capital Plan” for additional information on our strategy for future share repurchases.

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Critical accounting policies and estimates

Our consolidated financial statements have been prepared in accordance with GAAP. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. See “Item 8. Financial Statements and Supplementary Data—Note 4—Summary of Significant Accounting Policies” for the significant accounting policies and estimates made by management as well as the expected impact of recent accounting pronouncements on our consolidated financial statements. The following are the accounting policies, estimates and judgments used in preparation of our consolidated financial statements which we consider most critical:

Method of accounting for oil and gas properties

GAAP provides two alternative methods to account for oil and gas properties known as the successful efforts method and the full cost method. These two accounting methods differ in a number of ways, including the treatment of the costs of exploratory dry holes and geological and geophysical costs which are charged against earnings during the period incurred under the successful efforts method and capitalized within a pool of assets under the full cost method. We account for oil and gas properties under the successful efforts method of accounting. See “Item 8. Financial Statements and Supplementary Data—Note 4—Summary of Significant Accounting Policies—Property, Plant and Equipment” for additional information.

Estimated quantities of reserves

Our independent reserve engineers prepare our estimates of crude oil, NGL and natural gas reserves. While the SEC rules allow us to disclose proved, probable and possible reserves, we have elected to disclose only proved reserves in this Annual Report on Form 10-K. Estimates of reserve quantities and the related estimates of future net cash flows are used as inputs into the calculation of the fair value of oil and gas properties in a business combination, the assessment of whether sufficient future taxable income will be generated to realize deferred tax assets, the calculation of depletion expense, the evaluation of proved oil and gas properties for impairment and the Standardized Measure.

Estimates of reserves are prepared by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the Estimating and Auditing Standards. Crude oil, NGL and natural gas reserves engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Periodic revisions to the estimated reserves and related future net cash flows may be necessary as a result of a number of factors, including reservoir performance, changes to Company’s anticipated five-year development plan, changes to commodity prices, cost changes, technological advances, new geological or geophysical data or other economic factors. Accordingly, reserve estimates are generally different from the quantities of crude oil, NGL and natural gas that are ultimately recovered. We cannot predict the amounts or timing of future reserve revisions, and if such revisions are significant, they could significantly affect future depletion expense, the carrying amount of our proved oil and gas properties, the realizability of our deferred tax assets and the Standardized Measure. See “Item 1. Business—Exploration and Production Operations—Estimated net proved reserves” for additional information on the revisions to our estimated net proved reserves.

Our estimated net proved reserves and PV-10 were determined using the SEC Price. The SEC Price was $93.67 per Bbl for crude oil and $6.36 per MMBtu for natural gas for the year ended December 31, 2022. We cannot reasonably predict future commodity prices; however, assuming all other factors are held constant, a 10% decrease in the SEC Price for crude oil and natural gas would decrease our estimated net proved reserves by 9.5 MMBoe and decrease the PV-10 by $2.2 billion, and a 10% increase in the SEC Price for crude oil and natural gas would increase our estimated net proved reserves by 7.5 MMBoe and increase the PV-10 by $2.2 billion.

Business combinations

We account for business combinations under the acquisition method of accounting. Under the acquisition method of accounting, we recognize amounts for identifiable assets acquired and liabilities assumed measured at their estimated acquisition date fair values. Any excess of the purchase price consideration over the estimated acquisition date fair value of assets acquired and liabilities assumed is recorded as goodwill, while any deficit of the purchase price consideration under the estimated acquisition date fair value of assets acquired and liabilities assumed is recorded in current earnings as a gain on bargain purchase. Deferred taxes are recorded for any differences between the acquisition date fair value and the tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. Transaction and integration costs associated with business combinations are expensed as incurred. We may adjust the provisional amounts recorded in a business combination during the measurement period which extends for up to one year after the acquisition date.

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The Merger was accounted for as a business combination under the acquisition method of accounting. The purchase price consideration of $2.8 billion was allocated to the assets acquired and liabilities assumed based upon their estimated acquisition date fair values and resulted in no goodwill or bargain purchase. The most significant assumptions related to the measurement of the fair value of oil and gas properties, which was $3.2 billion as of the acquisition date on July 1, 2022. The fair value of the oil and gas properties was calculated by a third party valuation expert using an income approach based on the net discounted future cash flows that utilized inputs requiring significant judgement and assumptions, including future production volumes based upon estimates of reserves prepared by our reserve engineers, future commodity prices (adjusted for basis differentials), future operating and development costs and a market-based weighted average cost of capital discount rate.

The estimated fair value assigned to the assets acquired and liabilities assumed can have a significant effect on our future operating results. For example, a higher fair value measurement of oil and gas properties increases the likelihood of future impairment charges if reserves quantities and/or commodity prices are lower, or operating and/or development costs are higher, than those which were used to measure the fair value on the acquisition date. In addition, a higher fair value measurement of oil and gas properties results in higher depletion expense in future periods which reduces our future earnings.

Impairment of proved oil and gas properties

We review proved oil and gas properties for impairment whenever events and circumstances indicate that their carrying value may not be recoverable. We estimate the expected undiscounted future cash flows by field and compare such undiscounted amounts to the carrying amount to determine if the asset is recoverable. If the carrying amount is not recoverable, we will recognize an impairment by adjusting the carrying amount of the oil and gas properties to fair value. We estimate the fair value of proved oil and gas properties using an income approach that converts future cash flows to a single discounted amount.

The factors used to determine the undiscounted future cash flows and fair value require significant judgment and assumptions, including future production volumes based upon estimates of proved reserves, future commodity prices (adjusted for basis differentials) and estimates of future operating and development costs. These factors are generally consistent with those used in the planning and budgeting processes. Future production is based upon a combination of inputs and assumptions, including the timing and pace of our development plans, as well as estimates of reserve quantities. When discounting future cash flows to estimate fair value, cash flows realized later in the projection period are less valuable compared to those realized earlier in the projection period due to the time value of money. Future commodity prices are estimated by using a combination of quoted forward market prices adjusted for geographical location and quality differentials based upon assumptions that are developed by reviewing historical realized prices, market supply and demand factors, and other relevant factors. Future operating and development costs are generally estimated using inputs including authorizations for expenditures, review of historical data and forecasts developed during the budgeting and planning processes. In addition, estimates of future operating and development costs may be impacted by market supply and demand factors, including inflation expectations and the availability of materials, labor and services. To calculate fair value, future cash flows are discounted using a discount rate that is based on rates utilized by market participants and is commensurate with the risk and current market conditions associated with realizing the expected cash flows projected.

A substantial or extended decline in commodity prices could result in future impairment charges which would negatively impact our future operating results. However, because of the uncertainty inherent in the factors described above, we cannot predict when or if future impairment charges for proved oil and gas properties will be recorded. Our most recent impairment was recorded for $4.4 billion during the period from January 1, 2020 through November 19, 2020 (Predecessor) as a result of the significant decline in expected future commodity prices in the first quarter of 2020.

Income taxes

Our provision for taxes includes both federal and state income taxes. We record our income taxes in accordance with ASC 740, Income Taxes, which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes. During the ordinary course of business, there may be transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from our estimates, which could impact our financial position, results of operations and cash flows.

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We also account for uncertainty in income taxes recognized in the financial statements in accordance with GAAP by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Authoritative guidance for accounting for uncertainty in income taxes requires that we recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. As of December 31, 2022 and 2021, we had no unrecognized tax benefits.

Deferred tax assets are recognized for items such as temporary differences that will be deductible in future years’ tax returns, NOLs and tax credit carryforwards. As of each reporting date, we assess the available positive and negative evidence, including future reversals of temporary differences, tax-planning strategies and future taxable income, to estimate whether sufficient future taxable income will be generated to realize the deferred tax assets. As of December 31, 2022, our consolidated balance sheet includes a net deferred tax asset of $200.2 million, which was reduced by a valuation allowance of $9.6 million for certain state NOLs. As of December 31, 2021, substantially all of our deferred tax assets were reduced by a valuation allowance. During 2022, we decreased the valuation allowances against our deferred tax assets from $399.8 million as of December 31, 2021 to $9.6 million as of December 31, 2022 based upon our assessment of (i) cumulative income earned during the periods subsequent to our emergence from bankruptcy, (ii) the indefinite lives for many of our deferred tax assets and (iii) projections of future taxable income. Significant judgment is involved in this determination, including assumptions required to assess our future taxable income such as future production volumes based upon estimates of proved reserves, future commodity prices (adjusted for basis differentials) and estimates of future operating and development costs. See “Item 8. Financial Statements and Supplementary Data—Note 17—Income Taxes” for additional information.

An estimate of the sensitivity to changes in our assumptions resulting in future income calculations is not practical, given the numerous assumptions that can materially affect our estimates. Unfavorable adjustments to some of the assumptions would likely be offset by favorable adjustments in other assumptions.

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Item 7A. Quantitative and Qualitative Disclosures about Market Risk

We are exposed to a variety of market risks, including commodity price risk, interest rate risk, counterparty and customer risk and inflation risk. We address these risks through a program of risk management, including the use of derivative instruments.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in crude oil, NGL and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for hedging purposes, rather than for speculative trading.

Commodity price exposure risk. We are exposed to market risk as the prices of crude oil, NGLs and natural gas fluctuate as a result of a variety of factors, including changes in supply and demand and the macroeconomic environment, all of which are typically beyond our control. The markets for crude oil, NGLs and natural gas have been volatile, especially over the last several years and these prices will likely continue to be volatile in the future. To partially reduce price risk caused by these market fluctuations, we have entered into derivative instruments in the past and expect to enter into derivative instruments in the future to cover a significant portion of our future production. In addition, entering into derivative instruments could limit the benefit we would receive from increases in the prices for crude oil, NGLs and natural gas. We recognize all derivative instruments at fair value. The credit standing of our counterparties is analyzed and factored into the fair value amounts recognized on our Consolidated Balance Sheets. Derivative assets and liabilities arising from our derivative contracts with the same counterparty are also reported on a net basis, as all counterparty contracts provide for net settlement. See “Item 8. Financial Statements and Supplementary Data—Note 9— Derivative Instruments” and “Note 8—Fair Value Measurements” for additional information regarding our commodity derivative contracts.

The fair value of our unrealized crude oil derivative positions at December 31, 2022 was a net liability position of $291.9 million. A 10% increase in crude oil prices would increase the fair value of this unrealized derivative liability position by approximately $102.4 million, while a 10% decrease in crude oil prices would decrease the fair value of this unrealized derivative liability position by approximately $99.2 million. The fair value of our unrealized NGL derivative positions at December 31, 2022 was a net asset of $2.8 million. A 10% increase or decrease in NGL prices would decrease or increase, respectively, the fair value of this unrealized derivative asset position by approximately $0.6 million. The fair value of our unrealized natural gas derivative positions at December 31, 2022 was a net liability of $16.0 million. A 10% increase in natural gas prices would increase the fair value of this unrealized derivative liability position by approximately $2.2 million, while a 10% decrease in natural gas prices would decrease the fair value of this unrealized derivative liability position by approximately $5.8 million. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—Market Conditions and Commodity Prices,” for further discussion on the commodity price environment. See “Item 8. Financial Statements and Supplementary Data—Note 9—Derivative Instruments” for additional information regarding our derivative instruments.

In addition, in connection with the sale of our upstream assets in the Permian Basin in June 2021, we are entitled to receive up to three earn-out payments of $25.0 million per year for each of 2023, 2024 and 2025 if the average daily settlement price of NYMEX WTI crude oil exceeds $60 per barrel for such year. If the NYMEX WTI crude oil price for calendar year 2023 or 2024 is less than $45 per barrel, then each calendar year thereafter our right to receive any remaining earn-out payments is terminated. As of December 31, 2022, the fair value of this contingent consideration was $60.9 million. See “Item 8. Financial Statements and Supplementary Data—Note 9—Derivative Instruments” for additional information.

Interest rate risk. At December 31, 2022, we had $400.0 million of senior unsecured notes at a fixed cash interest rate of 6.375% per annum.

At December 31, 2022, we had no borrowings and $6.4 million of outstanding letters of credit issued under the Credit Facility, which were subject to varying rates of interest based on (i) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the borrowing base and (ii) whether the loan is a Term SOFR Loan or an ABR Loan (each as defined in the amended and restated credit agreement). See “Item 8. Financial Statements and Supplementary Data—Note 15—Long-Term Debt” for additional information on the interest incurred on the Credit Facility.

We do not currently, but may in the future, utilize interest rate derivatives to mitigate interest rate exposure in an attempt to reduce interest rate expense related to debt issued under the Credit Facility. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

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Counterparty and customer credit risk. Joint interest receivables arise from billing entities which own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we choose to drill. We have limited ability to control participation in our wells. For the year ended December 31, 2022, our credit losses on joint interest receivables were immaterial. We are also subject to credit risk due to concentration of our crude oil, NGL and natural gas receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us, or their insolvency or liquidation, may adversely affect our financial position and related financial results.

We monitor our exposure to counterparties on crude oil, NGL and natural gas sales primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s credit worthiness. We have not generally required our counterparties to provide collateral to secure crude oil, NGL and natural gas sales receivables owed to us. Historically, our credit losses on crude oil, NGL and natural gas sales receivables have been immaterial.

In addition, our crude oil, NGL and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. However, in order to mitigate the risk of nonperformance, we only enter into derivative contracts with counterparties that are high credit-quality financial institutions. All of the counterparties on our derivative instruments currently in place are lenders under the Credit Facility with investment grade ratings. We are likely to enter into any future derivative instruments with these or other lenders under the Credit Facility, which also carry investment grade ratings. This risk is also managed by spreading our derivative exposure across several institutions and limiting the volumes placed under individual contracts. Furthermore, the agreements with each of the counterparties on our derivative instruments contain netting provisions. As a result of these netting provisions, our maximum amount of loss due to credit risk is limited to the net amounts due to and from the counterparties under the derivative contracts.

Inflation risks. Similar to other companies in our industry, we have experienced an increase in the costs of labor, materials and services during 2022 due to a combination of factors, including: (i) global supply chain disruptions resulting in limited availability of certain materials and equipment (including drill pipe, casing and tubing), (ii) increased demand for fuel and steel, (iii) increased demand for services coupled with a limited availability of service providers and (iv) labor shortages. The combination of these factors increased our operating costs and capital expenditures in 2022, which in turn negatively impacted our operating results and cash flows. We believe that these inflationary pressures could continue in 2023 for certain costs, such as the costs of workover rigs, even if inflationary pressures were to level-off for certain other costs, such as steel and tubular goods. We seek to mitigate these inflationary impacts by reviewing our pricing agreements on a regular basis and entering into agreements with our service providers to manage costs and availability of certain services that are utilized in our operations. It is difficult to predict whether such inflationary pressures will have a materially negative impact to our overall financial and operating results in 2023; however, such inflationary pressures are not expected to materially impact our overall liquidity position, cash requirements or financial position, or the ability to conduct our day-to-day drilling, completion and production activities. See “Part I, Item 1A.—Risk Factors—Our profitability may be negatively impacted by inflation in the cost of labor, materials and services and general economic, business or industry conditions” for additional information.

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Item 8. Financial Statements and Supplementary Data

Index to Financial Statements

Reports of Independent Registered Public Accounting Firm (PCAOB ID 238)	78
Consolidated Balance Sheets at December 31, 2022 and December 31, 2021	82
Consolidated Statements of Operations for the Year Ended December 31, 2022 (Successor), the Year Ended December 31, 2021 (Successor), the Period from November 20, 2020 through December 31, 2020 (Successor) and the Period from January 1, 2020 through November 19, 2020 (Predecessor)	84
Consolidated Statements of Changes in Stockholders’ Equity for the Year Ended December 31, 2022 (Successor), the Year Ended December 31, 2021 (Successor), the Period from November 20, 2020 through December 31, 2020 (Successor) and the Period from January 1, 2020 through November 19, 2020 (Predecessor)	86
Consolidated Statements of Cash Flows for the Year Ended December 31, 2022 (Successor), the Year Ended December 31, 2021 (Successor), the Period from November 20, 2020 through December 31, 2020 (Successor) and the Period from January 1, 2020 through November 19, 2020 (Predecessor)	88
Notes to Consolidated Financial Statements
1. Organization and Operations of the Company	90
2. Emergence from Voluntary Reorganization under Chapter 11	90
3. Fresh Start Accounting	91
4. Summary of Significant Accounting Policies	99
5. Revenue Recognition	109
6. Inventory	109
7. Additional Balance Sheet Information	110
8. Fair Value Measurements	110
9. Derivative Instruments	113
10. Property, Plant and Equipment	116
11. Acquisitions	117
12. Divestitures	119
13. Discontinued Operations	121
14. Investment in Unconsolidated Affiliate	124
15. Long-Term Debt	124
16. Asset Retirement Obligations	126
17. Income Taxes	127
18. Equity-Based Compensation	129
19. Stockholders' Equity	134
20. Earnings (Loss) Per Share	136
21. Leases	137
22. Significant Concentrations	139
23. Commitments and Contingencies	139
24. Subsequent Events	141
25. Supplemental Oil and Gas Disclosures — Unaudited	141
26. Supplemental Oil and Gas Reserve Information — Unaudited	142

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Chord Energy Corporation

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of Chord Energy Corporation and its subsidiaries (Successor) (the “Company”) as of December 31, 2022 and 2021, and the related consolidated statements of operations, of changes in stockholders’ equity and of cash flows for the years ended December 31, 2022 and 2021 and for the period from November 20, 2020 through December 31, 2020, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for the years ended December 31, 2022 and 2021 and for the period from November 20, 2020 through December 31, 2020 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

Basis of Accounting

As discussed in Note 2 to the consolidated financial statements, the United States Bankruptcy Court for the Southern District of Texas confirmed the Joint Prepackaged Chapter 11 Plan of Reorganization of Oasis Petroleum Inc. (currently known as Chord Energy Corporation) and its Debtor Affiliates (the "plan") on November 10, 2020. Confirmation of the plan resulted in the discharge of all claims against Oasis Petroleum Inc. and its Debtor Affiliates that arose before November 19, 2020 and terminates all rights and interests of equity security holders as provided for in the plan. The plan was substantially consummated on November 19, 2020 and Oasis Petroleum Inc. and its Debtor Affiliates emerged from bankruptcy. In connection with its emergence from bankruptcy, Oasis Petroleum Inc. and its Debtor Affiliates adopted fresh start accounting as of November 19, 2020.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s report on internal control over financial reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting 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 audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated 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 consolidated 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 consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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As described in Management’s report on internal control over financial reporting, management has excluded Whiting Petroleum Corporation from its assessment of internal control over financial reporting as of December 31, 2022 because it was acquired by the Company in a purchase business combination during 2022. We have also excluded Whiting Petroleum Corporation from our audit of internal control over financial reporting. Whiting Petroleum Corporation is a wholly-owned subsidiary whose total assets and total revenues excluded from management’s assessment and our audit of internal control over financial reporting represent approximately 60% and 29%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2022.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed 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. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated 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.

The Impact of Proved Oil and Natural Gas Reserves on Proved Oil and Gas Properties, Net

As described in Notes 4 and 10 to the consolidated financial statements, the Company’s consolidated proved oil and gas properties, net balance was $4.6 billion as of December 31, 2022. Depreciation, depletion and amortization (DD&A) expense for the year ended December 31, 2022 was $369.5 million. Crude oil, NGL and natural gas exploration and development activities are accounted for using the successful efforts method. All capitalized well costs (including future abandonment costs, net of salvage value) and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and total proved reserves, respectively, related to the associated field. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, NGL and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. As disclosed by management, periodic revisions to the estimated reserves and related future net cash flows may be necessary as a result of a number of factors, including reservoir performance, changes to the Company’s anticipated five-year development plan, changes to commodity prices, cost changes, technological advances, new geological or geophysical data or other economic factors. Reserve engineers prepare the estimates of crude oil, NGL and natural gas reserves.

The principal considerations for our determination that performing procedures relating to the impact of proved oil and natural gas reserves on proved oil and gas properties, net is a critical audit matter are (i) the significant judgment by management, including the use of specialists, when developing the estimates of proved oil and natural gas reserves, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to the data, methods, and assumptions used by management and its specialists in developing the estimates of proved oil and natural gas reserves.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s estimates of proved oil and natural gas reserves. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved oil and natural gas reserves. As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluating the methods and assumptions used by the specialists, testing the completeness and accuracy of the data used by the specialists, and evaluating the specialists’ findings.

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Merger with Whiting Petroleum Corporation – Valuation of Proved Oil and Gas Properties

As described in Notes 4 and 11 to the consolidated financial statements, on July 1, 2022, the Company completed the merger with Whiting Petroleum Corporation, which has been accounted for under the acquisition method of accounting. Under the acquisition method of accounting, the assets and liabilities of Whiting Petroleum Corporation have been recorded at their respective fair values as of the acquisition date on July 1, 2022. The Company recorded the assets acquired and liabilities assumed at their estimated fair value on July 1, 2022 of $2.8 billion, of which $3.2 billion related to oil and gas properties. As disclosed by management, the fair value of the oil and gas properties was calculated using an income approach based on the net discounted cash flows that utilized inputs requiring significant judgment and assumptions, including future production volumes based upon estimates of reserves prepared by reserve engineers, future commodity prices (adjusted for basis differentials), future operating and development costs and a market-based weighted average cost of capital discount rate.

The principal considerations for our determination that performing procedures relating to the valuation of proved oil and gas properties acquired in the merger with Whiting Petroleum Corporation is a critical audit matter are (i) the significant judgment by management, including the use of specialists, when developing the fair value estimate of the proved oil and gas properties acquired, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to future production volumes, future commodity prices (adjusted for basis differentials), future operating and development costs, and the market-based weighted average cost of capital discount rate, and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to the acquisition accounting, including controls over the fair value estimate of the proved oil and gas properties acquired. These procedures also included, among others (i) reading the merger agreement, (ii) testing management’s process for developing the fair value estimate of the proved oil and gas properties acquired, (iii) evaluating the appropriateness of the discounted cash flow models, (iv) testing the completeness and accuracy of underlying data used in the discounted cash flow models, and (v) evaluating the reasonableness of the significant assumptions used by management related to future production volumes, future commodity prices (adjusted for basis differentials), future operating and development costs, and the market-based weighted average cost of capital discount rate. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the future production volumes used in the discounted cash flow models. As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluating the methods and assumptions used by the specialists, testing the completeness and accuracy of the data used by the specialists, and evaluating the specialists’ findings. Evaluating the reasonableness of management’s significant assumptions related to future commodity prices (adjusted for basis differentials) and future operating and development costs involved evaluating whether the assumptions used by management were reasonable considering the past performance of Whiting Petroleum Corporation, the consistency with external market and industry data, and whether the assumptions were consistent with evidence obtained in other areas of the audit. Professionals with specialized skill and knowledge were used to assist in evaluating the appropriateness of the discounted cash flow models and the reasonableness of the market-based weighted average cost of capital discount rate significant assumption.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 28, 2023

We have served as the Company’s auditor since 2007.

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Oasis Petroleum Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated statements of operations, of changes in stockholders’ equity and of cash flows of Chord Energy Corporation (formerly known as Oasis Petroleum Inc.) and its subsidiaries (Predecessor) (the “Company”) for the period from January 1, 2020 through November 19, 2020, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the results of operations and cash flows of the Company for the period from January 1, 2020 through November 19, 2020 in conformity with accounting principles generally accepted in the United States of America.

Basis of Accounting

As discussed in Note 2 to the consolidated financial statements, Oasis Petroleum Inc. (currently known as Chord Energy Corporation) and certain of its affiliates (the “Debtor Affiliates”) filed petitions on September 30, 2020 with the United States Bankruptcy Court for the Southern District of Texas for reorganization under the provisions of Chapter 11 of the Bankruptcy Code. The Company’s Joint Prepackaged Chapter 11 Plan of Reorganization of Oasis Petroleum Inc. and its Debtor Affiliates was substantially consummated on November 19, 2020 and the Company emerged from bankruptcy.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audit. 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 audit of these consolidated financial statements 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 consolidated financial statements are free of material misstatement, whether due to error or fraud.

Our audit included performing procedures to assess the risks of material misstatement of the consolidated 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 consolidated financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audit provides a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 8, 2021, except for the effects of discontinued operations discussed in Note 13 to the consolidated financial statements, as to which the date is February 24, 2022

We have served as the Company’s auditor since 2007.

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Chord Energy Corporation

Consolidated Balance Sheets 

	December 31,
	2022		2021
	(In thousands, except share data)
ASSETS
Current assets
Cash and cash equivalents	$	593,151	$	172,114
Accounts receivable, net	781,738		377,202
Inventory	54,411		28,956
Prepaid expenses	17,624		6,016
Derivative instruments	23,735		—
Other current assets	11,853		1,836
Current assets held for sale	—		1,029,318
Total current assets	1,482,512		1,615,442
Property, plant and equipment
Oil and gas properties (successful efforts method)	5,120,121		1,395,837
Other property and equipment	72,973		48,981
Less: accumulated depreciation, depletion and amortization	(481,751)		(124,386)
Total property, plant and equipment, net	4,711,343		1,320,432
Derivative instruments	37,965		44,865
Investment in unconsolidated affiliate	130,575		—
Long-term inventory	22,009		17,510
Operating right-of-use assets	23,875		15,782
Deferred tax assets	200,226		—
Other assets	22,576		12,756
Total assets	$	6,631,081	$	3,026,787
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	29,056	$	2,136
Revenues and production taxes payable	607,964		270,306
Accrued liabilities	362,454		150,674
Accrued interest payable	3,172		2,150
Derivative instruments	341,541		89,447
Advances from joint interest partners	3,736		1,892
Current operating lease liabilities	9,941		7,893
Other current liabilities	3,469		1,046
Current liabilities held for sale	—		699,653
Total current liabilities	1,361,333		1,225,197
Long-term debt	394,209		392,524
Deferred tax liabilities	—		7
Asset retirement obligations	146,029		57,604
Derivative instruments	2,829		115,282
Operating lease liabilities	13,266		6,724
Other liabilities	33,617		7,876
Total liabilities	1,951,283		1,805,214

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Commitments and contingencies (Note 23)
Stockholders’ equity
Common stock, $0.01 par value: 120,000,000 shares authorized, 43,726,181 shares issued and 41,477,093 shares outstanding at December 31, 2022; 60,000,000 shares authorized, 20,147,199 shares issued and 19,276,181 shares outstanding at December 31, 2021	438		200
Treasury stock, at cost: 2,249,088 and 871,018 shares at December 31, 2022 and December 31, 2021, respectively	(251,950)		(100,000)
Additional paid-in capital	3,485,819		863,010
Retained earnings	1,445,491		269,690
Chord share of stockholders’ equity	4,679,798		1,032,900
Non-controlling interests	—		188,673
Total stockholders’ equity	4,679,798		1,221,573
Total liabilities and stockholders’ equity	$	6,631,081	$	3,026,787

The accompanying notes are an integral part of these consolidated financial statements.

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Chord Energy Corporation

Consolidated Statements of Operations

(In thousands, except per share data)

	Successor						Predecessor
	Year Ended December 31,				Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020
	2022		2021
Revenues
Oil, NGL and gas revenues	$	2,976,296	$	1,200,256	$	86,145	$	601,510
Purchased oil and gas sales	670,174		378,983		20,633		237,111
Other services revenues	324		687		215		6,836
Total revenues	3,646,794		1,579,926		106,993		845,457
Operating expenses
Lease operating expenses	443,373		203,933		22,517		160,406
Gathering, processing and transportation expenses	141,644		122,614		13,198		117,884
Purchased oil and gas expenses	671,935		379,972		20,278		229,056
Production taxes	229,571		76,835		5,938		45,439
Depreciation, depletion and amortization	369,659		126,436		13,789		271,002
Exploration and impairment	2,204		2,763		—		4,828,278
Rig termination	—		—		—		1,279
General and administrative expenses	209,299		80,688		14,803		144,700
Litigation settlement	—		—		—		22,750
Other services expenses	187		47		—		6,658
Total operating expenses	2,067,872		993,288		90,523		5,827,452
Gain on sale of assets, net	4,867		222,806		11		10,396
Operating income (loss)	1,583,789		809,444		16,481		(4,971,599)
Other income (expense)
Net gain (loss) on derivative instruments	(208,128)		(589,641)		(84,615)		233,565
Net gain from investment in unconsolidated affiliate	34,366		—		—		—
Interest expense, net of capitalized interest	(29,349)		(30,806)		(2,020)		(141,836)
Gain on debt extinguishment	—		—		—		83,867
Reorganization items, net	—		—		—		665,916
Other income (expense)	2,901		(1,010)		(401)		1,271
Total other income (expense), net	(200,210)		(621,457)		(87,036)		842,783
Income (loss) from continuing operations	1,383,579		187,987		(70,555)		(4,128,816)
Income tax benefit	46,884		973		3,447		262,962
Net income (loss) from continuing operations	1,430,463		188,960		(67,108)		(3,865,854)
Income from discontinued operations attributable to Chord, net of income tax	425,696		130,642		17,196		225,526
Net income (loss) attributable to Chord	$	1,856,159	$	319,602	$	(49,912)	$	(3,640,328)
Earnings (loss) attributable to Chord per share:
Basic from continuing operations (Note 20)	$	46.90	$	9.55	$	(3.36)	$	(12.17)
Basic from discontinued operations (Note 20)	13.96		6.60		0.86		0.71
Basic total	$	60.86	$	16.15	$	(2.50)	$	(11.46)

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Diluted from continuing operations (Note 20)	$	44.35	$	9.15	$	(3.36)	$	(12.17)
Diluted from discontinued operations (Note 20)	13.20		6.33		0.86		0.71
Diluted total	$	57.55	$	15.48	$	(2.50)	$	(11.46)
Weighted average shares outstanding:
Basic (Note 20)	30,497		19,792		19,991		317,644
Diluted (Note 20)	32,251		20,648		19,991		317,644

The accompanying notes are an integral part of these consolidated financial statements.

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Chord Energy Corporation

Consolidated Statements of Changes in Stockholders’ Equity

	Attributable to Chord												Total Stockholders’ Equity
	Common Stock			Treasury Stock			Additional Paid-in-Capital		Retained Earnings (Deficit)		Non-controlling Interests
	Shares	Amount		Shares	Amount
	(In thousands)
Balance as of December 31, 2019 (Predecessor)	321,231	$	3,189	2,967	$	(33,881)	$	3,112,384	$	554,446	$	200,943	$	3,837,081
Cumulative-effect adjustment for adoption of new accounting pronouncements	—	—		—	—		—		(410)		—		(410)
Equity-based compensation	1,080	44		—	—		31,454		—		236		31,734
Distributions to non-controlling interest owners	—	—		—	—		—		—		(24,080)		(24,080)
Equity component of senior unsecured convertible notes, net	—	—		—	—		(337)		—		—		(337)
Treasury stock-tax withholdings	(2,010)	—		2,010	(2,756)		—		—		—		(2,756)
Net loss	—	—		—	—		—		(3,640,328)		(84,283)		(3,724,611)
Cancellation of Predecessor equity	(320,301)	(3,233)		(4,977)	36,637		(3,143,501)		3,086,292		—		(23,805)
Issuance of Successor common stock	20,000	200		—	—		941,610		—		—		941,810
Issuance of Successor warrants	—	—		—	—		23,805		—		—		23,805
Balance as of November 19, 2020 (Predecessor)	20,000	$	200	—	$	—	$	965,415	$	—	$	92,816	$	1,058,431
Balance as of November 20, 2020 (Successor)	20,000	$	200	—	$	—	$	965,415	$	—	$	92,816	$	1,058,431
Equity-based compensation	93	—		—	—		239		—		31		270
Net income (loss)	—	—		—	—		—		(49,912)		3,950		(45,962)
Balance as of December 31, 2020 (Successor)	20,093	200		—	—		965,654		(49,912)		96,797		1,012,739
Equity-based compensation	3	—		—	—		14,685		—		791		15,476
Dividends to stockholders	—	—		—	—		(116,852)		—		—		(116,852)
Distributions to non-controlling interest owners	—	—		—	—		—		—		(28,720)		(28,720)
Issuance of OMP common units, net of offering costs	—	—		—	—		—		—		86,467		86,467
Midstream Simplification (Note 12)	—	—		—	—		2,358		—		(2,358)		—
Common control transaction costs	—	—		—	—		(5,675)		—		—		(5,675)
Warrants exercised	51	—		—	—		2,840		—		—		2,840
Repurchase of common stock	(871)	—		871	(100,000)		—		—		—		(100,000)
Net income	—	—		—	—		—		319,602		35,696		355,298
Balance as of December 31, 2021 (Successor)	19,276	200		871	(100,000)		863,010		269,690		188,673		1,221,573
Equity-based compensation	835	4		—	—		61,217		—		48		61,269
Tax withholding on vesting of equity-based awards	(345)	—		35	(4,789)		(36,963)		—		—		(41,752)
Modification of equity-based awards	—	—		—	—		(226)		—		—		(226)
Dividends to stockholders	—	—		—	—		—		(680,358)		—		(680,358)
Transfer of equity plan shares from treasury	—	—		(35)	4,789		(4,789)		—		—		—
Shares issued in Merger	22,672	227		—	—		2,477,809		—		—		2,478,036
Replacement equity awards issued in Merger	—	—		—	—		27,402		—		—		27,402

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Replacement warrants issued in Merger	—	—		—	—		79,774		—		—		79,774
Share repurchases	(1,378)	—		1,378	(151,950)		—		—		—		(151,950)
Warrants exercised	417	7		—	—		18,585		—		—		18,592
OMP Merger	—	—		—	—		—		—		(191,032)		(191,032)
Net income	—	—		—	—		—		1,856,159		2,311		1,858,470
Balance as of December 31, 2022	41,477	$	438	2,249	$	(251,950)	$	3,485,819	$	1,445,491	$	—	$	4,679,798

The accompanying notes are an integral part of these consolidated financial statements.

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Chord Energy Corporation

Consolidated Statements of Cash Flows

(In thousands)

	Successor						Predecessor
	Year Ended December 31,				Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020
	2022		2021
Cash flows from operating activities:
Net income (loss) including non-controlling interests	$	1,858,470	$	355,298	$	(45,962)	$	(3,724,611)
Adjustments to reconcile net income (loss) including non-controlling interests to net cash provided by operating activities:
Depreciation, depletion and amortization	369,659		158,304		16,094		291,115
Gain on extinguishment of debt	—		—		—		(83,867)
Gain on sale of assets	(523,767)		(222,806)		(11)		(10,396)
Impairment	(344)		5		—		4,937,143
Deferred income taxes	28,341		(977)		(3,447)		(262,926)
Net gain from investment in unconsolidated affiliate	(34,366)		—		—		—
Net (gain) loss on derivative instruments	208,128		589,641		84,615		(233,565)
Equity-based compensation expenses	61,269		15,476		270		31,315
Non-cash reorganization items, net	—		—		—		(809,036)
Deferred financing costs amortization and other	3,194		12,992		6,824		41,811
Working capital and other changes:
Change in accounts receivable, net	84,041		(184,605)		68,322		96,436
Change in inventory	8,756		2,168		1,902		(4,005)
Change in prepaid expenses	3,423		5,605		(2,976)		1,674
Change in accounts payable, interest payable and accrued liabilities	(131,687)		184,517		(24,573)		(62,694)
Change in other assets and liabilities, net	(11,091)		(1,482)		(5,803)		(5,458)
Net cash provided by operating activities	1,924,026		914,136		95,255		202,936
Cash flows from investing activities:
Capital expenditures	(531,327)		(212,820)		(9,805)		(332,007)
Acquisitions, net of cash acquired	(148,144)		(590,097)		—		—
Proceeds from divestitures, net of cash divested	169,198		376,081		—		15,188
Costs related to divestitures	(11,368)		(2,926)		—		—
Derivative settlements	(633,025)		(270,118)		(76)		224,416
Derivative modifications	—		(220,889)		—		—
Proceeds from sale of investment in unconsolidated affiliate	428,231		—		—		—
Distributions from investment in unconsolidated affiliate	43,873		—		—		—
Net cash used in investing activities	(682,562)		(920,769)		(9,881)		(92,403)
Cash flows from financing activities:
Proceeds from revolving credit facilities	1,035,000		399,500		29,000		686,189
Principal payments on revolving credit facilities	(1,020,000)		(906,500)		(114,500)		(686,189)
Repurchase of senior unsecured notes	—		—		—		(68,060)
Proceeds from issuance of senior unsecured notes	—		850,000		—		—
Cash paid to settle Whiting debt	(2,154)		—		—		—
Deferred financing costs	(5,997)		(22,251)		—		(7,260)

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Debtor-in-possession credit facility fees	—		—		—		(5,853)
Proceeds from issuance of OMP common units, net of offering costs	—		86,467		—		—
Common control transaction costs	—		(5,675)		—		—
Purchases of treasury stock	(151,950)		(100,000)		—		—
Tax withholding on vesting of equity-based awards	(41,752)		—		—		(2,756)
Dividends paid	(654,728)		(111,905)		—		—
Distributions to non-controlling interests	—		(28,720)		—		(24,080)
Payments on finance lease liabilities	(1,299)		(1,161)		(202)		(1,989)
Proceeds from warrants exercised	19,784		1,435		—		—
Net cash provided by (used in) financing activities	(823,096)		161,190		(85,702)		(109,998)
Increase (decrease) in cash, cash equivalents and restricted cash	418,368		154,557		(328)		535
Cash, cash equivalents and restricted cash:
Beginning of period	174,783		20,226		20,554		20,019
End of period	$	593,151	$	174,783	$	20,226	$	20,554
Supplemental cash flow information:
Cash paid for interest, net of capitalized interest	$	24,266	$	41,603	$	2,411	$	152,416
Cash paid for income taxes	10,000		20,000		1		109
Cash received for income tax refunds	—		—		28		282
Cash paid for reorganization items	—		—		—		22,205
Supplemental non-cash transactions:
Change in accrued capital expenditures	$	(21,668)	$	8,304	$	7,938	$	(107,725)
Change in asset retirement obligations	852		14,724		377		(10,268)
Non-cash consideration exchanged in Merger	2,585,211		—		—		—
Investment in unconsolidated affiliate	568,312		—		—		—
Note receivable from divestiture	—		2,900		—		—
Contingent consideration from Permian Basin Sale	—		32,860		—		—
Dividends payable	30,630		4,946		—		—

The accompanying notes are an integral part of these consolidated financial statements.

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Chord Energy Corporation

Notes to Consolidated Financial Statements

1. Organization and Operations of the Company

Chord Energy Corporation (together with its consolidated subsidiaries, the “Company” or “Chord”) is an independent exploration and production (“E&P”) company with quality and sustainable long-lived assets in the Williston Basin. The Company, formerly known as Oasis Petroleum Inc. (“Oasis”), was established upon completion of the merger of equals with Whiting Petroleum Corporation (“Whiting”). Whiting was an independent oil and gas company engaged in the development, production and acquisition of crude oil, natural gas liquids (“NGL”) and natural gas primarily in the Rocky Mountains region of the United States.

On March 7, 2022, Oasis and Whiting entered into an Agreement and Plan of Merger (the “Merger Agreement”), which provided for, among other things, the combination of Oasis and Whiting in a merger of equals transaction (the “Merger”). The Merger was completed on July 1, 2022 and accounted for under the acquisition method of accounting in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 805, Business Combinations (“ASC 805”). Accordingly, unless otherwise specifically noted herein, the periods prior to July 1, 2022 report the financial results of legacy Oasis, while the periods as of and subsequent to July 1, 2022 report the financial results of Chord, which include the operating results of Whiting and the associated impacts from the Merger.

In connection with the Merger, the Board of Directors of Oasis unanimously (i) determined the issuance of the shares of common stock, par value $0.01 per share, of Oasis (the “Oasis Stock Issuance”), and the amendment of Oasis’ restated certificate of incorporation to (a) increase the number of authorized shares of common stock from 60,000,000 shares of common stock to 120,000,000 shares of common stock and (b) change the name of the Company from Oasis Petroleum Inc. to Chord Energy Corporation (the “Oasis Charter Amendment”) are fair to, and in the best interests of, Oasis and the holders of its common stock, (ii) approved and declared advisable the Oasis Stock Issuance and the Oasis Charter Amendment and (iii) recommended that the holders of common stock approve the Oasis Stock Issuance and the Oasis Charter Amendment. On June 28, 2022, all proposals relating to the Merger, including the Oasis Stock Issuance and Oasis Charter Amendment proposals, were approved by the stockholders of Oasis and Whiting.

Under the terms of the Merger Agreement, each holder of Whiting common stock received 0.5774 shares of Chord common stock (the “Share Consideration”) and $6.25 per share in cash (the “Cash Consideration” and together with the Share Consideration, the “Merger Consideration”) in exchange for each share of Whiting common stock. See Note 11—Acquisitions for additional information.

2. Emergence from Voluntary Reorganization under Chapter 11

Due to the volatile market environment that drove a severe downturn in crude oil and natural gas prices in early 2020, as well as the unprecedented impact of the novel coronavirus 2019 (“COVID-19”) pandemic, the Company evaluated strategic alternatives to reduce its debt, increase financial flexibility and position the Company for long-term success. On September 30, 2020 (the “Petition Date”), Oasis and its affiliates Oasis Petroleum LLC, Oasis Petroleum North America LLC (“OPNA”), Oasis Well Services LLC, Oasis Petroleum Marketing LLC, OP Permian LLC, OMS Holdings LLC, Oasis Midstream Services LLC and OMP GP LLC (“OMP GP”) (collectively, the “Debtors”) filed voluntary petitions (the “Chapter 11 Cases”) for relief under chapter 11 of title 11 (“Chapter 11”) of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). On November 10, 2020, the Bankruptcy Court confirmed the Joint Prepackaged Chapter 11 Plan of Reorganization of Oasis Petroleum Inc. and its Debtor Affiliates (the “Plan”), and on November 19, 2020 (the “Emergence Date”), the Debtors implemented the Plan and emerged from the Chapter 11 Cases. Oasis Midstream Partners LP (“OMP”) and its subsidiaries, OMP Operating LLC, Bighorn DevCo LLC, Bobcat DevCo LLC (“Bobcat DevCo”), Beartooth DevCo LLC (“Beartooth DevCo”) and Panther DevCo LLC, were not included in the Chapter 11 Cases.

At the Emergence Date, the Company adopted fresh start accounting in accordance with FASB ASC 852, Reorganizations (“ASC 852”), which resulted in a new basis of accounting and the Company becoming a new entity for financial reporting purposes (see Note 3—Fresh Start Accounting). As a result of the adoption of fresh start accounting and the effects of the implementation of the Plan, the consolidated financial statements after the Emergence Date are not comparable to the consolidated financial statements prior to that date. References to “Successor” relate to the reorganized Company’s financial position and results of operations as of and subsequent to the Emergence Date. References to “Predecessor” relate to the Company’s financial position prior to, and results of operations through and including, the Emergence Date.

The Predecessor operated as a debtor-in-possession from the Petition Date through the Emergence Date. As such, certain aspects of the Chapter 11 Cases and related matters are described below in order to provide context to the Company’s financial condition and results of operations for the period presented.

In accordance with the Plan, the following significant transactions occurred on the Emergence Date:

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•Shares of the Predecessor’s common stock outstanding immediately prior to the Emergence Date were cancelled, and on the Emergence Date, the Company issued (i) 20,000,000 shares of the Successor’s common stock pro rata to holders of the Predecessor’s senior unsecured notes and (ii) 1,621,622 warrants (the “Warrants”) pro rata to holders of the Predecessor’s common stock.

•All outstanding obligations under the following notes (collectively, the “Predecessor Notes”) issued by the Predecessor were cancelled: (i) 6.50% senior unsecured notes due 2021, (ii) 6.875% senior unsecured notes due 2022, (iii) 6.875% senior unsecured notes due 2023, (iv) 6.250% senior unsecured notes due 2026 and (v) 2.625% senior unsecured convertible notes due 2023.

•Oasis, as parent, OPNA, as borrower, and Wells Fargo Bank, N.A. (“Wells Fargo”), as administrative agent, issuing bank and swingline lender, and the lenders party thereto entered into a reserves-based credit agreement (the “Credit Facility”).

•The Amended and Restated Credit Agreement, dated as of October 16, 2018 (as amended prior to the Emergence Date, the “Predecessor Credit Facility”), by and among the Predecessor, as borrower, the lenders party thereto, and Wells Fargo, as administrative agent, was terminated and holders of claims under the Predecessor Credit Facility had such obligations refinanced through the Credit Facility.

•The Senior Secured Superpriority Debtor-in-Possession Credit Agreement, dated as of October 2, 2020 (the “DIP Credit Facility”), by and among the Predecessor, as borrower, its subsidiaries party thereto, as guarantors, the lenders party thereto, and Wells Fargo, as administrative agent, was terminated and the holders of claims under the DIP Credit Facility had such obligations refinanced through the Credit Facility.

•Mirada Claims (as defined in the Plan) were treated in accordance with the Settlement and Mutual Release Agreement dated September 28, 2020 (the “Mirada Settlement Agreement”) with Mirada Energy, LLC and certain related parties.

•The holders of other secured claims, other priority claims and general unsecured claims received payment in full in cash upon emergence or through the ordinary course of business after the Emergence Date.

•The Company adopted the Oasis Petroleum Inc. 2020 Long Term Incentive Plan (the “2020 LTIP”) effective on the Emergence Date and reserved 2,402,402 shares of its Successor’s common stock for distribution under the 2020 LTIP.

3. Fresh Start Accounting

On the Emergence Date, the Company was required to adopt fresh start accounting in accordance with ASC 852 as (i) the holders of existing voting shares of the Predecessor received less than 50% of the voting shares of the Successor and (ii) the reorganization value of the Company’s assets immediately prior to confirmation of the Plan of $2.2 billion was less than the total of post-petition liabilities and allowed claims of $3.2 billion. Refer to Note 2—Emergence from Voluntary Reorganization under Chapter 11 for the terms of the Plan.

Reorganization Value

Under fresh start accounting, reorganization value represents the value of the entity before considering liabilities and is intended to represent the approximate amount a willing buyer would pay for the assets immediately after the restructuring. Upon the adoption of fresh start accounting, the Company allocated the reorganization value to its individual assets and liabilities based on their fair values (except for deferred income taxes) in conformity with ASC 805. Deferred income tax amounts were determined in accordance with Accounting Standards Codification 740, Income Taxes (“ASC 740”).

Reorganization value is derived from an estimate of enterprise value, or the fair value of the Company’s interest-bearing debt and stockholders’ equity. As set forth in the Plan and related disclosure statement approved by the Bankruptcy Court, the enterprise value of the Successor was estimated to be between $1.3 billion and $1.7 billion. The enterprise value was prepared using reserve information, development schedules, other financial information and financial projections, and applying standard valuation techniques, including risked net asset value analysis, discounted cash flow analysis, public comparable company analysis and precedent transactions analysis. On the Emergence Date, the Company estimated the enterprise value to be $1.3 billion based on the estimates and assumptions used in determining the enterprise value coupled with consideration of the indicated enterprise value implied by the trading value of the Company’s notes prior to the Emergence Date (the “Predecessor Notes”), as the reorganized Successor’s equity would be issued to the holders of the Predecessor Notes under the Plan.

The Company’s principal assets are its oil and gas properties, which were valued using primarily an income approach. The fair value of proved oil and natural gas properties was estimated using a discounted cash flow model, which is subject to management’s judgment and expertise and includes, but is not limited to, future production volume estimates based upon

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estimates of proved reserves, future commodity pricing, estimates of operating and development costs and a discount rate. Estimated proved reserves were risked by reserve category and were limited to wells included in the Company's five-year development plan. The underlying future commodity prices used to estimate future cash flows were based on NYMEX forward strip prices as of the Emergence Date through 2022, escalating 2% per year thereafter (based on historical average annual consumer price index percentage changes) until reaching $75 per barrel for crude oil and $4.80 per Mcf for natural gas in 2051 after which prices were held flat. These prices were adjusted for transportation fees and quality and geographical differentials. Future operating and development costs were estimated based on the Company's recent actual costs, excluding the cost benefits the Company realizes from consolidating its midstream business segment. The cash flow models also included estimates not typically included in proved reserves, such as general and administrative expenses and income tax expenses, and estimated future cash flows were discounted using a weighted average cost of capital discount rate of 11%. In estimating the fair value of the Company’s unproved acreage, a market approach was used in which a review of recent transactions involving properties in the same geographical location were considered when estimating the fair value of the Company’s acreage.

The Company’s midstream business segment was primarily operated through OMP, which was classified as a discontinued operation (see Note 13—Discontinued Operations). OMP’s enterprise value as of the Emergence Date was determined using the market approach based on a volume weighted average price calculation for OMP’s outstanding limited partner units. The Company estimated the fair value of its retained interests as of the Emergence Date in Bobcat DevCo and Beartooth DevCo of 64.7% and 30%, respectively, using an income approach, which was based on the anticipated future cash flows associated with the respective DevCos and discounted using a weighted average cost of capital discount rate of 13%.

The midstream segment’s tangible assets primarily consisted of pipelines, natural gas processing plants, compressor stations, produced water gathering lines and disposal wells, tanks, other facilities and equipment and rights of way. The estimated fair value of these midstream assets was determined using a cost approach, based on current replacement costs of the assets less depreciation based on the estimated useful lives of the assets and ages of the assets. Economic and functional obsolescence were also considered and applied in the form of inutility and excess capital costs. The midstream segment’s identifiable intangible assets included third-party customer contracts and its interest in OMP GP. The Company determined the estimated fair value of customer contracts based on the excess earnings method of the income approach, which consists of estimating the incremental after-tax cash flows attributable to the intangible assets only. The Company estimated the fair value of its interest as of the Emergence Date in OMP GP using a combination of an income approach and market approach.

The excess reorganization value over the fair value of identified tangible and intangible assets was attributable to the midstream segment and recorded as goodwill, which was classified as held for sale on the Consolidated Balance Sheets as of December 31, 2021.

Although the Company believes the assumptions and estimates used to develop enterprise value and reorganization value are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. The assumptions used in estimating these values are inherently uncertain and require judgment. See below under “Fresh Start Adjustments” for additional information regarding assumptions used in the measurement of the Company’s various other significant assets and liabilities.

The following table reconciles the Company’s enterprise value to the estimated fair value of the Successor’s stockholders’ equity at the Emergence Date:

	November 19, 2020
	(In thousands)
Enterprise value	$	1,300,000
Plus: Cash(1)	5,615
Less: Fair value of Credit Facility(2)	(340,000)
Fair value of Oasis share of Successor stockholders’ equity(3)	965,615
Plus: Fair value of non-controlling interests	92,816
Fair value of total Successor stockholders’ equity	$	1,058,431

__________________ 

(1)Cash excludes $4.5 million of cash attributable to OMP and includes $1.4 million that was initially classified as restricted cash as of November 19, 2020 but subsequently released from escrow and returned to the Successor. A total of $10.4 million of restricted cash as of November 19, 2020 was used to pay professional fees and is not included in the table above.

(2)Enterprise value includes the value of the Company’s interests in OMP and OMP GP, which is net of debt under OMP’s senior secured revolving credit facility (the “OMP Credit Facility”), and as such, only the fair value of debt under the Credit Facility is subtracted in order to determine the value of the Successor’s stockholders’ equity.

(3)Reflects Successor equity issued in accordance with the Plan, including 20,000,000 shares of common stock and 1,621,622 Warrants.

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The following table reconciles the Company’s enterprise value to the estimated reorganization value as of the Emergence Date:

	November 19, 2020
	(In thousands)
Enterprise value	$	1,300,000
Plus: Fair value of OMP Credit Facility held for sale(1)	455,500
Plus: Fair value of non-controlling interests	92,816
Plus: Cash(2)	5,615
Plus: Current liabilities	266,796
Plus: Asset retirement obligations (non-current portion)	45,161
Plus: Other non-current liabilities	28,086
Plus: Current liabilities held for sale	38,796
Plus: Non-current liabilities held for sale	5,221
Reorganization value of Successor assets	$	2,237,991

_________________ 

(1)    Enterprise value includes the value of the Company’s interests in OMP and OMP GP, which is net of debt under the OMP Credit Facility, and as such, the fair value of the OMP Credit Facility is considered in the reconciliation of enterprise value to the reorganization value of the Successor’s assets.

(2)     Cash excludes $4.5 million of cash attributable to OMP and includes $1.4 million that was initially classified as restricted cash as of November 19, 2020 but subsequently released from escrow and returned to the Successor. A total of $10.4 million of restricted cash as of November 19, 2020 was used to pay professional fees and is not included in the table above.

Reorganization value and enterprise value were estimated using numerous projections and assumptions that are inherently subject to significant uncertainties and resolution of contingencies that are beyond the Company’s control. Accordingly, the estimates included in this report are not necessarily indicative of actual outcomes, and there can be no assurance that the estimates, projections or assumptions will be realized.

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Condensed Consolidated Balance Sheet

The adjustments set forth in the following fresh start Condensed Consolidated Balance Sheet reflect the effect of the transactions contemplated by the Plan (“Reorganization Adjustments”) and the fair value and other required adjustments as a result of applying fresh start accounting (“Fresh Start Adjustments”). The explanatory notes provide additional information with regard to the adjustments recorded, the methods used to determine fair values as well as significant assumptions.

	As of November 19, 2020
	Predecessor		Reorganization Adjustments			Fresh Start Adjustments			Successor
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	69,558	$	(65,317)	(a)	$	—		$	4,241
Restricted cash	—		11,800		(b)	—			11,800
Accounts receivable, net	234,413		—			—			234,413
Inventory	19,867		—			2,102		(q)	21,969
Prepaid expenses	8,085		(4,325)		(c)	—			3,760
Derivative instruments	728		—			—			728
Other current assets	104		—			—			104
Current assets held for sale	62,070		—			—			62,070
Total current assets	394,825		(57,842)			2,102			339,085
Property, plant and equipment
Oil and gas properties (successful efforts method)	9,301,065		—			(8,505,818)		(r)	795,247
Other property and equipment	105,410		—			(60,411)		(r)	44,999
Less: accumulated depreciation, depletion, amortization and impairment	(8,332,534)		—			8,332,534		(r)	—
Total property, plant and equipment, net	1,073,941		—			(233,695)			840,246
Derivative instruments	47		—			—			47
Long-term inventory	12,526		—			(292)		(q)	12,234
Operating right-of-use assets	11,509		—			(797)		(s)	10,712
Other assets	19,876		7,017		(d)	(8,139)		(t)	18,754
Non-current assets held for sale	921,031		—			95,882		(u)	1,016,913
Total assets	$	2,433,755	$	(50,825)		$	(144,939)		$	2,237,991
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities
Accounts payable	$	(291)	$	21,809	(e)	$	—		$	21,518
Revenues and production taxes payable	129,031		—			—			129,031
Accrued liabilities	46,561		57,470		(f)	1,885		(v)	105,916
Current maturities of long-term debt	360,640		(360,640)		(g)	—			—
Accrued interest payable	32,538		(32,496)		(h)	—			42
Derivative instruments	4,902		49		(i)	18		(w)	4,969
Advances from joint interest partners	170		2,555		(i)	—			2,725
Current operating lease liabilities	109		924		(i)	(76)		(s)	957
Other current liabilities	(102)		1,774		(i)	(34)		(s)	1,638
Current liabilities held for sale	66,810		(28,014)		(j)	—			38,796
Total current liabilities	640,368		(336,569)			1,793			305,592
Long-term debt	—		340,000		(k)	—			340,000
Deferred income taxes	1,097		9,746		(l)	(6,412)		(x)	4,431

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Asset retirement obligations	283		57,306		(i)	(12,428)		(v)	45,161
Derivative instruments	5,316		—			41		(w)	5,357
Operating lease liabilities	72		15,462		(i)	(740)		(s)	14,794
Other liabilities	80		3,456		(i)	(32)		(s)	3,504
Liabilities subject to compromise	2,051,294		(2,051,294)		(m)	—			—
Non-current liabilities held for sale	461,859		—			(1,138)		(y)	460,721
Total liabilities	3,160,369		(1,961,893)			(18,916)			1,179,560
Commitments and contingencies
Stockholders’ equity (deficit)
Predecessor common stock	3,233		(3,233)		(n)	—			—
Successor common stock	—		200		(o)	—			200
Predecessor treasury stock, at cost	(36,637)		36,637		(n)	—			—
Predecessor additional paid-in capital	3,131,446		(3,131,446)		(n)	—			—
Successor additional paid-in capital	—		965,415		(o)	—			965,415
Retained earnings (accumulated deficit)	(3,995,209)		4,034,401		(p)	(39,192)		(z)	—
Oasis share of stockholders’ equity (deficit)	(897,167)		1,901,974			(39,192)			965,615
Non-controlling interests	170,553		9,094		(p)	(86,831)		(z)	92,816
Total stockholders’ equity (deficit)	(726,614)		1,911,068			(126,023)			1,058,431
Total liabilities and stockholders’ equity (deficit)	$	2,433,755	$	(50,825)		$	(144,939)		$	2,237,991

Reorganization Adjustments

(a)The table below reflects the uses of cash on the Emergence Date from the implementation of the Plan:

	(In thousands)
Payment of Credit Facility principal(1)	$	20,640
Payment pursuant to the Mirada Settlement Agreement	20,000
Funding of the professional fees escrow account	11,800
Payment of Credit Facility fees	6,900
Payment of professional fees	3,766
Payment of DIP Credit Facility accrued interest and fees	1,375
Payment of Predecessor Credit Facility accrued interest and fees	836
Total uses of cash	$	65,317

_________________ 

(1)On the Emergence Date, the principal amounts under the DIP Credit Facility and the Predecessor Credit Facility of $300.0 million and $60.6 million, respectively, were converted to principal amounts of revolving loans under the Credit Facility in accordance with the Plan.

(b)Reflects the funding of an escrow account for professional fees associated with the Chapter 11 Cases, as required by the Plan.

(c)Reflects the remaining unamortized amount of prepaid cash incentives under the 2020 Incentive Compensation Program (as defined in Note 18—Equity-Based Compensation), which vested on the Emergence Date as a result of implementing the Plan, and was recorded in general and administrative expenses.

(d)Represents $7.3 million of fees related to the Credit Facility paid or accrued on the Emergence Date, which were capitalized as deferred financing costs and are being amortized to interest expense through the maturity date of July 1, 2027, offset by approximately $0.2 million of deferred financing costs related to the Predecessor Credit Facility, which were eliminated with a corresponding charge to reorganization items, net.

(e)Represents the reinstatement of $19.9 million of accounts payable included in liabilities subject to compromise to be satisfied in the ordinary course of business, coupled with a $1.9 million reclassification from accrued liabilities to accounts payable related to certain equity-based compensation awards classified as liabilities that vested on the Emergence Date.

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(f)Changes in accrued liabilities include the following:

	(In thousands)
Reinstatement of accrued expenses from liabilities subject to compromise	$	73,778
Accrual for professional fees incurred upon Emergence Date	4,603
Vesting of equity-based compensation awards classified as liabilities	1,142
Payment pursuant to Mirada Settlement Agreement	(20,000)
Reclassification of payable for vested liability awards to accounts payable	(1,913)
Payment of certain professional fees accrued prior to Emergence Date	(140)
Net impact to accrued liabilities	$	57,470

(g)Reflects the refinancing of the borrowings outstanding under the DIP Credit Facility and Predecessor Credit Facility of $300.0 million and $60.6 million, respectively, through the Credit Facility on the Emergence Date.

(h)Reflects the write-off of specified default interest of $30.3 million which was waived on the Emergence Date, and the payment of accrued interest for the DIP Credit Facility and Predecessor Credit Facility of $1.4 million and $0.8 million, respectively, on the Emergence Date.

(i)Reflects the reinstatement of obligations that were classified as liabilities subject to compromise.

(j)Reflects the write-off of specified default interest of $28.0 million related to the OMP Credit Facility that was waived on the Emergence Date.

(k)Reflects borrowings drawn under the Credit Facility on the Emergence Date, consisting of principal amounts that were converted from principal amounts under the DIP Credit Facility and the Predecessor Credit Facility of $300.0 million and $60.6 million, respectively, in accordance with the Plan, partially offset by a principal repayment amount of $20.6 million.

(l)Reflects an increase in the deferred tax liability recorded as a result of an ownership change under Section 382 of the Code.

(m)On the Emergence Date, liabilities subject to compromise were settled in accordance with the Plan as follows:

	(In thousands)
Predecessor Notes	$	1,825,757
Accrued interest on Predecessor Notes	50,337
Asset retirement obligations	57,306
Accounts payable and accrued liabilities	93,674
Other liabilities	24,220
Total liabilities subject to compromise of the Predecessor	2,051,294
Reinstatement of liabilities for general unsecured claims	(175,200)
Issuance of common stock to Predecessor Notes holders	(941,810)
Gain on settlement of liabilities subject to compromise	$	934,284

(n)Reflects the cancellation of the Predecessor’s accumulated deficit, common stock and treasury stock and changes in the Predecessor’s additional paid-in capital as follows:

	(In thousands)
Cancellation of accumulated deficit	$	(3,086,292)
Cancellation of common stock	3,233
Cancellation of treasury stock	(36,637)
Equity-based compensation for vesting of awards classified as equity	12,055
Issuance of Warrants to Predecessor common stockholders	(23,805)
Net impact to Predecessor additional paid-in capital	$	(3,131,446)

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(o)Reflects the distribution of Successor equity instruments in accordance with the Plan, including the issuance of 20,000,000 shares of common stock at a par value of $0.01 per share and 1,621,622 Warrants. The fair value of the Warrants was estimated at $14.68 per Warrant using a Black-Scholes model.

	(In thousands)
Common stock to Predecessor Notes holders	$	941,810
Warrants to Predecessor common stockholders	23,805
Total fair value of Successor equity	$	965,615

(p)The table below reflects the cumulative impact of the reorganization adjustments discussed above:

	(In thousands)
Gain on settlement of liabilities subject to compromise	$	934,284
Write-off of specified default interest	30,285
Gain on debt discharge	964,569
Professional fees incurred on the Emergence Date	(7,869)
Write-off of Predecessor Credit Facility deferred financing costs	(243)
Total reorganization items from reorganization adjustments	956,457
Equity-based compensation expense for vesting of awards on Emergence Date	(13,197)
Vesting of prepaid cash incentive compensation	(4,325)
Income from reorganization adjustments from continuing operations before income taxes	938,935
Income tax expense	(9,746)
Net income from reorganization adjustments from continuing operations	$	929,189
Gain on debt discharge from discontinued operations	28,014
Less: Net income from reorganization adjustments attributable to non-controlling interests	(9,094)
Net income from reorganization adjustments from discontinued operations	$	18,920
Net income from reorganization adjustments attributable to Oasis	$	948,109
Cancellation of accumulated deficit	3,086,292
Net impact to Predecessor retained earnings (accumulated deficit)	$	4,034,401

Fresh Start Adjustments

(q)Reflects fair value adjustments to the Company’s crude oil inventory, equipment inventory, and long-term linefill inventory of $1.6 million, $0.5 million and $(0.3) million, respectively, based on market prices as of the Emergence Date. Crude oil prices were estimated using NYMEX West Texas Intermediate crude oil index prices (“NYMEX WTI”) based on the estimated timing of liquidation and adjusted for quality and location differentials.

(r)Reflects adjustments to present the Company's proved oil and gas properties, unproved acreage and other property and equipment at their estimated fair values based on the valuation methodology discussed above as well as the elimination of accumulated depreciation, depletion, amortization and impairment. The following table summarizes the components of property, plant and equipment as of the Emergence Date:

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	Fair Value		Historical Book Value
	(In thousands)
Proved oil and gas properties	$	755,247	$	9,126,507
Less: Accumulated depreciation, depletion, amortization and impairment	—		(8,259,334)
Proved oil and gas properties, net	755,247		867,173
Unproved oil and gas properties	40,000		174,558
Other property and equipment	44,999		105,410
Less: Accumulated depreciation and impairment	—		(73,200)
Other property and equipment, net	44,999		32,210
Total property, plant and equipment, net	$	840,246	$	1,073,941

(s)Reflects adjustments required to present operating lease right-of-use assets and operating and finance lease liabilities at fair value. The Company's remaining lease obligations were remeasured using incremental borrowing rates applicable to the Company as of the Emergence Date and commensurate with the Successor's capital structure. The incremental borrowing rates ranged from 3.06% to 6.58% based on the tenor of the leases. Finance lease liabilities are included in other current liabilities and other liabilities on the Company’s Consolidated Balance Sheet.

(t)Reflects adjustments to eliminate certain deferred costs determined to have no fair value, including electrical infrastructure costs of $8.1 million and a $0.1 million adjustment to present finance lease right-of-use assets at fair value.

(u)Reflects the adjustments to non-current assets held for sale as follows:

	(In thousands)
Proved oil and gas properties	$	44,533
Other property and equipment	(312,657)
Accumulated depreciation and impairment	247,162
Goodwill	70,534
Interest in OMP GP	28,000
Customer contracts	15,000
Equipment inventory	705
Deferred financing costs related to the OMP Credit Facility	(1,515)
Non-current assets held for sale from discontinued operations, net	91,762
Non-current assets held for sale from continuing operations(1)	4,120
Total non-current assets held for sale, net	$	95,882

_________________ 

(1)Represents the adjustment to certain assets from continuing operations held for sale as of the Emergence Date for the sales price agreed upon with the buyer, less estimated costs to sell.

(v)Reflects the adjustment to present the Company's asset retirement obligations (“ARO”) at fair value using assumptions as of the Emergence Date, including an inflation factor of 2% and an estimated 30-year credit-adjusted risk-free rate of 8.5%.

(w)Reflects the fair value adjustment to the Company’s derivative instruments using the Company’s estimated credit-adjusted risk-free rate as of the Emergence Date of 5.12%.

(x)Reflects the adjustment to deferred income taxes to reflect the change in the financial reporting basis of assets as a result of the adoption of fresh start accounting.

(y)Reflects the adjustment to present ARO from discontinued operations at fair value.

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(z)The table below reflects the cumulative impact of the fresh start adjustments discussed above:

	(In thousands)
Loss on revaluation adjustments from continuing operations	$	(225,336)
Income tax benefit	6,412
Net loss from fresh start adjustments from continuing operations	$	(218,924)
Gain on revaluation adjustments from discontinued operations	$	92,901
Less: Net loss from fresh start adjustments attributable to non-controlling interests	86,831
Net gain from fresh start adjustments from discontinued operations	$	179,732
Net loss from fresh start adjustments attributable to Oasis	$	(39,192)

Reorganization Items, Net

Any expenses, gains and losses that were realized or incurred between the Petition Date and the Emergence Date and as a direct result of the Chapter 11 Cases and the implementation of the Plan were recorded in reorganization items, net in the Company’s Consolidated Statement of Operations for the period from January 1, 2020 through November 19, 2020 (Predecessor). The following table summarizes the components of reorganization items, net:

	(In thousands)
Continuing operations:
Gain on debt discharge	$	964,569
Loss on revaluation adjustments	(225,336)
Write-off of unamortized debt discount	(38,373)
Professional fees	(16,352)
Write-off of unamortized deferred financing costs	(12,739)
DIP Credit Facility fees	(5,853)
Total reorganization items from continuing operations, net	$	665,916
Discontinued operations:
Gain on debt discharge	$	28,014
Gain on revaluation adjustments	92,901
Total reorganization items from discontinued operations	$	120,915

4. Summary of Significant Accounting Policies

Basis of Presentation

The accompanying consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).

Fresh Start Accounting

Subsequent to the Petition Date, the Company applied ASC 852 in preparing its consolidated financial statements. At the Emergence Date, the Company adopted fresh start accounting in accordance with ASC 852, which resulted in a new basis of accounting and the Company becoming a new entity for financial reporting purposes. As a result of the adoption of fresh start accounting and the effects of the implementation of the Plan, the consolidated financial statements of the Successor are not comparable to the consolidated financial statements of the Predecessor. See Note 2—Emergence from Voluntary Reorganization under Chapter 11 and Note 3—Fresh Start Accounting for additional information.

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Business Segments

The Company has evaluated how it is organized and managed and has identified only one reportable business segment, which is the exploration and production of crude oil, NGLs and natural gas. The Company considers its gathering, processing and marketing functions as ancillary to its oil and gas producing activities. All of the Company’s operations and assets are located in the United States, and substantially all of its revenues are attributable to United States customers.

As of December 31, 2021, the Company had two business segments related to E&P and midstream operations. The Company’s midstream segment was classified as a discontinued operation in connection with the OMP Merger and is no longer presented as a separate reporting segment in accordance with ASC 280, Segment Reporting.

Use of Estimates

Preparation of the Company’s consolidated financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to (i) proved crude oil, NGL and natural gas reserves and related cash flow estimates, (ii) assignment of fair value and allocation of purchase price in connection with business combinations, including the determination of any resulting goodwill or bargain purchase, (iii) impairment tests of long-lived assets, (iv) estimates of future development, dismantlement and abandonment costs, (v) estimates relating to certain crude oil, NGL and natural gas revenues and expenses, (vi) income taxes, (vii) valuation of derivative instruments and (viii) estimates of expenses related to legal, environmental and other contingencies. Certain of these estimates require assumptions regarding future commodity prices, future costs and expenses and future production rates. Actual results could differ from those estimates.

Estimates of crude oil, NGL and natural gas reserves and their values, future production rates and future costs and expenses are inherently uncertain for numerous reasons, including many factors beyond the Company’s control. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, NGL and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, prevailing commodity prices, operating costs and other factors. These revisions may be material and could materially affect future depreciation, depletion and amortization (“DD&A”) expense, dismantlement and abandonment costs, and impairment expense.

Risks and Uncertainties

As a producer of crude oil, NGLs and natural gas, the Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for crude oil, NGLs and natural gas, which are dependent upon numerous factors beyond its control such as economic, political and regulatory developments and competition from other energy sources. The energy markets have historically been very volatile, and there can be no assurance that the prices for crude oil, NGLs or natural gas will not be subject to wide fluctuations in the future. A substantial or extended decline in prices for crude oil and, to a lesser extent, NGLs and natural gas, could have a material adverse effect on the Company’s financial position, results of operations, cash flows, the quantities of crude oil, NGLs and natural gas reserves that may be economically produced and the Company’s access to capital.

Cash and Cash Equivalents

The Company invests in certain money market funds, commercial paper and time deposits, all of which are stated at fair value or cost which approximates fair value due to the short-term maturity of these investments. The Company classifies all such investments with original maturity dates less than 90 days as cash equivalents. While the Company may maintain balances of cash and cash equivalents in excess of amounts that are federally insured by the Federal Deposit Insurance Corporation, the Company invests with financial institutions that it believes are creditworthy and has not experienced any material losses in such accounts.

The following table provides a reconciliation of cash and cash equivalents reported within the Consolidated Balance Sheets and Consolidated Statements of Cash Flows:

	December 31,
	2022		2021
	(In thousands)
Cash and cash equivalents	$	593,151	$	172,114
Cash and cash equivalents classified as held for sale	—		2,669
Total cash and cash equivalents	$	593,151	$	174,783

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Accounts Receivable

Accounts receivable are carried at cost on a gross basis, with no discounting, which approximates fair value due to their short-term maturities. The Company’s accounts receivable consist mainly of receivables from crude oil, NGL and natural gas purchasers and joint interest owners on properties the Company operates.

The Company regularly assesses the recoverability of all material trade and other receivables to determine their collectability and if an allowance for credit losses is warranted. The Company estimates credit losses and accrues a reserve on a receivable based on (i) historic loss experience for pools of receivable balances with similar characteristics, (ii) the length of time balances have been outstanding and (iii) the economic status of each counterparty. These loss estimates are then adjusted for current and expected future economic conditions, which may include an assessment of the probability of non-payment, financial distress or expected future commodity prices and the impact that any current or future conditions could have on a counterparty’s credit quality and liquidity. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, the Company’s crude oil, NGL and natural gas receivables are collected within two months.

Inventory

The Company’s inventory includes equipment and materials and crude oil inventory. Equipment and materials consist primarily of well equipment, tanks and tubular goods to be used in the Company’s exploration and production activities. Crude oil inventory includes crude oil in tanks and linefill. Linefill represents the minimum volume of product in a pipeline system that enables the system to operate and is generally not available to be withdrawn from the pipeline system until the expiration of the transportation contract. Crude oil and NGL linefill in third-party pipelines that is not expected to be withdrawn within one year is included in long-term inventory on the Company’s Consolidated Balance Sheets (see Note 6—Inventory).

Inventory, including long-term inventory, is stated at the lower of cost and net realizable value with cost determined on an average cost method. The Company assesses the carrying value of inventory and uses estimates and judgment when making any adjustments necessary to reduce the carrying value to net realizable value. Among the uncertainties that impact the Company’s estimates are the applicable quality and location differentials to include in the Company’s net realizable value analysis. Additionally, the Company estimates the upcoming liquidation timing of the inventory. Changes in assumptions made as to the timing of a sale can materially impact net realizable value.

Property, Plant and Equipment

Proved Oil and Gas Properties

Crude oil, NGL and natural gas exploration and development activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive. Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts. Estimated dismantlement and abandonment costs for oil, NGL and gas properties are capitalized at their estimated net present value.

The provision for depletion of oil and gas properties is calculated using the unit-of-production method. All capitalized well costs (including future abandonment costs, net of salvage value) and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and total proved reserves, respectively, related to the associated field. Natural gas is converted to barrel equivalents at the rate of six thousand cubic feet of natural gas to one barrel of crude oil.

Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated DD&A unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized.

The Company reviews its proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of its carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and gas properties by field and compares such undiscounted future cash flows to the carrying amount of the oil and gas properties in the applicable field to determine if the carrying amount is recoverable. The factors used to determine the undiscounted future cash flows are subject to management’s judgment and expertise and include, but are not limited to, future production volumes based upon estimates of proved reserves, future commodity prices, and estimates of operating and development costs. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, the Company’s estimated undiscounted future cash flows, the timing

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and pace of development and the discount rate commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Because of the uncertainty inherent in these factors, the Company cannot predict when or if future impairment charges for proved oil and gas properties will be recorded.

Unproved Oil and Gas Properties

Unproved properties consist of costs incurred to acquire unproved leases, or lease acquisition costs. Lease acquisition costs are capitalized until the leases expire or when the Company specifically identifies leases that will revert to the lessor, at which time the Company expenses the associated lease acquisition costs. The expensing of the lease acquisition costs is recorded as impairment in the Consolidated Statements of Operations. Lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis.

The Company assesses its unproved properties periodically for impairment on a prospect-by-prospect basis based on remaining lease terms, drilling results or future plans to develop acreage. The Company considers the following factors in its assessment of the impairment of unproved properties:

•the remaining amount of unexpired term under its leases;

•its ability to actively manage and prioritize its capital expenditures to drill leases and to make payments to extend leases that may be close to expiration;

•its ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development;

•its ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; and

•its evaluation of the continuing successful results from the development of properties by the Company or by other operators in areas adjacent to or near the Company’s unproved properties.

For sales of entire working interests in unproved properties, a gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property.

Capitalized Interest

The Company capitalizes a portion of its interest expense incurred on its outstanding debt. The amount capitalized is determined by multiplying the capitalization rate by the average amount of eligible accumulated capital expenditures and is limited to actual interest costs incurred during the period. The accumulated capital expenditures included in the capitalized interest calculation begin when the first costs are incurred and end when the asset is either placed into production or written off. For the years ended December 31, 2022 and 2021 (Successor), the Company capitalized interest costs of $4.6 million and $2.1 million, respectively. For the period from November 20, 2020 through December 31, 2020 (Successor) and the period from January 1, 2020 through November 19, 2020 (Predecessor), the Company capitalized interest costs of $0.1 million and $6.4 million, respectively. Capitalized interest costs are amortized over the life of the related assets.

Other Property and Equipment

Other property and equipment consists primarily of field office buildings, furniture, software, oilfield equipment and leasehold improvements and is recorded at cost and depreciated using the straight-line method based on expected lives of the individual assets (ranging from two years to 30 years) and net of estimated salvage values. The cost of assets disposed of and the associated accumulated DD&A are removed from the Company’s Consolidated Balance Sheets with any gain or loss realized upon the sale or disposal included in the Company’s Consolidated Statements of Operations.

Exploration Expenses

Exploration costs, including certain geological and geophysical expenses and the costs of carrying and retaining undeveloped acreage, are charged to expense as incurred.

Costs from drilling exploratory wells are initially capitalized but charged to expense if and when a well is determined to be unsuccessful. Determination is usually made on or shortly after drilling or completing the well, however, in certain situations a determination cannot be made when drilling is completed. The Company defers capitalized exploratory drilling costs for wells that have found a sufficient quantity of producible hydrocarbons but cannot be classified as proved because they are located in areas that require major capital expenditures or governmental or other regulatory approvals before production can begin. These costs continue to be deferred as wells-in-progress as long as development is underway, is firmly planned for in the near future or the necessary approvals are actively being sought.

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Net changes in capitalized exploratory well costs are reflected in the following table for the periods presented (in thousands):

	Successor						Predecessor
	Year Ended December 31,				Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020
	2022		2021
Beginning of period	$	1	$	—	$	—	$	—
Exploratory well cost additions (pending determination of proved reserves)	21		—		—		—
Exploratory well cost reclassifications (successful determination of proved reserves)	(2)		—		—		—
Exploratory well dry hole costs (unsuccessful in adding proved reserves)	—		—		—		—
Exploratory well cost reclassifications (canceled wells written off to predrill write-off)	(20)		1		—		—
End of period	$	—	$	1	$	—	$	—

As of December 31, 2022, the Company had no exploratory well costs that were capitalized for a period of greater than one year after the completion of drilling.

Business Combinations

The Company accounts for business combinations under the acquisition method of accounting. Accordingly, the Company recognizes amounts for identifiable assets acquired and liabilities assumed measured at the estimated acquisition date fair value. Transaction and integration costs associated with business combinations are expensed as incurred.

The Company makes various assumptions in estimating the fair value of the assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair value of proved and unproved oil and gas properties, which is measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include future production volumes based upon estimates of reserves prepared by the Company’s reserve engineers, future operating and development costs, future commodity prices (adjusted for basis differentials) and a market-based weighted average cost of capital discount rate. In addition, when appropriate, the Company reviews comparable transactions between market participants for the purchase and sale of oil and gas properties within the same region to measure fair value, which illustrates the amount a willing buyer and seller would enter into in exchange for such properties.

The Company records goodwill for any amount of the consideration transferred in excess of the estimated fair value of the net assets acquired and a bargain purchase gain for any amount of the estimated fair value of net assets acquired in excess of the consideration transferred. Deferred taxes are recorded for any difference between the acquisition date fair value and the tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. The Company may adjust the provisional amounts recorded in a business combination during the measurement period which extends for up to one year after the acquisition date.

The Merger was completed on July 1, 2022 and has been accounted for under the acquisition method of accounting in accordance with ASC 805. Oasis was treated as the acquirer for accounting purposes. Under the acquisition method of accounting, the assets and liabilities of Whiting have been recorded at their respective fair values as of the acquisition date on July 1, 2022. As provided under ASC 805, the purchase price allocation may be subject to change for up to one year after July 1, 2022. See Note 11—Acquisitions for additional information.

Assets Held for Sale

The Company occasionally markets assets for sale. At the end of each reporting period, the Company evaluates any assets being marketed to determine whether any should be reclassified as held for sale. The Company considers the following criteria to determine whether to report an asset as held for sale: management commits to a plan to sell; the asset is available for immediate sale; an active program to locate a buyer exists; the sale of the asset is probable and expected to be completed within one year; the asset is being actively marketed for sale; and it is unlikely that significant changes to the plan will be made. If each of these criteria is met, the property is reclassified as held for sale on the Company’s Consolidated Balance Sheets and measured at the lower of their carrying amount or estimated fair value less costs to sell. Fair values are estimated using accepted valuation techniques, such as a discounted cash flow model, valuations performed by third parties, earnings multiples, indicative bids or indicative market pricing, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ

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from the estimated fair values reflected in the consolidated financial statements. DD&A expense is not recorded on assets to be divested once they are classified as held for sale. The assets and liabilities of OMP were classified as held for sale in the Consolidated Balance Sheet as of December 31, 2021. See Note 12–Divestitures for additional information.

Discontinued Operations

The OMP Merger (defined in Note 12—Divestitures) represented a strategic shift for the Company and qualified for reporting as a discontinued operation in accordance with FASB ASC 205-20, Presentation of financial statements – Discontinued Operations (“ASC 205-20”). Accordingly, the results of operations of OMP were classified as discontinued operations in the Consolidated Statements of Operations for the years ended December 31, 2022 and 2021 (Successor), and the assets and liabilities of OMP were classified as held for sale in the Consolidated Balance Sheet as of December 31, 2021. Prior periods were recast so that the basis of presentation is consistent with that of the 2022 consolidated financial statements. The Consolidated Statements of Cash Flows were not required to be reclassified for discontinued operations for any period. See Note 13—Discontinued Operations for additional information.

Investment in Unconsolidated Affiliate

On February 1, 2022, the Company completed the OMP Merger (defined in Note 12—Divestitures) and received common units representing limited partner interests of Crestwood Equity Partners LP, a Delaware limited partnership (“Crestwood”). The Company elected to account for its investment in Crestwood using the fair value option under ASC 825-10, Financial Instruments. Under the fair value option, the Company measures the carrying amount of its investment in Crestwood at fair value each reporting period, with changes in fair value recorded to net gain from investment in unconsolidated affiliate on the Consolidated Statement of Operations. Cash distributions from Crestwood are recorded to net gain from investment in unconsolidated affiliate on the Consolidated Statement of Operations and distributions from investment in unconsolidated affiliate on the Consolidated Statement of Cash Flows. See Note 8—Fair Value Measurements, Note 12—Divestitures and Note 14—Investment in Unconsolidated Affiliate for additional information.

Deferred Financing Costs

The Company capitalizes costs incurred in connection with obtaining financing. These costs are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. The amortization expense is recorded as a component of interest expense in the Company’s Consolidated Statements of Operations. Deferred financing costs related to the Credit Facility are included in other assets on the Company’s Consolidated Balance Sheets, while deferred financing costs related to the Senior Notes (defined in Note 15—Long-Term Debt) are included as a reduction of long-term debt on the Company’s Consolidated Balance Sheets.

Asset Retirement Obligations

In accordance with the FASB’s authoritative guidance on ARO, the Company records the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred and can be reasonably estimated with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. For oil and gas properties and produced water disposal wells, this is the period in which the well is drilled or acquired. The ARO represents the estimated amount the Company will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable state laws. The liability is accreted to its present value each period, and the capitalized costs are amortized using the unit-of-production method. The accretion expense is recorded as a component of DD&A in the Company’s Consolidated Statements of Operations.

The Company determines the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. These assumptions represent Level 3 inputs, as further discussed in Note 8—Fair Value Measurements. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

Revenue Recognition

The Company recognizes revenue in accordance with FASB ASC 606, Revenue from Contracts with Customers (“ASC 606”). ASC 606 includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. Disclosures in accordance with ASC 606 have been provided in Note 5—Revenue Recognition.

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The unit of account in ASC 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a distinct good or service (or a bundle of goods or services) at a point in time or a series of distinct goods or services provided over a period of time. ASC 606 requires that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) the performance obligation is satisfied.

The Company’s revenues are predominantly derived from contracts for the sale of crude oil, NGLs and natural gas. Generally, for the crude oil, NGL and natural gas contracts: (i) each unit of commodity product is a separate performance obligation, as the Company’s promise is to sell multiple distinct units of commodity product at a point in time; (ii) the transaction price principally consists of variable consideration, which amount is determinable each month end based on the Company’s right to invoice at month end for the value of commodity product sold to the customer that month; and (iii) the transaction price is allocated to each performance obligation based on the commodity product’s standalone selling price and recognized as revenue at a point in time, which is typically when production is delivered and title or risk of loss transfers to the customer. The sales prices for crude oil, NGLs and natural gas are market-based and are adjusted for transportation and other related fees and deductions. Fees included in the contract that are incurred after the transfer of control to the customer are included as a reduction of the transaction price, while fees that are incurred prior to the transfer of control to the customer are classified as gathering, processing and transportation expenses in the Company’s Consolidated Statements of Operations. The sales of crude oil, NGL and natural gas as presented on the Company’s Consolidated Statements of Operations represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others. When selling crude oil, NGL and natural gas on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports the revenue on a net basis.

Substantially all of the Company’s crude oil and natural gas production is sold to purchasers under short-term (less than 12-month) contracts at market-based prices, and the Company’s NGL production is generally sold to purchasers under long-term (more than 12-month) contracts at market-based prices. The Company sells the majority of its production soon after it is produced at various locations, and, as a result, the Company maintains a minimum amount of product inventory in storage. For sales of commodities, the Company records revenue in the month that the production or purchased product is delivered to the purchaser. However, settlement statements and payments are typically not received for 20 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The Company uses knowledge of its properties, its properties’ historical performance, spot market prices and other factors as the basis for these estimates. The Company records the differences between estimates and the actual amounts received for product sales once payment is received from the purchaser. In certain cases, the Company is required to estimate these volumes during a reporting period and record any differences between the estimated volumes and actual volumes in the following reporting period. Differences between estimated and actual revenues have historically not been significant. Revenue recognized related to performance obligations satisfied in prior reporting periods was not material for the periods presented.

The Company’s purchased crude oil and natural gas sales are derived from the sale of crude oil and natural gas purchased from third parties. Revenues and expenses from these sales and purchases are recorded on a gross basis when the Company acts as a principal in these transactions by assuming control of the purchased crude oil or natural gas before it is transferred to the customer. In certain cases, the Company enters into sales and purchases with the same counterparty in contemplation of one another, and these transactions are recorded on a net basis in accordance with ASC 845, Nonmonetary Transactions.

Leases

The Company accounts for leases in accordance with ASC 842, Leases (“ASC 842”). In accordance with ASC 842, the Company determines whether an arrangement is a lease at its inception. The Company’s long-term operating and finance leases consist primarily of office space, vehicles and other property and equipment used in its operations. The operating lease right-of-use (“ROU”) asset also includes any lease incentives received in the recognition of the present value of future lease payments. The Company considers renewal and termination options in determining the lease term used to establish its ROU assets and lease liabilities to the extent the Company is reasonably certain to exercise the renewal or termination. The Company’s lease agreements do not contain any material residual value guarantees or material restrictive covenants. As most of the Company’s leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of future lease payments. The Company determines the incremental borrowing rate based upon the rate of interest that would have been paid on a collateralized basis over similar tenors to that of the leases.

The Company’s share of operating, variable and short-term lease costs are either capitalized and included in property, plant and equipment on the Company’s Consolidated Balance Sheets or are recognized in the Company’s Consolidated Statements of Operations in lease operating expenses and general and administrative expenses, as applicable. The finance lease costs for the

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amortization of ROU assets are included in depreciation, depletion and amortization and the interest on lease liabilities is included in interest expense, net of capitalized interest, on the Company’s Consolidated Statements of Operations.

The Company has elected practical expedients under ASC 842, including the practical expedient to not reassess under the new standard any prior conclusions about lease identification, lease classification and initial direct costs; the use-of hindsight practical expedient; the practical expedient to not reassess the prior accounting treatment for existing or expired land easements; and the practical expedient pertaining to combining lease and non-lease components for all asset classes. In addition, the Company elected not to apply the recognition requirements of ASC 842 to leases with terms of one year or less, and as such, recognition of lease payments for short-term leases are recognized in net income on a straight-line basis. See Note 21—Leases for additional information.

Fair Value Measurements

As defined in FASB ASC 820, Fair Value Measurement (“ASC 820”), fair value is 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). To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable.

ASC 820 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (“Level 1” measurements) and the lowest priority to unobservable inputs (“Level 3” measurements). The three levels of the fair value hierarchy are as follows:

Level 1 — Unadjusted quoted prices are available 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 — Pricing inputs, other than unadjusted quoted prices in active markets included in Level 1, are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3 — Pricing inputs are generally unobservable from objective sources, requiring internally developed valuation methodologies that result in management’s best estimate of fair value.

Concentrations of Market and Credit Risk

The future results of the Company’s operations will be affected by the market prices of crude oil, NGLs and natural gas. The availability of a ready market for crude oil, NGL and natural gas products in the future will depend on numerous factors beyond the Company’s control, including weather, imports, marketing of competitive fuels, proximity and capacity of crude oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of crude oil, NGLs and natural gas, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty. Commodity prices have been volatile in recent years and could be volatile in the future. A substantial or extended decline in the price of crude oil could have a material adverse effect on the Company’s financial position, cash flows and results of operations.

The Company’s receivables include amounts due from purchasers of its crude oil, NGL and natural gas production and amounts due from joint interest partners for their respective portions of operating expenses and development costs. While certain of these customers and joint interest partners are affected by periodic downturns in the economy in general or in their specific segment of the oil and gas industry, the Company believes that its level of credit-related losses due to such economic fluctuations has been and will continue to be immaterial to the Company’s results of operations over the long term. 

The Company manages market and counterparty credit risk. In the normal course of business, collateral is not required for financial instruments with credit risk. Financial instruments, which potentially subject the Company to credit risk, consist principally of cash balances and derivative financial instruments. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments. The Company attempts to limit the amount of credit exposure to any one financial institution or company. The Company believes the credit quality of its customers is generally high. In the normal course of business, letters of credit or parent guarantees are required for counterparties which management perceives to have a higher credit risk.

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Risk Management

The Company utilizes derivative financial instruments to manage risks related to changes in crude oil, NGL and natural gas prices. As of December 31, 2022, the Company utilized fixed-price swaps and collars to reduce the volatility of crude oil, NGL and natural gas prices on future expected production. In addition, at December 31, 2022, the Company had outstanding basis swaps to mitigate exposure to the price differential between the NYMEX Henry Hub natural gas index price (“NYMEX HH”) and the Northern Natural Gas Ventura (“NNG Ventura”) index price. See Note 9—Derivative Instruments for additional information.

The Company records all derivative instruments on the Consolidated Balance Sheets as either assets or liabilities measured at their estimated fair value. Derivative assets and liabilities arising from derivative contracts with the same counterparty are reported on a net basis, as all existing counterparty contracts provide for net settlement. The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. Gains and losses from valuation changes in commodity derivative instruments are reported in the other income (expense) section of the Company’s Consolidated Statements of Operations. The Company’s cash flow is only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from the counterparty. These cash settlements represent the cumulative gains and losses on the Company’s derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled. Cash settlements are reflected as investing activities in the Company’s Consolidated Statements of Cash Flows.

Derivative financial instruments that hedge the price of crude oil, NGL and natural gas are executed with major financial institutions that expose the Company to market and credit risks and which may, at times, be concentrated with certain counterparties or groups of counterparties. At December 31, 2022, the Company had derivatives in place with eleven counterparties, all of which are secured parties under the Credit Facility, which eliminates the need to post or receive collateral associated with its derivative positions. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk in the event of nonperformance by the counterparties are substantially smaller. The credit worthiness of the counterparties is subject to continual review. The Company believes the risk of nonperformance by its counterparties is low. Full performance is anticipated, and the Company has no past-due receivables from the counterparties to its commodity derivative contracts. The Company’s policy is to execute financial derivatives only with major, credit-worthy financial institutions.

The Company’s derivative contracts are documented with industry standard contracts known as a Schedule to the Master Agreement and International Swaps and Derivatives Association, Inc. Master Agreement (“ISDA”). Typical terms for the ISDAs include credit support requirements, cross default provisions, termination events and set-off provisions. The Company is not required to provide any credit support to its counterparties other than cross collateralization with the properties securing the Credit Facility. As of December 31, 2022, the Company was in compliance with these requirements.

Contingencies

Certain conditions may exist as of the date the Company’s consolidated financial statements are issued that may result in a loss to the Company, but which will only be resolved when one or more future events occur or fail to occur. The Company’s management, with input from legal counsel, assesses such contingent liabilities, and such assessment inherently involves judgment. In assessing loss contingencies related to legal proceedings that are pending against the Company or unasserted claims that may result in proceedings, the Company’s management, with input from legal counsel, evaluates 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.

If the assessment of a contingency indicates that it is probable that a loss has been incurred and the amount of liability can be estimated, then the estimated undiscounted liability is accrued in the Company’s consolidated financial statements. If the assessment indicates that a potentially material loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss if determinable and material, is disclosed. Actual results could vary from these estimates and judgments.

Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed. See Note 23—Commitments and Contingencies for additional information regarding the Company’s contingencies.

Environmental Costs

Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and which do not have future economic benefit, are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable, and the costs can be reasonably estimated.

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Equity-Based Compensation

The Company has the 2020 LTIP, which provides for the grant of incentive stock options, nonstatutory stock options, restricted stock, restricted stock units, stock appreciation rights, dividend equivalents, other stock-based awards, cash awards, performance awards or any combination of the foregoing. In connection with the Merger, the Company assumed the Whiting Petroleum Corporation 2020 Equity Incentive Plan (the “Whiting Equity Incentive Plan”), which provides for the grant of incentive stock options, nonstatutory stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units and annual incentive awards or any combination of the foregoing.

The Company determines the compensation expense for share-settled awards based on the grant date fair value, and such expense is recognized ratably over the requisite service period, which is generally the vesting period. The Company recognizes compensation expense using the straight-line attribution method for service-based awards with a graded vesting feature. Compensation expense for cash-settled awards is recognized over the requisite service period and is remeasured at the fair value of such awards at the end of each reporting period. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period. Equity awards that settle in shares of common stock are generally net settled by withholding shares of common stock to satisfy income tax withholding obligations due upon vesting.

The fair values of awards are determined based on the type of award and may utilize market prices on the date of grant (for service-based equity awards) or at the end of the reporting period (for liability-classified awards), Monte Carlo simulations or other acceptable valuation methodologies, as appropriate for the type of award. A Monte Carlo simulation model uses assumptions regarding random projections and must be repeated numerous times to achieve a probabilistic assessment. See Note 18—Equity-Based Compensation for additional information.

Any excess tax benefit arising from the Company’s equity-based compensation plans is recognized as a credit to income tax expense or benefit in the Company’s Consolidated Statements of Operations.

Treasury Stock

Treasury stock purchases are recorded at cost and represent shares of common stock repurchased under the Company’s share repurchase program.

Income Taxes

The Company’s provision for taxes includes both federal and state income taxes. The Company records its income taxes in accordance with ASC 740 which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

The Company applies significant judgment in evaluating its tax positions and estimating its provision for income taxes. During the ordinary course of business, there may be transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from the Company’s estimates, which could impact its financial position, results of operations and cash flows.

The Company also accounts for uncertainty in income taxes recognized in the financial statements in accordance with GAAP by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Authoritative guidance for accounting for uncertainty in income taxes requires that the Company recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. The Company did not have any uncertain tax positions outstanding and, as such, did not record a liability as of December 31, 2022 or 2021. All deferred tax assets and liabilities, along with any related valuation allowance, are classified as non-current on the Company’s Consolidated Balance Sheets.

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Recent Accounting Pronouncements

Reference rate reform. In March 2020, the FASB issued Accounting Standards Update 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 time to ease the potential burden in accounting for reference rate reform, including optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by reference rate reform if certain criteria are met. ASU 2020-04 applies only to contracts and hedging relationships that reference the London Interbank Offered Rate (“LIBOR”) or another reference rate expected to be discontinued due to reference rate reform. ASU 2020-04 is effective immediately and may be applied prospectively to contract modifications made and hedging relationships entered into or evaluated on or before December 31, 2022. On July 1, 2022, the Company entered into an amended and restated credit agreement to, among other things, provide for the replacement of LIBOR with the Secured Overnight Financing Rate (“SOFR”), an index supported by short-term Treasury repurchase agreements. The replacement of LIBOR with SOFR in the credit agreement did not have a material impact on the Company’s consolidated financial statements and related disclosures. See Note 15—Long-Term Debt for additional information.

5. Revenue Recognition

Revenues associated with contracts with customers were as follows for the periods presented (in thousands):

	Successor						Predecessor
	Year Ended December 31,				Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020
	2022		2021
Crude oil revenues	$	2,366,995	$	910,381	$	69,075	$	522,812
Purchased crude oil sales	511,020		247,252		6,861		181,320
NGL and natural gas revenues	609,301		289,875		17,070		78,698
Purchased NGL and natural gas sales	159,154		131,731		13,772		55,791
Other services revenues	324		687		215		6,836
Total revenues	$	3,646,794	$	1,579,926	$	106,993	$	845,457

The Company has elected practical expedients, pursuant to ASC 606, to exclude from the presentation of remaining performance obligations: (i) contracts with index-based pricing or variable volume attributes in which such variable consideration is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct service that forms part of a series of distinct services and (ii) contracts with an original expected duration of one year or less.

6. Inventory

The following table sets forth the Company’s inventory:

	December 31,
	2022		2021
	(In thousands)
Inventory
Equipment and materials	$	21,097	$	12,175
Crude oil inventory	33,314		16,781
Total inventory	$	54,411	$	28,956
Long-term inventory
Linefill in third-party pipelines	$	22,009	$	17,510
Long-term inventory	$	22,009	$	17,510
Total	$	76,420	$	46,466

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7. Additional Balance Sheet Information

Certain balance sheet amounts are comprised of the following:

	December 31,
	2022		2021
	(In thousands)
Accounts receivable, net
Trade accounts	$	623,254	$	309,756
Joint interest accounts	127,772		40,890
Other accounts	37,867		28,270
Total	788,893		378,916
Allowance for credit losses	(7,155)		(1,714)
Total accounts receivable, net	$	781,738	$	377,202
Revenues and production taxes payable
Royalties payable	$	368,574	$	147,932
Revenue suspense	203,388		103,693
Production taxes payable	36,002		18,681
Total revenue and production taxes payable	$	607,964	$	270,306
Accrued liabilities
Accrued oil and gas marketing	$	127,240	$	35,211
Accrued capital costs	76,747		33,085
Accrued lease operating expenses	73,714		29,478
Accrued general and administrative expenses	42,259		13,270
Current portion of asset retirement obligations	19,376		4,813
Accrued dividends	5,873		4,946
Other accrued liabilities	17,245		29,871
Total accrued liabilities	$	362,454	$	150,674

8. Fair Value Measurements

In accordance with the FASB’s authoritative guidance on fair value measurements, certain of the Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company’s financial instruments, including certain cash and cash equivalents, accounts receivable, accounts payable and other payables, are carried at cost, which approximates their respective fair market values due to their short-term maturities. The Company recognizes its non-financial assets and liabilities, such as ARO (see Note 16—Asset Retirement Obligations) and properties acquired in a business combination (see Note 11—Acquisitions) or upon impairment (see Note 10—Property, Plant and Equipment), at fair value on a non-recurring basis.

Financial Assets and Liabilities

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

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The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis:

	Fair value at December 31, 2022
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets:
Commodity derivative contracts (see Note 9)(1)	$	—	$	780	$	—	$	780
Contingent consideration (see Note 9)	—		60,920		—		60,920
Investment in unconsolidated affiliate (see Note 14)	130,575		—		—		130,575
Total assets	$	130,575	$	61,700	$	—	$	192,275
Liabilities:
Commodity derivative contracts (see Note 9)(2)	$	—	$	329,676	$	14,694	$	344,370
Total liabilities	$	—	$	329,676	$	14,694	$	344,370

	Fair value at December 31, 2021
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets:
Commodity derivative contracts (see Note 9)	$	—	$	55	$	—	$	55
Contingent consideration (see Note 9)	—		44,810		—		44,810
Total assets	$	—	$	44,865	$	—	$	44,865
Liabilities:
Commodity derivative contracts (see Note 9)(3)	$	—	$	204,729	$	—	$	204,729
Total liabilities	$	—	$	204,729	$	—	$	—

__________________     

(1)Cash deposit received in January 2023.

(2)Includes $24.5 million of commodity derivative liabilities paid in January 2023.

(3)Includes $27.5 million of commodity derivative liabilities paid in January 2022.

Commodity derivative contracts. The Company enters into commodity derivative contracts to manage risks related to changes in crude oil, NGL and natural gas prices. The Company’s swaps, collars and basis swaps are valued by a third-party preparer based on an income approach. The significant inputs used are commodity prices, volatility, discount rate and the contract terms of the derivative instruments. These assumptions are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace and are therefore designated as Level 2 within the fair value hierarchy. The Company compares the valuation performed by the third-party preparer to counterparty valuation statements to assess the reasonableness of its valuation. The determination of the fair value also incorporates a credit adjustment for non-performance risk, as required by GAAP. The Company calculates the credit adjustment for derivatives in a net asset position using current credit default swap values for each counterparty. The credit adjustment for derivatives in a net liability position is based on the market credit spread of the Company or similarly rated public issuers. The Company recorded an adjustment to reduce the fair value of its net derivative liability for these contracts by $3.5 million and $5.3 million at December 31, 2022 and December 31, 2021, respectively. See Note 9—Derivative Instruments for additional information.

Transportation derivative contracts. The Company acquired two buy/sell transportation contracts in the Merger that are derivative contracts for which the Company has not elected the “normal purchase normal sale” exclusion under FASB ASC 815, Derivatives and Hedging (“ASC 815”). The Company recorded these contracts at fair value in its Consolidated Balance Sheet at the completion of the Merger on July 1, 2022, with additional adjustments to fair value recorded as of December 31, 2022. These transportation derivative contracts were valued based on an income approach, which considers various assumptions, including quoted forward prices for commodities, market differentials for crude oil and either the Company’s or the counterparty’s nonperformance risk, as appropriate. The assumptions used in the valuation of these contracts include certain market differential metrics that are unobservable during the term of the contracts. Such unobservable inputs are significant to the contract valuation methodology, and the contracts’ fair values are therefore designated as Level 3 within the fair value hierarchy. See Note 9—Derivative Instruments for additional information.

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Contingent consideration. Pursuant to the purchase and sale agreement entered into in connection with the Company’s divestiture of E&P assets in the Permian Basin in 2021, the Company is entitled to receive up to three earn-out payments of $25.0 million per year for each of 2023, 2024 and 2025 if the average daily settlement price of NYMEX WTI exceeds $60 per barrel for such year (the “Permian Basin Sale Contingent Consideration”). If NYMEX WTI for calendar year 2023 or 2024 is less than $45 per barrel, then each calendar year thereafter the buyer’s obligation to make any remaining earn-out payments is terminated. The fair value of the Permian Basin Sale Contingent Consideration was determined by a third-party valuation specialist using a Monte Carlo simulation model and Ornstein-Uhlenbeck pricing process. The significant inputs include NYMEX WTI forward price curve, volatility, mean reversion rate and counterparty credit risk adjustment. The Company determined these were Level 2 fair value inputs that are substantially observable in active markets or can be derived from observable data. See Note 9—Derivative Instruments for additional information.

Investment in unconsolidated affiliate. The Company elected the fair value option to account for its investment in Crestwood. The fair value of the Company’s investment in Crestwood was determined using Level 1 inputs based upon the quoted market price of Crestwood’s publicly traded common units at December 31, 2022. As of the closing date of the OMP Merger (defined in Note 12—Divestitures) on February 1, 2022, fair value was determined using Level 2 inputs that included a discount to reflect a restriction on the Company's ability to sell the investment 90 days from the closing date. See Note 14—Investment in Unconsolidated Affiliate for additional information.

Non-Financial Assets and Liabilities

The fair value of the Company’s non-financial assets measured at fair value on a non-recurring basis is determined using valuation techniques that include Level 3 inputs.

Asset retirement obligations. The initial measurement of ARO at fair value is recorded in the period in which the liability is incurred. Fair value is determined by calculating the present value of estimated future cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding the timing and existence of a liability, as well as what constitutes adequate restoration when considering current regulatory requirements. Inherent in the fair value calculation are numerous assumptions and judgments, including the ultimate costs, inflation factors, credit-adjusted discount rates, timing of settlement and changes in the legal, environmental and regulatory environments.

Oil and gas and other properties. The Company records its properties at fair value when acquired in a business combination or upon impairment for proved oil and gas properties and other properties. Fair value is determined using a discounted cash flow model. The inputs used are subject to management’s judgment and expertise and include, but are not limited to, future production volumes based upon estimates of proved reserves, future commodity prices (adjusted for basis differentials), estimates of future operating and development costs and a risk-adjusted discount rate. These inputs are classified as Level 3 inputs, except the underlying commodity price assumptions are based on NYMEX forward strip prices (Level 1) and adjusted for price differentials.

Whiting merger. On July 1, 2022, the Company completed the Merger with Whiting. The assets acquired and liabilities assumed were recorded at fair value as of July 1, 2022. The fair value of Whiting’s oil and gas properties was calculated using an income approach based on the net discounted future cash flows from the producing properties and related assets. The inputs utilized in the valuation of the oil and gas properties and related assets acquired included mostly unobservable inputs which fall within Level 3 of the fair value hierarchy. Such inputs included future production volumes based upon estimates of reserves prepared by the Company’s reserve engineers, future operating and development costs, future commodity prices (adjusted for basis differentials) and a market-based weighted average cost of capital discount rate. The Company also recorded the asset retirement obligations assumed from Whiting at fair value. The inputs utilized in valuing the asset retirement obligations were mostly Level 3 unobservable inputs, including estimated economic lives of oil and natural gas wells as of July 1, 2022, anticipated future plugging and abandonment costs and an appropriate credit-adjusted risk-free rate to discount such costs. See Note 11—Acquisitions for additional information.

2021 Williston Basin Acquisition. The Company recognized the assets acquired in the 2021 Williston Basin Acquisition at cost on a relative fair value basis (see Note 11—Acquisitions). Fair value was determined using a discounted cash flow model. The underlying future commodity prices included in the Company’s estimated future cash flows of its proved oil and gas properties were determined using NYMEX forward strip prices as of October 21, 2021 for five years, escalating per year thereafter. The estimated future cash flows also included an inflation factor applied to the future operating and development costs after five years and every year thereafter. The estimated future cash flows were discounted at a market-based weighted average cost of capital discount rate.

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2020 Impairments. As a result of the significant decline in expected future commodity prices in the first quarter of 2020, the Company reviewed its properties for impairment as of March 31, 2020. The underlying future commodity prices included in the Company’s estimated future cash flows of its proved oil and gas properties were determined using NYMEX forward strip prices as of March 31, 2020 for five years, escalating per year thereafter. The estimated future cash flows also included an inflation factor applied to the future operating and development costs after five years and every year thereafter. The estimated future cash flows for the Company’s proved oil and gas properties and midstream assets were discounted at market-based weighted average cost of capital discount rates (see Note 10—Property, Plant and Equipment).

Fresh start accounting. On the Emergence Date, the Company emerged from the Chapter 11 Cases and adopted fresh start accounting. Upon the adoption of fresh start accounting, the Company’s assets and liabilities were recorded at their fair values as of November 19, 2020. The inputs utilized in the valuation of the Company’s most significant assets, its oil and gas properties and midstream long-lived assets, included mostly unobservable inputs which fall within Level 3 of the fair value hierarchy. Such inputs included estimates of future oil and gas production from the Company’s reserve reports, commodity prices based on forward strip price curves (adjusted for basis differentials) as of November 19, 2020, operating and development costs, expected future development plans for the properties, estimated replacement costs and weighted-average cost of capital discount rates. The Company also recorded its ARO at fair value as a result of fresh start accounting. The inputs utilized in valuing the ARO liability, which are discussed above, are mostly Level 3 unobservable inputs. Refer to Note 3—Fresh Start Accounting for a detailed discussion of the fair value approaches and significant inputs used by the Company.

9. Derivative Instruments

Commodity derivative contracts. The Company utilizes derivative financial instruments to manage risks related to changes in crude oil, NGL and natural gas prices. The Company’s crude oil contracts settle monthly based on the average NYMEX WTI. NGL contracts settle monthly based on the average Mont Belvieu propane or Conway propane index prices, as applicable. Natural gas contracts settle monthly based on the average NYMEX HH, while natural gas basis swaps settle monthly based on the average fixed differential between NYMEX HH and NNG Ventura.

The Company utilizes fixed-price swaps and collars to manage risks related to changes in crude oil, NGL and natural gas prices. Swaps are designed to establish a fixed price for the volumes under contract, while collars are designed to establish a minimum price (floor) and a maximum price (ceiling) for the volumes under contract. In addition, the Company utilizes basis swaps to manage commodity price locational risk. The Company’s basis swaps are designed to establish a fixed differential between NYMEX and the index price referenced in the contract. The Company may, from time to time, restructure existing derivative contracts or enter into new transactions to effectively modify the terms of current contracts in order to improve the pricing parameters in existing contracts.

2021 derivative contract modifications. During 2021, the Company entered into a series of transactions with derivative counterparties to modify the swap price of certain commodity derivative contracts. The Company modified the strike price of its 2022 crude oil swap contracts to $70.00 per barrel from a weighted average price of $40.89 per barrel and its 2023 crude oil swap contracts to $50.00 per barrel from a weighted average price of $43.68 per barrel. The commodity contracts modified included total notional volumes of 6,935 MBbl which settled in 2022 and 5,110 MBbl which settle in 2023. The Company paid $220.9 million to modify these commodity derivative contracts, which is reflected as a cash outflow from investing activities in the Consolidated Statement of Cash Flows for the year ended December 31, 2021 (Successor).

2020 liquidations. In June 2020, following a decrease in crude oil commodity prices and the related increase in the fair value of derivative assets, the Company liquidated a portion of its crude oil three-way costless collar contracts prior to the expiration of their contractual maturities, resulting in cash proceeds of $25.3 million, which are reflected as investing activities in the Company’s Consolidated Statement of Cash Flows during the Predecessor period from January 1, 2020 through November 19, 2020.

On September 15, 2020, the Company entered into a Direction Letter and Specified Swap Liquidation Agreement, which, among other things, amended its Predecessor Credit Facility in which upon occurrence of an event of default under the Predecessor Credit Facility, the Company was required to use commercially reasonable efforts with respect to each of its swap agreements, to either (x) terminate such swap agreement or (y) reset such swap agreement to current market terms in existence at the time of such reset in exchange for a lump-sum cash payment substantially similar to the payment it would have received in respect of a termination of such swap agreement (each a “Specified Swap Liquidation”). During the period from September 15, 2020 through the Petition Date of the Chapter 11 Cases, which constituted an event of default under the Predecessor Credit Facility, the Company liquidated its outstanding swap agreements and received cash proceeds of $37.4 million for Specified Swap Liquidations, which are reflected as investing activities in the Company’s Consolidated Statement of Cash Flows during the Predecessor period from January 1, 2020 through November 19, 2020.

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At December 31, 2022, the Company had the following outstanding commodity derivative instruments:

Commodity	Settlement Period	Derivative Instrument	Volumes		Weighted Average Prices
					Fixed-Price Swaps		Floor		Ceiling
Crude oil	2023	Two-way collar	7,823,500	Bbl			$	45.77	$	62.25
Crude oil	2023	Fixed-price swaps	6,282,000	Bbl	$	55.00
Natural gas	2023	Two-way collar	8,799,000	MMBtu			$	2.84	$	3.57
Natural gas	2023	Fixed-price swaps	1,800,000	MMBtu	$	4.25
Natural gas basis(1)	2023	Fixed-price swaps	5,920,000	MMbtu	$	0.39
NGL - Propane(2)	2023	Fixed-price swaps	7,560,000	Gallons	$	1.16

__________________ 

(1)    The weighted average price associated with the natural gas basis swaps shown in the tables above represents the average fixed differential to NYMEX HH as stated in the related contracts, which is compared to the NNG Ventura index price for each period. If NYMEX HH combined with the fixed differential as stated in each contract is higher than the NNG Ventura index price at any settlement date, the Company receives the difference. Conversely, if the NNG Ventura index price is higher than NYMEX HH combined with the fixed differential, the Company pays the difference.

(2)    Settled based on the Conway propane price.

Transportation derivative contracts. The Company acquired two contracts in the Merger that provide for the transportation of crude oil through a buy/sell structure from North Dakota to either Cushing, Oklahoma or Guernsey, Wyoming. The contracts require the purchase and sale of fixed volumes of crude oil through July 2024 as specified in the agreements. At July 1, 2022, upon the closing of the Merger, the Company determined that these contracts qualified as derivatives and did not elect the “normal purchase normal sale” exclusion. The fair value of these transportation derivative contracts as of July 1, 2022 was estimated to be a liability of $22.0 million. As of December 31, 2022 (Successor), the estimated fair value of these contracts was $14.7 million, of which $11.9 million was classified as a current derivative liability and $2.8 million was classified as a non-current derivative liability on the Consolidated Balance Sheet (see Note 8—Fair Value Measurements). The Company records the changes in fair value of these contracts to gathering, processing and transportation expenses on the Company’s Consolidated Statements of Operations. Settlements on these contracts are reflected as operating activities on the Company’s Consolidated Statements of Cash Flows and represent cash payments to the counterparties for transportation of crude oil or the net settlement of contract liabilities if the transportation was not utilized, as applicable.

Contingent consideration. The Company bifurcated the Permian Basin Sale Contingent Consideration from the host contract and accounted for it separately at fair value. The fair value of the Permian Basin Sale Contingent Consideration was estimated to be $32.9 million as of the close date of the Permian Basin Sale (defined in Note 12—Divestitures). The Permian Basin Sale Contingent Consideration is marked-to-market each reporting period, with changes in fair value recorded in the other income (expense) section of the Company’s Consolidated Statements of Operations as a net gain or loss on derivative instruments. As of December 31, 2022, the estimated fair value of the Permian Basin Sale Contingent Consideration was $60.9 million, of which $23.0 million was classified as a current derivative asset and $38.0 million was classified as a non-current derivative asset on the Consolidated Balance Sheet. See Note 8—Fair Value Measurements and Note 12—Divestitures for additional information.

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The following table summarizes the location and amounts of gains and losses from the Company’s derivative instruments recorded in the Company’s Consolidated Statements of Operations for the periods presented (in thousands):

		Successor						Predecessor
		Year Ended December 31,				Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020
Derivative Instrument	Statement of Operations Location	2022		2021
Commodity derivatives	Net gain (loss) on derivative instruments	$	(224,238)	$	(601,591)	$	(84,615)	$	233,565
Commodity derivatives (buy/sell transportation contracts)	Gathering, processing and transportation expenses(1)	7,331		—		—		—
Contingent consideration	Net gain (loss) on derivative instruments	16,110		11,950		—		—
Contingent consideration	Gain on sale of assets, net	—		32,860		—		—

__________________ 

(1)    The change in the fair value of the transportation derivative contracts was recorded as a gain in gathering, processing and transportation expenses for the year ended December 31, 2022 (Successor).

In accordance with the FASB’s authoritative guidance on disclosures about offsetting assets and liabilities, the Company is required to disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an agreement similar to a master netting agreement. The Company’s derivative instruments are presented as assets and liabilities on a net basis by counterparty, as all counterparty contracts provide for net settlement. No margin or collateral balances are deposited with counterparties, and as such, gross amounts are offset to determine the net amounts presented in the Company’s Consolidated Balance Sheets.

The following tables summarize the location and fair value of all outstanding commodity derivative instruments recorded in the Company’s Consolidated Balance Sheets:

		December 31, 2022
Derivative Instrument	Balance Sheet Location	Gross Recognized Assets/Liabilities		Gross Amount Offset		Net Recognized Fair Value Assets/Liabilities
		(In thousands)
Derivatives assets:
Commodity derivatives(1)	Derivative instruments — current assets	$	10,194	$	(9,414)	$	780
Contingent consideration	Derivative instruments — current assets	22,955		—		22,955
Contingent consideration	Derivative instruments — non-current assets	37,965		—		37,965
Total derivatives assets		$	71,114	$	(9,414)	$	61,700
Derivatives liabilities:
Commodity derivatives(2)	Derivative instruments — current liabilities	$	339,090	$	(9,414)	$	329,676
Commodity derivatives (buy/sell transportation contracts)	Derivative instruments — current liabilities	11,865		—		11,865
Commodity derivatives (buy/sell transportation contracts)	Derivative instruments — non-current liabilities	2,829		—		2,829
Total derivatives liabilities		$	353,784	$	(9,414)	$	344,370

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		December 31, 2021
Derivative Instrument	Balance Sheet Location	Gross Recognized Assets/Liabilities		Gross Amount Offset		Net Recognized Fair Value Assets/Liabilities
		(In thousands)
Derivatives assets:
Commodity derivatives	Derivative instruments — non-current assets	$	55	$	—	$	55
Contingent consideration	Derivative instruments — non-current assets	44,810		—		44,810
Total derivatives assets		$	44,865	$	—	$	44,865
Derivatives liabilities:
Commodity derivatives(3)	Derivative instruments — current liabilities	$	96,172	$	(6,725)	$	89,447
Commodity derivatives	Derivative instruments — non-current liabilities	133,655		(18,373)		115,282
Total derivatives liabilities		$	229,827	$	(25,098)	$	204,729

__________________ 

(1)Cash deposit received in January 2023.    

(2)Includes $24.5 million of commodity derivative liabilities paid in January 2023.

(3)Includes $27.5 million of commodity derivative liabilities paid in January 2022.

10. Property, Plant and Equipment

The following table sets forth the Company’s property, plant and equipment:

	December 31,
	2022		2021
	(In thousands)
Proved oil and gas properties	$	5,089,185	$	1,393,836
Less: Accumulated depletion	(461,175)		(107,277)
Proved oil and gas properties, net	4,628,010		1,286,559
Unproved oil and gas properties	30,936		2,001
Other property and equipment	72,973		48,981
Less: Accumulated depreciation and impairment	(20,576)		(17,109)
Other property and equipment, net	52,397		31,872
Total property, plant and equipment, net	$	4,711,343	$	1,320,432

Impairment

The Company reviews its property, plant and equipment for impairment by asset group whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. If events occur that indicate an asset group may not be recoverable, the asset group is tested for recoverability.

Proved oil and gas properties. The Company estimates the expected undiscounted future cash flows of its proved oil and gas properties by field and then compares such amount to the carrying amount of the proved oil and gas properties in the applicable field to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company adjusts the carrying amount of the proved oil and gas properties to fair value. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production volume estimates, the timing and pace of development, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows. These assumptions represent Level 3 inputs, as further discussed under Note 8—Fair Value Measurements.

In the first quarter of 2020, as a result of the significant decline in expected future commodity prices coupled with the Company’s liquidity concerns, and the resulting decrease in its estimated proved reserves, the Company reviewed its proved oil and gas properties in both the Williston Basin and the Permian Basin for impairment. During the period from January 1, 2020 through November 19, 2020 (Predecessor), the Company recorded impairment charges of $4.4 billion, including $3.8 billion related to the Williston Basin and $637.3 million related to the Permian Basin, to reduce the carrying values of its proved oil

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and gas properties to their estimated fair values. For the years ended December 31, 2022 and 2021 (Successor), and the period from November 20, 2020 through December 31, 2020 (Successor), the Company did not record impairment of proved oil and gas properties.

Unproved oil and gas properties. The Company assessed its unproved oil and gas properties for impairment and recorded impairment charges on its unproved oil and gas properties of $401.1 million for the period from January 1, 2020 through November 19, 2020 (Predecessor) as a result of expiring leases, periodic assessments and drilling plan uncertainty on certain acreage of unproved properties. For the years ended December 31, 2022 and 2021 (Successor), and the period from November 20, 2020 through December 31, 2020 (Successor), the Company did not record impairment of unproved oil and gas properties.

Other property and equipment. The Company reviews its other property and equipment for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Due to the significant decline in expected future commodity prices during the first quarter of 2020, the Company and other crude oil and natural gas producers changed their development plans, which resulted in lower forecasted throughput volumes for the Company’s midstream assets. As a result, the Company reviewed its midstream assets, grouped by commodity for each basin, for impairment as of March 31, 2020. The carrying amounts exceeded the estimated undiscounted future cash flows for certain midstream asset groups in the Williston Basin and the Permian Basin, and as a result, the Company recorded impairment charges of $108.3 million during the period from January 1, 2020 through November 19, 2020 (Predecessor) to reduce the carrying values of these midstream assets to their estimated fair values. In addition, during the period from January 1, 2020 through November 19, 2020 (Predecessor), the Company recorded impairment charges of $1.6 million on certain midstream equipment, including a right-of-use asset associated with mechanical refrigeration units leased at the Company’s natural gas processing complex in the Williston Basin. These amounts were recorded as a component of income from discontinued operations, net of income tax in the Company’s Consolidated Statements of Operations. As part of the OMP Merger, the company no longer owns these midstream assets as of February 1, 2022. No impairment charges were recorded on the Company’s other property and equipment for the years ended December 31, 2022 and 2021 (Successor), and for the period from November 20, 2020 through December 31, 2020 (Successor).

11. Acquisitions

2022 Acquisitions

Whiting merger. On July 1, 2022, the Company completed the Merger with Whiting and issued 22,671,871 shares of common stock and paid $245.4 million of cash to Whiting stockholders. Also on July 1, 2022 and pursuant to the Merger Agreement, the Company (i) assumed the outstanding Whiting Series A Warrants and Whiting Series B Warrants, (ii) assumed the outstanding Whiting equity-based compensation awards and (iii) paid cash to satisfy and discharge in full the Whiting credit facility.

Purchase price allocation. The Company recorded the assets acquired and liabilities assumed in the Merger at their estimated fair value on July 1, 2022 of $2.8 billion. The preliminary allocation of the fair value to the identifiable assets acquired and liabilities assumed resulted in no goodwill or bargain purchase gain being recognized. Determining the fair value of the assets and liabilities of Whiting requires judgement and certain assumptions to be made. See Note 8—Fair Value Measurements for additional information.

The tables below present the total consideration transferred and its preliminary allocation to the identifiable assets acquired and liabilities assumed as of the acquisition date on July 1, 2022.

	Purchase Price Consideration
	(In thousands)
Common stock issued to Whiting stockholders(1)	$	2,478,036
Cash paid to Whiting stockholders(1)	245,436
Replacement of Whiting Series A Warrants and Whiting Series B Warrants(2)	79,774
Replacement of Whiting equity-based compensation awards(3)	27,402
Cash paid to settle Whiting credit facility(4)	2,154
Total consideration transferred	$	2,832,802

__________________ 

(1)     The Company issued 22,671,871 shares of common stock and paid $245.4 million of cash to Whiting stockholders as Merger Consideration. Each holder of Whiting common stock received 0.5774 shares of common stock as Share Consideration and $6.25 of cash as Cash Consideration. The fair value of the common stock issued was based on the closing price of the Company’s common stock on July 1, 2022 of $109.30. See Note 19—Stockholder's Equity for additional information.

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(2)    The Company assumed (i) 4,833,455 Whiting Series A Warrants and (ii) 2,418,832 Whiting Series B Warrants. The replacement of Whiting Series A and B Warrants was based on the closing price of the warrants on July 1, 2022 of $11.25 and $10.50, respectively. See Note 19—Stockholder's Equity for additional information.

(3)    The Whiting equity awards were replaced with awards issued by Chord with similar terms and conditions as the original awards. The fair value of the replacement equity awards attributable to pre-Merger service was recorded as consideration transferred. See Note 18— Equity-Based Compensation for additional information.

(4)    On July 1, 2022, the Company fully satisfied all obligations under the Whiting credit facility and the Whiting credit facility was concurrently terminated. See Note 15—Long-Term Debt for additional information.

	Preliminary Purchase Price Allocation
	(In thousands)
Assets acquired:
Cash and cash equivalents	$	94,641
Accounts receivable, net	491,514
Inventory	35,256
Prepaid expenses	14,851
Other current assets	5,719
Current assets held for sale	16,074
Oil and gas properties	3,211,043
Other property and equipment	31,244
Long-term inventory	3,138
Operating right-of-use assets	15,752
Deferred tax assets	228,574
Other assets	3,346
Total assets acquired	$	4,151,152
Liabilities assumed:
Accounts payable	$	116,769
Revenues and production taxes payable	411,553
Accrued liabilities	215,218
Derivatives instruments (current liability)	471,693
Current operating lease liabilities	2,629
Other current liabilities	2,902
Current liabilities held for sale	9,410
Asset retirement obligations	57,197
Derivative instruments (long-term liability)	15,128
Operating lease liabilities	13,123
Other liabilities	2,728
Total liabilities assumed	$	1,318,350
Net assets acquired	$	2,832,802

Post-merger operating results. The results of operations of Whiting have been included in the Company’s consolidated financial statements since the closing of the Merger on July 1, 2022. The following table summarizes the total revenues and income from continuing operations before income taxes attributable to Whiting that were recorded in the Company’s Consolidated Statement of Operations for the period presented.

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	Year Ended December 31, 2022
	(In thousands)
Revenues	$	1,044,079
Income from continuing operations before income taxes	553,686

Other information. The Company recorded an assumed liability of $18.0 million in accrued liabilities on the Consolidated Balance Sheet as of July 1, 2022 related to success-based transaction costs that were incurred by Whiting prior to the consummation of the Merger. These amounts were paid during the year ended December 31, 2022.

In addition, the Company recorded an assumed liability of $55.0 million in accrued liabilities on the Consolidated Balance Sheet as of July 1, 2022 related to a loss contingency from a legal proceeding with Arguello Inc. and Freeport-McMoran Oil & Gas LLC that the Company determined was both probable and reasonably estimable under FASB ASC 450-20, Loss Contingencies as of the consummation of the Merger. See Note 23—Commitments and Contingencies for additional information.

Unaudited pro forma financial information. Summarized below are the consolidated results of operations for the periods presented, on an unaudited pro forma basis, as if the Merger had occurred on January 1, 2021. The information presented below reflects pro forma adjustments based on available information and certain assumptions that the Company believes are factual and supportable. The pro forma financial information includes certain non-recurring pro forma adjustments that were directly attributable to the Merger, including transaction costs incurred by the Company and Whiting. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the Merger occurred on the basis assumed above, nor is such information indicative of the Company’s expected future results. The pro forma results of operations do not include any future cost savings or other synergies that may result from the Merger or any estimated costs that have not yet been incurred by the Company to integrate the Whiting assets.

	Year Ended December 31,
	2022		2021
	(In thousands)
Revenues	$	4,759,706	$	3,113,407
Net income attributable to Chord	2,093,776		477,184
Net income attributable to Chord per share:
Basic	$	50.00	$	11.21
Diluted	47.88		10.93

2021 Acquisitions

Williston Basin Acquisition. On October 21, 2021, the Company completed the acquisition of approximately 95,000 net acres in the Williston Basin, effective April 1, 2021, from QEP Energy Company (“QEP”), a wholly-owned subsidiary of Diamondback Energy Inc., for total cash consideration of $585.8 million (the “2021 Williston Basin Acquisition”). The Company paid a deposit to QEP of $74.5 million on May 3, 2021 and $511.3 million at closing on October 21, 2021. The Company funded the 2021 Williston Basin Acquisition with cash on hand, including proceeds from the Permian Basin Sale (defined in Note 12—Divestitures) and the Senior Notes (defined in Note 15—Long-Term Debt).

The 2021 Williston Basin Acquisition was accounted for as an asset acquisition under ASC 805, since substantially all of the fair value of the assets acquired related to proved oil and gas properties. The Company applied the cost accumulation model under ASC 805, and as such, recognized the assets acquired in the 2021 Williston Basin Acquisition at cost, including transaction costs, on a relative fair value basis. There were no material deferred income taxes from the 2021 Williston Basin Acquisition, as the tax basis of the assets acquired, and liabilities assumed was equal to the book basis at closing.

No significant acquisitions occurred during the year ended December 31, 2020.

12. Divestitures

2022 Divestitures

OMP Merger. In October 2021, OMP, a master limited partnership formed by the Company to own, develop, operate and acquire midstream assets in North America, and OMP GP, the general partner of OMP, entered into an Agreement and Plan of Merger (the “OMP Merger Agreement”) with Crestwood and Crestwood Equity GP LLC, a Delaware limited liability company and the general partner of Crestwood (“Crestwood GP”). Pursuant to the OMP Merger Agreement, the Company agreed to

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merge OMP into a subsidiary of Crestwood and exchange all of its OMP common units and all of the limited liability company interests of OMP GP for $160.0 million in cash and 20,985,668 common units of Crestwood (the “OMP Merger”). The OMP Merger represented a strategic shift for the Company and qualified for reporting as a discontinued operation under ASC 205-20. See Note 13—Discontinued Operations for additional information.

On February 1, 2022, the Company completed the OMP Merger. Immediately prior to the completion of the OMP Merger, the Company owned approximately 70% of OMP’s issued and outstanding common units. The Company recorded a pre-tax gain on sale of assets of $518.9 million, which included (i) the cash consideration of $160.0 million, (ii) the fair value of the Company’s retained investment in Crestwood of $568.3 million; less (iii) the book value of the Company’s investment in OMP of $198.0 million and (iv) transaction costs of $11.4 million. The gain on sale of assets was reported within income (loss) from discontinued operations attributable to Chord, net of income tax on the Company’s Consolidated Statement of Operations for the year ended December 31, 2022.

OMP’s long-term debt consisted of the OMP Credit Facility and $450.0 million of 8.00% senior unsecured notes due April 1, 2029 (the “OMP Senior Notes”). As of December 31, 2021, there were $203.0 million of borrowings outstanding and $5.5 million of outstanding letters of credit issued under the OMP Credit Facility. OMP was in compliance with the financial covenants under the OMP Credit Facility as of December 31, 2021. As of December 31, 2021, OMP’s long-term debt was classified as held for sale on the Consolidated Balance Sheet. Upon consummation of the OMP Merger on February 1, 2022, Crestwood assumed the obligations pursuant to the OMP Senior Notes and paid in full all amounts due under the OMP Credit Facility.

The Company had previously entered into several long-term, fee-based contractual arrangements with OMP for midstream services, including (i) natural gas gathering, compression, processing and gas lift supply services; (ii) crude oil gathering, terminaling and transportation services; (iii) produced and flowback water gathering and disposal services; and (iv) freshwater distribution services. In connection with the closing of the OMP Merger, these contracts were assigned to Crestwood, and the Company has continuing cash outflows to Crestwood for these services. See Note 14—Investment in Unconsolidated Affiliate for additional information.

2021 Divestitures

Permian Basin Sale. On May 20, 2021, Oasis Petroleum Permian LLC (“OP Permian”), a wholly-owned subsidiary of the Company, entered into a purchase and sale agreement (the “Permian Basin Sale PSA”) with Percussion Petroleum Operating II, LLC (“Percussion”). Pursuant to the Permian Basin Sale PSA, OP Permian agreed to sell to Percussion its remaining upstream assets in the Texas region of the Permian Basin with an effective date of March 1, 2021, for an aggregate purchase price of $450.0 million (the “Permian Basin Sale”). The aggregate purchase price consisted of $375.0 million in cash at closing and up to three earn-out payments of $25.0 million per year for each of 2023, 2024 and 2025 (see Note 8—Fair Value Measurements for additional information). The Company completed the Permian Basin Sale on June 29, 2021 and received cash proceeds of $342.3 million. In addition, the Company divested certain wellbore interests in the Texas region of the Permian Basin to separate buyers in the second quarter of 2021 and received cash proceeds of $30.0 million.

Well services. On March 22, 2021, the Company completed the sale of certain well services equipment and inventory in connection with its 2020 exit from the well services business for total consideration of $5.5 million, comprised of cash proceeds of $2.6 million and a $2.9 million promissory note. As of December 31, 2022, the remaining principal balance on the promissory note was immaterial.

Midstream Simplification. On March 30, 2021, the Company contributed to OMP its remaining 64.7% limited liability company interest in Bobcat DevCo LLC and 30.0% limited liability company interest in Beartooth DevCo LLC, as well as eliminated OMP’s incentive distribution rights, in exchange for a cash distribution of $231.5 million and 12,949,644 common units in OMP (the “Midstream Simplification”). The Midstream Simplification was accounted for as a transaction between entities under common control.

2020 Divestitures

Other. The Predecessor sold certain oil and gas properties through various transactions and recognized a net gain on sale of properties of $11.1 million during the period from January 1, 2020 through November 19, 2020 (Predecessor).

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13. Discontinued Operations

The OMP Merger represented a strategic shift for the Company and qualified for reporting as a discontinued operation in accordance with ASC 205-20. Accordingly, the results of operations of OMP were classified as discontinued operations in the Consolidated Statements of Operations for the years ended December 31, 2022 and 2021 (Successor), and the assets and liabilities of OMP were classified as held for sale in the Consolidated Balance Sheet as of December 31, 2021. Prior periods were recast so that the basis of presentation is consistent with that of the 2022 consolidated financial statements.

The Company has continuing involvement with Crestwood following the completion of the OMP Merger for midstream services pursuant to contractual arrangements between the Company and OMP that were assigned to Crestwood at closing. These contracts include “evergreen” provisions that provide for renewal on a periodic basis if not terminated by either party. The Company depends on Crestwood as a core provider of midstream services to support its production and marketing activities and expects to have continuing involvement with Crestwood for these services for the foreseeable future. Intercompany transactions between the Company and OMP have historically been eliminated in consolidation within lease operating expenses and gathering, processing and transportation expenses for operated properties and within oil and gas revenues for non-operated properties. In addition, the intercompany purchases and sales of residue gas and NGLs between the Company and OMP, which was historically eliminated in consolidation, were reclassified to purchased oil and gas expenses and purchased oil and gas sales, respectively.

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Consolidated Statements of Operations

The results of operations reported as discontinued operations in connection with the OMP Merger were as follows for the periods presented (in thousands):

	Successor						Predecessor
	Year Ended December 31,				Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020
	2022		2021
Revenues
Oil and gas revenues	$	—	$	1,013	$	297	$	2,075
Purchased oil and gas sales(1)	(13,364)		(131,369)		(13,406)		(50,744)
Midstream revenues	23,271		254,228		26,031		166,631
Total revenues	9,907		123,872		12,922		117,962
Operating expenses
Lease operating expenses(1)	(4,535)		(62,142)		(4,676)		(42,034)
Midstream expenses	13,224		122,040		10,572		42,987
Gathering, processing and transportation expenses (1)	(3,555)		(49,795)		(4,074)		(31,988)
Purchased oil and gas expenses(1)	(12,506)		(125,709)		(12,921)		(43,163)
Depreciation, depletion and amortization	—		31,868		2,305		20,113
Impairment	—		2		—		111,613
General and administrative expenses(1)	3,314		4,193		(579)		594
Total operating expenses	(4,058)		(79,543)		(9,373)		58,122
Gain on sale of assets	518,900		—		—		—
Operating income	532,865		203,415		22,295		59,840
Other income (expense)
Interest expense, net of capitalized interest	(3,685)		(36,945)		(1,148)		(39,648)
Reorganization items, net			—		—		120,915
Other income (expense)	(93)		(115)		(1)		136
Total other income (expense), net	(3,778)		(37,060)		(1,149)		81,403
Income from discontinued operations before income taxes	529,087		166,355		21,146		141,243
Income tax expense(2)	(101,080)		(17)		—		—
Income from discontinued operations, net of income tax	428,007		166,338		21,146		141,243
Net income (loss) attributable to non-controlling interests	2,311		35,696		3,950		(84,283)
Income from discontinued operations attributable to Chord, net of income tax	$	425,696	$	130,642	$	17,196	$	225,526

__________________ 

(1)Includes discontinued intercompany eliminations.

(2)The Company applied the intraperiod tax allocation rules in accordance with FASB ASC 740-20, Intraperiod Tax Allocation (“ASC 740-20”) to determine the allocation of tax expense between continuing operations and discontinued operations. ASC 740-20 generally requires the allocation of tax expense to be based on a comparative calculation of tax expense with and without income from discontinued operations. During the year ended December 31, 2022, the Company released a portion of its valuation allowance (see Note 17—Income Taxes for additional information) and allocated the majority of the income tax benefit associated with this valuation allowance release to continuing operations. The total tax expense associated with the OMP Merger was partially offset by the release of the Company’s valuation allowance allocated to discontinued operations, resulting in a tax expense of $101.1 million attributable to discontinued operations during the year ended December 31, 2022.

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Consolidated Balance Sheets

The carrying amounts of the major classes of assets and liabilities related to the OMP Merger are as follows for the period presented:

	December 31, 2021
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	2,669
Accounts receivable, net	6,509
Inventory	8,541
Prepaid expenses	456
Total current assets of discontinued operations	18,175
Property, plant and equipment
Oil and gas properties (successful efforts method)(1)	(3,207)
Other property and equipment	933,667
Less: accumulated depreciation, depletion and amortization	(32,102)
Total property, plant and equipment, net	898,358
Operating right-of-use assets	671
Intangible assets	40,277
Goodwill	70,534
Other assets	1,303
Total non-current assets of discontinued operations	1,011,143
Total assets of discontinued operations	$	1,029,318
LIABILITIES
Current liabilities
Accounts payable	$	43
Revenues and production taxes payable	1,635
Accrued liabilities	36,183
Accrued interest payable	9,296
Current operating lease liabilities	733
Other current liabilities	564
Total current liabilities of discontinued operations	48,454
Long-term debt	644,078
Asset retirement obligations	904
Other liabilities	6,217
Total non-current liabilities of discontinued operations	651,199
Total liabilities of discontinued operations	$	699,653

_______________________

(1)Includes discontinued intercompany eliminations.    

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Consolidated Statements of Cash Flows

There was no depreciation, depletion and amortization contained in “Cash flows from operating activities” from discontinued operations for the year ended December 31, 2022 (Successor). DD&A contained in “Cash flows from operating activities” from discontinued operations was $31.9 million for the year ended December 31, 2021 (Successor), $2.3 million for the period from November 20, 2020 through December 31, 2020 (Successor) and $20.1 million for the period from January 1, 2020 through November 19, 2020 (Predecessor). Capital expenditures contained in “Cash flows used in investing activities” that were attributable to discontinued operations were $6.1 million for the year ended December 31, 2022 (Successor), $38.5 million for the year ended December 31, 2021 (Successor), $2.5 million for the period from November 20, 2020 through December 31, 2020 (Successor) and $54.8 million for the period from January 1, 2020 through November 19, 2020 (Predecessor). There were no significant non-cash activities from discontinued operations for the periods presented.

14. Investment in Unconsolidated Affiliate

On February 1, 2022, the Company completed the OMP Merger and received 20,985,668 Crestwood common units. On September 12, 2022, the Company sold an aggregate of 16,000,000 common units in separate transactions and received net proceeds of $428.2 million. As of December 31, 2022, the Company owned 4,985,668 common units of Crestwood, representing less than 5% of Crestwood’s issued and outstanding common units. The carrying amount of the Company’s investment in Crestwood is recorded to investment in unconsolidated affiliate on the Consolidated Balance Sheet. The fair value of the Company’s investment in Crestwood was $130.6 million as of December 31, 2022.

During the year ended December 31, 2022, the Company recorded an unrealized loss for the change in the fair value of its investment in Crestwood of $52.5 million, a realized gain of $43.0 million for the sale of 16,000,000 common units and a realized gain of $43.9 million for cash distributions from Crestwood for the Company’s ownership of common units.

The Company initially appointed two directors to the Board of Directors of Crestwood GP pursuant to a director nomination agreement executed in connection with the consummation of the OMP Merger. On September 15, 2022, in connection with the completion of the sale of Crestwood common units and pursuant to the terms of the previously executed director nomination agreement, both directors resigned from the Board of Directors of Crestwood GP. As a result of the Company’s sale of Crestwood common units and the subsequent resignation of two directors from the Board of Directors of Crestwood GP, the Company does not have the ability to exercise significant influence over Crestwood as of December 31, 2022.

Related Party Transactions

On September 12, 2022, the Company sold an aggregate of 16,000,000 common units of Crestwood, which reduced its ownership of Crestwood’s issued and outstanding common units below 5%. As such, Crestwood is no longer considered a related party as of December 31, 2022. Prior to the sale of 16,000,000 common units of Crestwood, the Company owned greater than 5% of Crestwood’s issued and outstanding common units and therefore Crestwood was considered a related party. For the year ended December 31, 2022, related party transactions with Crestwood totaled $15.7 million of revenues, $69.5 million of lease operating expenses and $56.6 million of gathering, processing and transportation expenses.

15. Long-Term Debt

The Company’s long-term debt consists of the following:

	December 31,
	2022		2021
	(In thousands)
Senior secured revolving line of credit	$	—	$	—
Senior unsecured notes	400,000		400,000
Less: unamortized deferred financing costs	(5,791)		(7,476)
Total long-term debt, net	$	394,209	$	392,524

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Senior secured revolving line of credit. The Company has the Credit Facility with a $2.75 billion borrowing base and $1.0 billion of elected commitments that matures on July 1, 2027. At December 31, 2022, the Company had no borrowings outstanding and $6.4 million of outstanding letters of credit issued under the Credit Facility, resulting in an unused borrowing capacity of $993.6 million. At December 31, 2021, the Company had no borrowings outstanding and $2.4 million of outstanding letters of credit issued under the Credit Facility. For the years ended December 31, 2022 and 2021, the weighted average interest rate incurred on borrowings under the Credit Facility was 4.6% and 4.2%, respectively. The Company was in compliance with the financial covenants under the Credit Facility at December 31, 2022.

In connection with the consummation of the Merger on July 1, 2022, the Company entered into the Amended and Restated Credit Agreement to, among other things (i) increase the aggregate maximum credit amount to $3.0 billion, (ii) increase the borrowing base to $2.0 billion, (iii) increase the aggregate amount of elected commitments to $800.0 million, (iv) extend the maturity date to July 1, 2027, (v) reduce the margin on outstanding borrowings by 125 basis points and (vi) increase the consolidated total leverage ratio financial covenant to 3.50x. Borrowings are subject to varying rates of interest based on (i) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the borrowing base and (ii) whether the loan is a Term SOFR Loan or an ABR Loan (each as defined in the Credit Facility). The Company incurs interest on outstanding Term SOFR Loans or ABR Loans at their respective interest rate plus the margin shown in the table below plus a 0.1% credit spread adjustment applicable to Term SOFR Loans. In addition, the unused borrowing base is subject to a commitment fee as shown in the table below:

Total Commitment Utilization Percentage	ABR Loans		SOFR Loans		Commitment Fee
Less than 25%	0.75	%	1.75	%	0.375	%
Greater than or equal to 25% but less than 50%	1.00	%	2.00	%	0.375	%
Greater than or equal to 50% but less than 75%	1.25	%	2.25	%	0.500	%
Greater than or equal to 75% but less than 90%	1.50	%	2.50	%	0.500	%
Greater than or equal to 90%	1.75	%	2.75	%	0.500	%

The Credit Facility is restricted to a borrowing base, which is reserve-based and subject to semi-annual redeterminations on April 1 and October 1 of each year, with one interim redetermination available to each of the Company and the administrative agent between scheduled redeterminations during any 12-month period.

The Company completed two amendments to the Amended and Restated Credit Agreement during 2022, as follows: (i) on August 8, 2022, the Company entered into the First Amendment to the Amended and Restated Credit Agreement to provide additional flexibility for SOFR borrowings; and (ii) on October 31, 2022, the Company completed its semi-annual borrowing base redetermination and entered into the Second Amendment to Amended and Restated Credit Agreement to increase the aggregate amount of elected commitments to $1.0 billion and increase the borrowing base to $2.75 billion. The next scheduled redetermination is expected to occur in or around April 2023.

A portion of the Credit Facility, in an aggregate amount not to exceed $100.0 million, may be used for the issuance of letters of credit. Additionally, the Credit Facility provides the ability for the Company to request swingline loans subject to a swingline loans sublimit of $50.0 million.

Borrowings under the Credit Facility are collateralized by perfected first priority liens and security interests on substantially all of the assets of Chord, as parent, OPNA, as borrower, and certain of the Company’s subsidiaries, as guarantors, including mortgage liens on oil and gas properties having at least 85% of the reserve value as determined by reserve reports.

A loan may be repaid at any time before the scheduled maturity of the Credit Facility upon the Company providing advance notification to the lenders.

The Credit Facility contains customary affirmative and negative covenants, including, among other things, as to compliance with laws (including environmental laws and anti-corruption laws), delivery of quarterly and annual financial statements, conduct of business, maintenance of property, maintenance of insurance, restrictions on the incurrence of liens, indebtedness, investments, asset dispositions, fundamental changes, restricted payments, transactions with affiliates, and other customary covenants.

The financial covenants in the Credit Facility include:

•a requirement that the Company maintain a Ratio of Total Net Debt to EBITDAX (as defined in the Credit Facility, the “Leverage Ratio”) of less than 3.50 to 1.00 as of the last day of any fiscal quarter; and

•a requirement that the Company maintain a Current Ratio (as defined in the Credit Facility) of no less than 1.0 to 1.0 as of the last day of any fiscal quarter.

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The Credit Facility contains customary events of default, as well as cross-default provisions with other indebtedness of OPNA and the restricted subsidiaries under the Credit Facility. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Credit Facility to be immediately due and payable.

Senior unsecured notes. At December 31, 2022, the Company had $400.0 million of 6.375% senior unsecured notes outstanding due June 1, 2026 (the “Senior Notes”). The Senior Notes were issued in a private placement on June 9, 2021 at par and resulted in net proceeds of $391.6 million, after deducting the underwriters’ discounts, commissions and other expenses. The Company recorded deferred financing costs of $8.4 million, which are being amortized over the term of the Senior Notes. The proceeds were used to fund a portion of the 2021 Williston Basin Acquisition consideration. See Note 11—Acquisitions for additional information.

Interest on the Senior Notes is payable semi-annually on June 1 and December 1 of each year. The Senior Notes are guaranteed on a senior unsecured basis by the Company, along with its wholly-owned subsidiaries (the “Guarantors”). These guarantees are full and unconditional and joint and several among the Guarantors, subject to certain customary release provisions. The indentures governing the Senior Notes contain customary events of default. In addition, the indenture governing the Senior Notes contains cross-default provisions with other indebtedness of the Company and its restricted subsidiaries.

The indentures governing the Senior Notes restrict the Company’s ability and the ability of certain of its subsidiaries to, among other things: (i) make investments, (ii) incur additional indebtedness or issue preferred stock, (iii) create liens, (iv) sell assets, (v) enter into agreements that restrict dividends or other payments by restricted subsidiaries, (vi) consolidate, merge or transfer all or substantially all of the Company’s assets with another company, (vii) enter into transactions with affiliates, (viii) pay dividends or make other distributions on capital stock or prepay subordinated indebtedness and (ix) create unrestricted subsidiaries. These covenants are subject to a number of important exceptions and qualifications. If at any time when the Senior Notes are rated investment grade by two out of the three rating agencies and no default (as defined in the indentures) has occurred and is continuing, many of such covenants will terminate and the Company will cease to be subject to such covenants. The Company was in compliance with the terms of the indentures for the Senior Notes as of December 31, 2022.

The fair value of the Senior Notes, which are publicly traded and represent a Level 1 fair value measurement, was $389.6 million and $419.0 million at December 31, 2022 and December 31, 2021, respectively.

Whiting credit facility. Whiting had a reserves-based credit facility with a syndicate of banks. Upon consummation of the Merger on July 1, 2022, the Whiting credit facility was terminated, and the Company paid the remaining outstanding accrued interest and other fees of approximately $2.2 million to satisfy and discharge in full all such outstanding obligations that were owed under the Whiting credit facility.

Bridge facility. On May 3, 2021, the Company entered into a commitment letter to provide for a senior secured second lien facility and incurred a fee of $7.8 million, which was recorded to interest expense on the Company’s Consolidated Statement of Operations for the year ended December 31, 2021 (Successor). The senior secured second lien facility was terminated prior to being drawn.

16. Asset Retirement Obligations

The following table reflects the changes in the Company’s ARO:

	Year Ended December 31,
	2022		2021
	(In thousands)
Asset retirement obligation — beginning of period	$	62,416	$	47,763
Liabilities incurred during period	852		729
Liabilities incurred through acquisitions	87,265		14,850
Liabilities settled during period	(4,532)		(5,193)
Liabilities settled through divestitures	(8,535)		—
Accretion expense during period	7,613		4,068
Revisions to estimates	20,326		199
Asset retirement obligation — end of period	$	165,405	$	62,416

At December 31, 2022 and 2021, the current portion of the total ARO balance was approximately $19.4 million and $4.8 million, respectively, and is included in accrued liabilities on the Company’s Consolidated Balance Sheets.

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17. Income Taxes

The Company’s income tax benefit from continuing operations consists of the following (in thousands):

	Successor						Predecessor
	Year Ended December 31,				Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020
	2022		2021
Current:
Federal	$	7,127	$	—	$	—	$	(36)
State	883		4		—		—
Total current tax expense (benefit)	8,010		4		—		(36)
Deferred:
Federal	(46,767)		(977)		(2,918)		(221,277)
State	(8,127)		—		(529)		(41,649)
Total deferred tax benefit	(54,894)		(977)		(3,447)		(262,926)
Total income tax benefit	$	(46,884)	$	(973)	$	(3,447)	$	(262,962)

The reconciliation of income taxes from continuing operations calculated at the U.S. federal tax statutory rate to the Company’s effective tax rate is set forth below: 

	Successor												Predecessor
	Year Ended December 31,								Period from November 20, 2020 through December 31, 2020				Period from January 1, 2020 through November 19, 2020
	2022				2021
	(%)		(In thousands)		(%)		(In thousands)		(%)		(In thousands)		(%)		(In thousands)
U.S. federal tax statutory rate	21.0	%	$	291,068	21.0	%	$	39,477	21.0	%	$	(14,817)	21.0	%	$	(867,051)
State income taxes, net of federal income tax benefit	2.6	%	36,156		3.0	%	5,679		2.6	%	(1,817)		2.4	%	(98,946)
Non-deductible executive compensation	0.7	%	9,204		1.3	%	2,510		—	%	—		—	%	1,372
Transaction costs	0.3	%	3,855		—	%	—		—	%	—		—	%	—
Change in valuation allowance	(27.2)	%	(377,233)		(71.7)	%	(134,713)		(18.3)	%	12,941		(14.7)	%	606,642
Equity-based compensation windfall (shortfall)	(0.4)	%	(5,723)		—	%	—		—	%	—		(0.2)	%	8,687
Discharge of debt and nondeductible professional fees	—	%	—		46.3	%	87,070		(0.3)	%	232		(2.1)	%	85,149
Other	(0.4)	%	(4,211)		(0.4)	%	(996)		—	%	14		—	%	1,185
Annual effective tax benefit	(3.4)	%	$	(46,884)	(0.5)	%	$	(973)	5.0	%	$	(3,447)	6.4	%	$	(262,962)

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Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2022 and 2021 were as follows:

	December 31,
	2022		2021
	(In thousands)
Deferred tax assets
Net operating loss carryforward	$	316,085	$	51,942
Oil and natural gas properties	—		237,051
Derivative instruments	72,761		91,213
Bonus and equity-based compensation	9,806		6,718
Investment in partnerships	—		12,924
Other deferred tax assets	7,863		14,843
Total deferred tax assets	406,515		414,691
Less: Valuation allowance	(9,617)		(399,770)
Total deferred tax assets, net	$	396,898	$	14,921
Deferred tax liabilities
Oil and natural gas properties	$	117,995	$	—
Investment in partnerships	69,867		—
Other deferred tax liabilities	8,810		14,928
Total deferred tax liabilities	$	196,672	$	14,928
Total deferred tax assets (liabilities), net	$	200,226	$	(7)

The Company’s effective tax rate for the year ended December 31, 2022 (Successor) was (3.4)% of pre-tax income from continuing operations, as compared to an effective tax rate of (0.5)% of pre-tax income from continuing operations for the year ended December 31, 2021 (Successor).

The effective tax rates from continuing operations for the year ended December 31, 2022 (Successor) and 2021 (Successor) were lower than the statutory federal rate of 21% primarily as a result of the Company’s valuation allowance, the substantial majority of which was released as of December 31, 2022. This benefit was partially offset by the impacts of state income taxes.

As a result of the Merger, which qualified as a tax-free reorganization for U.S. federal income tax purposes, the Company recognized a net deferred tax asset of $228.6 million in its purchase price allocation as of the acquisition date to reflect the difference between the tax basis and the fair value of Whiting’s assets acquired and liabilities assumed. The net deferred tax asset includes the tax effected benefit of federal net operating loss (“NOL”) carryforwards of $1.1 billion that were acquired in the Merger and are subject to various limitations under Section 382 of the Internal Revenue Code of 1986 (the “Code”), as discussed further below.

As of December 31, 2022, the Company had gross U.S. federal NOL carryforwards of $1.1 billion, of which approximately $1.0 billion will not expire and $105.3 million will expire from 2023 to 2037, and gross state NOL carryforwards of $2.2 billion. The gross state NOL carryforwards expire between 2023 and 2041. Both the Company and Whiting experienced an “ownership change” as defined by the Code in the past, including as a result of the Merger. Accordingly, under Section 382 of the Code, the Company’s NOL carryforwards and other tax attributes (collectively, “Tax Benefits”) are subject to various limitations going forward. However, the limitations applicable under Section 382 of the Code resulting from the Merger are not expected to have a material impact on the realizability of the Company’s deferred tax assets. The Company may experience ownership changes in the future as a result of subsequent shifts in its stock ownership that it cannot predict or control that could result in further limitations being placed on its ability to utilize its Tax Benefits. Determining the limitations under Section 382 of the Code is technical and highly complex, and upon future analysis the Company may determine that its ability to utilize its Tax Benefits may be limited to a greater extent than currently anticipated.

Tax Benefits are recorded as an asset to the extent that management assesses the utilization of such Tax Benefits to be more likely than not, and when the future utilization of some portion of the Tax Benefits is determined not to be more likely than not, then a valuation allowance is provided to reduce the Tax Benefits from such assets.

The Company initially recorded a valuation allowance against substantially all of its net deferred tax assets as of March 31, 2020. As of each reporting date, the Company assesses the available positive and negative evidence, including future reversals of temporary differences, tax-planning strategies and future taxable income, to estimate whether sufficient future taxable income will be generated to realize its deferred tax assets. A significant piece of objective positive evidence that the Company has evaluated is the cumulative income earned during the periods since the Company and Whiting each emerged from voluntary

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restructuring under Chapter 11 of the Bankruptcy Code in 2020. This source of objective positive evidence combined with the indefinite lives for many of the Company’s deferred tax assets and projections of future taxable income led the Company to determine that there is sufficient positive evidence to conclude that it is more likely than not that the Company will realize the majority of its net deferred tax assets and release a substantial majority of the valuation allowance previously recorded for the year. The Company’s estimated valuation allowance as of December 31, 2022 was $9.6 million, which relates to state NOL carryforwards acquired in the Merger. The Company’s estimated valuation allowance as of December 31, 2021 was $399.8 million and was released during the year ended December 31, 2022 (Successor), including $377.2 million that was attributable to continuing operations and $22.6 million that was attributable to discontinued operations.

Accounting for uncertainty in income taxes prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The Company had no unrecognized tax benefits as of December 31, 2022 and 2021. With respect to income taxes, the Company’s policy is to account for interest charges as interest expense and any penalties as tax expense in its Consolidated Statements of Operations. The Company files a U.S. federal income tax return and income tax returns in the various states where it operates. As the Company has NOL carryforwards from previous tax years, of which the earliest relate to the 2012 tax year, the Internal Revenue Service (“IRS”) may examine the Company’s loss years back to the 2012 tax year.

The Company has filed a non-automatic method change with the IRS to change the method of accounting for losses on undeveloped oil and gas leases that have expired for an entity acquired as part of the Merger. Should this method change be approved by the IRS, additional tax deductions may be available with respect to the Company’s 2022 tax year.

18. Equity-Based Compensation

Successor equity-based compensation

The Company has granted equity-based compensation awards under the 2020 LTIP. In accordance with the FASB’s authoritative guidance for share-based payments, the Company accounts for awards that settle in shares of common stock as equity classified awards and awards that settle in cash as liability classified awards.

Equity-based compensation expense from continuing operations is recognized in general and administrative expenses on the Company’s Consolidated Statements of Operations, and equity-based compensation expense from discontinued operations is recognized in discontinued operations, net of income tax on the Company’s Consolidated Statements of Operations. The Company recognized $61.2 million and $14.7 million in equity-based compensation expenses related to equity classified awards that were attributable to continued operations during the years ended December 31, 2022 and 2021 (Successor), respectively. Equity-based compensation expenses related to liability classified awards that were attributable to continued operations were $4.9 million and $0.5 million during the years ended December 31, 2022 and 2021 (Successor), respectively. Stock-based compensation expense related to equity classified awards that was attributable to discontinued operations was immaterial during the years ended December 31, 2022 and 2021 (Successor). Stock-based compensation expenses were not material for both continuing operations and discontinued operations during the period from November 20, 2020 through December 31, 2020 (Successor). Unrecognized compensation expense as of December 31, 2022 for all outstanding awards was $46.3 million and will be recognized over a weighted average period of approximately 1.8 years.

Merger impacts. Pursuant to the Merger Agreement, at the effective time of the Merger, the Company assumed the Whiting Equity Incentive Plan and the outstanding restricted stock units (“RSUs”) and performance share units (“PSUs”) granted under the Whiting Equity Incentive Plan. Accordingly, (i) all shares remaining available for issuance under the Whiting Equity Incentive Plan as of the Merger were automatically converted into shares of the Company’s common stock, available for issuance under the Whiting Equity Incentive Plan and (ii) all Whiting RSUs and PSUs were automatically converted into RSUs and PSUs of the Company, respectively, that, to the extent earned, will be settled in shares of the Company’s common stock, subject to appropriate adjustments to the number of shares subject to each award, resulting in the following as of July 1, 2022: (x) 1,611,725 shares of the Company’s common stock remaining available for issuance to eligible participants under the Whiting Equity Incentive Plan, (y) 335,386 shares of the Company’s common stock subject to RSUs assumed under the Whiting Equity Incentive Plan and (z) 275,310 shares of the Company’s common stock subject to PSUs assumed under the Whiting Equity Incentive Plan. The number of PSUs assumed by the Company was determined based upon the change-in-control provisions contained in the original award agreement at the greater of (i) the target number of PSUs subject to such award and (ii) the actual achievement of the performance criteria measured based on the truncated performance period ending immediately prior to the effective time of the Merger. Following completion of the Merger, the Whiting RSUs and PSUs are subject to time-based vesting criteria. The fair value of the RSU and PSU awards assumed by the Company was $73.3 million, including $27.4 million that was attributable to pre-Merger services and recorded as a part of the consideration transferred and $45.9 million that is attributable to post-Merger services that will be recognized as equity-based compensation expense in the post-combination period.

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Restricted stock awards. The Company previously granted restricted stock awards (“RSAs”) to non-employee directors. RSAs are legally issued shares which were scheduled to vest over a three-year period subject to a service condition. The Company measured the awards at fair value on the date of grant, which was based on the closing price of the Company’s common stock. Pursuant to the award agreements governing the RSAs, each outstanding RSA became fully vested upon completion of the Merger due to a “change in control” (as defined in the award agreement). As a result, 64,920 outstanding RSAs became fully vested on July 1, 2022 and the Company recognized the remaining unrecognized compensation expense immediately.

The following table summarizes information related to RSAs held by non-employee directors of the Company:

	Shares	Weighted Average Grant Date Fair Value per Share
Non-vested shares outstanding December 31, 2021	64,920	$	41.37
Granted	—	—
Vested	(64,920)	41.37
Forfeited	—	—
Non-vested shares outstanding December 31, 2022	—	$	—

The fair value of awards vested was $7.1 million and $4.0 million for the years ended December 31, 2022 and 2021 (Successor), respectively.

Restricted stock units. The Company has granted RSUs to employees and non-employee directors. RSUs are contingent shares with a service-based vesting condition. The RSUs granted to employees vest follow a graded vesting schedule and vest ratably each year over a three-year or four-year period. The RSUs granted to non-employee directors vest over a one-year period. The fair value is based on the closing price of the Company’s common stock on the date of grant or, if applicable, the date of modification. The Company recognizes compensation expense under the straight-line method over the requisite service period.

The following table summarizes information related to RSUs held by employees and non-employee directors of the Company:

	Shares	Weighted Average Grant Date Fair Value per Share
Non-vested shares outstanding December 31, 2021	512,806	$	62.66
Granted	76,472	144.16
Merger impacts(1)	335,386	109.30
Vested	(475,409)	85.29
Forfeited	(27,672)	74.66
Non-vested shares outstanding December 31, 2022	421,583	$	88.26

__________________ 

(1)     Represents awards assumed on July 1, 2022 in connection with the Merger.

The fair value of awards vested was $62.3 million for the year ended December 31, 2022 (Successor). The fair value of awards vested was immaterial for the year ended December 31, 2021 (Successor). The weighted average grant date fair value of RSUs was $144.16 per share and $62.61 per share for the years ended December 31, 2022 and 2021 (Successor), respectively.

Performance share units. The Company has granted PSUs to certain employees. PSUs are contingent shares that may be earned over three-year and four-year performance periods subject to market-based and service-based vesting conditions. The number of PSUs to be earned was initially subject to a market condition that was based on a comparison of the total stockholder return (“TSR”) achieved with respect to shares of the Company’s common stock against the TSR achieved by a defined peer group at the end of the applicable performance periods, with 50% of the PSU awards eligible to be earned based on performance relative to a certain group of the Company’s oil and gas peers and 50% of the PSU awards eligible to be earned based on performance relative to the broad-based Russell 2000 index. Depending on the Company’s TSR performance relative to the defined peer group, award recipients could earn between 0% and 150% of target. Pursuant to the PSU award agreements, the number of PSUs earned was certified at the greater of (i) target performance and (ii) actual achievement of the performance criteria measured based on the truncated performance period ending immediately prior to the effective time of a “change in control.” The completion of the Merger on July 1, 2022 represented a “change in control” such that 250,016 PSUs were earned by legacy Oasis award recipients subject to a service-based vesting condition, including 183,915 PSUs that were outstanding at December 31, 2021 and an incremental 66,101 PSUs that were earned based upon the achievement of the performance criteria described above.

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The following table summarizes information related to PSUs held by employees of the Company:

	Shares	Weighted Average Grant Date Fair Value per Share
Non-vested shares outstanding December 31, 2021	183,915	$	63.95
Granted	—	—
Merger impacts(1)	341,411	100.52
Vested	(152,185)	76.42
Forfeited	—	—
Non-vested shares outstanding December 31, 2022	373,141	$	92.53

___________________ 

(1)Includes 275,310 awards assumed on July 1, 2022 in connection with the Merger and an incremental 66,101 legacy Oasis PSU awards that were earned based upon the achievement of the performance criteria described above.

The fair value of awards vested was $16.6 million for the year ended December 31, 2022 (Successor). No awards vested for the year ended December 31, 2021 (Successor). No PSUs were granted during the year ended December 31, 2022 (Successor). The weighted average grant date fair value was $63.95 per share for the year ended December 31, 2021 (Successor).

Leveraged stock units. The Company has granted leveraged stock units (“LSUs”) to certain employees. LSUs are contingent shares that may be earned over a three-year or four-year performance period subject to market-based and service-based vesting conditions. The number of LSUs to be earned was initially subject to a market condition that was based on the TSR performance of the Company’s common stock measured against specific premium return objectives. Depending on the Company’s TSR performance, award recipients could earn between 0% and 300% of target; however, the number of shares delivered in respect to these awards during the grant cycle could not exceed ten times the fair value of the award on the grant date. Pursuant to LSU award agreements, the number of LSUs earned was certified at the greater of (i) target performance and (ii) actual achievement of the performance criteria measured based on the truncated performance period ending immediately prior to the effective time of a “change in control.” The completion of the Merger on July 1, 2022 represented a “change in control” such that 787,218 LSUs were earned by award recipients subject to a service-based vesting condition.

The following table summarizes information related to LSUs held by employees of the Company:

	Shares	Weighted Average Grant Date Fair Value per Share
Non-vested shares outstanding December 31, 2021	262,406	$	78.79
Granted	—	—
Merger impacts(1)	524,812	78.79
Vested	(290,181)	68.86
Forfeited	—	—
Non-vested shares outstanding December 31, 2022	497,037	$	84.59

__________________ 

(1)Represents legacy Oasis awards that were earned as result of the Merger. Upon completion of the Merger, there were 787,218 LSUs outstanding.

The fair value of awards vested was $31.5 million for the year ended December 31, 2022 (Successor). No awards vested for the year ended December 31, 2021 (Successor). No LSUs were granted during the year ended December 31, 2022 (Successor). The weighted average grant date fair value was $78.79 per share for the year ended December 31, 2021 (Successor).

Fair value assumptions. The aggregate grant date fair value of PSUs and LSUs was determined by a third-party valuation specialist using a Monte Carlo simulation model. The key valuation inputs were: (i) the forecast period, (ii) risk-free interest rate, (iii) implied equity volatility, (iv) stock price on the date of grant and, for PSUs, (v) correlation coefficient. The risk-free interest rates are the U.S. Treasury bond rates on the date of grant that correspond to each performance period. Implied equity volatility is derived by solving for an asset volatility and equity volatility based on the leverage of the Company and each of its peers. For the PSUs, the correlation coefficient measures the strength of the linear relationship between and amongst the Company and its peers based on historical stock price data.

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The following table summarizes the assumptions used in the Monte Carlo simulation model to determine the grant date fair value and associated equity-based compensation expenses by grant date:

Grant date	January 18, 2021	February 11, 2021	April 13, 2021
Forecast period (years)	3 - 4	3 - 4	3 - 4
Risk-free interest rates	0.2% - 0.3%	0.2% - 0.3%	0.3% - 0.6%
Implied equity volatility	55% - 60%	55% - 60%	45% - 50%
Stock price on date of grant	$44.41	$49.66	$68.07

Phantom unit awards. The Company has granted phantom unit awards to certain employees. Phantom unit awards represent the right to receive, upon vesting of the award, a cash payment equal to the fair market value of one share of common stock. The phantom unit awards are subject to a service-based vesting condition and generally vest in equal installments each year over a three-year period from the date of grant. Compensation expense is recognized over the requisite service period.

The following table summarizes information related to phantom unit awards held by employees of the Company:

	Phantom Unit Awards	Weighted Average Grant Date Fair Value per Share
Non-vested phantom unit awards outstanding December 31, 2021	15,780	$	127.91
Granted	7,504	144.74
Vested	(13,551)	132.43
Forfeited	(1,865)	129.00
Non-vested phantom unit awards outstanding December 31, 2022	7,868	$	135.91

The fair value of vested phantom unit awards was $2.0 million and immaterial for the years ended December 31, 2022 and 2021 (Successor), respectively.

Predecessor equity-based compensation

The Predecessor granted equity awards to its officers, employees and directors under the Amended and Restated 2010 Long Term Incentive Plan (the “2010 LTIP”).

During the period from January 1, 2020 through November 19, 2020 (Predecessor) for continuing operations, the Company recognized $29.8 million in stock-based compensation expense related to equity classified awards and $1.2 million related to liability classified awards. During the period from January 1, 2020 through November 19, 2020 (Predecessor) for discontinued operations, the Company recognized $1.5 million in stock-based compensation expense related to equity classified awards and $0.2 million related to liability classified awards.

Restricted stock awards. The Company granted restricted stock awards to its employees and directors under the 2010 LTIP, the majority of which vested over a three-year period. The fair value of restricted stock grants was based on the closing sales price of the Company’s common stock on the date of grant or, if applicable, the date of modification. Compensation expense was recognized ratably over the requisite service period.

The fair value of awards vested was $47.3 million for the period from January 1, 2020 through November 19, 2020 (Predecessor). The weighted average grant date fair value of restricted stock awards granted was $3.06 per share for the period from January 1, 2020 through November 19, 2020 (Predecessor).

Performance share units. The Company granted PSUs to its officers under the 2010 LTIP. The PSUs are awards of restricted stock units that were earned based on the level of achievement with respect to the applicable performance metric, and each PSU that was earned represented the right to receive one share of the Company’s common stock.

The Company accounted for the PSUs as equity awards pursuant to the FASB’s authoritative guidance for share-based payments. The number of PSUs to be earned was subject to a market condition, which is based on a comparison of the TSR achieved with respect to shares of the Company’s common stock against the TSR achieved by a defined peer group at the end of the performance periods. Depending on the Company’s TSR performance relative to the defined peer group, award recipients could have earned between 0% and 240% of the initial PSUs granted. All compensation expense related to the PSUs was recognized if the requisite performance period was fulfilled, even if the market condition was not achieved.

The fair value of PSUs vested was $7.6 million for the period from January 1, 2020 through November 19, 2020 (Predecessor). The weighted average grant date fair value of PSUs granted was $2.56 per share for the period from January 1, 2020 through November 19, 2020 (Predecessor).

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The aggregate grant date fair value of the market-based awards was determined using a Monte Carlo simulation model. The Monte Carlo simulation model uses assumptions regarding random projections and must be repeated numerous times to achieve a probabilistic assessment. The key valuation assumptions for the Monte Carlo model are the forecast period, risk-free interest rates, stock price volatility, initial value, stock price on the date of grant and correlation coefficients. The risk-free interest rates are the U.S. Treasury bond rates on the date of grant that corresponds to each performance period. The initial value is the average of the volume weighted average prices for the 30 trading days prior to the start of the performance cycle for the Company and each of its peers. Volatility is the standard deviation of the average percentage change in stock price over a historical period for the Company and each of its peers. The correlation coefficients are measures of the strength of the linear relationship between and amongst the Company and its peers estimated based on historical stock price data.

The following assumptions were used for the Monte Carlo model to determine the grant date fair value and associated equity-based compensation expense of the PSUs granted during the periods presented (Predecessor):

	2020
Forecast period (years)	2 - 4
Risk-free interest rates	1.53% - 1.55%
Oasis stock price volatility	68.56%
Oasis initial value	$3.19
Oasis stock price on date of grant	$2.77

Associated tax benefit. The Company did not have any associated tax benefits related to equity-based compensation during the period from January 1, 2020 through November 19, 2020 (Predecessor) as a result of recording a valuation allowance on its deferred tax assets or during the period from November 20, 2020 through December 31, 2020 (Successor) as a result of the vesting of equity-based awards on the Emergence Date.

Class B units in OMP GP. OMP GP previously granted restricted Class B units, representing membership interests in OMP GP, to certain employees, including OMP’s named executive officers, under the 2010 LTIP. The Class B units granted to employees other than the named executive officers vested on the Emergence Date. In connection with the Midstream Simplification, the Class B units granted to OMP’s named executive officers were converted into and exchanged for restricted common units in OMP. On March 30, 2021, 34% of these awards vested, and the remaining awards vested on February 1, 2022.

2020 Incentive Compensation Program. In order to effectively incentivize employees in the then-current environment, the Board of Directors approved a revised 2020 incentive compensation program applicable to all employees effective June 12, 2020 (the “2020 Incentive Compensation Program”).

Under the 2020 Incentive Compensation Program, all 2020 equity-based awards of the Predecessor previously granted under the 2010 LTIP, were forfeited and concurrently replaced with cash retention incentives, which were accounted for as modifications of such 2020 awards. In addition, all employees waived participation in the Company’s 2020 annual cash incentive plan and instead became eligible to earn cash performance incentives based on the achievement of certain specified incentive metrics measured on a quarterly basis from July 1, 2020 to June 30, 2021. The 2020 Incentive Compensation Program resulted in $15.6 million being paid in June 2020 with the remainder of the target amount under such program payable over the following 12 months.

For the Company’s officers and certain other senior employees, the prepaid cash incentives paid in June 2020 could be clawed back if (i) certain specified incentive metrics measured on a quarterly basis were not achieved from July 1, 2020 to December 31, 2020, and (ii) such individuals did not remain employed for a period of up to 12 months, unless such individuals were terminated without cause or resigned for good reason. The after-tax value of the cash incentives paid to the Company’s officers and certain other senior employees of $8.8 million was capitalized to prepaid expenses and amortized over the relevant service periods. The Company immediately expensed the difference between the cash and after-tax value of the prepaid cash incentives of $4.1 million, which was not subject to the clawback provisions of the 2020 Incentive Compensation Program, and recognized additional compensation expense of $0.4 million to adjust for the grant date fair value of certain original 2020 equity-based awards that exceeded the replacement cash retention incentives less amounts previously recognized for the original 2020 equity-based awards. On the Emergence Date and pursuant to the Plan, the remaining unamortized amount of prepaid cash incentives of $4.3 million was vested and included in general and administrative expenses on the Company’s Consolidated Statement of Operations for the period from January 1, 2020 through November 19, 2020 (Predecessor).

For all other employees, the June 2020 incentive payment of $2.7 million was not subject to any clawback provisions, and $2.1 million, which represented the excess of the cash retention payment over amounts previously recognized for the original 2020 equity-based awards in which these cash incentives replaced, was immediately expensed.

The expenses related to the 2020 Incentive Compensation Program are included in general and administrative expenses on the Company’s Consolidated Statements of Operations.

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19. Stockholder's Equity

Authorized Shares of Common Stock

On June 28, 2022, the Company’s stockholders approved an amendment to the Amended and Restated Certificate of Incorporation to increase the number of authorized shares of common stock from 60,000,000 to 120,000,000 in connection with the Merger. The amendment became effective on July 1, 2022.

Issuance of Common Stock

Pursuant to the Merger Agreement, each share of Whiting common stock issued and outstanding immediately prior to the effective time of the Merger was converted into the right to receive 0.5774 shares of common stock, par value $0.01 per share, of the Company. As a result of the completion of the Merger on July 1, 2022, the Company issued 22,671,871 shares of common stock to Whiting stockholders.

Dividends

During the year ended December 31, 2022, the Company declared base plus variable cash dividends of $12.03 per share of common stock or $373.0 million in aggregate and a special cash dividend of $15.00 per share of common stock, or $307.4 million in aggregate. On February 22, 2023, the Company declared a base cash dividend of $1.25 per share of common stock and a variable cash dividend of $3.55 per share of common stock. The dividends will be payable on March 21, 2023 to shareholders of record as of March 7, 2023. As of December 31, 2022, the Company had dividends payable of $30.6 million related to dividend equivalent rights accrued on equity-based compensation awards, including $5.9 million that was recorded under accrued liabilities and $24.8 million that was recorded under other liabilities on the Consolidated Balance Sheet.

During the year ended December 31, 2021, the Company declared base cash dividends of $1.625 per share of common stock, or $32.3 million in aggregate, and a special cash dividend of $4.00 per share of common stock, or $80.0 million in aggregate.

Share-Repurchase Program

In February 2022, the Board of Directors of the Company authorized a share-repurchase program covering up to $150.0 million of the Company’s common stock. In August 2022, the Board of Directors of the Company authorized a new share-repurchase program covering up to $300.0 million of the Company’s common stock, which resulted in the expiration of the $150.0 million share-repurchase program. During the year ended December 31, 2022, the Company repurchased 1,378,070 shares of common stock at a weighted average price of $110.24 per common share for a total cost of $151.9 million under both of these 2022 programs.

In March 2021, the Board of Directors authorized a share-repurchase program covering up to $100.0 million of the Company’s common stock. During the year ended December 31, 2021, the Company completed the entire share-repurchase program and repurchased 871,018 shares of common stock at a weighted average price of $114.79 per common share for a total cost of $100.0 million.

Warrants

Legacy Oasis warrants. On November 19, 2020, the Company entered into a Warrant Agreement with Computershare Inc. and Computershare Trust Company N.A., as warrant agent. The warrants, which are indexed to the Company’s common stock and are classified as equity, are exercisable until November 19, 2024, at which time all unexercised warrants will expire and the rights of the holders of such warrants to purchase common stock will terminate. In the event that a holder of a warrant elects to exercise their option to acquire shares of the Company’s common stock, the warrant is required to be settled through physical settlement or net share settlement.

The warrants were initially exercisable for a price of $94.57 per warrant. The number of shares of Chord common stock for which a warrant is exercisable and the exercise prices are subject to adjustment from time to time upon the occurrence of certain events, including stock splits, reverse stock splits or stock dividends to holders of common stock or a reclassification in respect of common stock. Pursuant to the terms of the Warrant Agreement, the exercise price per warrant decreased to $75.57 per warrant effective June 30, 2022 in connection with the payment of the Special Dividend.

No holder of a warrant, by virtue of holding or having a beneficial interest in a warrant, will have the right to vote, receive dividends, receive notice as stockholders with respect to any meeting of stockholders for the election of directors or any other matter, or exercise any rights whatsoever as a stockholder of Chord unless, until and only to the extent such holders become holders of record of shares of Chord common stock issued upon settlement of the warrants.

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Assumed Whiting warrants. Pursuant to the Merger Agreement, all of Whiting’s outstanding warrants immediately prior to the effective time of the Merger were assumed by the Company at the closing of the Merger. Prior to the Merger, each legacy Whiting warrant was exercisable for one share of Whiting common stock. Following the completion of the Merger and the Company’s assumption of the legacy Whiting warrants, each such warrant was exercisable for 0.5774 shares of the Company’s common stock, which reflects an adjustment in accordance with the exchange ratio under the Merger Agreement. Also, in accordance with the Merger Agreement, the exercise price of each such legacy Whiting warrant per share of the Company’s common stock was adjusted to equal the quotient of (x) the exercise price of such warrant per share of Whiting common stock immediately prior to the effective time of the Merger less $6.25 divided by (y) the exchange ratio of 0.5774.

Therefore, as a result of the completion of the Merger on July 1, 2022, the Company assumed (i) 4,833,455 legacy Whiting Series A Warrants which were exercisable for an aggregate amount of 2,790,837 shares of the Company’s common stock at an exercise price of $116.37 per share and (ii) 2,418,832 legacy Whiting Series B Warrants which were exercisable for an aggregate amount of 1,396,634 shares of the Company’s common stock at an exercise price of $133.70 per share.

In the event that a holder of Whiting warrants elects to exercise their option to acquire shares of the Company’s common stock, the Company shall issue a net number of exercised shares of common stock. The net number of exercised shares is calculated as (i) the number of Whiting warrants exercised multiplied by (ii) the difference between the 30 day daily volume weighted average price of the common stock leading up to the exercise date and the relevant exercise price, calculated as a percentage of the current market price on the exercise date.

The legacy Whiting Series A Warrants are exercisable until September 1, 2024 and the legacy Whiting Series B Warrants are exercisable until September 1, 2025, at which respective times all unexercised Whiting warrants will expire and the rights of the holders of such Whiting warrants to acquire common stock will terminate. Pursuant to the Whiting warrant agreements, no holder of a Whiting warrant, by virtue of holding or having a beneficial interest in a Whiting warrant, will have the right to vote, receive dividends, receive notice as stockholders with respect to any meeting of stockholders for the election of directors or any other matter, or exercise any rights whatsoever as a stockholder of Chord unless, until and only to the extent such holders become holders of record of shares of Chord common stock issued upon settlement of the Whiting warrants.

The number of shares of Chord common stock for which a Whiting warrant is exercisable and the exercise prices are subject to adjustment from time to time upon the occurrence of certain events, including stock splits, reverse stock splits or stock dividends to holders of common stock or a reclassification in respect of common stock.

Chord warrants. The following table summarizes the Company’s outstanding warrants as of December 31, 2022:

	Warrants(1)	Exercise Price(2)
Legacy Oasis	807,843	$	75.57
Legacy Whiting - Series A	2,777,179	$	116.37
Legacy Whiting - Series B	1,394,491	$	133.70
Total	4,979,513

__________________ 

(1)Represents the number of warrants in terms of shares of Chord common stock. During the year ended December 31, 2022, there were 715,934 warrants exercised.

(2)The exercise price of legacy Whiting warrants was adjusted in accordance with the Merger Agreement.

Tax benefits preservation plan

On August 3, 2021, the Board of Directors adopted a Tax Benefits Preservation Plan (the “Tax Plan”) designed to protect the availability of the Company’s NOLs and other tax attributes (collectively, “Tax Benefits”). Adopting the Tax Plan reduced the likelihood that changes in the Company’s investor base would limit the Company’s future use of its Tax Benefits. On February 1, 2022, the Company announced the termination of the Tax Plan after the Board of Directors determined the Tax Plan was no longer necessary or desirable for the preservation of the Tax Benefits.

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20. Earnings (Loss) Per Share

The Company calculates earnings per share under the two-class method. During the third quarter of 2022, the Company granted RSUs to non-employee directors which include non-forfeitable rights to dividends and are therefore considered “participating securities.” Accordingly, effective in the third quarter of 2022, the Company computes earnings per share under the two-class earnings allocation method. The two-class method is an earnings allocation formula that computes earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings.

Basic earnings per share amounts have been computed as (i) net income (loss) (ii) less distributed and undistributed earnings allocated to participating securities (iii) divided by the weighted average number of basic shares outstanding for the periods presented. Diluted earnings per share amounts have been computed as (i) basic net income attributable to common stockholders (ii) plus the reallocation of distributed and undistributed earnings allocated to participating securities (iii) divided by the weighted average number of diluted shares outstanding for the periods presented. The Company calculates diluted earnings per share under both the two-class method and treasury stock method and reports the more dilutive of the two calculations.

The following table summarizes the basic and diluted earnings per share for the periods presented (in thousands, except per share data):

	Successor						Predecessor
	Year Ended				Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020
	2022		2021
Net income (loss) from continuing operations	$	1,430,463	$	188,960	$	(67,108)	$	(3,865,854)
Distributed and undistributed earnings from continuing operations allocated to participating securities	(182)		—		—		—
Net income (loss) from continuing operations attributable to common stockholders (basic)	1,430,281		188,960		(67,108)		(3,865,854)
Reallocation of distributed and undistributed earnings from continuing operations allocated to participating securities	6		—		—		—
Net income (loss) from continuing operations attributable to common stockholders (diluted)	$	1,430,287	$	188,960	$	(67,108)	$	(3,865,854)
Weighted average common shares outstanding:
Basic weighted average common shares outstanding	30,497		19,792		19,991		317,644
Dilutive effect of share-based awards	1,134		856		—		—
Dilutive effect of warrants	620		—		—		—
Diluted weighted average common shares outstanding	32,251		20,648		19,991		317,644
Basic earnings (loss) per share from continuing operations	$	46.90	$	9.55	$	(3.36)	$	(12.17)
Diluted earnings (loss) per share from continuing operations	$	44.35	$	9.15	$	(3.36)	$	(12.17)
Anti-dilutive weighted average common shares:
Potential common shares	2,901		2,144		1,631		5,216

For the years ended December 31, 2022 and 2021 (Successor), the diluted earnings per share calculation excludes the impact of unvested share-based awards and outstanding warrants that were anti-dilutive. During the period from November 20, 2020 through December 31, 2020 (Successor) and the period from January 1, 2020 through November 19, 2020 (Predecessor), the Company incurred a net loss, and therefore the diluted loss per share calculation for those periods excludes the anti-dilutive effect of unvested share-based awards and outstanding warrants.

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Basic earnings per share from discontinued operations was $13.96 for the year ended December 31, 2022 (Successor), $6.60 for the year ended December 31, 2021 (Successor), $0.86 for the period from November 20, 2020 through December 31, 2020 (Successor) and $0.71 for the period from January 1, 2020 through November 19, 2020 (Predecessor). Diluted earnings per share from discontinued operations was $13.20 for the year ended December 31, 2022 (Successor), $6.33 for the year ended December 31, 2021 (Successor), $0.86 for the period from November 20, 2020 through December 31, 2020 (Successor) and $0.71 for the period from January 1, 2020 through November 19, 2020 (Predecessor).

21. Leases

The Company’s long-term leases consist primarily of office space, vehicles and other property and equipment used in its operations. The components of lease costs attributable to continuing operations were as follows for the periods presented (in thousands):

	Successor						Predecessor
	Year Ended December 31,				Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020
	2022		2021
Operating lease costs	$	11,292	$	2,966	$	666	$	3,245
Variable lease costs(1)	8,562		1,737		425		2,433
Short-term lease costs	25,716		8,244		554		9,807
Finance lease costs:
Amortization of ROU assets	1,342		1,578		151		1,959
Interest on lease liabilities	65		86		9		145
Total lease costs	$	46,977	$	14,611	$	1,805	$	17,589

___________________

(1)Based on payments made by the Company to lessors for the right to use an underlying asset that vary because of changes in circumstances occurring after the commencement date, other than the passage of time, such as property taxes, operating and maintenance costs, which do not depend on an index or rate.

The amounts disclosed herein are presented on a gross basis and do not reflect the Company’s net proportionate share of such amounts. A portion of these costs have been or will be billed to other working interest owners.

Total lease costs attributable to discontinued operations were recorded in income from discontinued operations, net of income tax on the Consolidated Statements of Operations. Total lease costs attributable to discontinued operations were immaterial for the periods reported.

As of December 31, 2022, maturities of the Company’s lease liabilities were as follows:

	Operating Leases		Finance Leases
	(In thousands)
2023	$	10,762	$	1,078
2024	3,853		389
2025	2,344		330
2026	1,939		122
2027	1,975		—
Thereafter	5,434		—
Total future lease payments	26,307		1,919
Less: Imputed interest	3,100		118
Present value of future lease payments	$	23,207	$	1,801

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Supplemental balance sheet information related to the Company’s leases were as follows:

	Balance Sheet Location	December 31, 2022		December 31, 2021
		(In thousands)
Assets
Operating lease assets(1)	Operating right-of-use assets	$	23,875	$	15,782
Finance lease assets(2)(3)	Other assets	1,803		1,124
Total lease assets		$	25,678	$	16,906
Liabilities
Current
Operating lease liabilities(1)	Current operating lease liabilities	$	9,941	$	7,893
Finance lease liabilities(3)	Other current liabilities	1,012		1,008
Long-term
Operating lease liabilities(1)	Operating lease liabilities	13,266		6,724
Finance lease liabilities(3)	Other liabilities	789		180
Total lease liabilities		$	25,008	$	15,805

___________________

(1)The Company acquired certain operating leases for office buildings and operating equipment in connection with the Merger. As of December 31, 2022, these included operating lease assets of $14.5 million, current operating lease liabilities of $2.5 million and long-term operating lease liabilities of $11.9 million. In connection with the 2021 Williston Basin Acquisition, the Company acquired certain operating leases for generators and compressors. As of December 31, 2021, these included operating lease assets of $11.0 million, current operating lease liabilities of $6.7 million and long-term operating lease liabilities of $4.5 million.

(2)Finance lease ROU assets are recorded net of accumulated amortization of $1.6 million as of December 31, 2022 and $0.9 million as of December 31, 2021.

(3)The Company acquired certain finance leases for vehicles in connection with the Merger. As of December 31, 2022, these included finance lease assets of $1.4 million, current finance lease liabilities of $0.8 million and long-term finance lease liabilities of $0.6 million.

Operating lease assets and liabilities and finance lease assets and liabilities that were attributable to discontinued operations were classified as held for sale as of December 31, 2021 and were immaterial.

Supplemental cash flow information and non-cash transactions related to the Company’s leases were as follows (in thousands):

	Successor						Predecessor
	Year Ended December 31,				Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020
	2022		2021
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$	15,843	$	3,420	$	1,992	$	6,624
Operating cash flows from finance leases	57		62		9		145
Financing cash flows from finance leases	1,299		1,161		202		1,989
ROU assets obtained in exchange for lease obligations
Operating leases(1)	$	20,164	$	14,140	$	—	$	797
Finance leases(2)	2,659		127		—		24
Reductions to ROU assets resulting from reductions to lease obligations
Operating leases(3)	$	—	$	—	$	(6,255)	$	—

___________________

(1)The year ended December 31, 2022 includes $15.8 million related to operating leases acquired in the Merger. The year ended December 31, 2021 includes $12.3 million related to operating leases acquired in the 2021 Williston Basin Acquisition.

(2)The year ended December 31, 2022 includes $2.1 million related to finance leases acquired in the Merger.

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(3)The period from November 20, 2020 through December 31, 2020 includes amounts added to or reduced from the carrying amount of ROU assets resulting from lease modifications and remeasurements in connection with the Company’s emergence from bankruptcy.

Weighted-average remaining lease terms and discount rates for the Company’s leases were as follows:

	December 31,
	2022		2021
Operating Leases
Weighted average remaining lease term	4.6 years		1.9 years
Weighted average discount rate	4.9	%	3.4	%
Finance Leases
Weighted average remaining lease term	2.3 years		1.1 years
Weighted average discount rate	5.4	%	3.5	%

22. Significant Concentrations

Major customers. For the year ended December 31, 2022 (Successor), sales to Phillips 66 Company and Shell Trading (US) Company accounted for approximately 17% and 11%, respectively, of the Company’s total product sales. For the year ended December 31, 2021 (Successor), sales to Phillips 66 Company accounted for approximately 13% of the Company’s total product sales. For the Successor period of November 20, 2020 through December 31, 2020, sales to ExxonMobil Oil Corporation and Phillips 66 Company accounted for approximately 22% and 15%, respectively, of the Company’s total product sales. For the Predecessor period of January 1, 2020 through November 19, 2020, Phillips 66 Company and Gunvor USA LLC accounted for approximately 11% and 10%, respectively, of the Company’s total product sales. No other purchasers accounted for more than 10% of the Company’s total sales for the years ended December 31, 2022, 2021 or 2020.

Substantially all of the Company’s accounts receivable result from sales of crude oil, NGLs and natural gas as well as joint interest billings to third-party companies who have working interest payment obligations in projects completed by the Company. This concentration of customers and joint interest owners may impact the Company’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. Management believes that the loss of any of these purchasers would not have a material adverse effect on the Company’s operations, as there are a number of alternative crude oil, NGL and natural gas purchasers in the Company’s producing regions.

23. Commitments and Contingencies

Included below is a discussion of various future commitments of the Company as of December 31, 2022. The commitments under these arrangements are not recorded in the accompanying Consolidated Balance Sheets. The amounts disclosed represent undiscounted cash flows on a gross basis and no inflation elements have been applied. As of December 31, 2022, the Company’s material off-balance sheet arrangements and transactions include $6.4 million in outstanding letters of credit issued under the Credit Facility and $17.7 million in net surety bond exposure issued as financial assurance on certain agreements.

Volume commitment agreements. As of December 31, 2022, the Company had certain agreements with an aggregate requirement to deliver, transport or purchase a minimum quantity of approximately 44.7 MMBbl of crude oil, 17.0 MMBbl of NGLs, 494.2 Bcf of natural gas and 1.6 MMBbl of water, prior to any applicable volume credits, within specified timeframes, the majority of which are ten years or less.

The estimable future commitments under these volume commitment agreements as of December 31, 2022 are as follows:

	(In thousands)
2023	$	173,080
2024	120,897
2025	83,796
2026	56,552
2027	36,358
Thereafter	48,862
	$	519,545

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The future commitments under certain agreements cannot be estimated and are therefore excluded from the table above as they are based on fixed differentials relative to a commodity index price under the agreements as compared to the differential relative to a commodity index price for the production month.

The Company enters into long-term contracts to provide production flow assurance in oversupplied areas with limited infrastructure, which provides for optimization of transportation and processing costs. As properties are undergoing development activities, the Company may experience temporary delivery or transportation shortfalls until production volumes grow to meet or exceed the minimum volume commitments. The Company recognizes any monthly deficiency payments in the period in which the under delivery takes place and the related liability has been incurred. The table above does not include any such deficiency payments that may be incurred under the Company’s physical delivery contracts, since it cannot be predicted with accuracy the amount and timing of any such penalties incurred.

In connection with the Merger, the Company assumed certain agreements with an aggregate requirement to deliver a minimum quantity of crude oil from the Company’s Sanish field in Mountrail County, North Dakota through June 2024. As of December 31, 2022, the Company had remaining commitments to deliver approximately 10.5 million barrels (“MMBbl”) of crude oil under these agreements. The Company believes its production and reserves at the Sanish field are sufficient to fulfill this delivery commitment, and therefore expects to avoid any payments for deficiencies under this contract. Additionally, the Company assumed two buy/sell transportation agreements with an aggregate requirement to deliver a minimum quantity of crude oil through July 2024. As of December 31, 2022, the Company had remaining commitments to deliver approximately 4.0 MMBbl of crude oil under these agreements. The future commitments related to these contracts are included in the table above.

In connection with the Williston Basin Acquisition, the Company acquired gathering and transportation contracts that included minimum volume commitments. The Company believed it was probable it would not be able to meet the minimum volume commitment in certain of these contracts and recorded a liability of $11.9 million on the Consolidated Balance Sheet as of December 31, 2021, of which $5.5 million was recorded to accrued liabilities and $6.4 million was recorded to other liabilities. The future commitments related to these contracts are included in the table above.

Whiting Chapter 11 bankruptcy claims. On April 1, 2020, Whiting and certain of its subsidiaries (the “Whiting Debtors”) commenced voluntary cases (the “Whiting Chapter 11 Cases”) under chapter 11 of the Bankruptcy Code. On June 30, 2020, the Whiting Debtors filed their proposed Joint Chapter 11 Plan of Reorganization of Whiting and its Debtor affiliates (as amended, modified and supplemented, the “Whiting Plan”). On August 14, 2020, the Bankruptcy Court confirmed the Whiting Plan and on September 1, 2020, the Whiting Debtors satisfied all conditions required for Plan effectiveness and emerged from the Whiting Chapter 11 Cases.

The filing of the Whiting Chapter 11 Cases allowed Whiting to, upon approval of the Bankruptcy Court, assume, assign or reject certain contractual commitments, including certain executory contracts. Generally, the rejection of an executory contract or unexpired lease is treated as a pre-petition breach of such contract and, subject to certain exceptions, relieves Whiting from performing future obligations under such contract but entitles the counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. The claims resolution process is ongoing and certain of these claims remain subject to the jurisdiction of the Bankruptcy Court. To the extent that the Bankruptcy Court allows any unsecured claims against the Company, such claims may be satisfied through an issuance of the Company’s common stock or other remedy or agreement under and pursuant to the Whiting Plan. In connection with the closing of the Merger on July 1, 2022, the Company assumed Whiting’s obligations with respect to the Whiting Plan and, accordingly, has reserved 1,224,840 shares of common stock for potential future distribution to certain general unsecured claimants whose claim values are pending resolution in the Bankruptcy Court.

Arguello Inc. and Freeport-McMoRan Oil & Gas LLC. Whiting Oil and Gas Corporation (“WOG”), a wholly-owned subsidiary of the Company, had interests in federal oil and gas leases in the Point Arguello Unit located offshore in California. While those interests have expired, pursuant to certain related agreements (the “Point Arguello Agreements”), WOG was subject to certain abandonment and decommissioning obligations prior to WOG and Whiting rejecting the related contracts pursuant to the Whiting Plan. On October 1, 2020, Arguello Inc. and Freeport-McMoRan Oil & Gas LLC, individually and in its capacity as the designated Point Arguello Unit operator (collectively, the “FMOG Entities”) filed with the Bankruptcy Court an application for allowance of certain administrative claims arguing the FMOG Entities were entitled to recover Whiting’s proportionate share of decommissioning obligations owed to the U.S. government through subrogation to the U.S. government’s economic rights. The U.S. Government may also be able to bring claims against WOG directly for decommissioning costs. On February 18, 2021, WOG entered into a stipulation and agreed order with the United States Department of the Interior, Bureau of Safety & Environmental Enforcement (the “BSEE”) pursuant to which the BSEE withdrew its proofs of claims against Whiting and WOG and acknowledged their respective rights and obligations pursuant to the Whiting Plan. On October 20, 2022, the Company filed stipulations and proposed orders with the Bankruptcy Court to resolve all outstanding claims asserted by the FMOG Entities. Those stipulations and proposed orders were signed by the Bankruptcy Court on October 27, 2022. On November l, 2022, the Company paid $55.0 million in cash as full and final satisfaction, discharge and release of all such claims.

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Litigation. The Company is party to various legal and/or regulatory proceedings from time to time arising in the ordinary course of business. When the Company determines that a loss is probable of occurring and is reasonably estimable, the Company accrues an undiscounted liability for such contingencies based on its best estimate using information available at the time. The Company discloses contingencies where an adverse outcome may be material, or in the judgment of management, the matter should otherwise be disclosed.

Mandan, Hidatsa and Arikara Nation (“MHA Nation”) Title Dispute. This matter relates to certain leases acquired by the Company from QEP in October 2021: In June 2018, the MHA Nation notified QEP of its position that QEP has no valid lease covering certain minerals underlying the Missouri and Little Missouri Riverbeds on the Fort Berthold Reservation in North Dakota. The MHA Nation also passed a resolution purporting to rescind those portions of QEP's Indian Mineral Development Act of 1982 lease covering the disputed minerals underlying the Missouri River. QEP responded in September 2018 stating that the minerals underlying the Missouri River are properly leased. In May 2020, the Office of the Solicitor of the United States Department of the Interior (the “Department of the Interior”) issued an opinion (the “Missouri River Opinion”) finding that the State of North Dakota, not the MHA Nation, is the legal owner of the minerals underlying the Missouri River. The MHA Nation filed actions in two federal courts seeking to overturn the May 2020 decision, and in March 2021, the Department of the Interior withdrew the Missouri River Opinion and on February 4, 2022, the Department of the Interior issued a new opinion on the matter stating that the minerals beneath the Missouri River riverbed located on the Fort Berthold Indian Reservation belong to the MHA Nation and not the state of North Dakota. Based on the new opinion from the Department of Interior, on June 21, 2022, the D.C. Federal District Court issued an order dismissing the MHA Nation’s claims relating to title of the riverbed as moot and denied the State of North Dakota’s motion to intervene on remaining counts. Although the D.C. Federal District Court did not address the substantive question of ownership, its decision on mootness and denial of the State of North Dakota’s request to intervene effectively prevents the State of North Dakota from disputing riverbed ownership through this action. On June 29, 2022, the State of North Dakota appealed this order to the D.C. Circuit Court of Appeals. As of the date of this report, there has been no decision with regard to the appeal.

24. Subsequent Events

The Company has evaluated the period after the balance sheet date, noting no subsequent events or transactions that required recognition or disclosure in the financial statements, other than those matters previously disclosed herein.

25. Supplemental Oil and Gas Disclosures — Unaudited

The supplemental data presented below reflects information for all of the Company’s oil and gas producing activities. Prior periods have not been recast for discontinued operations.

Capitalized Costs

The following table sets forth the capitalized costs related to the Company’s oil and gas producing activities:

	December 31,
	2022		2021
	(In thousands)
Proved oil and gas properties	$	5,089,185	$	1,393,836
Less: Accumulated depreciation, depletion, amortization and impairment	(461,175)		(107,277)
Proved oil and gas properties, net	4,628,010		1,286,559
Unproved oil and gas properties	30,936		2,001
Total oil and gas properties, net	$	4,658,946	$	1,288,560

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Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

The following table sets forth costs incurred related to the Company’s oil and gas activities for the periods presented (in thousands):

	Successor						Predecessor
	Year Ended December 31,				Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020
	2022		2021
Acquisition costs:
Proved oil and gas properties	$	3,164,665	$	605,868	$	—	$	—
Unproved oil and gas properties	43,084		85		336		536
Exploration costs	859		1		105		1,225
Development costs	507,961		170,178		14,624		199,537
Asset retirement costs	21,165		15,750		35		181
Total costs incurred	$	3,737,734	$	791,882	$	15,100	$	201,479

Results of Operations for Oil and Gas Producing Activities

The following table sets forth the results of operations for oil and gas producing activities, which exclude general and administrative expenses and interest expense, for the periods presented (in thousands):

	Successor						Predecessor
	Year Ended December 31,				Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020
	2022		2021
Revenues	$	2,976,296	$	1,200,256	$	86,442	$	603,585
Production costs	814,588		403,382		32,903		249,707
Depreciation, depletion and amortization	354,050		109,881		12,745		264,822
Exploration and impairment	2,204		2,763		—		4,803,533
Rig termination	—		—		—		1,279
Income tax (benefit) expense	426,087		162,163		9,648		(1,115,276)
Results of operations for oil and gas producing activities	$	1,379,367	$	522,067	$	31,146	$	(3,600,480)

26. Supplemental Oil and Gas Reserve Information — Unaudited

The reserve estimates presented below at December 31, 2022 are based on reports prepared by Netherland, Sewell & Associates, Inc., the Company’s independent reserve engineers. The reserve estimates at December 31, 2021 and 2020 were based on reports prepared by DeGolyer and MacNaughton, the Company’s previous independent reserve engineers. All of the Company’s oil and gas reserves are attributable to properties within the United States.

Proved oil and gas reserves are the estimated quantities of crude oil, NGLs and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made. Proved developed oil and gas reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.

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Estimated Quantities of Proved Reserves

The following table summarizes changes in quantities of the Company’s estimated net proved reserves by product for the periods presented:

	Crude Oil (MBbl)	NGLs(1) (MBbl)	Natural Gas (MMcf)	MBoe(2)
2020
Proved reserves
Beginning balance (Predecessor)	200,787	—	513,533	286,376
Revisions of previous estimates	(69,782)	—	(98,815)	(86,251)
Extensions, discoveries and other additions	4,578	—	8,659	6,021
Production	(15,818)	—	(47,207)	(23,686)
Net proved reserves at December 31, 2020	119,765	—	376,170	182,460
Proved developed reserves, December 31, 2020	85,428	—	262,676	129,207
Proved undeveloped reserves, December 31, 2020	34,337	—	113,494	53,253
2021
Proved reserves
Beginning balance	119,765	—	376,170	182,460
Revisions of previous estimates	42,411	—	68,768	53,871
Extensions, discoveries and other additions	7,734	—	14,539	10,157
Sales of reserves in place	(24,760)	—	(40,211)	(31,461)
Purchases of reserves in place	42,656	—	86,153	57,015
Production	(13,489)	—	(46,157)	(21,182)
Net proved reserves at December 31, 2021	174,317	—	459,262	250,860
Proved developed reserves, December 31, 2021	114,041	—	361,836	174,347
Proved undeveloped reserves, December 31, 2021	60,276	—	97,426	76,513
2022
Proved reserves
Beginning balance	174,317	—	459,262	250,860
Revisions of previous estimates	(8,032)	64,557	(56,500)	47,110
Extensions, discoveries and other additions	38,144	7,452	35,689	51,544
Sales of reserves in place	—	—	—	—
Purchases of reserves in place	202,316	73,468	443,903	349,768
Production	(25,457)	(7,026)	(67,428)	(43,722)
Net proved reserves at December 31, 2022	381,288	138,451	814,926	655,560
Proved developed reserves, December 31, 2022	272,529	115,227	689,651	502,698
Proved undeveloped reserves, December 31, 2022	108,759	23,224	125,275	152,862

__________________ 

(1)For periods prior to July 1, 2022, we reported crude oil and natural gas on a two-stream basis, and NGLs were combined with the natural gas stream when reporting reserves. As of July 1, 2022, NGLs are reported separately from the natural gas stream on a three-stream basis. This prospective change impacts the comparability of the periods presented.

(2)Natural gas is converted to barrel of oil equivalents at the rate of six thousand cubic feet of natural gas to one barrel of oil.

2022

Proved reserves increased by 404.7 MMBoe during the year ended December 31, 2022 due to the following:

Purchases of reserves in place. The Company added 349.8 MMBoe of proved reserves from the purchase of reserves in place as a result of the Merger.

Extensions, discoveries and other additions. The Company added 51.5 MMBoe of proved reserves associated with extensions and discoveries primarily attributable to successful drilling in the Williston Basin. New wells drilled in this area, as well as proved undeveloped (“PUD”) locations added as a result of offset drilling, increased proved reserves.

Revisions of previous estimates. The Company had net positive revisions of 47.1 MMBoe attributable to the following:

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Increases:

•30.3 MMBoe associated with the change to reporting reserves on a three-stream basis in 2022

•26.1 MMBoe associated with higher crude oil, NGL and natural gas prices

•2.6 MMBoe associated with tighter differentials and stronger NGL yields

Decreases:

•6.7 MMBoe associated with reservoir and engineering analysis and well performance across the Company’s Williston Basin assets

•5.2 MMBoe primarily associated with lower working interests as a result of well payouts associated with higher commodity pricing

Production. Production decreased proved reserves by 43.7 MMBoe.

Sales of reserves in place. There were no impacts to proved reserves as a result of the sale of reserves in place.

2021

Proved reserves increased by 68.4 MMBoe during the year ended December 31, 2021 due to the following:

Purchases of reserves in place. The Company added 57.0 MMBoe of proved reserves from the purchase of reserves in place as a result of the 2021 Williston Basin Acquisition.

Revisions of previous estimates. The Company had net positive revisions of 53.9 MMBoe attributable to the following:

Increases:

•38.6 MMBoe associated with alignment to the anticipated five-year development plan

•37.2 MMBoe associated with higher realized prices

•6.2 MMBoe associated with lower operating expenses

Decreases:

•22.9 MMBoe associated with reservoir analysis and well performance across the Company’s Williston Basin assets

•5.2 MMBoe associated with the impact of removing the benefits of midstream operations from operating expenses

Extensions, discoveries and other additions. The Company added 10.2 MMBoe of proved reserves associated with extensions and discoveries. Of these additions, 7.6 MMBoe were associated with the Company’s anticipated five-year development plan and 2.6 MMBoe were associated with new producing wells.

Sales of reserves in place. Proved reserves decreased 31.5 MMBoe as a result of the Permian Basin Sale in June 2021.

Production. Production decreased proved reserves by 21.2 MMBoe.

2020

Proved reserves decreased by 103.9 MMBoe during the year ended December 31, 2020 due to the following:

Revisions of previous estimates. The Company had net negative revisions of 86.3 MMBoe attributable to the following:

Decreases:

•60.1 MMBoe associated with alignment to the anticipated five-year development plan

•31.9 MMBoe associated with lower realized prices

Increases:

•5.6 MMBoe associated with the addition of PUD reserves that were previously removed from the anticipated five-year development plan

Production. Production decreased proved reserves by 23.7 MMBoe.

Extensions, discoveries and other additions. The Company added 6.0 MMBoe of proved reserves associated with extensions and discoveries. Of these additions, 3.2 MMBoe were associated with new producing wells and 2.8 MMBoe were associated with the Company’s anticipated five-year development plan.

Purchases of reserves in place. The Company added no proved reserves from the purchase of reserves in place.

Sales of reserves in place. There were no impacts to proved reserves as a result of the sale of reserves in place.

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Changes in Proved Undeveloped Reserves

The following table summarizes the changes in the Company’s estimates of PUD reserves during 2022:

	Year Ended December 31, 2022
	(MBoe)
Proved undeveloped reserves, beginning of period	76,513
Purchases of minerals in place	68,097
Extensions, discoveries and other additions	50,250
Revisions of previous estimates	1,060
Conversion to proved developed reserves	(43,058)
Proved undeveloped reserves, end of period	152,862

Proved undeveloped reserves increased by 76.4 MMBoe during the year ended December 31, 2022 due to the following:

Purchases of minerals in place. The Company added 68.1 MMBoe of PUD reserves from the purchase of minerals in place as a result of the Merger.

Extensions, discoveries and other additions. The Company added 50.3 MMBoe of PUD reserves associated with extensions and discoveries primarily attributable to successful drilling in the Williston Basin.

Revisions of previous estimates. The Company had net positive revisions of 1.1 MMBoe attributable to the following:

Increases:

•6.7 MMBoe associated with the change to reporting reserves on a three-stream basis in 2022

•1.9 MMBoe associated with higher crude oil, NGL and natural gas prices

Decreases:

•7.5 MMBoe primarily associated with reservoir and engineering analysis and well performance across the Company’s Williston Basin assets

Conversions to proved developed reserves. The Company incurred $270.8 million in capital expenditures to convert 43.1 MMBoe of PUD reserves to proved developed reserves during 2022. The PUD conversions represented 56% of the Company’s PUD reserves balance at the beginning of 2022. The conversions to proved developed reserves included 28.0 MMBoe of PUD reserves attributable to Whiting that were converted to proved developed reserves subsequent to the Merger and therefore were not included in the PUD reserves balance at the beginning of 2022. Whiting incurred an additional $147.9 million prior to the Merger associated with the 28.0 MMBoe of PUD reserves that were converted during the period subsequent to the Merger.

The Company expects to develop all of its PUD reserves, including all wells drilled but not yet completed, as of December 31, 2022 within five years after the initial year booked. Substantially all PUD locations are located on properties where the leases are held by existing production or continuous drilling operations. Approximately 11% of the Company’s PUD reserves at December 31, 2022 are attributable to wells that have been drilled but not yet completed, and substantially all of the Company’s PUD reserves are within its core acreage in the Williston Basin.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The Standardized Measure represents the present value of estimated future net cash flows from estimated net proved oil and natural gas reserves, less future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows. Production costs do not include DD&A of capitalized acquisition, exploration and development costs.

The Company’s estimated net proved reserves and related future net revenues and Standardized Measure were determined using index prices for crude oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $93.67 per Bbl for crude oil and $6.36 per MMBtu for natural gas, $66.55 per Bbl for crude oil and $3.64 per MMBtu for natural gas and $39.54 per Bbl for crude oil and $2.03 per MMBtu for natural gas for the years ended December 31, 2022, 2021 and 2020, respectively. These prices were adjusted by lease for quality, energy content, transportation fees and marketing differentials. Future operating costs, production taxes and capital costs were based on current costs as of each year end.

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The following table sets forth the Standardized Measure of discounted future net cash flows from projected production of the Company’s estimated net proved reserves at December 31, 2022, 2021 and 2020:

	At December 31,
	2022		2021		2020
	(In thousands)
Future cash inflows	$	44,544,247	$	13,366,064	$	5,197,220
Future production costs	(15,879,712)		(6,548,794)		(2,792,921)
Future development costs	(2,553,605)		(1,322,207)		(610,658)
Future income tax expense	(5,283,201)		(717,721)		(232,849)
Future net cash flows	20,827,729		4,777,342		1,560,792
10% annual discount for estimated timing of cash flows	(9,333,254)		(2,080,404)		(611,915)
Standardized measure of discounted future net cash flows	$	11,494,475	$	2,696,938	$	948,877

The following table sets forth the changes in the Standardized Measure of discounted future net cash flows applicable to estimated net proved reserves for the periods presented:

	2022		2021		2020
	(In thousands)
January 1	$	2,696,938	$	948,877	$	2,844,369
Net changes in prices and production costs	3,148,745		1,617,331		(1,088,936)
Net changes in future development costs	35,427		(36,645)		4,640
Sales of crude oil and natural gas, net	(2,161,708)		(796,874)		(407,417)
Extensions	958,924		98,125		47,693
Purchases of reserves in place	7,441,750		780,442		—
Sales of reserves in place	—		(204,153)		—
Revisions of previous quantity estimates	1,434,357		639,320		(694,320)
Previously estimated development costs incurred	137,534		102,519		87,640
Accretion of discount	683,631		94,090		293,445
Net change in income taxes	(2,539,182)		(252,347)		(76,066)
Changes in timing and other	(341,941)		(293,747)		(62,171)
December 31	$	11,494,475	$	2,696,938	$	948,877

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Evaluation of disclosure controls and procedures

As required by Rule 13a-15(b) of the Exchange Act, management, under the supervision and with the participation of our Chief Executive Officer (“CEO”), our principal executive officer, and our Chief Financial Officer (“CFO”), our principal financial officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2022. Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our CEO and CFO as appropriate, to allow timely decisions regarding required disclosure. Based on the evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of December 31, 2022 at the reasonable assurance level.

Management’s report on internal control over financial reporting

Management, including our CEO and CFO, is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act). Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external purposes in accordance with GAAP.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

As of December 31, 2022, management assessed the effectiveness of our internal control over financial reporting. In making this assessment, management, including our CEO and CFO, used the criteria set forth by the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on this assessment, management has concluded that our internal control over financial reporting was effective as of December 31, 2022. Management’s assessment and conclusion on the effectiveness of our internal control over financial reporting as of December 31, 2022 excludes an assessment of the internal control over financial reporting of Whiting as it was acquired by the Company in a purchase business combination on July 1, 2022. The total assets of Whiting represent approximately 60% of the related consolidated financial statement amounts as of December 31, 2022. The total revenues of Whiting represent approximately 29% of the related consolidated financial statement amounts for the year ended December 31, 2022.

PricewaterhouseCoopers LLP, the independent registered public accounting firm that audited our consolidated financial statements included in this annual report on Form 10-K, has also audited the effectiveness of our internal control over financial reporting as of December 31, 2022 and has issued an unqualified opinion on the effectiveness of our internal control over financial reporting as of December 31, 2022. Please see their “Report of Independent Registered Public Accounting Firm” included in “Item 8. Financial Statements and Supplementary Data.”

Changes in internal control over financial reporting

On July 1, 2022, we completed the Merger. As part of the ongoing integration of the acquired business, we are in the process of incorporating the controls and related procedures of Whiting. Other than incorporating Whiting’s controls, there were no changes in internal control over financial reporting that occurred during the quarter ended December 31, 2022 that have materially affected, or are reasonably likely to have a material effect on, our internal control over financial reporting.

Item 9B. Other Information

On February 24, 2023, our Board of Directors approved and adopted the Fourth Amended and Restated Bylaws of the Company (the “Bylaws”). The Bylaws became effective immediately and include the following changes:

•updating the advance notice provisions relating to stockholder nominations of directors to address Rule 14a-19 of the Exchange Act;

•requiring stockholders soliciting proxies to use a proxy card color other than white;

•updating the advance notice provisions relating to stockholders intending to propose other business (other than proposals to be included in the Company’s proxy statement pursuant to Rule 14a-8 under the Exchange Act) at meetings of stockholders;

•updating the requirements for stockholders to request a special meeting;

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•clarifying that our Board of Directors shall elect a Lead Independent Director when the Board Chair is not independent;

•revisions to align with recent amendments to the Delaware General Corporation Law (“DGCL”);

•revisions to the descriptions of certain Board of Directors and officer positions identified in the Bylaws;

•clarifying the notice procedures in connection with officer and director resignations;

•updating the provisions regarding the right to indemnification by the Company for certain persons; and

•clarifying the vote required for stockholders to amend the Bylaws.

The Bylaws also includes various other updates, including certain technical, conforming and clarifying changes.

The foregoing description of the changes effected through the adoption of the Bylaws does not purport to be complete and is qualified in its entirety by reference to the complete text of the Bylaws, a copy of which is attached hereto as Exhibit 3.5(a) and is incorporated herein by reference.

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

Not applicable.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2023 Annual Meeting of Stockholders.

We have adopted a Code of Business Conduct and Ethics Policy that applies to all of our directors, officers and employees, including our principal executive, principal financial and principal accounting officers, or persons performing similar functions. Our Code of Business Conduct and Ethics Policy can be found on our website located at http://www.chordenergy.com, under “Investors — Corporate Governance.” Any stockholder may request a printed copy of the Code of Business Conduct and Ethics Policy by submitting a written request to our Corporate Secretary.

We intend to disclose future amendments to certain provisions of the Code of Business Conduct and Ethics Policy, and waivers of the Code of Business Conduct and Ethics Policy granted to executive officers and directors, on our website within four business days following the date of the amendment or waiver. The waiver information will remain on our website for at least 12 months after the initial disclosure of such waiver. We intend to satisfy the disclosure requirement under Item 5.05 of Form 8-K relating to amendments to or waivers from any provision of the Code of Business Conduct and Ethics Policy applicable to such persons by posting such information on our website.

Item 11. Executive Compensation

Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2023 Annual Meeting of Stockholders.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2023 Annual Meeting of Stockholders.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2023 Annual Meeting of Stockholders.

Item 14. Principal Accountant Fees and Services

Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2023 Annual Meeting of Stockholders.

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PART IV

Item 15. Exhibits, Financial Statement Schedules

a. The following documents are filed as a part of this Annual Report on Form 10-K or incorporated herein by reference:

(1)Financial Statements:

See Item 8. Financial Statements and Supplementary Data.

(2)Financial Statement Schedules:

None.

(3)Exhibits:

The following documents are included as exhibits to this report:

Exhibit No.	Description of Exhibit
2.1	Joint Chapter 11 Plan of Reorganization of Oasis Petroleum Inc. and its Debtor Affiliates (Technical Modifications) (filed as Exhibit 2.1 to Oasis’s Current Report on Form 8-K filed on November 13, 2020, and incorporated herein by reference).
2.2	Joint Chapter 11 Plan of Reorganization of Whiting Petroleum Corporation and its Debtor Affiliates (filed as Exhibit A of Exhibit 99 to Whiting’s Current Report on Form 8-K filed on August 17, 2020, and incorporated herein by reference).
2.3	Purchase and Sale Agreement, dated as of May 3, 2021, among Oasis Petroleum North America LLC and QEP Energy Company (filed as Exhibit 2.2 to the Company’s Quarterly Report on Form 10-Q on May 7, 2021, and incorporated herein by reference).
2.4	Purchase and Sale Agreement dated May 20, 2021, between Oasis Petroleum Permian LLC and Percussion Petroleum Operating II, LLC (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K on May 21, 2021, and incorporated herein by reference).
2.5	Agreement and Plan of Merger, dated October 25, 2021, by and among Crestwood Equity Partners LP, Project Falcon Merger Sub LLC, Project Phantom Merger Sub LLC, Oasis Midstream Partners LP, OMP GP LLC and, solely for purposes of Section 2.1(a)(i), Crestwood Equity GP LLC (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K on October 28, 2021, and incorporated herein by reference).
2.6	Agreement and Plan of Merger, dated as of March 7, 2022 by and among Oasis Petroleum Inc., Ohm Merger Sub Inc., New Ohm LLC and Whiting Petroleum Corporation (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K on March 8, 2022, and incorporated herein by reference).
3.1(a)	Conformed version of Amended and Restated Certificate of Incorporation of Chord Energy Corporation, as amended by amendment filed on July 1, 2022.
3.2	Third Amended and Restated Bylaws of Chord Energy Corporation adopted as of July 1, 2022 (filed as Exhibit 3.3 to the Company’s Current Report on Form 8-K on July 7, 2022, and incorporated herein by reference).
3.3	Certificate of Designations of Series A Junior Participating Preferred Stock of Oasis Petroleum Inc. (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on August 4, 2021, and incorporated herein by reference).
3.4	Certificate of Elimination of the Series A Junior Participating Preferred Stock of Oasis Petroleum Inc. (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on July 7, 2022, and incorporated herein by reference).
3.5(a)	Fourth Amended and Restated Bylaws of Chord Energy Corporation adopted as of February 24, 2023.
4.1	Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Registration Statement on Form S-1/A on May 19, 2010, and incorporated herein by reference).

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Exhibit No.	Description of Exhibit
4.2	Registration Rights Agreement, dated February 14, 2018, between the Oasis Petroleum Inc. and Forge Energy, LLC (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on February 16, 2018, and incorporated herein by reference).
4.3(a)	Description of the Registrant’s Securities Registered Pursuant to Section 12 of the Exchange Act of 1934.
4.4	Indenture, dated as of June 9, 2021, among Chord Energy Corporation (f/k/a Oasis Petroleum Inc.), the Guarantors and Regions Bank, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on June 15, 2021, and incorporated herein by reference).
4.5	First Supplemental Indenture to Indenture dated February 7, 2022, by and among Chord Energy Corporation (f/k/a Oasis Petroleum Inc.), the Guarantors and Regions Bank, as trustee (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K on August 12, 2022, and incorporated herein by reference).
4.6	Second Supplemental Indenture to Indenture dated August 12, 2022, by and among Chord Energy Corporation, the Guarantors and Regions Bank, as trustee (filed as Exhibit 4.3 to the Company’s Current Report on Form 8-K on August 12, 2022, and incorporated herein by reference).
10.1**	Form of Indemnification Agreement between Chord Energy Corporation (f/k/a Oasis Petroleum Inc.) and each of the directors and executive officers thereof (filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K on November 20, 2020, and incorporated herein by reference).
10.2**	Amended and Restated 2010 Annual Incentive Compensation Plan of Oasis Petroleum Inc. (filed as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q on August 6, 2014, and incorporated herein by reference).
10.3	Letter Agreement dated as of March 4, 2015 between the Company and SPO Advisory Corp. (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on March 9, 2015, and incorporated herein by reference).
10.4	Contribution Agreement, dated as of September 25, 2017, by and among Oasis Midstream Partners LP, Oasis Petroleum LLC, OMS Holdings LLC, Oasis Midstream Services LLC, OMP GP LLC and OMP Operating LLC (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K on September 29, 2017, and incorporated herein by reference).
10.5	Omnibus Agreement, dated as of September 25, 2017, by and among Oasis Midstream Partners LP, the Company, Oasis Petroleum LLC, OMS Holdings LLC, Oasis Midstream Services LLC, OMP GP LLC and OMP Operating LLC (filed as Exhibit 10.2 to the Company's Current Report on Form 8-K on September 29, 2017, and incorporated herein by reference).
10.6	Third Amended and Restated Credit Agreement, dated as of October 16, 2018, by and among Oasis Petroleum Inc., as parent, Oasis Petroleum North America LLC, as borrower, the other credit parties thereto, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 19, 2018, and incorporated herein by reference).
10.7	First Amendment to the Third Amended and Restated Credit Agreement, dated as of April 15, 2019, among Oasis Petroleum Inc., as parent, Oasis Petroleum North America LLC, as borrower, the other credit parties party thereto, Wells Fargo Bank, N.A., as administrative agent and the lenders party thereto (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q on May 8, 2019, and incorporated herein by reference).
10.8	Second Amendment to the Third Amended and Restated Credit Agreement, dated as of July 2, 2019, among Oasis Petroleum Inc., as parent, Oasis Petroleum North America LLC, as borrower, the other credit parties party thereto, Wells Fargo Bank, N.A., as administrative agent and the lenders party thereto (filed as Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q on August 9, 2019, and incorporated herein by reference).

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Exhibit No.	Description of Exhibit
10.9	Third Amendment to the Third Amended and Restated Credit Agreement, dated as of November 4, 2019, among Oasis Petroleum Inc., as parent, Oasis Petroleum North America LLC, as borrower, the other credit parties party thereto, Wells Fargo Bank, N.A., as administrative agent and the lenders party thereto (filed as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q on November 6, 2019, and incorporated herein by reference).
10.10	Limited Waiver and Fourth Amendment to the Third Amended and Restated Credit Agreement, dated as of April 24, 2020, among Oasis Petroleum North America LLC, as borrower, the guarantors thereto, Wells Fargo Bank, N.A., as administrative agent and issuing bank and the lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on April 30, 2020, and incorporated herein by reference).
10.11	Direction Letter and Specified Swap Liquidation Agreement (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on September 21, 2020, and incorporated herein by reference).
10.12	Restructuring Support Agreement, dated September 29, 2020 (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on September 30, 2020, and incorporated herein by reference).
10.13	DIP Commitment Letter, dated September 29, 2020 (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on September 30, 2020, and incorporated herein by reference).
10.14	Exit Commitment Letter, dated September 29, 2020 (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K on September 30, 2020, and incorporated herein by reference).
10.15	Senior Secured Superpriority Debtor-in-Possession Revolving Credit Agreement, dated as of October 2, 2020, by and among Oasis Petroleum Inc., Oasis Petroleum North America LLC, the Guarantors party thereto, the Lenders party from time to time thereto, and Wells Fargo Bank, National Association (filed as Exhibit 10.9 to the Company’s Quarterly Report on Form 10-Q on November 5, 2020, and incorporated herein by reference).
10.16†	Credit Agreement dated as of November 19, 2020, among Oasis Petroleum Inc., as parent, Oasis Petroleum North America LLC, as borrower, the other credit parties party hereto, Wells Fargo Bank, N.A., as administrative agent, issuing bank and swingline lender and the lenders party hereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on November 20, 2020, and incorporated herein by reference).
10.17	Warrant Agreement, dated as of November 19, 2020, by and between Oasis Petroleum Inc., and Computershare Trust Company, N.A. (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on November 20, 2020, and incorporated herein by reference).
10.18	Registration Rights Agreement, dated as of November 19, 2020, by and between the Oasis Petroleum Inc. and the holders party thereto (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K on November 20, 2020, and incorporated herein by reference).
10.19**	Form of Indemnification Agreement, by and between Oasis Petroleum Inc. and its officers and directors (filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K on November 20, 2020, and incorporated herein by reference).
10.20**	Oasis Petroleum Inc. 2020 Long Term Incentive Plan (filed as Exhibit 10.5 to the Company’s Current Report on Form 8-K on November 20, 2020, and incorporated herein by reference).
10.21**	Employment Agreement, dated January 18, 2021, by and between Oasis Petroleum Inc. and Michael H. Lou (filed as Exhibit 99.3 to the Company’s Current Report on Form 8-K on January 21, 2021, and incorporated herein by reference).

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Exhibit No.	Description of Exhibit
10.22**	Employment Agreement, dated April 13, 2021, by and between Oasis Petroleum Inc. and Daniel E. Brown (filed as Exhibit 99.2 to the Company’s Current Report on Form 8-K on April 19, 2021, and incorporated herein by reference).
10.23**	Form of Notice of Grant for Restricted Stock Units (with form of associated Restricted Stock Unit Agreement attached thereto) (filed as Exhibit 99.5 to the Company’s Current Report on Form 8-K on January 21, 2021, and incorporated herein by reference).
10.24**	Form of Notice of Grant for Relative Total Shareholder Return Performance Share Units (with form of associated Phantom Share Unit Agreement attached thereto) (filed as Exhibit 99.6 to the Company’s Current Report on Form 8-K/A on February 5, 2021, and incorporated herein by reference).
10.25**	Form of Notice of Grant for Absolute Total Shareholder Return Performance Share Units (with form of associated Phantom Share Unit Agreement attached thereto) (filed as Exhibit 99.7 to the Company’s Current Report on Form 8-K/A on February 5, 2021, and incorporated herein by reference).
10.26	First Amendment to Credit Agreement, dated as of February 19, 2021, among Oasis Petroleum Inc., as parent, Oasis Petroleum North America LLC, as borrower, Oasis Petroleum LLC, as OP LLC, the lenders party thereto and Wells Fargo Bank, N.A., as administrative agent (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on February 24, 2021, and incorporated herein by reference).
10.27	Second Amendment to Credit Agreement, dated March 22, 2021, by and among Oasis Petroleum Inc., as parent, Oasis Petroleum LLC, a Delaware limited liability company, Oasis Petroleum North America LLC, a Delaware limited liability company, as borrower, the guarantors party thereto, Wells Fargo Bank, N.A., as administrative agent, issuing bank and swingline lender, and the lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on March 22, 2021, and incorporated herein by reference).
10.28	Third Amendment to Credit Agreement, dated May 3, 2021, by and among Oasis Petroleum Inc., as parent, Oasis Petroleum LLC, a Delaware limited liability company, Oasis Petroleum North America LLC, a Delaware limited liability company, as borrower, the guarantors party thereto, Wells Fargo Bank, N.A., as administrative agent, issuing bank and swingline lender, and the lenders party thereto (filed as Exhibit 10.9 to the Company’s Quarterly Report on Form 10-Q on May 6, 2021, and incorporated herein by reference).
10.29	Fourth Amendment to Credit Agreement, dated May 21, 2021, by and among Oasis Petroleum Inc., as parent, Oasis Petroleum LLC, a Delaware limited liability company, Oasis Petroleum North America LLC, a Delaware limited liability company, as borrower, the guarantors party thereto, Wells Fargo Bank, N.A., as administrative agent, issuing bank, swingline lender, and the lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on May 21, 2021, and incorporated herein by reference).
10.30	Fifth Amendment to Credit Agreement, dated October 21, 2021, by and among Oasis Petroleum Inc., as parent, Oasis Petroleum LLC, a Delaware limited liability company, Oasis Petroleum North America LLC, a Delaware limited liability company, as borrower, the guarantors party thereto, Wells Fargo Bank, N.A., as administrative agent, issuing bank and swingline lender, and the lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on October 22, 2021, and incorporated herein by reference).
10.31	Sixth Amendment to Credit Agreement, dated December 22, 2021, by and among Oasis Petroleum Inc., as parent, Oasis Petroleum LLC, a Delaware limited liability company, Oasis Petroleum North America LLC, a Delaware limited liability company, as borrower, the guarantors party thereto, Wells Fargo Bank, N.A., as administrative agent, issuing bank and swingline lender, and the lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on December 29, 2021, and incorporated herein by reference).

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Exhibit No.	Description of Exhibit
10.32	Commitment Letter, dated as of May 3, 2021, by and among the Company and JPMorgan Chase Bank, N.A. and Wells Fargo Bank, National Association (filed as Exhibit 10.10 to the Company’s Quarterly Report on Form 10-Q on May 6, 2021, and incorporated herein by reference).
10.33	Purchase Agreement, dated as of May 25, 2021 among Oasis Petroleum Inc., the Guarantors and J.P. Morgan Securities LLC as representative of the several initial purchasers named therein (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on May 26, 2021, and incorporated herein by reference).
10.34	Support Agreement, dated October 25, 2021, by and among Crestwood Equity Partners LP, Oasis Midstream Partners LP, Oasis Petroleum Inc., OMP GP LLC and OMS Holdings LLC (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on October 28, 2021, and incorporated herein by reference).
10.35**	Whiting Petroleum Corporation 2020 Equity Incentive Plan (filed as Exhibit 99.1 to the Company’s Registration Statement on Form S-8 on July 14, 2022, and incorporated herein by reference).
10.36**	Executive Employment and Severance Agreement, dated February 2, 2021, by and between Whiting Petroleum Corporation and Lynn A. Peterson (filed as Exhibit 10.1 to Whiting’s Current Report on Form 8-K on February 4, 2021, and incorporated herein by reference).
10.37**	Letter Agreement, dated as of March 7, 2022, between Oasis Petroleum Inc. and Lynn A. Peterson (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on March 8, 2022, and incorporated herein by reference).
10.38**	Executive Employment and Severance Agreement by and between Whiting Petroleum Corporation and Charles J. Rimer, effective as of February 2, 2021 (filed as Exhibit 10.3 to Whiting’s Current Report on Form 8-K on February 4, 2021, and incorporated herein by reference).
10.39**	First Addendum to Executive Employment and Severance Agreement by and between Whiting Petroleum Corporation and Charles J. Rimer, dated April 13, 2022 (filed as Exhibit 10.1 to Whiting’s Current Report on Form 8-K on April 15, 2022, and incorporated herein by reference).
10.40(a)**	Second Addendum to Executive Employment and Severance Agreement by and between Whiting Petroleum Corporation and Charles J. Rimer, effective as of January 1, 2023.
10.41**	Form of Executive Employment Agreement and Severance Agreement for former executive officers of Whiting Petroleum Corporation who served or are serving as executive officers of Chord Energy Corporation other than Lynn A. Peterson, James P. Henderson and Charles J. Rimer (filed as Exhibit 10.20 to Whiting’s Annual Report on Form 10-K on February 24, 2021, and incorporated herein by reference).
10.42(a)**	Oasis Petroleum Inc. 2021 Executive Change in Control and Severance Benefit Plan.
10.43(a)**	Chord Energy Corporation Restricted Stock Unit Award Agreement (Non-Employee Director Form).
10.44(a)**	Chord Energy Corporation Restricted Stock Unit Award Agreement (Time Vesting Form).
10.45	Series A Warrant Agreement, dated as of September 1, 2020, by and among Whiting Petroleum Corporation, Computershare Inc. and Computershare Trust Company, N.A. (filed as Exhibit 10.2 to Whiting’s Current Report on Form 8-K12B on September 1, 2020, and incorporated herein by reference).
10.46	Series B Warrant Agreement, dated as of September 1, 2020, by and among Whiting Petroleum Corporation, Computershare Inc. and Computershare Trust Company, N.A. (filed as Exhibit 10.3 to Whiting’s Current Report on Form 8-K12B on September 1, 2020, and incorporated herein by reference).

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Exhibit No.	Description of Exhibit
10.47	Warrant Assignment and Assumption Agreement, dated as of July 1, 2022, by and among Oasis Petroleum Inc., Whiting Petroleum Corporation, Computershare Inc. and Computershare Trust Company, N.A. (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K on July 7, 2022, and incorporated herein by reference).
10.48	Amended and Restated Credit Agreement, dated as of July 1, 2022, by and among Oasis Petroleum Inc., Oasis Petroleum LLC, Oasis Petroleum North America LLC, Wells Fargo Bank, N.A., and the other parties party thereto. (filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K on July 7, 2022, and incorporated herein by reference).
10.49	First Amendment to Amended and Restated Credit Agreement, dated as of August 8, 2022, by and among Chord Energy Corporation, Oasis Petroleum North America LLC, Wells Fargo Bank, N.A., and the other parties thereto (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on August 12, 2022, and incorporated herein by reference).
10.50	Second Amendment to Amended and Restated Credit Agreement, dated October 31, 2022, by and among Chord Energy Corporation, Oasis Petroleum North America LLC, Wells Fargo Bank, N.A., and the other parties thereto (filed as Exhibit 10.7 to the Company’s Report on Form 10-Q on November 11, 2022, and incorporated herein by reference).
21.1(a)	List of Subsidiaries of Chord Energy Corporation.
23.1(a)	Consent of PricewaterhouseCoopers LLP.
23.2(a)	Consent of PricewaterhouseCoopers LLP.
23.3(a)	Consent of Netherland, Sewell & Associates, Inc.
23.4(a)	Consent of DeGolyer and MacNaughton.
31.1(a)	Sarbanes-Oxley Section 302 certification of Principal Executive Officer.
31.2(a)	Sarbanes-Oxley Section 302 certification of Principal Financial Officer.
32.1(b)	Sarbanes-Oxley Section 906 certification of Principal Executive Officer.
32.2(b)	Sarbanes-Oxley Section 906 certification of Principal Financial Officer.
99.1	Report of Netherland, Sewell & Associates, Inc., Independent Petroleum Engineers relating to Total Proved Reserves, dated February 2, 2023.
101(a)	The following financial information from Chord’s Annual Report on Form 10-K for the year ended December 31, 2022, formatted in Inline XBRL: (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Stockholders’ Equity, (iv) Consolidated Statements of Cash Flows and (v) Notes to the Consolidated Financial Statements.
104(a)	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

__________________

(a)Filed herewith.

(b)Furnished herewith.

**Management contract or compensatory plan or arrangement.

† Certain schedules and similar attachments have been omitted pursuant to Item 601(a)(5) of Regulation S-K and will be provided to the SEC upon request.

Item 16. Form 10-K Summary

None.

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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 February 28, 2023.

CHORD ENERGY CORPORATION
By:	/s/ Daniel E. Brown
	Daniel E. Brown President & 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 capacity and on the dates indicated:

Signature	Title	Date
/s/ Daniel E. Brown	President & Chief Executive Officer (Principal Executive Officer)	February 28, 2023
Daniel E. Brown
/s/ Michael H. Lou	Executive Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)	February 28, 2023
Michael H. Lou
/s/ Lynn A. Peterson	Executive Chair	February 28, 2023
Lynn A. Peterson
/s/ Douglas E. Brooks	Lead Independent Director	February 28, 2023
Douglas E. Brooks
/s/ Susan M. Cunningham	Director	February 28, 2023
Susan M. Cunningham
/s/ Samantha F. Holroyd	Director	February 28, 2023
Samantha F. Holroyd
/s/ Paul J. Korus	Director	February 28, 2023
Paul J. Korus
/s/ Kevin S. McCarthy	Director	February 28, 2023
Kevin S. McCarthy
/s/ Anne Taylor	Director	February 28, 2023
Anne Taylor
/s/ Cynthia L. Walker	Director	February 28, 2023
Cynthia L. Walker
/s/ Marguerite N. Woung-Chapman	Director	February 28, 2023
Marguerite N. Woung-Chapman

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GLOSSARY OF TERMS

The terms defined in this section are used throughout this Annual Report on Form 10-K:

“Basin.” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

“Bbl.” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate, natural gas liquids or fresh water.

“Bcf.” One billion cubic feet of natural gas.

“Boe.” Barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of crude oil.

“Boepd.” Barrels of oil equivalent per day.

“British thermal unit.” The heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

“Completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“DAPL.” Dakota Access Pipeline.

“Developed acreage.” The number of acres that are allocated or assignable to productive wells or wells capable of production.

“Developed reserves.” Reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or for which the cost of required equipment is relatively minor when compared to the cost of a new well.

“Development well.” A well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

“Dry hole.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

“Economically producible.” A resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

“Environmental assessment.” An environmental assessment, a study that can be required pursuant to federal law to assess the potential direct, indirect and cumulative impacts of a project.

“ESG.” Environmental, social and governance.

“Exploratory well.” 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 natural gas in another reservoir.

“FDIC.” Federal Deposit Insurance Corporation

“Field.” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

“Formation.” A layer of rock which has distinct characteristics that differ from nearby rock.

“GAAP.” Generally accepted accounting principles in the United States.

“GHG(s).” Greenhouse Gas(es). Gases in the atmosphere known to trap heat, the most prevalent of which are carbon dioxide, methane, nitrous oxide and water vapor, among many others.

“Horizontal drilling.” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

“MBbl.” One thousand barrels of crude oil, condensate, natural gas liquids or fresh water.

“MBoe.” One thousand barrels of oil equivalent.

“Mcf.” One thousand cubic feet of natural gas.

“MMBbl.” One million barrels of crude oil, condensate, natural gas liquids or fresh water.

“MMBoe.” One million barrels of oil equivalent.

“MMBtu.” One million British thermal units.

“MMcf.” One million cubic feet of natural gas.

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“Net acres.” The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.

“NGL.” Natural gas liquids.

“NYMEX.” The New York Mercantile Exchange.

“OPEC+.” The Organization of Petroleum Exporting Countries and other oil exporting nations.

“Plug.” A down-hole packer assembly used in a well to seal off or isolate a particular formation for testing, acidizing, cementing, etc.; also a type of plug used to seal off a well temporarily while the wellhead is removed.

“Possible reserves.” Additional reserves that are less certain to be recovered than probable reserves.

“Probable reserves.” 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.

“Productive well.” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

“Proppant.” Sized particles mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment. In addition to naturally occurring sand grains, man-made or specially engineered proppants, such as resin-coated sand or high-strength ceramic materials like sintered bauxite, may also be used. Proppant materials are carefully sorted for size and sphericity to provide an efficient conduit for production of fluid from the reservoir to the wellbore.

“Proved developed reserves.” Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

“Proved reserves.” 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. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible crude oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil, 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. 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 (i) 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 (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. 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.

“Proved undeveloped reserves or PUD reserves.” Proved reserves 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.

“PV-10.” When used with respect to oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC.

“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 percent 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 with time, reasonably certain estimated ultimate recovery is much more likely to increase or remain constant than to decrease.

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“Recompletion.” The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

“Reserves.” Estimated remaining quantities of crude oil and natural gas and related substances anticipated to be economically producible as of a given date by application of development prospects to known accumulations.

“Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or crude oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

“Resource play.” An expansive contiguous geographical area with known accumulations of crude oil or natural gas reserves that has the potential to be developed uniformly with repeatable commercial success due to advancements in horizontal drilling and completion technologies.

“SEC.” The U.S. Securities and Exchange Commission.

“Spacing.” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

“Throughput.” The volume of product passing through a pipeline, plant, terminal or other facility.

“Turn-in-line” or “TIL” To turn a drilled and completed well online to begin sales.

“Unconventional resource.” An umbrella term for crude oil and natural gas that is produced by means that do not meet the criteria for conventional production. What has qualified as “unconventional” at any particular time is a complex function of resource characteristics, the available E&P technologies, the economic environment, and the scale, frequency and duration of production from the resource. Perceptions of these factors inevitably change over time and often differ among users of the term. At present, the term is used in reference to crude oil and natural gas resources whose porosity, permeability, fluid trapping mechanism, or other characteristics differ from conventional sandstone and carbonate reservoirs. Coalbed methane, gas hydrates, shale gas, fractured reservoirs and tight gas sands are considered unconventional resources.

“Unit.” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

“Well stimulation.” A treatment performed to restore or enhance the productivity of a well. Stimulation treatments fall into two main groups, hydraulic fracturing treatments and matrix treatments. Fracturing treatments are performed above the fracture pressure of the reservoir formation and create a highly conductive flow path between the reservoir and the wellbore. Matrix treatments are performed below the reservoir fracture pressure and generally are designed to restore the natural permeability of the reservoir following damage to the near-wellbore area. Stimulation in shale gas reservoirs typically takes the form of hydraulic fracturing treatments.

“Wellbore.” The hole drilled by the bit that is equipped for crude oil or gas production on a completed well. Also called well or borehole.

“Working interest.” The right granted to the lessee of a property to explore for and to produce and own crude oil, gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

“Workover.” The repair or stimulation of an existing productive well for the purpose of restoring, prolonging or enhancing the production of hydrocarbons.

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