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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, 2021
    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
Commission File No. 001-13726
chk-20211231_g1.jpg
CHESAPEAKE ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
Oklahoma
73-1395733
(State or other jurisdiction of incorporation or organization)(I.R.S. Employer Identification No.)
6100 North Western Avenue,
Oklahoma City,
Oklahoma
73118
(Address of principal executive offices)(Zip Code)
(405)
 848-8000
(Registrant’s telephone number, including area code)
Securities Registered Pursuant to Section 12(b) of the Act:
Title of Each ClassTrading Symbol(s)Name of Each Exchange on Which Registered
Common Stock, $0.01 par value per shareCHKThe Nasdaq Stock Market LLC
Class A Warrants to purchase Common StockCHKEWThe Nasdaq Stock Market LLC
Class B Warrants to purchase Common StockCHKEZThe Nasdaq Stock Market LLC
Class C Warrants to purchase Common StockCHKELThe Nasdaq Stock Market LLC
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes      No 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act. Yes      No 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes     No  
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes     No  
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer   Accelerated Filer   Non-accelerated Filer  
Smaller Reporting Company   Emerging Growth Company  
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 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.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes    No  
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 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 No 
The aggregate market value of our common stock held by non-affiliates on June 30, 2021, was approximately $1.6 billion. As of February 21, 2022, there were 118,558,307 shares of our $0.01 par value common stock outstanding.
__________________________________________
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement for the 2022 Annual Meeting of Shareholders are incorporated by reference in Part III.




PART I
Page
PART II
PART III
PART IV

3

TABLE OF CONTENTS
Definitions
Unless the context otherwise indicates, references to “us,” “we,” “our,” “ours,” “Chesapeake,” the “Company” and “Registrant” refer to Chesapeake Energy Corporation and its consolidated subsidiaries. All monetary values, other than per unit and per share amounts, are stated in millions of U.S. dollars unless otherwise specified. In addition, the following are other abbreviations and definitions of certain terms used within this Annual Report on Form 10-K:
“Adjusted Free Cash Flow” (a non-GAAP measure) means net cash provided by operating activities (GAAP) less cash capital expenditures, adjusted to exclude certain items management believes affect the comparability of operating results.
“ASC” means Accounting Standards Codification.
“Backstop Commitment Agreement” means that certain Backstop Commitment Agreement, dated as of June 28, 2020, by and between Chesapeake and the Backstop Parties, as may be further amended, modified, or supplemented from time to time, in accordance with its terms.
“Backstop Parties” means the members of the FLLO Ad Hoc Group that are signatories to the Backstop Commitment Agreement and Franklin Advisers, Inc., as investment manager on behalf of certain funds and accounts.
“Bankruptcy Code” means Title 11 of the United States Code, 11 U.S.C. §§ 101–1532, as amended.
“Bankruptcy Court” means the United States Bankruptcy Court for the Southern District of Texas.
“Bbl” or “Bbls” means barrel or barrels.
“Bcf” means billion cubic feet.
“Boe” means barrel of oil equivalent. Natural gas proved reserves and production are converted to Boe, at the pressure and temperature base standard of each respective state in which the natural gas is produced, at the rate of six Mcf of gas per Bbl of oil, based upon the approximate relative energy content of natural gas and oil. NGL proved reserves and production are converted to Boe on a one-to-one basis with oil.
“Chapter 11 Cases” means, when used with reference to a particular Debtor, the case pending for that Debtor under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court, and when used with reference to all the Debtors, the procedurally consolidated Chapter 11 cases pending for the Debtors in the Bankruptcy Court.
“Chief” means Chief E&D Holdings, LP.
“Chief Acquisition” means Chesapeake’s planned acquisition of Chief E&D Holdings, LP and associated non-operated interests held by affiliates of Tug Hill, Inc., which, subject to the satisfaction or waiver of certain closing conditions, including certain regulatory approvals, is expected to close in the first quarter of 2022.
“Class A Warrants” means warrants to purchase 10 percent of the New Common Stock (after giving effect to the Rights Offering, but subject to dilution by the Management Incentive Plan, the Class B Warrants, and the Class C Warrants), at an initial exercise price per share of $27.63. The Class A Warrants are exercisable from the Effective Date until February 9, 2026.
“Class B Warrants” means warrants to purchase 10 percent of the New Common Stock (after giving effect to the Rights Offering, but subject to dilution by the Management Incentive Plan and the Class C Warrants), at an initial exercise price per share of $32.13. The Class B Warrants are exercisable from the Effective Date until February 9, 2026.
“Class C Warrants” means warrants to purchase 10 percent of the New Common Stock (after giving effect to the Rights Offering, but subject to dilution by the Management Incentive Plan), at an initial exercise price per share of $36.18. The Class C Warrants are exercisable from the Effective Date until February 9, 2026.
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“Completion” means the process of treating a drilled well followed by the installation of permanent equipment for the production of oil, natural gas or natural gas liquids, or in the case of a dry well, the reporting to the appropriate authority that the well has been abandoned.
“Confirmation Order” means the order confirming the Fifth Amended Joint Chapter 11 Plan of Reorganization of Chesapeake Energy Corporation and its Debtor Affiliates, Docket No. 2915, entered by the Bankruptcy Court on January 16, 2021.
“Debtors” means the Company, together with all of its direct and indirect subsidiaries that have filed the Chapter 11 Cases.
“Developed Acreage” means acres which are allocated or assignable to producing wells or wells capable of production.
“DIP Facility” means that certain debtor-in-possession financing facility documented pursuant to the DIP Documents and DIP Order.
“Dry Well” means a well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
“Effective Date” means February 9, 2021.
“Exit Credit Facility” means the reserve-based revolving credit facility available upon emergence from bankruptcy.
“Exploratory Well” means 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.
“FLLO Term Loan Facility” means the facility outstanding under the FLLO Term Loan Facility Credit Agreement.
“FLLO Term Loan Facility Credit Agreement” means that certain Term Loan Agreement, dated as of December 19, 2019 ((i) as supplemented by that certain Class A Term Loan Supplement, dated as of December 19, 2019 (as amended, restated or otherwise modified from time to time), by and among Chesapeake, as borrower, the Debtor guarantors party thereto, GLAS USA LLC, as administrative agent, and the lenders party thereto, and (ii) as further amended, restated, or otherwise modified from time to time), by and among Chesapeake, the Debtor guarantors party thereto, GLAS USA LLC, as administrative agent, and the lenders party thereto.
“Formation” means a succession of sedimentary beds that were deposited under the same general geologic conditions.
“Free Cash Flow” (a non-GAAP measure) means net cash provided by operating activities (GAAP) less cash capital expenditures.
“GAAP” means U.S. generally accepted accounting principles.
“General Unsecured Claim” means any Claim against any Debtor that is not otherwise paid in full during the Chapter 11 Cases pursuant to an order of the Bankruptcy Court and is not an Administrative Claim, a Priority Tax Claim, an Other Priority Claim, an Other Secured Claim, a Revolving Credit Facility Claim, a FLLO Term Loan Facility Claim, a Second Lien Notes Claim, an Unsecured Notes Claim, an Intercompany Claim, or a Section 510(b) Claim.
“Gross Acres or Gross Wells” means the total acres or wells, as the case may be, in which a working interest is owned.
“MBbls” means thousand barrels.
“MMBbls” means million barrels.
“MBoe” means thousand Boe.
“MMBoe” means million Boe.
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“Mcf” means thousand cubic feet.
“MMcf” means million cubic feet.
“Net Acres or Net Wells” means the sum of the fractional working interests owned in gross acres or gross wells.
“New Common Stock” means the single class of common stock issued by Reorganized Chesapeake on the Effective Date.
“NGL” means natural gas liquids.
“NYMEX” means New York Mercantile Exchange.
“OPEC” means Organization of the Petroleum Exporting Countries.
“Petition Date” means June 28, 2020, the date on which the Debtors commenced the Chapter 11 Cases.
“Plan” means the Fifth Amended Joint Chapter 11 Plan of Reorganization of Chesapeake Energy Corporation and its Debtor Affiliates, attached as Exhibit A to the Confirmation Order.
“Play” means a portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential oil, natural gas and NGL reserves.
“Present Value of Estimated Future Net Revenues or PV-10 (non-GAAP)” means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices calculated as the average oil and natural gas price during the preceding 12-month period prior to the end of the current reporting period, (determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period) and costs in effect at the determination date (unless such costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%.
“Price Differential” means the difference in the price of oil, natural gas or NGL received at the sales point and the NYMEX price.
“Productive Well” means a well that is not a dry well. Productive wells include producing wells and wells that are mechanically capable of production.
“Proved Developed Reserves” means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.
“Proved Properties” means properties with proved reserves.
“Proved Reserves” As used in this report, proved reserves has the meaning given to such term in Rule 4-10(a)(22) of Regulation S-X, which states in part proved oil and natural gas reserves are those quantities of 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 – 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.
“Proved Undeveloped Reserves (PUDs)” means 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. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
“Put Option Premium” means a nonrefundable aggregate fee of $60 million, which represents 10 percent of the Rights Offering Amount, payable to the Backstop Parties in accordance with, and subject to the terms of the
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Backstop Commitment Agreement based on their respective backstop commitment percentages at the time such payment is made.
“Reservoir” means a porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
“Rights Offering” means the New Common Stock rights offering for the Rights Offering Amount consummated by the Debtors on the Effective Date.
“SEC” means United States Securities and Exchange Commission.
“Second Lien Notes” means the 11.50% senior notes due 2025 issued by Chesapeake pursuant to the Second Lien Notes Indenture.
“Second Lien Notes Claim” means any Claim on account of the Second Lien Notes.
“Standardized Measure” means the discounted future net cash flows relating to proved reserves based on the means of the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices calculated as the average oil and natural gas price during the preceding 12-month period prior to the end of the current reporting period (determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period). The standardized measure differs from the PV-10 measure only because the former includes the effects of estimated future income tax expenses.
“Tranche A Loans” means the fully revolving loans made under and on the terms set forth under the Exit Credit Facility which will be partially funded on the Effective Date, will have a scheduled maturity of 3 years from the Effective Date, and shall at all times be repaid prior to the repayment of the Tranche B Loans.
“Tranche B Loans” means term loans made under and on the terms set forth under the Exit Credit Facility which will be fully funded on the Effective Date, will have a scheduled maturity of 4 years from the Effective Date, will be repaid or prepaid only after there are no Tranche A Loans outstanding, and once so prepaid or repaid, may not be reborrowed.
“Undeveloped Acreage” means acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and natural gas regardless of whether the acreage contains proved reserves.
“Unproved Properties” means properties with no proved reserves.
“Vine Acquisition” means Chesapeake’s acquisition of Vine Energy Inc. which closed on November 1, 2021.
“Vine” means Vine Energy Inc.
“Volumetric Production Payment (VPP)” means a limited-term overriding royalty interest in oil and natural gas reserves that: (i) entitles the purchaser to receive scheduled production volumes over a period of time from specific lease interests; (ii) is free and clear of all associated future production costs and capital expenditures; (iii) is nonrecourse to the seller (i.e., the purchaser's only recourse is to the reserves acquired); (iv) transfers title of the reserves to the purchaser; and (v) allows the seller to retain the remaining reserves, if any, after the scheduled production volumes have been delivered.
“Warrants” means collectively, the Class A Warrants, Class B Warrants and Class C Warrants.
“Working Interest” means the operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.
“WTI” means West Texas Intermediate.
“/Bbl” means per barrel.
“/Boe” means per Boe.
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“/Mcf” means per Mcf.
“2019 Predecessor Period” means the year ended December 31, 2019.
“2020 Predecessor Period” means the year ended December 31, 2020.
“2021 Predecessor Period” means the period of January 1, 2021 through February 9, 2021.
“2021 Successor Period” means the period of February 10, 2021 through December 31, 2021.
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Forward-Looking Statements
This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). Forward-looking statements include our current expectations or forecasts of future events, including matters relating to the continuing effects of the COVID-19 pandemic and the impact thereof on our business, financial condition, results of operations and cash flows, the potential effects of the Plan restructuring on our operations, management, and employees, actions by, or disputes among or between, members of OPEC+ and other foreign oil-exporting countries, market factors, market prices, our ability to meet debt service requirements, our ability to continue to pay cash dividends, the amount and timing of any cash dividends, our ESG initiatives, and the other items discussed in the Introduction to Item 7 of Part II of this report. In this context, forward-looking statements often address our expected future business, financial performance and financial condition, and often contain words such as "expect," “could,” “may,” "anticipate," "intend," "plan," “ability,” "believe," "seek," "see," "will," "would," “estimate,” “forecast,” "target," “guidance,” “outlook,” “opportunity” or “strategy.”
Although we believe the expectations and forecasts reflected in our forward-looking statements are reasonable, they are inherently subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. No assurance can be given that such forward-looking statements will be correct or achieved or that the assumptions are accurate or will not change over time. Particular uncertainties that could cause our actual results to be materially different than those expressed in our forward-looking statements include:
the ability to execute on our business strategy following emergence from bankruptcy;
the impact of the COVID-19 pandemic and its effect on our business, financial condition, employees, contractors, vendors and the global demand for oil and natural gas and U.S. and world financial markets;
risks related to the Vine Acquisition, including our ability to successfully integrate the business of Vine into the Company and achieve the expected synergies from the Vine Acquisition within the expected timeframe;
risks related to the Chief Acquisition, including a delay or failure to complete the Chief Acquisition caused by a failure to receive required regulatory approvals or satisfy or waive, as applicable, other closing conditions to the Chief Acquisition, and if the Chief Acquisition is completed, our ability to successfully integrate the business of Chief into the Company and achieve the expected synergies from the Chief Acquisition within the expected timeframe;
our ability to comply with the covenants under our Exit Credit Facility and other indebtedness;
our ability to realize our anticipated cash cost reductions;
the volatility of oil, natural gas and NGL prices, which are affected by general economic and business conditions, as well as increased demand for (and availability of) alternative fuels and electric vehicles;
uncertainties inherent in estimating quantities of oil, natural gas and NGL reserves and projecting future rates of production and the amount and timing of development expenditures;
our ability to replace reserves and sustain production;
drilling and operating risks and resulting liabilities;
our ability to generate profits or achieve targeted results in drilling and well operations;
the limitations our level of indebtedness may have on our financial flexibility;
our inability to access the capital markets on favorable terms;
the availability of cash flows from operations and other funds to finance reserve replacement costs or satisfy our debt obligations;
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adverse developments or losses from pending or future litigation and regulatory proceedings, including royalty claims;
legislative, regulatory and environmental, social and governance (“ESG”) initiatives, including as a result of the change in the U.S. presidential administration, addressing environmental concerns, including initiatives addressing the impact of global climate change or further regulating hydraulic fracturing, methane emissions, flaring or water disposal;
terrorist activities and/or cyber-attacks adversely impacting our operations;
effects of purchase price adjustments and indemnity obligations; and
other factors that are described under Risk Factors in Item 1A of Part I of this Annual Report on Form 10-K (this “Form 10-K” or this “report”).
We caution you not to place undue reliance on the forward-looking statements contained in this report, which speak only as of the filing date, and we undertake no obligation to update this information. We urge you to carefully review and consider the disclosures in this report and our other filings with the SEC that attempt to advise interested parties of the risks and factors that may affect our business.
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PART I
ITEM 1.Business
Unless the context otherwise requires, references to “Chesapeake,” the “Company,” “us,” “we” and “our” in this report are to Chesapeake Energy Corporation together with its subsidiaries. Our principal executive offices are located at 6100 North Western Avenue, Oklahoma City, Oklahoma 73118, and our main telephone number at that location is (405) 848-8000.
Our Business
We are an independent exploration and production company engaged in the acquisition, exploration and development of properties to produce oil, natural gas and NGL from underground reservoirs. We own a large and geographically diverse portfolio of onshore U.S. unconventional natural gas and liquids assets, including interests in approximately 8,200 gross oil and natural gas wells.
On June 28, 2020, we and certain of our subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Bankruptcy Court confirmed the Plan in a bench ruling on January 13, 2021 and entered the Confirmation Order on January 16, 2021. The Debtors emerged from bankruptcy on February 9, 2021. Upon emergence, all existing equity was canceled and New Common Stock was issued to the previous holders of our FLLO Term Loan Facility, Second Lien Notes, senior unsecured notes and certain general unsecured creditors whose claims were impaired as a result of our bankruptcy, as well as to other parties as set forth in the Plan, including to other parties participating in a $600 million rights offering. Upon emergence from bankruptcy, we adopted fresh start accounting, which resulted in us becoming a new entity for financial reporting purposes. Accordingly, the consolidated financial statements on or after February 9, 2021 are not comparable to the consolidated financial statements prior to that date. To facilitate our discussion in this report, we refer to the post-emergence reorganized company as the “Successor” and the pre-emergence company as the “Predecessor.” See Note 2 and Note 3 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion of our bankruptcy, the resulting reorganization and fresh start accounting.
On November 1, 2021, we completed our acquisition of Vine, an energy company focused on the development of natural gas properties in the over-pressured stacked Haynesville and Mid-Bossier shale plays in Northwest Louisiana. The Vine Acquisition strengthens Chesapeake’s competitive position, meaningfully increasing our Free Cash Flow outlook and deepening our inventory of premium natural gas locations, while preserving the strength of our balance sheet.
On January 24, 2022, we entered into a definitive agreement to acquire Chief and associated non-operated interests held by affiliates of Tug Hill, Inc. (“Tug Hill”), for $2.0 billion in cash and approximately 9.44 million common shares. Chief and Tug Hill hold producing assets and an inventory of premium drilling locations in the Marcellus Shale in Northeast Pennsylvania. The cash portion of the Chief Acquisition will be financed with cash on hand and the use of our Exit Credit Facility. The Chief Acquisition, which is subject to customary closing conditions, including certain regulatory approvals, is expected to close by the end of the first quarter of 2022.
On January 24, 2022, we entered into an agreement to sell our Powder River Basin assets in Wyoming to Continental Resources, Inc. for approximately $450 million in cash. The transaction, which is subject to certain customary closing conditions, is expected to close in the first quarter of 2022.
The completion of these transactions will clarify and strengthen our asset portfolio, concentrating on three operating areas and advancing our highest-return assets in the Marcellus and Haynesville gas basins.
Information About Us
We make available, free of charge on our website at chk.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. From time to time, we also post announcements, updates, events, investor information and presentations on our website in addition to copies of all recent news releases. Documents and information on our website are not incorporated by reference herein.
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The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers, including Chesapeake, that file electronically with the SEC.
Business Strategy
Consistent returns, sustainable future. Our strategy is to create shareholder value by generating sustainable Free Cash Flow from our oil and natural gas development and production activities. We continue to focus on improving margins through operating efficiencies and financial discipline and improving our Environmental, Social, and Governance (“ESG”) performance. To accomplish these goals, we intend to allocate our human resources and capital expenditures to projects we believe offer the highest cash return on capital invested, to deploy leading drilling and completion technology throughout our portfolio and to take advantage of acquisition and divestiture opportunities to strengthen our portfolio. We also intend to continue to dedicate capital to projects that reduce the environmental impact of our oil and natural gas producing activities. We continue to seek opportunities to reduce cash costs (production, gathering, processing and transportation and general and administrative) per barrel of oil equivalent production through operational efficiencies, including but not limited to improving our production volumes from existing wells. We believe that we have emerged from Chapter 11 bankruptcy as a fundamentally stronger company, built to generate sustainable Free Cash Flow with a strengthened balance sheet, geographically diverse asset base and continuously improving ESG performance.
Maintain low leverage and strong liquidity. Subsequent to our emergence from Chapter 11 bankruptcy, we believe that maintaining low net leverage is integral to our business strategy and will allow us to maintain lower fixed costs, improve our margins and maintain the flexibility of our capital program.
Returns-focused capital reinvestment strategy. Our business focus will be on optimizing the development of our large, geographically diverse resource base with a prioritization of generating high cash returns on capital invested. We expect our maintenance capital program to yield in excess of annual production of 700 mboe per day and generate significant Free Cash Flow at today’s prevailing commodity market prices.
Low-cost operator with expected top-quartile cash costs. We expect to continue to focus on our cost optimization initiatives.
Continue efforts to reduce greenhouse gas (GHG) emissions and operate in an environmentally responsible manner with a goal of net zero direct GHG emissions by 2035. We are committed to operating our business responsibly and protecting the environments in which we operate. We eliminated routine flaring on all new wells completed in 2021, and plan to accomplish the same on all wells enterprise-wide by 2025. We reduced our methane loss rate to 0.08% and our GHG intensity to 5.0 as of December 31, 2021.
Manage commodity price exposure and ensure stability through prudent hedging strategy. We employ a prudent hedging strategy, which is aligned with our capital expenditure program and is designed to manage our exposure to commodity price volatility, ensure the stability of our cash flows and mitigate our risks to realizing attractive cash returns on capital invested. As of February 21, 2022, we have 11 mmbbls and 899 bcf of expected 2022 production, representing 58% and 68% of 2022 forecasted oil and natural gas production, hedged at prices of $44.30/bbl and $2.69/mcf, respectively, for swaps and $3.21/mcf to $4.26/mcf, respectively, for collars. Additionally, as of February 21, 2022, we have hedged 6 mmbbl and 467 bcf of expected 2023 oil and natural gas production at prices of $47.17/bbl and $2.69/mcf, respectively, for swaps and $65.00/bbl to $79.09/bbl and $3.03/mcf to $4.02/mcf, respectively, for collars. Metrics include hedges that are contingent upon the closing of the Chief Acquisition.
Operating Areas
We focus our acquisition, exploration, development and production efforts in the geographic operating areas described below.
Marcellus - Northern Appalachian Basin in Pennsylvania.
Haynesville - Haynesville/Bossier Shales in Northwestern Louisiana.
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Eagle Ford - Eagle Ford Shale in South Texas.
Powder River Basin - Stacked pay in Wyoming (purchase and sale agreement to divest executed on January 24, 2022, and which, subject to the satisfaction or waiver of certain closing conditions, is expected to close in the first quarter of 2022).
Well Data
As of December 31, 2021, we held an interest in approximately 8,200 gross productive wells, including 6,500 wells in which we held a working interest and 1,700 wells in which we held an overriding or royalty interest. Of the 6,500 (4,100 net) wells in which we held a working interest, 3,000 (1,700 net) wells were classified as productive natural gas wells and 3,500 (2,400 net) wells were classified as productive oil wells. During 2021, excluding sold properties, we operated 5,700 gross wells and held a non-operating working interest in 800 gross wells. We also completed 126 gross (74 net) wells as operator and participated in another 13 gross (1 net) wells completed by other operators. We operate approximately 98% of our current daily production volumes.
Drilling Activity
The following table sets forth the wells we completed or participated in during the periods indicated. In the table, "gross" refers to the total wells in which we had a working interest and "net" refers to gross wells multiplied by our working interest:
202120202019
Gross%Net%Gross%Net%Gross%Net%
Development:
Productive137 100 74 100 203 100 126 100 414 100 271 100 
Dry— — — — — — — — — — — — 
Total137 100 74 100 203 100 126 100 414 100 271 100 
Exploratory:
Productive100 100 — — — — 20 20 
Dry— — — — 100 100 80 80 
Total100 100 100 100 100 100 
The following table shows the wells we completed or participated in by operating area:
202120202019
 Gross WellsNet WellsGross WellsNet WellsGross WellsNet Wells
Marcellus83 34 79 33 44 22 
Haynesville40 31 21 19 22 16 
Eagle Ford12 86 65 233 164 
Powder River Basin12 75 57 
Mid-Continent— — — 40 12 
Other— — 
Total139 75 205 128 419 276 
As of December 31, 2021, we had 55 gross (32 net) wells in the process of being drilled or completed.
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Production Volumes, Sales Prices, Production Expenses and Gathering, Processing and Transportation Expenses
The following table sets forth information regarding our net production volumes, average sales price received for our production, average sales price of our production combined with our realized gains or losses on derivatives and production and gathering, processing and transportation expenses per boe for the periods indicated:
SuccessorPredecessor
 Period from February 10, 2021 through December 31, 2021Period from January 1, 2021 through February 9, 2021Year Ended December 31, 2020Year Ended December 31, 2019
Net Production:
Oil (mmbbl)23 337 43 
Natural gas (bcf)727 80685 728 
NGL (mmbbl)111 12 
Oil equivalent (mmboe)150 18163 177 
Average Sales Price of Production:
Oil ($ per bbl)$69.07 $53.21 $38.16 $59.16 
Natural gas ($ per mcf)$3.61 $2.45 $1.73 $2.45 
NGL ($ per bbl)$31.37 $25.92 $11.55 $15.62 
Oil equivalent ($ per boe)$29.19 $22.63 $16.84 $25.57 
Average Sales Price (including realized gains (losses) on derivatives):
Oil ($ per bbl)$49.06 $46.85 $56.74 $60.00 
Natural gas ($ per mcf)$2.62 $2.52 $1.97 $2.60 
NGL ($ per bbl)$31.42 $25.55 $11.55 $15.62 
Oil equivalent ($ per boe)$21.46 $21.72 $22.09 $26.42 
Expenses ($ per boe):
Production$1.97 $1.80 $2.29 $2.94 
Gathering, processing and transportation$5.17 $5.78 $6.64 $6.13 

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Oil, Natural Gas and NGL Reserves
The tables below set forth information as of December 31, 2021, with respect to our estimated proved reserves, the associated estimated future net revenue, the present value of estimated future net revenue (“PV-10”) and the standardized measure of discounted future net cash flows (“standardized measure”). None of the estimated future net revenue, PV-10 nor the standardized measure are intended to represent the current market value of the estimated oil, natural gas and NGL reserves we own. All of our estimated reserves are located within the United States.
December 31, 2021
OilNatural GasNGLTotal
(mmbbl)(bcf)(mmbbl)(mmboe)
Proved developed166 4,246 62 935 
Proved undeveloped44 3,578 20 661 
Total proved(a)
210 7,824 82 1,596 

Proved
Developed
Proved
Undeveloped
Total
Proved
Estimated future net revenue(b)
$14,502 $8,776 $23,278 
Present value of estimated future net revenue (PV-10)(b)
$8,654 $5,057 $13,711 
Standardized measure(b)
$12,287 
___________________________________________
(a)    Haynesville, Marcellus, and Eagle Ford accounted for approximately 39%, 36%, and 23% respectively, of our estimated proved reserves by volume as of December 31, 2021.
(b)    Estimated future net revenue represents the estimated future revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using pricing differentials and costs under existing economic conditions as of December 31, 2021, and assuming commodity prices as set forth below. For the purpose of determining prices used in our reserve reports, we used the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended December 31, 2021. The prices used in our PV-10 measure were $66.56 per bbl of oil and $3.60 per mcf of natural gas, before basis differential adjustments. These prices should not be interpreted as a prediction of future prices, nor do they reflect the value of our commodity derivative instruments in place as of December 31, 2021. The amounts shown do not give effect to non-property-related expenses, such as corporate general and administrative expenses and debt service, or to depreciation, depletion and amortization. The present value of estimated future net revenue typically differs from the standardized measure because the former does not include the effects of estimated future income tax expense of $1.424 billion as of December 31, 2021.
Management uses PV-10, which is calculated without deducting estimated future income tax expenses, as a measure of the value of the Company's current proved reserves and to compare relative values among peer companies. We also understand that securities analysts and rating agencies use this measure in similar ways. While estimated future net revenue and the present value thereof are based on prices, costs and discount factors which may be consistent from company to company, the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each individual company. PV-10, a non-GAAP measure, should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows or any other measure of a company's financial or operating performance presented in accordance with GAAP.
A comparison of the standardized measure of discounted future net cash flows to PV-10 is presented above. Neither PV-10 nor the standardized measure of discounted future net cash flows purport to represent the fair value of our proved oil and gas reserves.
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As of December 31, 2021, our proved reserve estimates included 661 mmboe of reserves classified as proved undeveloped, compared to 60 mmboe as of December 31, 2020. Presented below is a summary of changes in our proved undeveloped reserves (“PUDs”) for 2021:
Total
(mmboe)
Proved undeveloped reserves, beginning of period (Predecessor)60 
Extensions and discoveries321 
Revisions of previous estimates145 
Conversion to proved developed reserves(60)
Purchase of reserves-in-place195 
Proved undeveloped reserves, end of period (Successor)661 

As of December 31, 2021, all PUDs were planned to be developed within five years of original recording. In 2021, we invested approximately $97 million to convert 60 mmboe of PUDs to proved developed reserves. In 2022, we estimate that we will invest approximately $794 million for PUD conversion. We added 321 mmboe of proved undeveloped reserves through extensions and discoveries following our emergence from bankruptcy on February 9, 2021 and certainty regarding our ability to finance the development of our proved reserves over a five-year period. In addition, during 2021, we recorded an upward revision of 145 mmboe from previous estimates due to lateral length adjustments, performance and updates to our five-year development plan. We also added 195 mmboe of proved undeveloped reserves through purchase of reserves-in-place related to the Vine Acquisition.
The future net revenue attributable to our estimated PUDs was $8.776 billion and the present value was $5.057 billion as of December 31, 2021. These values were calculated assuming that we will expend approximately $2.7 billion to develop these reserves ($794 million in 2022, $814 million in 2023, $539 million in 2024, $378 million in 2025 and $217 million in 2026). The amount and timing of these expenditures will depend on a number of factors, including actual drilling results, service costs, commodity prices and the availability of capital. Our developmental drilling schedules are subject to revision and reprioritization throughout the year resulting from unknowable factors such as unexpected developmental drilling results, title issues and infrastructure availability or constraints.
Of our 1,596 mmboe of proved developed reserves as of December 31, 2021, approximately 20 mmboe, or 1%, were non-producing.
Our ownership interest used for calculating proved reserves and the associated estimated future net revenue assumes maximum participation by other parties to our farm-out and participation agreements.
Our estimated proved reserves and the standardized measure of discounted future net cash flows of the proved reserves as of December 31, 2021, 2020 and 2019, along with the changes in quantities and standardized measure of the reserves for each of the three years then ended, are shown in Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities included in Item 8 of Part II of this report. No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency other than the SEC.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. The reserve data represents only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary. Accordingly, reserve estimates often differ from the actual quantities of oil, natural gas and NGL that are ultimately recovered. Furthermore, the estimated future net revenue from proved reserves and the associated present value are based upon certain assumptions, including prices, future production levels and costs that may not prove correct. Future prices and costs may be materially higher or lower than the prices and costs as of the date of any estimate. See Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities included in Item 8 of Part II of this report for further discussion of our reserve quantities.
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Reserves Estimation
Our Corporate Reserves Department prepared approximately 9% by volume, and approximately 4% by value, of our estimated proved reserves as of December 31, 2021, disclosed in this report. Those estimates were based upon the best available production, engineering and geologic data.
Our Director – Corporate Reserves, is the technical person primarily responsible for overseeing the preparation of our reserve estimates and for coordinating any reserves work conducted by a third-party engineering firm. Her qualifications include the following:
Over 19 years of practical experience in the oil and gas industry, with over 16 years in reservoir engineering;
Bachelor of Science degree in Geology and Environmental Sciences;
Master’s Degree in Petroleum and Natural Gas Engineering;
Executive MBA; and
member in good standing of the Society of Petroleum Engineers.
We ensure that the key members of our Corporate Reserves Department have appropriate technical qualifications to oversee the preparation of reserve estimates. Each of our Corporate Reserves Engineers has significant engineering experience in reserve estimation. Our engineering technicians have a minimum of a four-year degree in mathematics, economics, finance or other technical/business/science field. We maintain a continuous education program for our engineers and technicians on new technologies and industry advancements as well as refresher training on basic skills and analytical techniques.
We maintain internal controls such as the following to ensure the reliability of reserves estimations:
We follow comprehensive SEC-compliant internal policies to estimate and report proved reserves. Reserve estimates are made by experienced reservoir engineers or under their direct supervision. All material changes are reviewed and approved by Corporate Reserves Engineers.
The Corporate Reserves Department reviews our proved reserves at the close of each quarter.
Each quarter, Reservoir Managers, the Director – Corporate Reserves, the Vice Presidents of each operating area and the Vice President of Corporate and Strategic Planning review all significant reserves changes and all new proved undeveloped reserves additions.    
The Corporate Reserves Department reports independently of our operations.
The five-year PUD development plan is reviewed and approved annually by the Director – Corporate Reserves and the Vice President of Corporate and Strategic Planning.
We engaged LaRoche Petroleum Consultants, Ltd., a third-party engineering firm, to prepare approximately 91% by volume, and approximately 96% by value, of our estimated proved reserves as of December 31, 2021. A copy of the report issued by the engineering firm is filed with this report as Exhibit 99.1. The qualifications of the technical person at the firm primarily responsible for overseeing the preparation of our reserve estimates are set forth below.
Over 40 years of practical experience in the estimation and evaluation of reserves;
licensed professional engineer in the State of Texas; and
Bachelor of Science and Master of Science degrees in Petroleum Engineering.
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Acreage
The following table sets forth our gross and net developed and undeveloped oil and natural gas leasehold and fee mineral acreage as of December 31, 2021. Gross acres are the total number of acres in which we own a working interest. Net acres refer to gross acres multiplied by our fractional working interest. Acreage numbers do not include our unexercised options to acquire additional acreage.
Developed LeaseholdUndeveloped LeaseholdTotal
Gross
Acres
Net
Acres
Gross
Acres
Net
Acres
Gross
Acres
Net
Acres
(in thousands)
Marcellus556 339 216 172 772 511 
Haynesville359 323 33 23 392 346 
Eagle Ford678 478 235 133 913 611 
Powder River Basin106 86 126 95 232 181 
Other(a)
231 212 1,256 1,195 1,487 1,407 
Total1,930 1,438 1,866 1,618 3,796 3,056 
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(a)     Includes 1.2 million net acres retained in the 2016 divestiture of our Devonian Shale assets, in which we retained all rights below the base of the Kope formation.
Most of our leases have a three- to five-year primary term, and we manage lease expirations to ensure that we do not experience unintended material expirations. Our leasehold management efforts include scheduling our drilling to establish production in paying quantities in order to hold leases by production, timely exercising our contractual rights to pay delay rentals to extend the terms of leases we value, planning non-core divestitures to high-grade our lease inventory and letting some leases expire that are no longer part of our development plans. The acreage in the table above includes a total of 0.1 million net acres subject to expiration in the next three years.

Marketing
The principal function of our marketing operations is to provide oil, natural gas and NGL marketing services, including commodity price structuring, securing and negotiating of gathering, hauling, processing and transportation services, contract administration and nomination services for us and other interest owners in Chesapeake-operated wells. The marketing operations also provide other services for our exploration and production activities, including services to enhance the value of oil and natural gas production by aggregating volumes sold to various intermediary markets, end markets and pipelines. This aggregation allows us to attract larger, more creditworthy customers that in turn assist in maximizing the prices received.
Generally, our oil production is sold under market-sensitive short-term or spot price contracts. Natural gas and NGL production are sold to purchasers under percentage-of-proceeds contracts, percentage-of-index contracts or spot price contracts. Under the terms of our percentage-of-proceeds contracts, we receive a percentage of the resale price received from the ultimate purchaser. Under our percentage-of-index contracts, the price we receive is tied to published indices.
We have entered into long-term gathering, processing, and transportation contracts with various parties that require us to deliver fixed, determinable quantities of production over specified periods of time. Certain of our contracts require us to make payments for any shortfalls in delivering or transporting minimum volumes under these commitments. See Note 7 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion of commitments.
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Major Customers
For the 2021 Successor Period, sales to Valero Energy Corporation and Energy Transfer Crude Marketing accounted for approximately 14% and 11%, respectively, of total revenues (before the effects of hedging). For the 2021 Predecessor Period, sales to Valero Energy Corporation accounted for approximately 19% of total revenues (before the effects of hedging). For the 2020 and 2019 Predecessor Periods, sales to Valero Corporation constituted 17% and 12% of total revenues (before the effects of hedging). No other purchasers accounted for more than 10% of our total revenues during the 2021 Successor Period or 2021, 2020 or 2019 Predecessor Periods.
Competition
We compete with both major integrated and other independent oil and natural gas companies in all aspects of our business to explore, develop and operate our properties and market our production. Some of our competitors may have larger financial and other resources than us. Competitive conditions may be affected by future legislation and regulations as the United States develops new energy and climate-related policies. In addition, some of our competitors may have a competitive advantage when responding to factors that affect demand for oil and natural gas production, such as changing prices, domestic and foreign political conditions, weather conditions, the price and availability of alternative fuels, the proximity and capacity of natural gas pipelines and other transportation facilities and overall economic conditions. We also face indirect competition from alternative energy sources, including wind, solar and electric power. We believe that our technological expertise, combined with our exploration, land, drilling and production capabilities and the experience of our management team, enables us to compete effectively.
Public Policy and Government Regulation
All of our operations are conducted onshore in the United States. Our industry is subject to a wide range of regulations, laws, rules, taxes, fees and other policy implementation actions that have been pervasive and are under constant review for amendment or expansion. Numerous government agencies have issued extensive regulations that are binding on our industry, some of which carry substantial penalties for failure to comply. These laws and regulations increase the cost of doing business and consequently affect profitability. Additionally, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. We actively monitor regulatory developments applicable to our industry in order to anticipate, design and implement required compliance activities and systems. The following are significant areas of government control and regulation affecting our operations.
Exploration and Production, Environmental, Health and Safety and Occupational Laws and Regulations
Our operations are subject to federal, tribal, state, and local laws and regulations. These laws and regulations relate to matters that include, but are not limited to, the following:
reporting of workplace injuries and illnesses;
industrial hygiene monitoring;
worker protection and workplace safety;
approval or permits to drill and to conduct operations;
provision of financial assurances (such as bonds) covering drilling and well operations;
calculation and disbursement of royalty payments and production taxes;
seismic operations/data;
location, drilling, cementing and casing of wells;
well design and construction of pad and equipment;
construction and operations activities in sensitive areas, such as wetlands, coastal regions or areas that contain endangered or threatened species, their habitats, or sites of cultural significance;
method of well completion and hydraulic fracturing;
water withdrawal;
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well production and operations, including processing and gathering systems;
emergency response, contingency plans and spill prevention plans;
emissions and discharges permitting;
climate change;
use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations;
surface usage, maintenance, monitoring and the restoration of properties associated with well pads, pipelines, impoundments and access roads;
plugging and abandoning of wells; and
transportation of production.

Shortly after taking office in January 2021, President Biden issued a series of executive orders designed to address climate change and requiring agencies to review environmental actions taken by the Trump administration, as well as a memorandum to departments and agencies to refrain from proposing or issuing rules until a departmental or agency head appointed or designated by the Biden administration has reviewed and approved the rule. In November 2021, the Biden Administration released “The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” which establishes a roadmap to net zero emissions in the United States by 2050 through, among other things, improving energy efficiency; decarbonizing energy sources via electricity, hydrogen, and sustainable biofuels; and reducing non-carbon dioxide GHG emissions, such as methane and nitrous oxide. These executive orders and policy priorities may result in the development of additional regulations or changes to existing regulations, certain of which could negatively impact our financial position, results of operations and cash flows. In addition, the United States is one of almost 200 nations that, in December 2015, agreed to the Paris Agreement, an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will take to achieve its GHG emissions targets. 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. In November 2021, the international community gathered again in Glasgow at the 26th Conference to the Parties on the UN Framework Convention on Climate Change (“COP26”), during which multiple announcements were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-carbon dioxide GHGs. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. In addition, several states and geographic regions in the United States have also adopted legislation and regulations regarding climate change-related matters, and additional legislation or regulation by these states and regions, U.S. federal agencies, including the Environmental Protection Agency (the “EPA”), and/or international agreements to which the United States may become a party could result in increased compliance costs for us and our customers. Failure to comply with these laws and regulations can lead to the imposition of remedial liabilities, administrative, civil or criminal fines or penalties or injunctions limiting our operations in affected areas. Moreover, multiple environmental laws provide for citizen suits which allow environmental organizations to act in the place of the government and sue operators for alleged violations of environmental law. We consider the responsibility and costs of environmental protection and safety and health compliance fundamental, manageable parts of our business. To date, we have been able to plan for and comply with environmental, safety and health laws and regulations without materially altering our operating strategy or incurring significant unreimbursed expenditures. However, based on regulatory trends and increasingly stringent laws, as well as the increasing number of climate-related commitments by capital providers, our capital expenditures and operating expenses related to the protection of the environment and safety and health compliance have increased over the years and may continue to increase. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters.
Our operations also are subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in a unit, the rate of production allowable from oil and gas wells, and the unitization or pooling of oil and gas properties. In the United States, some states allow the statutory pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases, which may make it more difficult to develop oil and gas properties. In addition, federal and state conservation laws generally limit the venting or flaring of natural gas, and state conservation laws impose certain requirements regarding the ratable purchase of production. These regulations limit the amounts of oil and gas we
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can produce from our wells and the number of wells or the locations at which we can drill. For further discussion, see Item 1A. Risk Factors - We are subject to extensive governmental regulation, which can change and could adversely impact our business.
Regulatory proposals in some states and local communities have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. Federal and state agencies have continued to assess the potential impacts of hydraulic fracturing, which could spur further action toward federal, state and/or local legislation and regulation. Further restrictions of hydraulic fracturing could make it difficult or impossible to conduct our drilling and completion operations, and thereby reduce the amount of oil, natural gas and NGL that we are ultimately able to produce from our properties.
Certain of our U.S. natural gas and oil leases, primarily in our Powder River Basin operating area, are granted or approved by the federal government and administered by the Bureau of Land Management (BLM) or Bureau of Indian Affairs (BIA) of the Department of the Interior. Such leases require compliance with 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, tribes or tribal members. The federal government has been particularly active in recent years in evaluating and, in some cases, promulgating new rules and regulations regarding competitive lease bidding, venting and flaring, oil and gas measurement and royalty payment obligations for production from federal lands. On January 20, 2021, the Acting Secretary for the Department of the Interior signed an order effectively suspending new fossil fuel leasing and permitting on federal lands for 60 days. Then on January 27, 2021, President Biden issued an executive order indefinitely suspending new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. A federal district court judge in Louisiana issued a nationwide preliminary injunction on June 15, 2021, effectively preventing the Biden Administration from implementing the pause of new oil and natural gas leases on federal lands and waters and forcing the lease sale. On November 26, 2021, the U.S. Department of the Interior released its “Report On The Federal Oil And Gas Leasing Program,” which assessed the current state of oil and gas leasing on federal lands and proposed several reforms, including raising royalty rates and implementing stricter standards for entities seeking to purchase oil and gas leases. Recently, on January 27, 2022, a federal district court judge 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 from its greenhouse gas emissions analysis. These recent developments and the Biden Administration’s and certain federal courts’ focus on the climate change impacts of federal projects could result in significant changes to the federal oil and gas leasing program in the future. Restrictions surrounding onshore drilling, onshore federal lease availability, and restrictions on the ability to obtain required permits could have a material adverse impact on our operations.
Permitting activities on federal lands are also subject to frequent delays. Delays in obtaining permits or an inability to obtain new permits or permit renewals could inhibit our ability to execute our drilling and production plans. Failure to comply with applicable regulations or permit requirements could result in revocation of our permits, inability to obtain new permits and the imposition of fines and penalties.
For further discussion, see Item 1A. Risk Factors - Oil and natural gas operations are uncertain and involve substantial costs and risks.
Title to Properties
Our title to properties is subject to royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the oil and natural gas industry, to liens for current taxes not yet due and to other encumbrances. As is customary in the industry in the case of undeveloped properties, only cursory investigation of record title is made at the time of acquisition. Drilling title opinions are usually prepared before commencement of drilling operations. We believe we have satisfactory title to substantially all of our active properties in accordance with standards generally accepted in the oil and natural gas industry. Nevertheless, we are involved in title disputes from time to time that may result in litigation.
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Operating Hazards and Insurance
The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, natural gas leaks, ruptures or discharges of toxic gases. If any of these should occur, we could incur legal defense costs and could suffer substantial losses due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations. Our horizontal and deep drilling activities involve greater risk of mechanical problems than vertical and shallow drilling operations.
We maintain a control of well insurance policy with a $50 million single well limit and a $100 million multiple wells limit that insures against certain sudden and accidental risks associated with drilling, completing and operating our wells. This insurance may not be adequate to cover all losses or exposure to liability. We also carry a $250 million comprehensive general liability umbrella insurance policy. In addition, we maintain a $50 million pollution liability insurance policy providing coverage for gradual pollution related risks and in excess of the general liability policy for sudden and accidental pollution risks. We provide workers' compensation insurance coverage to employees in all states in which we operate. While we believe these policies are customary in the industry, they do not provide complete coverage against all operating risks, and policy limits scale to our working interest percentage in certain situations. In addition, our insurance does not cover penalties or fines that may be assessed by a governmental authority. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. Our insurance coverage may not be sufficient to cover every claim made against us or may not be commercially available for purchase in the future.
Facilities
We own an office complex in Oklahoma City and we own or lease various field offices in cities or towns in the areas where we conduct our operations.
Executive Officers
Michael A. Wichterich, Executive Chairman and Director
Michael A. (“Mike”) Wichterich, 53, has served as Executive Chair of Chesapeake's Board of Directors since October 2021. He previously served as Chair of the Board of Directors since February 2021, and as the Company's Interim Chief Executive Officer from April 2021 to October 2021. Mr. Wichterich is Founder and Chief Executive Officer of Three Rivers Operating Company LLC, a private exploration and production company with a focus in the Permian Basin. Prior to founding Three Rivers Operating, Mr. Wichterich served as the Chief Financial Officer of Texas American Resources, New Braunfels Utilities and Mariner Energy. Additionally, Mr. Wichterich began his career with PricewaterhouseCoopers in its energy auditing practice. Mr. Wichterich also serves as a board member of Grizzly Energy. He earned a B.B.A. from the University of Texas.
Domenic J. Dell'Osso, Jr., President, Chief Executive Officer and Director
Domenic J. (“Nick”) Dell'Osso, Jr., 45, has served as President and Chief Executive Officer since October 2021. Prior to being named as CEO, Mr. Dell’Osso served as our Executive Vice President and Chief Financial Officer since November 2010. Mr. Dell'Osso served as our Vice President – Finance and Chief Financial Officer of our wholly owned midstream subsidiary, Chesapeake Midstream Development, L.P., from August 2008 to November 2010. Before joining Chesapeake, Mr. Dell’Osso was an energy investment banker with Jefferies & Co. from 2006 to 2008 and Banc of America Securities from 2004 to 2006. Mr. Dell’Osso graduated from Boston College in 1998 and from the University of Texas at Austin in 2003.
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Mohit Singh, Executive Vice President and Chief Financial Officer
Mohit Singh, 44, was appointed Executive Vice President and Chief Financial Officer in December 2021. For the last six years, Mr. Singh has served on the executive leadership team at BPX Energy, the United States onshore subsidiary of BP (NYSE: BP). He most recently led the M&A, corporate land and reserves functions, having previously served as Head of Business Development and Exploration and as Senior Vice President – North Business Unit. Prior to joining BPX, Mr. Singh worked as an investment banker focused on oil and gas transactions for RBC Capital Markets and Goldman Sachs. A chemical engineer by training, he began his career at Shell Exploration & Production Company where he held business planning, reservoir engineering and research engineering roles of increasing importance. Mr. Singh earned a PhD in Chemical Engineering from the University of Houston, an MBA from the University of Texas and a BTech in Chemical Engineering from the Indian Institute of Technology.
Josh Viets, Executive Vice President and Chief Operating Officer
Josh Viets, 43, was appointed Executive Vice President and Chief Operating Officer in February 2022. For the last 20 years, Mr. Viets has worked in operational positions of increasing importance at ConocoPhillips Company (NYSE: COP). He most recently served as Vice President, Delaware Basin and previously held leadership positions in operations, engineering, subsurface, and capital project across the ConocoPhillips portfolio. Mr. Viets earned a Bachelor of Science in Petroleum Engineering from Colorado School of Mines in 2001.
Benjamin E. Russ, Executive Vice President - General Counsel and Corporate Secretary
Benjamin E. (“Ben”) Russ, 47, was appointed Executive Vice President – General Counsel and Corporate Secretary in June 2021. Prior to that time, he served as Associate General Counsel – Corporate from May 2014 to June 2021; Division Counsel/Senior Division Counsel managing day-to-day legal matters in the Barnett, East Texas and Louisiana from July 2010 to May 2014; and Attorney/Senior Attorney managing litigation in Louisiana from September 2008 to July 2010. Before joining Chesapeake, Mr. Russ worked at Gulfport Energy Corporation serving as Assistant General Counsel from 2005 to 2006 and General Counsel from 2006 to 2008. Prior to Gulfport, he was an associate at the McKinney & Stringer, P.C. Mr. Russ received a B.S. in Finance from Oklahoma State University in 1996 and a J.D. from Oklahoma City University in 2004.
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Human Capital Resources
One Team. One Chesapeake.
Our “One CHK” culture and company core values promote an inclusive, diverse and productive workplace. Working as One CHK defines Chesapeake’s culture and unites our team to achieve shared goals for the benefit of our stakeholders. It is a culture of accountability where innovation and collaboration help us achieve sustainable operational success. We had approximately 1,300 employees as of February 21, 2022.
Our Culture, Our Core Values
At Chesapeake, our employees are driven to create value every day in a safe and responsible manner. Our core values are the foundation of our culture and the driving force behind our goal to achieve ESG excellence. Serving as the lens through which we evaluate every business decision, our commitment to these values, in both words and actions builds a stronger, healthier Chesapeake, benefiting all our stakeholders. Our core values are:
Integrity and Trust
Respect
Transparency and Open Communication
Commercial Focus
Change Leadership
Celebrating Inclusion and Diversity
We are committed to inclusion and diversity. We proactively embrace our diversity of people, thoughts and talents, and combine these strengths to pursue results and meaningful change for our company, employees and stakeholders, and we provide education and training for our employees on topics related to inclusion and diversity.
In 2019, Chesapeake joined a coalition of companies pledging to advance diversity and inclusion in the workplace. On February 9, 2021, we formed a board committee dedicated to ESG oversight, including our inclusion and diversity efforts. Two of the seven members of our Board of Directors are considered diverse, including one female and one “underrepresented minority” (as defined in Nasdaq’s newly proposed listing rule). Chesapeake cultivates a workplace in which diverse perspectives are welcomed and respected and where employees feel encouraged to discuss diversity and inclusion.
Stewards of Our Environment
Chesapeake is committed to protecting our country’s natural resources and reducing our environmental footprint. We have strict standards for environmental stewardship and a culture of environmental excellence among our employees and business partners. We recognize that ownership and accountability are key to helping ensure our work sites are safe and protective of the environment.
Our path to leading a responsible energy future begins with our goal to achieve net-zero direct greenhouse gas emissions by 2035. To meet this challenge, we have set meaningful initial steps including:
Eliminating routine flaring from all new wells completed from 2021 forward, and enterprise-wide by 2025;
Reducing our methane intensity to 0.09% by 2025 (achieved 0.08% in 2021); and
Reducing our GHG intensity to 5.5 by 2025 (achieved 5.0 in 2021).
Safety First Every Day
Safety is more than a company metric, it is core to our commitment to leading a responsible energy future. We set and deliver strict safety standards, prioritizing the well-being of our employees and partners. Our safety culture is championed by our Board of Directors and executive leadership team, owned by every employee and contractor and managed by our Health, Safety, Environmental and Regulatory (HSER) team. Maintaining a safe work environment and promoting safe behaviors is a commitment that each of our employees own together. We hold each other accountable to keeping our sites, our co-workers and our contractors safe.
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One program that reinforces this philosophy of personal responsibility is Stop Work Authority. Through Stop Work Authority, every employee and contractor has the right, responsibility and authority to stop work if conditions are unsafe or could cause harm to the environment. Creating an incident-free work environment starts with setting clear expectations among employees, contractors and suppliers regarding our safety standards, and working to empower and equip individuals with the skills necessary to promote safety in their areas of work. The foundation of our safety training efforts is our Stay Accident Free Every Day (S.A.F.E.) program, which encourages all workers on our locations to take personal responsibility for their safety and the safety of those around them. This behavior-based program addresses the activities that can often lead to safety incidents and encourages actions that create safe work sites and a safe corporate campus.
Every year our HSER team provides targeted trainings based on safety performance analysis, job functions and location specific factors. Our training program includes a mix of in-person and virtual training, with greater emphasis on in-person instruction and includes all employees. Job-specific learning paths aim to exceed regulatory requirements and ensure employees are holistically prepared to execute their job functions safely and responsibly.

Chesapeake’s training philosophy values contractor training in the same manner as employees. We design contractor training to align as much as possible with employee training, encouraging synchronized knowledge sharing and understanding, critical to decreasing our cumulative incidents.
Ethical Business Conduct
Chesapeake works hard to maintain the confidence of our stakeholders. We earn this trust by acting in an ethical manner to protect our people, the environment and the communities where we operate. This starts by driving accountability through all levels of the company and having systems in place to uphold our high standards for conduct. Strong governance practices begin at the top providing our organization with clear guidelines to define standards for ethical behavior at every level. Each Chesapeake director or employee, regardless of position, must abide by Chesapeake’s Code of Business Conduct (the "Code"), which is structured around our core values. Each year all employees must sign a Code certification confirming they have reviewed the Code and related policies, understand the high standards expected of them and will report actual or potential ethics concerns or Code violations.
Employee Wellness and Benefits
Supporting the individual well-being of our employees is foundational to our safety culture and success as a company. We champion healthy lifestyles and offer health resources. Across the company, employees are offered preventive programs and are encouraged to complete an annual screening for common health-related issues. We support our employees’ and their families’ health by offering full medical, dental, vision, prescription drug insurance for employees and their families, life insurance, short- and long-term disability coverage, and health savings and dependent care flexible spending accounts. We offer parental leave for the birth or adoption of a child, an adoption assistance program, alternate work schedules, a 401(k) savings plan with company match, flexible work hours, tuition reimbursement and access to a child development center and fitness center at market rates. Additionally, Chesapeake provides employees and their families access to a confidential Employee Assistance Program (EAP) which connects employees with trained counselors and other support professionals.
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Item 1A.Risk Factors
There are numerous factors that affect our business and results of operations, many of which are beyond our control. The following is a description of factors that we consider to be material and that might cause our future results to differ materially from those currently expected. The risks described below are not the only risks facing our company. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also affect our business operations. If any of these risks actually occur, our business, financial position, results of operations, cash flows, reserves and/or our ability to pay our debts and other liabilities could suffer, the trading price and liquidity of our securities could decline and you may lose all or part of your investment in our securities.

Summary Risk Factors

Risks Related to our Emergence from Bankruptcy
We recently emerged from bankruptcy, which may adversely affect our business and relationships.
Our actual financial results after emergence from bankruptcy may not be comparable to our historical financial information as a result of the implementation of the Plan and the transactions contemplated thereby.
Risks Related to Operating our Business
Conservation measures and technological advances could reduce demand for natural gas and oil.
Negative public perception regarding us or our industry could have an adverse effect on our operations.
The oil and gas exploration and production industry is very competitive; some of our competitors have greater financial and other resources than we do, and there is competition to attract and retain talent, and competition over access to certain industry equipment.
Oil, natural gas and NGL prices fluctuate widely, and lower prices for an extended period of time are likely to have a material adverse effect on our business.
The ongoing coronavirus (COVID-19) pandemic and related economic turmoil have affected and could continue to adversely affect our business, financial condition, results of operations and cash flows.
If commodity prices fall or drilling efforts are unsuccessful, we may be required to record write downs of the carrying value of our oil and natural gas properties.
Significant capital expenditures are required to replace our reserves and conduct our business.
If we are not able to replace reserves, we may not be able to sustain production.
The actual quantities of and future net revenues from our proved reserves may be less than our estimates.
Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.
Certain of our undeveloped properties are subject to leases that will expire over the next several years unless production is established on units containing the acreage or the leases are renewed.
Our commodity price risk management activities may limit the benefit we would receive from increases in commodity prices, may require us to provide collateral for derivative liabilities and involve risk that our counterparties may be unable to satisfy their obligations to us.
Oil and natural gas operations are uncertain and involve substantial costs and risks.
Our ability to produce oil, natural gas and NGL economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.
Risks related to potential acquisitions or dispositions may adversely affect our business.
Our operations may be adversely affected by pipeline, trucking and gathering system capacity constraints and may be subject to interruptions that could adversely affect our cash flow.
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Cyber-attacks targeting systems and infrastructure used by the oil and gas industry and related regulations may adversely impact our operations and, if we or our third-party providers are unable to obtain and maintain adequate protection for our data, our business may be harmed.
Our operations could be disrupted by natural or human causes beyond our control.
Financial Risks Related to our Business
We have significant capital needs, and our ability to access the capital and credit markets to raise capital on favorable terms is limited by industry conditions.
Restrictive covenants in certain of our debt agreements could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.
Changes in the method of determining the London Interbank Offered Rate (LIBOR), or the replacement of LIBOR with an alternative reference rate, may adversely affect interest expense related to outstanding debt.
Risks Related to Recent and Pending Acquisitions
The Chief Acquisition may not be completed. Failure to complete the Chief Acquisition could negatively impact the price of shares of our common stock, as well as our future business and financial results.
The synergies attributable to the Vine Acquisition, or Chief Acquisition, if consummated, may vary from expectations, and we will be subject to business uncertainties for a period of time after the closing of the Vine Acquisition and Chief Acquisition, if consummated, which could adversely affect the combined company after these acquisitions. These uncertainties could include, but may not be limited to, loss of key personnel, retention of customer or supplier contracts or relationships, and litigation in connection with the Chief Acquisition.
Legal and Regulatory Risks
We are subject to extensive governmental regulation, which can change and could adversely impact our business.
Environmental and regulatory matters and related costs can be significant.
Increasing attention to environmental, social and governance matters may impact our business, financial results or stock price.
The taxation of independent producers is subject to change, and changes in tax law could increase our cost of doing business.
Trading in our new common stock, additional issuances of new common stock, and certain other stock transactions could lead to a second, potentially more restrictive annual limitation on the utilization of our tax attributes reducing their ability to offset future taxable income, which may result in an increase to income tax liabilities.
General Risk Factors
A deterioration in general economic, political, business or industry conditions would have a material adverse effect on our results of operations, liquidity and financial condition.
Military and other armed conflicts, including terrorist activities, could materially and adversely affect our business and results of operations.


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Risks Related to our Emergence from Bankruptcy
We recently emerged from bankruptcy, which may adversely affect our business and relationships.
It is possible that our having filed for bankruptcy and our recent emergence from bankruptcy may adversely affect our business and relationships with customers, vendors, contractors or employees. Due to uncertainties, many risks exist, including the following:
key vendors or other contract counterparties may terminate their relationships with us or require additional financial assurances or enhanced performance from us;
our ability to renew existing contracts and compete for new business may be adversely affected;
our ability to attract, motivate and/or retain key executives may be adversely affected; and
competitors may take business away from us, and our ability to attract and retain customers may be negatively impacted.
The occurrence of one or more of these events could have a material and adverse effect on our operations, financial condition and reputation. We cannot assure you that having been subject to bankruptcy protection will not adversely affect our operations in the future.
Our actual financial results after emergence from bankruptcy may not be comparable to our historical financial information as a result of the implementation of the Plan and the transactions contemplated thereby.
In connection with the disclosure statement we filed with the Bankruptcy Court, and the hearing to consider confirmation of the Plan, we prepared projected financial information to demonstrate to the Bankruptcy Court the feasibility of the Plan and our ability to continue operations upon our emergence from bankruptcy. Those projections were prepared solely for the purpose of bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors. At the time they were prepared, the projections reflected numerous assumptions concerning our anticipated future performance with respect to prevailing and anticipated market and economic conditions that were and remain beyond our control and that may not materialize. Projections are inherently subject to substantial and numerous uncertainties and to a wide variety of significant business, economic and competitive risks and the assumptions underlying the projections and/or valuation estimates may prove to be wrong in material respects. Actual results may vary significantly from those contemplated by the projections. As a result, investors should not rely on these projections.
Risks Related to Operating our Business
Conservation measures and technological advances could reduce demand for natural gas and oil.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to natural gas and oil, technological advances in fuel economy and energy generation devices could reduce demand for natural gas and oil. The impact of the changing demand for natural gas and oil could adversely impact our earnings, cash flows and financial position.
Negative public perception regarding us or our industry could have an adverse effect on our operations.
Negative public perception regarding us or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, waste disposal, oil spills, seismic activity, climate change, explosions of natural gas transmission lines and the development and operation of pipelines and other midstream facilities may lead to generally increased political pressure and regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. Additionally, environmental groups, landowners, local groups and other advocates may oppose our operations through organized protests, attempts to block or sabotage our operations or those of our midstream transportation providers, encourage capital providers to divest of their interests in us or our industry, intervene in regulatory or administrative proceedings involving our assets or those of our midstream transportation providers, or file lawsuits or other actions
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designed to prevent, disrupt or delay the development or operation of our assets and business or those of our midstream transportation providers. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we require to conduct our operations to be withheld, delayed or burdened by requirements that restrict our ability to profitably conduct our business. A change in control of national or local governments, including the U.S. presidential administration, Congress, state or local governments, and governments of other countries may also result in uncertainty regarding the degree to which there will be increased restrictions on oil and gas production activities, which could materially adversely affect our industry and our financial condition and results of operations.
Recently, activists concerned about the potential effects of climate change have directed their attention towards sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in energy-related activities. Ultimately, this could make it more difficult or costly for us to secure funding for exploration and production activities. Members of the investment community have also begun to screen companies such as ours for sustainability performance, including practices related to GHGs and climate change, before investing in our common units. Any efforts to improve our sustainability practices in response to these pressures may increase our costs, and we may be forced to implement technologies that are less economically efficient or are not economically viable in order to improve our sustainability performance and to meet the specific requirements to perform services for certain customers.
The oil and gas exploration and production industry is very competitive; some of our competitors have greater financial and other resources than we do, and there is competition to attract and retain talent and competition over access to certain industry equipment.
We face competition in every aspect of our business, including, but not limited to, buying and selling reserves and leases, obtaining goods and services needed to operate our business and marketing oil, natural gas or NGL. Competitors include multinational oil companies, independent production companies and individual producers and operators. Some of our competitors have greater financial and other resources than we do. As a result, these competitors may be able to address industry challenges more effectively or weather industry downturns more easily than we can. We also face indirect competition from alternative energy sources, including wind, solar and electric power.
Our performance depends largely on the talents and efforts of highly skilled individuals and on our ability to attract new employees and to retain and motivate our existing employees. Competition in our industry for qualified employees is intense. If we are unsuccessful in attracting and retaining skilled employees and managerial talent, our ability to compete effectively may be diminished. We also compete for the equipment required to explore, develop and operate properties. Typically, during times of rising commodity prices, drilling and operating costs will also increase. During these periods, there is often a shortage of drilling rigs and other oilfield equipment and services, which could adversely affect our ability to execute our development plans on a timely basis and within budget.
Oil, natural gas and NGL prices fluctuate widely, and lower prices for an extended period of time are likely to have a material adverse effect on our business.
Our revenues, results of operations, profitability, liquidity, leverage ratio and ability to grow and invest in capital expenditures depend primarily upon the prices we receive for the oil, natural gas and NGL we sell. We incur substantial expenditures to replace reserves, sustain production and fund our business plans. Low oil, natural gas and NGL prices can negatively affect the amount of cash available for capital expenditures, debt service and debt repayment and our ability to borrow money or raise additional capital and, as a result, could have a material adverse effect on our financial condition, results of operations, cash flows and reserves. In addition, periods of low oil and natural gas prices may result in a reduction of the carrying value of our oil and natural gas properties due to recognizing impairments in proved and unproved properties.
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Volatility in oil, natural gas and NGL prices may result from factors that are beyond our control, including:
domestic and worldwide supplies of oil, natural gas and NGL, including U.S. inventories of oil and natural gas reserves;
weather conditions;
changes in the level of consumer and industrial demand, including impacts from global or national health epidemics and concerns, such as the COVID-19 pandemic;
the price and availability of alternative fuels;
technological advances affecting energy consumption;
the effectiveness of worldwide conservation measures;
the availability, proximity and capacity of pipelines, other transportation facilities and processing facilities;
the level and effect of trading in commodity futures markets, including by commodity price speculators and others;
U.S. exports of oil, natural gas, liquefied natural gas and NGL;
the price and level of foreign imports;
the nature and extent of domestic and foreign governmental regulations and taxes;
the ability of the members of the Organization of Petroleum Exporting Countries (OPEC) and others to agree to and maintain oil price and production controls;
increased use of competing energy products, including alternative energy sources;
political instability or armed conflict in oil and natural gas producing regions;
acts of terrorism; and
domestic and global economic and political conditions.
These factors and the volatility of the energy markets make it extremely difficult to predict future oil, natural gas and NGL price movements. In addition, any prolonged period of lower prices could reduce the quantities of reserves that we may economically produce.
The ongoing COVID-19 pandemic and related economic turmoil have affected, and could continue to adversely affect, our business, financial condition, results of operations and cash flows.
The global spread of COVID-19 created significant volatility, uncertainty, and economic disruption during 2020 and 2021, and threatens to do the same in 2022. The ongoing COVID-19 pandemic has reached more than 200 countries and continues to present rapidly evolving economic and public health risks. The pandemic has adversely impacted the entire global economy, and there is considerable uncertainty regarding how long the pandemic and related market conditions will persist and the extent and duration of governmental and other measures implemented to try to slow the spread of the virus, such as quarantines, shelter-in-place orders, business and government shutdowns and restrictions on operations. In certain cases, states that had begun taking steps to reopen their economies experienced a subsequent surge in cases of COVID-19, causing these states to cease or dramatically scale back such reopening measures in some cases and reinstitute restrictions in others. Our precautionary measures and plans may not be effective in preventing future disruptions to our business. Moreover, future operations could be negatively affected if a significant number of our employees are quarantined as a result of exposure to the virus. In addition, actions by our customers and derivative contract counterparties in response to COVID-19 and its economic impacts, including potential non-performance or delays, may also have an adverse impact on our business.
Furthermore, the impact of the pandemic, including the initial resulting reduction in demand for oil and natural gas, coupled with the sharp decline in commodity prices following the announcement of price reductions and production increases in March 2020 by members of OPEC+ has led to significant global economic contraction generally and in our industry in particular. While an agreement to cut production has since been announced by OPEC+ and its allies, the supply and demand imbalance created by such price reductions and production increases, coupled with the impact of COVID-19, has continued to result in a significant downturn in the oil and gas industry. Although OPEC+ agreed in April 2020 to cut oil production and has extended such production cuts through
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March 2021, crude oil prices have remained depressed as a result of the oversupply of oil, an increasingly utilized global storage network and the decrease in crude oil demand due to COVID-19. Oil and natural gas prices are expected to continue to be volatile as a result of the ongoing COVID-19 pandemic and as changes in oil and natural gas inventories, industry demand and national and economic performance are reported, and we cannot predict when prices will improve and stabilize. Due to numerous uncertainties, we cannot at this time predict the full impact that COVID-19 or the significant disruption and volatility currently being experienced in the oil and natural gas markets will have on our business, financial condition and results of operations.
The ultimate impact of COVID-19 will depend on future developments that cannot be anticipated, including, among others, the ultimate severity of the virus and its rapidly evolving and spreading variants, the consequences of governmental and other measures designed to mitigate the spread of the virus, the development and availability of treatments and vaccines and the extent to which these treatments and vaccines may remain effective as new strains of the virus emerge, the duration of the pandemic, any further actions taken by members of OPEC+, actions taken by governmental authorities, customers, suppliers and other third parties, workforce availability, and the timing and extent of any return to normal economic and operating conditions.
If commodity prices fall or drilling efforts are unsuccessful, we may be required to record write downs of the carrying value of our oil and natural gas properties.
We have been required to write down the carrying value of certain of our oil and natural gas properties in the past, and there is a risk that we will be required to take additional writedowns in the future. Writedowns may occur in the future when oil and natural gas prices are low, or if we have downward adjustments to our estimated proved reserves, increases in our estimates of operating or development costs, or due to the anticipated sale of properties.
The successful efforts method of accounting requires that we periodically review the carrying value of our oil and natural gas properties for possible impairment. Impairment is recognized for the excess of book value over fair value when the book value of a proven property is greater than the expected undiscounted future net cash flows from that property and on acreage when conditions indicate the carrying value is not recoverable. We may be required to write down the carrying value of a property based on oil and natural gas prices at the time of the impairment review, or as a result of continuing evaluation of drilling results, production data, economics, divestiture activity, and other factors. A writedown constitutes a non-cash charge to earnings and does not impact cash or cash flows from operating activities; however, it reflects our long-term ability to recover an investment, reduces our reported earnings and increases certain leverage ratios. See Impairment of Oil and Natural Gas Properties included in Item 7 of this report for further information.
Significant capital expenditures are required to replace our reserves and conduct our business.
Our exploration, development and acquisition activities require substantial capital expenditures. We intend to fund our capital expenditures through cash flows from operations, and to the extent that is not sufficient, borrowings under our revolving credit facility. Our ability to generate operating cash flow is subject to a number of risks and variables, such as the level of production from existing wells, prices of oil, natural gas and NGL, our success in developing and producing new reserves and the other risk factors discussed herein. Our forecasted 2022 capital expenditures, inclusive of capitalized interest, are $1.5 - $1.8 billion compared to our 2021 capital spending level of $746 million. Management continues to review operational plans for 2022 and beyond, which could result in changes to projected capital expenditures and projected revenues from sales of oil, natural gas and NGL. If we are unable to fund our capital expenditures as planned, we could experience a curtailment of our exploration and development activity, a loss of properties and a decline in our oil, natural gas and NGL reserves.
If we are not able to replace reserves, we may not be able to sustain production.
Our future success depends largely upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition activities, our proved reserves and production will decline over time. Thus, our future oil and natural gas reserves and production, and therefore our cash flow and income, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves.
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The actual quantities of and future net revenues from our proved reserves may be less than our estimates.
The estimates of our proved reserves and the estimated future net revenues from our proved reserves included in this report are based upon various assumptions, including assumptions required by the SEC relating to oil, natural gas and NGL prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil, natural gas and NGL reserves is complex and involves significant decisions and assumptions associated with geological, geophysical, engineering and economic data for each well. Therefore, these estimates are subject to future revisions.
Actual future production, oil, natural gas and NGL prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil, natural gas and NGL reserves most likely will vary from these estimates. Such variations may be significant and could materially affect the estimated quantities and present value of our proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
As of December 31, 2021, approximately 41% of our estimated proved reserves (by volume) were undeveloped. These reserve estimates reflect our plans for capital expenditures to convert PUDs into proved developed reserves, including approximately $2.7 billion during the next five years. You should be aware that the estimated development costs may not equal our actual costs, development may not occur as scheduled and results may not be as estimated. If we choose not to develop our PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove them from our reported proved reserves. In addition, under the SEC's reserve reporting rules, because PUDs generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, we may be required to remove any PUDs that are not developed within this five-year time frame.
You should not assume that the present values included in this report represent the current market value of our estimated reserves. In accordance with SEC requirements, the estimates of our present values are based on prices and costs as of the date of the estimates. The price on the date of estimate is calculated as the average oil and natural gas price during the 12 months ending in the current reporting period, determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period. The December 31, 2021 present value is based on a $66.56 per bbl of oil price and a $3.60 per mcf of natural gas price, before considering basis differential adjustments. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of an estimate.
The timing of both the production and the expenses from the development and production of oil and natural gas properties will affect both the timing of future net cash flows from our proved reserves and their present value. Any changes in demand for oil and natural gas, governmental regulations or taxation will also affect the future net cash flows from our production. In addition, the 10% discount factor that is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes is not necessarily the most appropriate discount factor. Interest rates in effect from time to time and the risks associated with our business or the oil and gas industry in general will affect the appropriateness of the 10% discount factor.
Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.
We have a substantial inventory of undeveloped properties. Development and exploratory drilling and production activities are subject to many risks, including the risk that commercially productive reservoirs will not be discovered. We have acquired undeveloped properties that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our initial investments. Additionally, there can be no assurance that undeveloped properties acquired by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive, or that we will recover all or any portion of our investment in such undeveloped properties or wells.
Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient commercial quantities to cover the drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling and completion operations may be curtailed, delayed or canceled as a
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result of unexpected drilling conditions, title problems, equipment failures or accidents, shortages of midstream transportation, equipment or personnel, environmental issues, state or local bans or moratoriums on hydraulic fracturing and produced water disposal, federal restrictions on oil and gas leasing and permitting, and a decline in commodity prices, among others. The profitability of wells, particularly in certain of the areas in which we operate, will be reduced or eliminated if commodity prices decline. In addition, wells that are profitable may not meet our internal return targets, which are dependent upon the current and future market prices for oil, natural gas and NGL, costs associated with producing oil, natural gas and NGL and our ability to add reserves at an acceptable cost.
We rely to a significant extent on seismic data and other technologies in evaluating undeveloped properties and in conducting our exploration activities. The seismic data and other technologies we use do not allow us to know conclusively, prior to acquisition of undeveloped properties, or drilling a well, whether oil or natural gas is present or may be produced economically. If we incur significant expense in acquiring or developing properties that do not produce as expected or at profitable levels, it could have a material adverse effect on our results of operations and financial condition.
Certain of our undeveloped properties are subject to leases that will expire over the next several years unless production is established on units containing the acreage or the leases are renewed.
Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established. If our leases on our undeveloped properties expire and we are unable to renew the leases, we will lose our right to develop the related properties. Although we seek to actively manage our undeveloped properties, our drilling plans for these areas are subject to change based upon various factors, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. Low commodity prices may cause us to delay our drilling plans and, as a result, lose our right to develop the related properties.
Our commodity price risk management activities may limit the benefit we would receive from increases in commodity prices, may require us to provide collateral for derivative liabilities and involve risk that our counterparties may be unable to satisfy their obligations to us.
To manage our exposure to price volatility, we enter into oil, natural gas and NGL price derivative contracts. Our oil, natural gas and NGL derivative arrangements may limit the benefit we would receive from increases in commodity prices. The fair value of our oil, natural gas and NGL derivative instruments can fluctuate significantly between periods. Our decision to mitigate cash flow volatility through derivative arrangements, if any, is based in part on our view of current and future market conditions and our desire to stabilize cash flows necessary for the development of our proved reserves. We may choose not to enter into derivatives if we believe the pricing environment for certain time periods is unfavorable. Additionally, we may choose to liquidate existing derivative positions prior to the expiration of their contractual maturities to monetize gain positions for the purpose of funding our capital program.
Most of our oil, natural gas and NGL derivative contracts are with counterparties under bilateral hedging arrangements. Under a majority of our arrangements, the collateral provided for our obligations is secured by the same hydrocarbon interests that secure our Exit Credit Facility. Our counterparties’ obligations under the arrangements must be secured by cash or letters of credit to the extent that any mark-to-market amounts owed to us exceed defined thresholds. Collateral requirements are dependent to a large extent on oil and natural gas prices.
Oil, natural gas and NGL derivative transactions expose us to the risk that our counterparties, which are generally financial institutions, may be unable to satisfy their obligations to us. During periods of declining commodity prices, the value of our commodity derivative asset positions increase, which increases our counterparty exposure. Although the counterparties to our hedging arrangements are required to secure their obligations to us under certain scenarios, if any of our counterparties were to default on their obligations to us under the derivative contracts or seek bankruptcy protection, it could have an adverse effect on our ability to fund our planned activities and could result in a larger percentage of our future cash flows being exposed to commodity price changes.
Oil and natural gas operations are uncertain and involve substantial costs and risks.
Our operating activities are subject to numerous costs and risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. Drilling for oil, natural gas and NGL can be unprofitable, not only from
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dry holes, but from productive wells that do not return a profit because of insufficient revenue from production or high costs. Substantial costs are required to locate, acquire and develop oil and gas properties, and we are often uncertain as to the amount and timing of those costs. Our cost of drilling, completing, equipping and operating wells is often uncertain before drilling commences. Declines in commodity prices and overruns in budgeted expenditures are common risks that can make a particular project uneconomic or less economic than forecasted. Although both exploratory and developmental drilling activities involve these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. In addition, our oil and gas properties can become damaged, our operations may be curtailed, delayed or canceled and the costs of such operations may increase as a result of a variety of factors, including, but not limited to:
unexpected drilling conditions, pressure conditions or irregularities in reservoir formations;
equipment failures or accidents;
fires, explosions, blowouts, cratering or loss of well control;
the mishandling or underground migration of fluids and chemicals;
adverse weather conditions and natural disasters, such as tornadoes, earthquakes, hurricanes and extreme temperatures;    
issues with title or in receiving governmental permits or approvals;
restricted takeaway capacity for our production, including due to inadequate midstream infrastructure or constrained downstream markets;
environmental hazards or liabilities;
restrictions in access to, or disposal of, water used or produced in drilling and completion operations;
shortages or delays in the availability of services or delivery of equipment; and
unexpected or unforeseen changes in regulatory policy, and political or public opinion.
The occurrence of one or more of these factors could result in a partial or total loss of our investment in a particular property, as well as significant liabilities. Although we may maintain insurance against some, but not all, of the risks described above, our insurance may not be adequate to cover casualty losses or liabilities, and our insurance does not cover penalties or fines that may be assessed by a governmental authority. For certain risks, such as political risk, business interruption, war, terrorism and piracy, we have limited or no insurance coverage. Also, in the future we may not be able to obtain insurance at premium levels that justify its purchase. The occurrence of a significant event against which we are not fully insured may expose us to liabilities.
Moreover, certain of these events could result in environmental pollution and impact to third parties, including persons living in proximity to our operations, our employees and employees of our contractors, leading to possible injuries, death or significant damage to property and natural resources.
Our ability to produce oil, natural gas and NGL economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.

Development activities, particularly hydraulic fracturing, require the use and disposal of significant quantities of water. In certain areas, there may be insufficient local aquifer capacity to provide a source of water for drilling activities. Water must be obtained from other sources and transported to the drilling site. Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, could adversely impact our operations in certain areas. The imposition of environmental initiatives and regulations could further restrict our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other materials associated with the exploration, development or production of oil and natural gas.
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Risks related to potential acquisitions or dispositions may adversely affect our business.
From time to time, we evaluate acquisitions and dispositions of assets, businesses and other investments. These transactions may not result in the anticipated benefits or efficiencies. In addition, acquisitions may be financed by borrowings, requiring us to incur more debt, or by the issuance of our common stock. Any such acquisition or disposition involves risks and we cannot assure you that:
any acquisition will be successfully integrated into our operations and internal controls;
the due diligence conducted prior to an acquisition will uncover situations that could result in financial or legal exposure, such as title defects and potential environmental and other liabilities;
post-closing purchase price adjustments will be realized in our favor;
our assumptions about, among other things, reserves, estimated production, revenues, capital expenditures, operating, operating expenses and costs will be accurate;
any investment, acquisition, disposition or integration will not divert management resources from the operation of our business; and
any investment, acquisition, or disposition or integration will not have a material adverse effect on our financial condition, results of operations, cash flows or reserves.
If any of these risks materialize, the benefits of such acquisition or disposition may not be fully realized, if at all, and our financial condition, results of operations, cash flows and reserves could be negatively impacted.
Our operations may be adversely affected by pipeline, trucking and gathering system capacity constraints and may be subject to interruptions that could adversely affect our cash flow.
In certain resource plays, the capacity of gathering and transportation systems is insufficient to accommodate potential production from existing and new wells. We rely heavily on third parties to meet our oil, natural gas and NGL gathering needs. Capital constraints could limit the construction of new pipelines and gathering systems and the provision or expansion of trucking services by third parties. Until this new capacity is available, we may experience delays in producing and selling our oil, natural gas and NGL. In such event, we might have to shut in our wells while awaiting a pipeline connection or additional capacity, which would adversely affect our results of operations.
A portion of our oil, natural gas and NGL production in any region may be interrupted, or shut in, from time to time for numerous reasons, including weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could materially adversely affect our cash flow.
Cyber-attacks targeting systems and infrastructure used by the oil and gas industry and related regulations may adversely impact our operations and, if we or our third-party providers are unable to obtain and maintain adequate protection for our data, our business may be harmed.
Our business has become increasingly dependent on digital technologies to conduct certain exploration, development and production activities. We depend on digital technology to estimate quantities of oil, natural gas and NGL reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our customers, employees and third-party partners. In addition, many third-party providers, such as vendors and others in the supply chain, directly or indirectly provide to us various products and services across an array of internal and external functions that enable us to conduct, monitor and/or protect our business, systems and data assets. In addition, in the ordinary course, we and our service providers collect, process, transmit, and store proprietary and confidential data, including personal information.
We have been the subject of cyber-attacks on our internal systems and through those of third parties in the past. As an energy company, we expect to continue to be a target for such attacks in the future. We are vulnerable to malicious attacks by third parties or insiders, social engineering and human error, as well as to bugs and other vulnerabilities that may exist in our third-party providers systems. Unauthorized access to our seismic data, reserves information, customer or employee data or other proprietary or commercially sensitive information could lead to data corruption, communication interruption, or other disruptions in our exploration or production operations or planned business transactions, any of which could have a material adverse impact on our results of operations. If
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our information technology systems cease to function properly or our cybersecurity is breached (for example, due to ransomware), we could suffer disruptions to our normal operations, which may include disruptions to our drilling, completion, production and corporate functions. A cyber-attack involving our information systems and related infrastructure, or that of our business associates or third-party providers, could result in supply chain disruptions that delay or prevent the transportation and marketing of our production, non-compliance leading to regulatory fines or penalties, loss or disclosure of, or damage to, our or any of our customer’s or supplier’s data or confidential information that could harm our business by damaging our reputation, subjecting us to potential financial or legal liability, and requiring us to incur significant costs, including costs to repair or restore our systems and data or to take other remedial steps.
Both the frequency and magnitude of cyberattacks is expected to increase and attackers are becoming more sophisticated. As a result, we may be unable to anticipate, detect or prevent future attacks, particularly as the methodologies utilized by attackers change frequently or are not recognized until launched, and we may be unable to investigate or remediate incidents because attackers are increasingly using techniques and tools designed to circumvent controls, to avoid detection, and to remove or obfuscate forensic evidence. Further, our increased reliance on remote access to our information systems as a result of the COVID-19 pandemic increases our exposure to potential cybersecurity breaches. As cyber-attacks continue to evolve, we may be required to spend significant additional resources to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyber-attacks. In addition, new laws and regulations governing data privacy and the unauthorized disclosure of confidential information pose increasingly complex compliance challenges and potentially elevate costs as we collect and store personal data related to employees, royalty owners and other parties. Any failure to comply with these laws and regulations could result in significant penalties and legal liability. For example, the California Consumer Privacy Act (“CCPA”) was signed into law on June 28, 2018 and largely took effect on January 1, 2020. The CCPA, among other things, contains new disclosure obligations for businesses that collect personal information about California residents and enhanced consumer protections for those individuals, and provides for statutory fines and penalties for certain data security breaches or other CCPA violations. At least fifteen other states have considered, and some have already enacted privacy laws like the CCPA.
Any losses, costs or liabilities directly or indirectly related to cyberattacks or similar incidents may not be covered by, or may exceed the coverage limits of, any or all of our insurance policies.

Our operations could be disrupted by natural or human causes beyond our control.

Our operations are subject to disruption from natural or human causes beyond our control, including risks from extreme weather events, such as hurricanes, severe storms, floods, heat waves, and ambient temperature increases, as well as wildfires, war, accidents, civil unrest, political events, earthquakes, system failures, cyber threats, terrorist acts and epidemic or pandemic diseases, such as the COVID-19 pandemic, any of which could result in suspension of operations or harm to people, our assets or the natural environment.

It is difficult to predict with certainty the timing, frequency or severity of such events, any of which could have a material adverse effect on our results of operations or financial condition.
In addition, our headquarters are located in Oklahoma City, Oklahoma, an area that experiences severe weather events, including tornadoes and earthquakes. Our information systems and administrative and management processes are primarily provided to our various drilling projects and producing wells throughout the United States from this location, which could be disrupted if a catastrophic event, such as a tornado, power outage or act of terror, destroyed or severely damaged our headquarters. Any such catastrophic event could harm our ability to conduct normal operations and could adversely affect our business.
Financial Risks Related to our Business
We have significant capital needs, and our ability to access the capital and credit markets to raise capital on favorable terms is limited by industry conditions.
Disruptions in the capital and credit markets, in particular with respect to the energy sector, could limit our ability to access these markets or may significantly increase our cost to borrow. In the past, low commodity prices have caused and may continue to cause lenders to increase the interest rates under upstream operators’ credit
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facilities, enact tighter lending standards, refuse to refinance existing debt around maturity on favorable terms or at all and may reduce or cease to provide funding to borrowers. Additionally, certain financial institutions have announced their intention to cease investment banking and corporate lending activities in the North American oil and gas sector or have established climate-related funding commitments that could have the effect of limiting their investment in us or our industry. If we are unable to access the capital and credit markets on favorable terms, it could have a material adverse effect on our business, financial condition, results of operations, cash flows and liquidity and our ability to repay or refinance our debt. Additionally, challenges in the economy have led and could further lead to reductions in the demand for oil and gas, or further reductions in the prices of oil and gas, or both, which could have a negative impact on our financial position, results of operations and cash flows.
Restrictive covenants in certain of our debt agreements could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.
Our debt agreements impose operating and financial restrictions on us. These restrictions limit our ability and that of our restricted subsidiaries to, among other things:
incur additional indebtedness;
make investments or loans;
create liens;
consummate mergers and similar fundamental changes;
make restricted payments;
make investments in unrestricted subsidiaries;
enter into transactions with affiliates; and
use the proceeds of asset sales.

We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under certain of our debt agreements. The restrictions contained in the covenants could:
limit our ability to plan for, or react to, market conditions, to meet capital needs or otherwise to restrict our activities or business plan; and
adversely affect our ability to finance our operations, enter into acquisitions or divestitures to engage in other business activities that would be in our interest.
Changes in the method of determining the London Interbank Offered Rate (LIBOR), or the replacement of LIBOR with an alternative reference rate, may adversely affect interest expense related to outstanding debt.
Amounts drawn under certain of our debt instruments may bear interest at rates based on LIBOR. On July 27, 2017, the Financial Conduct Authority in the United Kingdom (the “FCA”) announced that it would phase out LIBOR as a benchmark by the end of 2021. The publication of USD LIBOR will cease after June 30, 2023, and the FCA confirmed that use of USD LIBOR will not be permitted in most new contracts after December 31, 2021. The Credit Agreement adopts the hardwire approach for LIBOR replacement which provides that Term SOFR (or Daily Simple SOFR, to the extent Term SOFR is unavailable) will be used in the event of LIBOR cessation or upon an election to early opt-in, once SOFR becomes available. The Credit Agreement also provides that in the event that SOFR is not available at the time of LIBOR cessation, the borrower and agent must agree on a successor rate subject to negative consent rights of the lenders. We are currently evaluating the impact of the potential replacement of the LIBOR interest rate. In addition, the overall financial markets may be disrupted as a result of the phase-out or replacement of LIBOR. Uncertainty as to the nature of such potential phase-out and alternative reference rates or disruption in the financial market could have a material adverse effect on our financial condition, results of operations and cash flows.
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Risks Related to Recent and Pending Acquisitions
The Chief Acquisition may not be completed. Failure to complete the Chief Acquisition could negatively impact the price of shares of our common stock, as well as our future business and financial results.
The Chief Acquisition is subject to a number of conditions that must be satisfied or, to the extent permitted by applicable law, waived, prior to the completion of the merger. These conditions to the completion of the Chief Acquisition, some of which are beyond our control, may not be satisfied or waived in a timely manner or at all, and, accordingly, the Chief Acquisition may be delayed or may not be completed.
If the Chief Acquisition is not completed for any reason, our ongoing business, financial condition and financial results may be adversely affected. Without realizing any of the benefits of having completed the transactions, we will be subject to a number of risks, including the following:
we may be required to pay certain costs relating to the Chief Acquisition, which are substantial, such as legal, accounting, financial advisory and printing fees, whether or not the transactions are completed;
time and resources committed by our management to matters relating to the Chief Acquisition could otherwise have been devoted to pursuing other beneficial opportunities;
we may experience negative reactions from financial markets, including negative impacts on the price of our common stock, including to the extent that the current market price reflects a market assumption that the Chief Acquisition will be completed;
we may experience negative reactions from employees, customers or vendors; and
we may not have been able to take certain actions during the pendency of the Chief Acquisition that would have benefitted us as an independent company and the opportunity to take such actions may no longer be available.
In addition, any delay in completing the Chief Acquisition may significantly reduce the synergies and other benefits that we expect that the combined company may achieve if the Chief Acquisition is completed within the expected timeframe.

Required regulatory approvals for the Chief Acquisition may not be received, may take longer than expected to be received, or may impose conditions that are not presently anticipated or cannot be met.

Completion of the Chief Acquisition is conditioned upon the expiration or termination of any waiting period applicable to the merger under the HSR Act. Although each party has agreed to use its reasonable best efforts to ensure the prompt expiration or termination of any applicable waiting period under the HSR Act and to respond to and comply with any request for information from any governmental entity charged with enforcing, applying, administering or investigating the HSR Act or any other antitrust laws, there can be no assurance that HSR clearance will be obtained and that the other conditions to completing the Chief Acquisition will be satisfied. In addition, the governmental authorities from which the regulatory approvals are required may impose conditions on the completion of the Chief Acquisition or require changes to the terms of the Chief Acquisition. We cannot provide any assurance that these approvals will be obtained or that there will not be any adverse consequences to our business resulting from the failure to obtain these governmental approvals or from conditions that could be imposed in connection with obtaining these governmental approvals.

Completion of the Chief Acquisition is also conditioned upon the authorization for listing of our common stock to be issued in connection with the Chief Acquisition on the Nasdaq Global Select Market, or such other Nasdaq market on which our shares of common stock are then listed. There can be no assurance that such approval will be obtained or that the other conditions to completing the Chief Acquisition will be satisfied.

Such conditions or changes and the process of obtaining regulatory approvals could have the effect of delaying or impeding consummation of the Chief Acquisition or of imposing additional costs or limitations on us following completion of the Chief Acquisition, any of which might have an adverse effect on us following completion of the Chief Acquisition and may diminish the anticipated benefits of the Chief Acquisition.

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The synergies attributable to the Vine Acquisition, or Chief Acquisition, if consummated, may vary from expectations.

We may fail to realize the anticipated benefits and synergies expected from the Vine Acquisition, or Chief Acquisition, if consummated, which could adversely affect our business, financial condition and results of operations. The success of these acquisitions will depend, in significant part, on our ability to successfully integrate the acquired businesses, grow the revenue of the combined company and realize the anticipated strategic benefits and synergies from the combinations, such as operational and financial scale, and increased Free Cash Flow. However, achieving these goals requires, among other things, realization of the targeted cost synergies expected from these acquisitions. The growth and the anticipated benefits of the acquisitions may not be realized fully or at all, or may take longer to realize than expected. Actual operating, technological, strategic and revenue opportunities, if achieved at all, may be less significant than expected or may take longer to achieve than anticipated. If we are not able to achieve these objectives and realize the anticipated benefits and synergies expected from the Vine Acquisition, or Chief Acquisition, if consummated, within the anticipated timing or at all, our business, financial condition and results of operations may be adversely affected.

We will be subject to business uncertainties for a period of time after the closing of the Vine Acquisition and Chief Acquisition, if consummated, which could adversely affect the combined company after these acquisitions.

Uncertainty about the effect of these acquisitions on employees, industry contacts and business partners may have an adverse effect on the combined company. These uncertainties may impair the combined company’s ability to attract, retain and motivate key personnel for a period of time after the closing of these acquisitions and could cause industry contacts, business partners and others that deal with the combined company to seek to change their existing business relationships with the combined company.

Uncertainties associated with the Vine Acquisition and Chief Acquisition, if consummated, may cause a loss of management personnel and other key employees, which could adversely affect the future business and operations of the combined company.

The combined company’s success after the Vine Acquisition and Chief Acquisition, if consummated, will depend in part upon the ability to retain key management personnel and other key employees of the Company, Vine and Chief. Current and prospective employees may experience uncertainty about their roles within the combined company following the Vine Acquisition, and Chief Acquisition, if consummated, which may have an adverse effect on the ability of the combined company to attract or retain key management and other key personnel. Accordingly, no assurance can be given that the combined company will achieve the same success attracting or retaining key management personnel and other key employees as the Company may have independently achieved prior to the Vine Acquisition and Chief Acquisition, if consummated.

We have incurred and will continue to incur significant transaction and acquisition-related costs in connection with the Vine Acquisition and Chief Acquisition, which may be in excess of our expectations.

We have incurred and expect to continue to incur a number of non-recurring costs associated with negotiating and completing the Vine Acquisition and Chief Acquisition and combining the operations of the acquired entities and achieving desired synergies. These fees and costs have been, and will continue to be, substantial. The substantial majority of non-recurring expenses will consist of transaction costs related to the Vine Acquisition and Chief Acquisition and include, among others, employee retention costs, fees paid to financial, legal and accounting advisors, severance and benefit costs and filing fees.

We will also incur transaction fees and costs related to the integration of the companies, which may be substantial. Moreover, we may incur additional unanticipated expenses in connection with the Vine Acquisition and the integration, including costs associated with any stockholder litigation related to the Vine Acquisition. Although we expect that the elimination of duplicative costs as well as the realization of other efficiencies related to the integration of the businesses should offset integration-related costs over time, this net benefit may not be achieved
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in the near term, or at all. Similar risks regarding the integration of Chief may arise if the Chief Acquisition is completed.

The costs described above, as well as other unanticipated costs and expenses, could have a material adverse effect on our financial condition and results of operations.

Completion of the Chief Acquisition may trigger change in control or other provisions in certain agreements to which Chief or its subsidiaries is a party.

The completion of the Chief Acquisition may trigger change in control or other provisions in certain agreements to which Chief or its subsidiaries is a party. If we are unable to negotiate waivers of those provisions, the counterparties may exercise their rights and remedies under such agreements, potentially terminating the agreement or seeking monetary damages. Additionally, even if we are able to negotiate waivers, the counterparties may require a fee for such waivers or seek to renegotiate the agreements on terms less favorable to the combined company.

Lawsuits may be filed against the Company Chief and their respective affiliates in connection with the Chief Acquisition. An adverse ruling could result in substantial costs and could result in an injunction preventing the completion of the Chief Acquisition.

Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into acquisition, merger or other business combination agreements like those related to the Chief Acquisition. Even if any of the lawsuits which have been filed and may be filed are without merit, defending against these claims can result in substantial costs and divert management time and resources. An adverse judgment could result in monetary damages, which could have a negative impact on our liquidity and financial condition.

One of the conditions to the closing of the Chief Acquisition is that no injunction by any governmental entity has been entered and continues to be in effect and no law has been adopted, in either case, that prohibits the closing of the Chief Acquisition. Consequently, if a plaintiff is successful in obtaining an injunction prohibiting completion of the Chief Acquisition, that injunction may delay or prevent the Chief Acquisition from being completed within the expected timeframe, or at all, which may adversely affect our business, financial position and results of operations.

Additionally, there can be no assurance that any of the defendants in any potential future lawsuits will be successful in the outcome of such lawsuits. The defense or settlement of any lawsuit or claim that remains unresolved at the time the merger is completed may adversely affect our business, financial condition, results of operations and cash flows.

Our integration of the acquired businesses into the Company may not be as successful as anticipated, and we may not achieve the intended benefits or do so within the intended timeframes.

The Vine Acquisition and Chief Acquisition, if consummated, involve numerous operational, strategic, financial, accounting, legal, tax and other risks, potential liabilities associated with the acquired businesses, and uncertainties related to design, operation and integration of the acquired businesses’ internal control over financial reporting. Difficulties in integrating the acquired businesses into the Company may result in the acquired businesses performing differently than expected, operational challenges, or the failure to realize anticipated expense-related efficiencies. Potential difficulties that may be encountered in the integration process include, among others:

the inability to successfully integrate the acquired businesses into the Company in a manner that permits the Company to achieve the full revenue and cost savings anticipated from the Vine Acquisition and Chief Acquisition, if consummated;
complexities associated with managing the larger, more complex integrated business;
not realizing anticipated operating synergies;
integrating personnel from different entities and the loss of key employees;
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potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with the Vine Acquisition or Chief Acquisition, if consummated;
integrating relationships with industry contacts and business partners;
performance shortfalls as a result of the diversion of management’s attention caused by completing the acquisitions and the integration process; and
the disruption of, or the loss of momentum in, ongoing business or inconsistencies in standards, controls, procedures and policies.

Additionally, the success of the Vine Acquisition and Chief Acquisition, if consummated, will depend, in part, on our ability to realize the anticipated benefits and cost savings from combining the acquired businesses, including operational and other synergies that we believe the combined company will achieve. The anticipated benefits and cost savings of the Vine Acquisition and Chief Acquisition, if consummated, may not be realized fully or at all, may take longer to realize than expected or could have other adverse effects that we do not currently foresee.

Our results may suffer if we do not effectively manage our expanded operations following the Vine Acquisition and Chief Acquisition, if consummated.

The success of the Vine Acquisition and Chief Acquisition, if consummated, will depend, in part, on our ability to realize the anticipated benefits and cost savings from combining the acquired businesses, including the need to integrate the operations and businesses of the acquired entities into our existing business in an efficient and timely manner, to combine systems and management controls and to integrate relationships with customers, vendors, industry contacts and business partners.

The anticipated benefits and cost savings of the Vine Acquisition and Chief Acquisition, if consummated, may not be realized fully or at all, may take longer to realize than expected or could have other adverse effects that we do not currently foresee. Some of the assumptions that we have made, such as the achievement of operating synergies, may not be realized. There could also be unknown liabilities and unforeseen expenses associated with the acquisitions that were not discovered in the due diligence review conducted prior to entering into each transaction.

The market price of our common stock may be affected by factors different from those that historically have affected the price of our common stock.

Our business differs from that of Vine in certain respects, and if consummated, the business acquired in the Chief Acquisition will also differ. Accordingly, the financial position or results of operations and/or cash flows of the combined company, as well as the market price of our common stock, may be affected by factors different from those currently affecting our financial position or results of operations and/or cash flows as an independent standalone company.

As a result of the Vine Acquisition, we have incorporated Vine’s hedging activities into our business, and we may be exposed to additional commodity price risks arising from such hedges.

To mitigate its exposure to changes in commodity prices, Vine hedges natural gas prices from time to time, primarily through the use of certain derivative instruments. As a result of the Vine Acquisition, we assumed Vine’s existing derivative instruments. Actual natural gas prices may differ from our expectations and, as a result, such derivative instruments may have a negative impact on our business, financial condition and results of operations.

The combined company may not be able to retain customers or suppliers, and customers or suppliers may seek to modify contractual obligations with the combined company, either of which could have an adverse effect on the combined company’s business and operations. Third parties may terminate or alter existing contracts or relationships as a result of the Vine Acquisition or Chief Acquisition, if consummated.

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As a result of the Vine Acquisition, or Chief Acquisition, if consummated, the combined company may experience impacts on relationships with customers and suppliers that may harm the combined company’s business and results of operations. Certain customers or suppliers may seek to terminate or modify contractual obligations following the Vine Acquisition, or Chief Acquisition, if consummated, whether or not contractual rights are triggered as a result of such acquisition. There can be no guarantee that customers and suppliers will remain with or continue to have a relationship with the combined company or do so on the same or similar contractual terms following the acquisitions. If any customers or suppliers seek to terminate or modify contractual obligations or discontinue their relationships with the combined company, then the combined company’s business and results of operations may be harmed. If the combined company’s suppliers were to seek to terminate or modify an arrangement with the combined company, then the combined company may be unable to procure necessary supplies or services from other suppliers in a timely and efficient manner and on acceptable terms, or at all.

The acquired entities also have contracts with vendors, landlords, licensors and other business partners that may require consents from these other parties in connection with the Vine Acquisition or Chief Acquisition, if consummated. If these consents cannot be obtained, the combined company may suffer a loss of potential future revenue, incur costs and/or lose rights that may be material to the business of the combined company. Any such disruptions could limit the combined company’s ability to achieve the anticipated benefits of the Vine Acquisition or Chief Acquisition, if consummated.

We are subject to risks related to health epidemics and pandemics, including the ongoing COVID-19 pandemic, and it is difficult to predict what effect, if any, this might have on the combined company after the Vine Acquisition and Chief Acquisition, if consummated.

We face various risks related to public health issues, including epidemics, pandemics and other outbreaks, including the ongoing COVID-19 pandemic. The actual and potential effects of COVID-19 include, but are not limited to, its impact on general economic conditions, trade and financing markets, changes in customer behavior and continuity in business operations, all of which create significant uncertainty. In addition, the pandemic has resulted in governmental authorities implementing significant and varied measures to contain the spread of COVID-19, including travel bans and restrictions, quarantines, shelter in place and stay at home orders and business shutdowns. Governmental authorities may enact additional restrictions, or tighten existing measures if COVID-19 continues to spread. These measures, as well as the COVID-19 pandemic broadly, may have a negative effect on the combined company after the Vine Acquisition and Chief Acquisition, if consummated, which effect will be difficult to predict.
Legal and Regulatory Risks
We are subject to extensive governmental regulation, which can change and could adversely impact our business.
Our operations are subject to extensive federal, state, local and other laws, rules and regulations, including with respect to environmental matters, worker health and safety, wildlife conservation, the gathering and transportation of oil, gas and NGL, conservation policies, reporting obligations, royalty payments, unclaimed property and the imposition of taxes, and tribal laws for a minor portion of our acreage. Such regulations include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling, completion and well operations. If permits are not issued, or if unfavorable restrictions or conditions are imposed on our drilling or completion activities, we may not be able to conduct our operations as planned. For example, on January 20, 2021, the Acting Secretary for the Department of the Interior signed an order effectively suspending new fossil fuel leasing and permitting on federal lands for 60 days. Then, on January 27, 2021, President Biden issued an executive order indefinitely suspending new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. On November 26, 2021, the U.S. Department of the Interior released its “Report On The Federal Oil And Gas Leasing Program,” which assessed the current state of oil and gas leasing on federal lands and proposed several reforms, including raising royalty rates and implementing stricter standards for entities seeking to purchase oil and gas leases. With respect to offshore oil and gas leases, challenges to President Biden’s moratorium on leasing initially prevailed on June 15, 2021, when a federal court judge in Louisiana issued a nationwide preliminary injunction effectively preventing the Biden Administration from implementing the pause of
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new oil and natural gas leases on federal lands and waters and forcing the lease sale; however, on January 25, 2022, the U.S. District Court for the District of Columbia invalidated the lease sale, reasoning that the Biden Administration did not properly evaluate the climate change impacts of drilling in the Gulf of Mexico. Although we do not expect this ruling to impact the availability of onshore federal oil and gas lease sales, the Biden Administration’s and certain federal courts’ focus on the climate change impacts of federal projects could result in similar restrictions surrounding onshore drilling, onshore federal lease availability, and restrictions on the ability to obtain required permits, which could have a material adverse impact on our operations. In addition, we may be required to make large, sometimes unexpected, expenditures to comply with applicable governmental laws, rules, regulations, permits or orders.
In addition, changes in public policy have affected, and in the future could further affect, our operations. Regulatory developments could, among other things, restrict production levels, impose price controls, change environmental protection requirements with respect to the treatment of hazardous waste, air emissions, or water discharges, and increase taxes, royalties and other amounts payable to the government. Our operating and compliance costs could increase further if existing laws and regulations are revised, reinterpreted, or if new laws and regulations become applicable to our operations. We do not expect that any of these laws and regulations will affect our operations materially differently than they would affect other companies with similar operations, size and financial strength. Although we are unable to predict changes to existing laws and regulations, such changes could significantly impact our profitability, financial condition and liquidity. This is particularly true of changes related to pipeline safety, hydraulic fracturing and climate change, as discussed below.
Pipeline Safety. The pipeline assets in which we own interests are subject to stringent and complex regulations related to pipeline safety and integrity management. The Pipeline and Hazardous Materials Safety Administration (PHMSA) has established a series of rules that require pipeline operators to develop and implement integrity management programs for gas, NGL and condensate transmission pipelines as well as for certain low stress pipelines and gathering lines transporting hazardous liquids, such as oil, that, in the event of a failure, could affect “high consequence areas.” Recent PHMSA rules have also extended certain requirements for integrity assessments and leak detections beyond high consequence areas and impose a number of reporting and inspection requirements on regulated pipelines. Further, legislation funding PHMSA through 2023 requires the agency to engage in additional rulemaking to amend the integrity management program, emergency response plan, operation and maintenance manual, and pressure control recordkeeping requirements for gas distribution operators; to create new leak detection and repair program obligations; and to set new minimum federal safety standards for onshore gas gathering lines. At this time, we cannot predict the cost of these requirements or other potential new or amended regulations, but they could be significant. Moreover, violations of pipeline safety regulations can result in the imposition of significant penalties.
Hydraulic Fracturing. Several states have adopted or are considering adopting regulations that could impose more stringent permitting, public disclosure and/or well construction requirements on hydraulic fracturing operations. We cannot predict whether additional federal, state or local laws or regulations applicable to hydraulic fracturing will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed on hydraulic fracturing operations, our business and operations could be subject to delays, increased operating and compliance costs and potential bans. Additional regulation could also lead to greater opposition to hydraulic fracturing, including litigation.
Climate Change. Continuing political and social attention to the issue of climate change has resulted in legislative, regulatory and other initiatives to reduce greenhouse gas emissions, such as carbon dioxide and methane. Policy makers at both the U.S. federal and state levels have introduced legislation and proposed new regulations designed to quantify and limit the emission of greenhouse gases through inventories, limitations and/or taxes on greenhouse gas emissions. The EPA and the BLM have issued regulations for the control of methane emissions, which also include leak detection and repair requirements, for the oil and gas industry and are likely to create additional regulations regarding such matters. For example, on November 15, 2021, the EPA proposed new regulations to establish comprehensive standards of performance and emission guidelines for methane and volatile organic compound (VOC) emissions from new and existing operations in the oil and gas sector, including the exploration and production, transmission, processing, and storage segments. The comment period for the proposed rule ended on January 31, 2022, and the EPA hopes to finalize it by the end of 2022. Once finalized, the regulations are likely to be subject to legal challenge, and will also need to be incorporated into the states’ implementation plans, which will need to be approved by the EPA in individual rulemakings that could also be subject to legal challenge. As a result, we cannot predict the scope of any final methane regulatory requirements or the cost to
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comply with such requirements. However, given the long-term trend toward increasing regulation, future federal GHG regulations of the oil and gas industry remain a significant possibility. In addition, several states in which we operate have imposed limitations designed to reduce methane emissions from oil and gas exploration and production activities. Legislative and state initiatives to date have generally focused on the development of renewable energy standards and/or cap-and-trade and/or carbon tax programs. Renewable energy standards (also referred to as renewable portfolio standards) require electric utilities to provide a specified minimum percentage of electricity from eligible renewable resources, with potential increases to the required percentage over time. The development of a federal renewable energy standard, or the development of additional or more stringent renewable energy standards at the state level could reduce the demand for oil and gas, thereby adversely impacting our earnings, cash flows and financial position. A cap-and-trade program generally would cap overall greenhouse gas emissions on an economy-wide basis and require major sources of greenhouse gas emissions or major fuel producers to acquire and surrender emission allowances. A federal cap and trade program or expanded use of cap and trade programs at the state level could impose direct costs on us through the purchase of allowances and could impose indirect costs by incentivizing consumers to shift away from fossil fuels. In addition, federal or state carbon taxes could directly increase our costs of operation and similarly incentivize consumers to shift away from fossil fuels.
In addition, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in an increasing number of financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this would make it more difficult and expensive to secure funding for exploration and production activities. Members of the investment community have also begun to screen companies such as ours for sustainability performance, including practices related to greenhouse gases and climate change, before investing in our common stock. Any efforts to improve our sustainability practices in response to these pressures may increase our costs, and we may be forced to implement technologies that are not economically viable in order to improve our sustainability performance and to meet the specific requirements to perform services for certain customers.
These various legislative, regulatory and other activities addressing greenhouse gas emissions could adversely affect our business, including by imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations, which could require us to incur costs to reduce emissions of greenhouse gases associated with our operations. Limitations on greenhouse gas emissions could also adversely affect demand for oil and gas, which could lower the value of our reserves and have a material adverse effect on our profitability, financial condition and liquidity.
Environmental matters and related costs can be significant.
As an owner, lessee or operator of oil and gas properties, we are subject to various federal, state, tribal and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on us for the cost of remediating pollution that results from our operations. Environmental laws may impose strict, joint and several liability, and failure to comply with environmental laws and regulations can result in the imposition of administrative, civil or criminal fines and penalties, as well as injunctions limiting operations in affected areas. Any future costs associated with these matters are uncertain and will be governed by several factors, including future changes to regulatory requirements. Changes in or additions to public policy regarding the protection of the environment could have a significant impact on our operations and profitability.
Increasing attention to environmental, social and governance matters (“ESG”) may impact our business, financial results or stock price.
In recent years, increasing attention has been given to corporate activities related to ESG matters in public discourse and the investment community. A number of advocacy groups, both domestically and internationally, have campaigned for governmental and private action to promote change at public companies related to ESG matters, including through the investment and voting practices of investment advisers, public pension funds, activist investors, universities and other members of the investing community. These activities include increasing attention and demands for action related to climate change, advocating for changes to companies’ boards of directors, and promoting the use of energy saving building materials. These activities may result in demand shifts for oil, natural gas and NGL. In addition, a failure to comply with investor or customer expectations and standards, which are evolving, or if we are perceived to not have responded appropriately to the growing concern for ESG issues,
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regardless of whether there is a legal requirement to do so, could cause reputational harm to our business, increase our risk of litigation, and could have a material adverse effect on our results of operations.
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings systems for evaluating companies on their approach to ESG matters. These ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings may lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital.
The taxation of independent producers is subject to change, and changes in tax law could increase our cost of doing business.
We are subject to taxation by various governmental authorities at the federal, state and local levels in the jurisdictions in which we do business. New legislation could be enacted by any of these governmental authorities making it more costly for us to produce oil and natural gas by increasing our tax burden. The Biden administration has called for changes to fiscal and tax policies which could lead to comprehensive tax reform. For example, federal legislation has been proposed that, if enacted, would impact federal income tax law applicable to the deduction of intangible drilling and development costs, percentage depletion and, the expensing of geological, geophysical, exploration and development costs. Other proposals changing federal income tax law could include a new corporate minimum tax based on book income, an increase to the corporate tax rate and the elimination of certain tax credits. If enacted, certain of these proposals could have a correlative impact on state income taxes. In addition, state and local authorities could enact new legislation that would increase various taxes such as sales, severance and ad valorem taxes as well as accelerate the collection of such taxes.
Trading in our new common stock, additional issuances of new common stock, and certain other stock transactions could lead to a second, potentially more restrictive annual limitation on the utilization of our tax attributes reducing their ability to offset future taxable income, which may result in an increase to income tax liabilities.
Upon emergence from bankruptcy on February 9, 2021, the Company experienced an ownership change under Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”), as all of the common stock and preferred stock of the Predecessor, or the old loss corporation, was canceled and replaced with new common stock of the Successor, or the new loss corporation (the “First Ownership Change”). As such, an annual limitation was computed based on the fair market value of the new equity immediately after emergence multiplied by the long-term tax-exempt rate in effect for the month of February 2021. This annual limitation will restrict the future utilization of our net operating loss (NOL) carryforwards, disallowed business interest carryforwards and tax credits that existed at the time of emergence.
Trading in our stock, additional issuances, and other stock transactions occurring subsequent to the emergence from Bankruptcy could lead to a second ownership change. In the event of a second ownership change, a second annual limitation would be determined at such time which could be more restrictive than the limitation of the First Ownership Change. Depending on the market conditions and the Company’s tax basis, a second ownership change may result in a net unrealized built-in loss. The annual limitation in such a case would additionally be applied to certain of the Company’s tax items other than just NOL carryforwards, disallowed business interest carryforwards and tax credits. For example, a portion of tax depreciation, depletion and amortization would also be subject to the annual limitation for a five-year period following the ownership change but only to the extent of the net unrealized built-in loss existing at the time of the second ownership change. Whether the new annual limitation would be more restrictive would depend on the value of our stock and the long-term tax-exempt rate in effect at the time of a second ownership change. If the new annual limitation is more restrictive it would apply to certain of the tax attributes existing at the time of the second ownership change including those remaining from the time of the First Ownership Change.
Further, should the Company be in a net unrealized built-in gain position at the time of a second ownership change, the proposed regulations issued on September 10, 2019, and on January 14, 2020, under Section 382(h) of the Code (the “Proposed Regulations”) would, if finalized in their present form, change the currently existing rules and limit the potential increases to the annual limitation amount for certain built-in gains existing at the time of an ownership change, (unless the transition relief provisions of the Proposed Regulations are applicable), thereby possibly reducing the ability to utilize tax attributes significantly.
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Some states impose similar limitations on tax attribute utilization upon experiencing an ownership change.
General Risk Factors
A deterioration in general economic, political, business or industry conditions would have a material adverse effect on our results of operations, liquidity and financial condition.
Historically, concerns about global economic growth and international political stability have had a significant impact on global financial markets and commodity prices. If the economic or political climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and materially adversely impact our results of operations, liquidity and financial condition.
Military and other armed conflicts, including terrorist activities, could materially and adversely affect our business and results of operations.
Military and other armed conflicts, terrorist attacks and the threat of both, whether domestic or foreign, could cause instability in the global financial and energy markets. Continued instability in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy in unpredictable ways, including the disruption of energy supplies and markets, increased volatility in commodity prices, or the possibility that the infrastructure on which we rely could be a direct target or an indirect casualty of an act of terrorism, and, in turn, could materially and adversely affect our business and results of operations.
Item 1B.Unresolved Staff Comments
Not applicable.
Item 2.Properties
Information regarding our properties is included in Item 1. Business and in the Supplementary Information included in Item 8 of Part II of this report.
Item 3.Legal Proceedings
Chapter 11 Proceedings
Commencement of the Chapter 11 Cases automatically stayed the proceedings and actions against us that are referenced below, in addition to actions seeking to collect pre-petition indebtedness or to exercise control over the property of the Company’s bankruptcy estates. The Plan in the Chapter 11 Cases, which became effective on February 9, 2021, provided for the treatment of claims against the Company’s bankruptcy estates, including pre-petition liabilities that had not been satisfied or addressed during the Chapter 11 Cases. See Note 2 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for additional information.
Litigation and Regulatory Proceedings
We were involved in a number of litigation and regulatory proceedings as of the Petition Date. Many of these proceedings were in early stages, and many of them sought damages and penalties, the amount of which is currently indeterminate. See Note 7 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for information regarding our estimation and provision for potential losses related to litigation and regulatory proceedings.
Business Operations. We are involved in various lawsuits and disputes incidental to our business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions. The majority of these prepetition legal proceedings were settled during the Chapter 11 Cases or will be resolved in connection with the claims reconciliation process before the Bankruptcy Court. Any allowed claim related to such prepetition litigation will be treated in accordance with the Plan.
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Environmental Contingencies
The nature of the oil and gas business carries with it certain environmental risks for us and our subsidiaries. We have implemented various policies, programs, procedures, training and audits to reduce and mitigate such environmental risks. We conduct periodic reviews, on a company-wide basis, to assess changes in our environmental risk profile. Environmental reserves are established for environmental liabilities for which economic losses are probable and reasonably estimable. We manage our exposure to environmental liabilities in acquisitions by using an evaluation process that seeks to identify pre-existing contamination or compliance concerns and address the potential liability. Depending on the extent of an identified environmental concern, we may, among other things, exclude a property from the transaction, require the seller to remediate the property to our satisfaction in an acquisition or agree to assume liability for the remediation of the property.
We were recently dismissed from numerous lawsuits in Oklahoma alleging that we and other companies engaged in activities that have caused earthquakes. The lawsuits sought compensation for injury to real and personal property, diminution of property value, economic losses due to business interruption, interference with the use and enjoyment of property, annoyance and inconvenience, personal injury and emotional distress.  In addition, they sought the reimbursement of insurance premiums and the award of punitive damages, attorneys’ fees, costs, expenses and interest.
Other Matters
Based on management’s current assessment, we are of the opinion that no pending or threatened lawsuit or dispute relating to our business operations is likely to have a material adverse effect on our future consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.
Item 4.Mine Safety Disclosures
The information concerning mine safety violations and other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17CFR 229.104) is included in Exhibit 95.1 to this Form 10-K.
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PART II
Item 5.Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Common Stock
Upon our emergence from Chapter 11 bankruptcy on February 9, 2021, our then-authorized common stock and preferred stock were canceled and released under the Plan without receiving any recovery on account thereof. In accordance with the Plan confirmed by the Bankruptcy Court on February 9, 2021, we issued 97,097,081 shares of New Common Stock of the Successor, which are listed on the Nasdaq Stock Market LLC under the symbol CHK. In addition, on February 9, 2021, we issued 11,111,111 Class A Warrants, 12,345,679 Class B Warrants and 9,768,527 Class C Warrants, each of which are exercisable for one share of common stock per warrant at the initial exercise prices of $27.63, $32.13 and $36.18 per share, respectively. The warrants are immediately exercisable and will expire on February 9, 2026. For more information regarding our emergence from Chapter 11 bankruptcy and our Plan of Reorganization, see Note 2 of the notes to our consolidated financial statements included in Item 8 of Part II of this report.
Dividends
We declared the first quarterly dividend on our New Common Stock in the second quarter of 2021 of $0.34375 per share (an initial annual rate of $1.375 per share). In the third quarter of 2021, we announced an increase in the base quarterly dividend to $0.4375 per share (an annual rate of $1.75 per share) and announced our intent to adopt a variable return program that will result in the payment of an additional variable dividend, payable beginning in March 2022, equal to the sum of Adjusted Free Cash Flow from the prior quarter less the base quarterly dividend, multiplied by 50%. In January 2022, we announced our intent to increase the base dividend to $0.50 per share (an annual rate of $2.00 per share) beginning in the second quarter of 2022.
Repurchases of Equity Securities; Unregistered Sales of Equity Securities and Use of Proceeds
There were no repurchases or unregistered sales of our common stock during the quarter ended December 31, 2021.
On December 2, 2021, we announced that our Board of Directors authorized the repurchase of up to $1.0 billion in aggregate value of our common stock and/or warrants from time to time. The repurchase authorization permits repurchases on a discretionary basis as determined by management, subject to market conditions, applicable legal requirements, available liquidity, compliance with the Company’s debt agreements and other appropriate factors. As of February 21, 2022, no repurchases had occurred.
Shareholders
As of February 21, 2022, there were approximately 146 holders of record of our common stock.
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Item 6.Selected Financial Data
We have adopted the SEC’s Disclosure Modernization Final Rule, effective February 10, 2021, for Item 301 of Regulation S-K. As such, Item 6 Selected Financial Data has not been provided.
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Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis presents management’s perspective of our business, financial condition and overall performance. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future and should be read in conjunction with Item 8 of Part II of this report.
Introduction
We are an independent exploration and production company engaged in the acquisition, exploration and development of properties to produce oil, natural gas and NGL from underground reservoirs. We own a large and geographically diverse portfolio of onshore U.S. unconventional natural gas and liquids assets, including interests in approximately 8,200 oil and natural gas wells. Upon closing of the Chief Acquisition and divestiture of our assets in the Powder River Basin in Wyoming, our portfolio will be focused on three operating areas including the natural gas resource plays in the Marcellus Shale in the northern Appalachian Basin in Pennsylvania (“Marcellus”) and the Haynesville/Bossier Shales in northwestern Louisiana (“Haynesville”) and the liquids-rich resource play in the Eagle Ford Shale in South Texas (“Eagle Ford”).
Our strategy is to create shareholder value by generating sustainable Free Cash Flow from our oil and natural gas development and production activities. We continue to focus on improving margins through operating efficiencies and financial discipline and improving our Environmental, Social, and Governance (“ESG”) performance. To accomplish these goals, we intend to allocate our human resources and capital expenditures to projects we believe offer the highest cash return on capital invested, to deploy leading drilling and completion technology throughout our portfolio, and to take advantage of acquisition and divestiture opportunities to strengthen our portfolio. We also intend to continue to dedicate capital to projects that reduce the environmental impact of our oil and natural gas producing activities. We continue to seek opportunities to reduce cash costs (production, gathering, processing and transportation and general and administrative) per barrel of oil equivalent production through operational efficiencies by, among other things, improving our production volumes from existing wells.
Leading a responsible energy future is foundational to Chesapeake's success. Our core values and culture demand we continuously evaluate the environmental impact of our operations and work diligently to improve our ESG performance across all facets of our Company. Our path to leading a responsible energy future begins with our initiative to achieve net-zero direct greenhouse gas emissions by 2035, which we announced in February 2021. To meet this challenge, we have set meaningful initial goals including:
Eliminate routine flaring from all new wells completed from 2021 forward, and enterprise-wide by 2025;
Reduce our methane intensity to 0.09% by 2025 (achieved 0.08% in 2021); and
Reduce our GHG intensity to 5.5 by 2025 (achieved 5.0 in 2021).
In July 2021, we announced our plan to receive independent certification of our natural gas production under the MiQ methane standard and EO100 Standard for Responsible Energy Development. Certified natural gas was available in our Haynesville assets as of the end of 2021, and we expect it to be available in our legacy Marcellus assets by the end of the second quarter of 2022. The MiQ certification will provide a verified approach to tracking our commitment to reduce our methane intensity to 0.09% by 2025, as well as support our overall objective of achieving net-zero direct greenhouse gas emissions by 2035.
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Our results of operations as reported in our consolidated financial statements for the 2021 Successor Period, 2021 Predecessor Period, 2020 Predecessor Period and 2019 Predecessor Period are in accordance with GAAP. Although GAAP requires that we report on our results for the periods January 1, 2021 through February 9, 2021 and February 10, 2021 through December 31, 2021 separately, management views our operating results for the year ended December 31, 2021 by combining the results of the 2021 Predecessor Period and the 2021 Successor Period because management believes such presentation provides the most meaningful comparison of our results to prior periods. We are not able to compare the 40 days from January 1, 2021 through February 9, 2021 operating results to any of the previous periods reported in the consolidated financial statements and do not believe reviewing this period in isolation would be useful in identifying any trends in, or reaching any conclusions regarding, our overall operating performance. We believe the key performance indicators such as operating revenues and expenses for the 2021 Successor Period combined with the 2021 Predecessor Period provide more meaningful comparisons to other periods and are useful in understanding operational trends. Additionally, there were no changes in policies between the periods, and any material impacts as a result of fresh start accounting were included within the discussion of these changes. These combined results do not comply with GAAP and have not been prepared as pro forma results under applicable regulations, but are presented because we believe they provide the most meaningful comparison of our results to prior periods.
Recent Developments
Vine Acquisition
On November 1, 2021, we completed our acquisition of Vine pursuant to a definitive agreement with Vine dated August 10, 2021. The transaction strengthens Chesapeake’s competitive position, meaningfully increasing our Free Cash Flow outlook and deepening our inventory of premium natural gas locations, while preserving the strength of our balance sheet.
Chief Acquisition and Powder River Basin Divestiture
On January 25, 2022, we announced our planned Chief Acquisition and the planned divestiture of our Powder River Basin assets. These transactions, which are subject to certain customary closing conditions, including certain regulatory approvals, are expected to close in the first quarter of 2022. In conjunction with the Vine Acquisition, these transactions simplify and refocus our asset portfolio, concentrating on three operating areas and advancing our highest-return assets in the Marcellus and Haynesville gas basins.
Chief Executive Officer, Chief Financial Officer, and Chief Operating Officer
On April 27, 2021, we announced the departure of Doug Lawler from his positions as Chief Executive Officer and Director of Chesapeake, effective April 30, 2021. Michael A. Wichterich, the Chairman of our Board of Directors, served as Interim Chief Executive Officer while the Board of Directors conducted a search for a new Chief Executive Officer.
On October 11, 2021, we announced that the Board of Directors appointed Domenic “Nick” Dell’Osso Jr. as President and Chief Executive Officer and as member of the Board of Directors, effective October 11, 2021. Additionally, on October 11, 2021, the Board of Directors appointed Michael A. Wichterich, who resigned as Interim Chief Executive Officer upon the appointment of Mr. Dell’Osso, as Executive Chairman of the Company.
On November 30, 2021, we announced that the Board of Directors appointed Mohit Singh as Executive Vice President and Chief Financial Officer, effective December 6, 2021.
On January 25, 2022, we announced that the Board of Directors appointed Josh Viets as Executive Vice President and Chief Operating Officer, effective February 1, 2022.
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Emergence from Bankruptcy
On the Petition Date, the Debtors filed the Chapter 11 Cases under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. On June 29, 2020, the Bankruptcy Court entered an order authorizing the joint administration of the Chapter 11 Cases under the caption In re Chesapeake Energy Corporation, Case No. 20-33233. Subsidiaries with noncontrolling interests, consolidated variable interest entities and certain de minimis subsidiaries (collectively, the “Non-Filing Entities”) were not part of the bankruptcy filing. The Non-Filing Entities continued to operate in the ordinary course of business.
The Bankruptcy Court confirmed the Plan and the Debtors entered the Confirmation Order on January 16, 2021. The Debtors emerged from bankruptcy on the Effective Date. In connection with our exit from bankruptcy, we filed a registration statement with the SEC to facilitate future sales of our equity by certain holders of our New Common Stock and warrants. See Item 1 Business, Item 3 Legal Proceedings, Item 5 Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities and Note 2 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for a complete discussion of our Chapter 11 proceedings.
COVID-19 Pandemic and Impact on Global Demand for Oil and Natural Gas
The global spread of COVID-19, created, and continues to create, significant volatility, uncertainty, and economic disruption during 2020 through 2021. The pandemic has reached more than 200 countries and territories and has resulted in widespread adverse impacts on the global economy and on our customers and other parties with whom we have business relations. To date, we have experienced limited operational impacts as a result of COVID-19 or related governmental restrictions. While we cannot predict the full impact that COVID-19 or the related significant disruption and volatility in the oil and natural gas markets will have on our business, cash flows, liquidity, financial condition and results of operations, we believe demand is recovering and prices will continue to be positively impacted in the near term. For additional discussion regarding risks associated with the COVID-19 pandemic, see Item 1A Risk Factors in this report.
Liquidity and Capital Resources
Liquidity Overview
For the 2021 Successor Period, our primary sources of capital resources and liquidity have consisted of internally generated cash flows from operations, and our primary uses of cash have been for the development of our oil and natural gas properties, acquisitions of additional oil and natural gas properties and return of value to shareholders through dividends. Historically, our primary sources of capital resources and liquidity have consisted of internally generated cash flows from operations, borrowings under certain credit agreements and dispositions of non-core assets. Our ability to issue additional indebtedness, dispose of assets or access the capital markets was substantially limited during the Chapter 11 Cases and required court approval in most instances. Accordingly, our liquidity in the 2021 and 2020 Predecessor Periods depended mainly on cash generated from operations and available funds under certain credit agreements including the DIP Facility in the 2021 Predecessor Period and revolving credit facility in the 2020 Predecessor Period.
We believe we have emerged from the Chapter 11 Cases as a fundamentally stronger company, built to generate sustainable Free Cash Flow with a strengthened balance sheet, geographically diverse asset base and continuously improving ESG performance. As a result of the Chapter 11 Cases, we reduced our total indebtedness by $9.4 billion by issuing equity in a reorganized entity to the holders of our FLLO Term Loan, Second Lien Notes, unsecured notes and allowed general unsecured claimants.
We believe our cash flow from operations, cash on hand and borrowing capacity under the Exit Credit Facility, as discussed below, will provide sufficient liquidity during the next 12 months and the foreseeable future. As of December 31, 2021, we had $2.625 billion of liquidity available, including $905 million of cash on hand and $1.720 billion of aggregate unused borrowing capacity available under the Exit Credit Facility. As of December 31, 2021, we had no outstanding borrowings under our Exit Credit Facility – Tranche A Loans, and $221 million in borrowings under our Exit Credit Facility – Tranche B Loans. See Note 6 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion of our debt obligations, including principal and carrying amounts of our senior notes.
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Dividend
With our strong liquidity position, we initiated a new dividend strategy in 2021. We paid dividends of $119 million on our New Common Stock in the 2021 Successor Period. See Note 12 for further discussion.
On August 10, 2021, we announced a variable return program that will result in the payment of an additional dividend, payable beginning in March 2022, equal to the sum of Adjusted Free Cash Flow from the prior quarter less the base dividend, multiplied by 50%. On February 23, 2022, we declared a quarterly dividend payable of $1.7675 per share, which will be paid on March 22, 2022 to stockholders of record at the close of business on March 7, 2022. The dividend consists of a base quarterly dividend in the amount of $0.4375 per share and a variable quarterly dividend in the amount of $1.33 per share. In January 2022, we announced our intent to increase the base quarterly dividend to $0.50 per share beginning in the second quarter of 2022.
The declaration and payment of any future dividend, whether fixed or variable, will remain at the full discretion of the Board and will depend on the Company’s financial results, cash requirements, future prospects and other relevant factors. The Company’s ability to pay dividends to its stockholders is restricted by (i) Oklahoma corporate law, (ii) its Certificate of Incorporation, (iii) the terms and provisions of its Credit Agreement and (iv) the terms and provisions of the indentures governing its 5.50% Senior Notes due 2026, 5.875% Senior Notes due 2029 and 6.75% senior notes due 2029.
Derivative and Hedging Activities
Our results of operations and cash flows are impacted by changes in market prices for oil, natural gas and NGL. We enter into various derivative instruments to mitigate a portion of our exposure to commodity price declines, but these transactions may also limit our cash flows in periods of rising commodity prices. Our oil, natural gas and NGL derivative activities, when combined with our sales of oil, natural gas and NGL, allow us to better predict the total revenue we expect to receive. See Item 7A Quantitative and Qualitative Disclosures About Market Risk included in Part II of this report for further discussion on the impact of commodity price risk on our financial position.
Contractual Obligations and Off-Balance Sheet Arrangements
As of December 31, 2021, our material contractual obligations include repayment of senior notes, outstanding borrowings and interest payment obligations under the Exit Credit Facility, derivative obligations, asset retirement obligations, lease obligations, undrawn letters of credit and various other commitments we enter into in the ordinary course of business that could result in future cash obligations. In addition, we have contractual commitments with midstream companies and pipeline carriers for future gathering, processing and transportation of oil, natural gas and NGL to move certain of our production to market. The estimated gross undiscounted future commitments under these agreements were approximately $3.83 billion as of December 31, 2021. As discussed above, we believe our existing sources of liquidity will be sufficient to fund our near and long-term contractual obligations. See Notes 6, 7, 9, 15 and 23 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion.
Post-Emergence Debt
On the Effective Date, pursuant to the terms of the Plan, the Company, as borrower, entered into a reserve-based credit agreement (the “Credit Agreement”) providing for the Exit Credit Facility which features an initial borrowing base of $2.5 billion. The borrowing base will be redetermined semiannually on or around May 1 and November 1 of each year. Our borrowing base was reaffirmed in October 2021, and the next scheduled redetermination will be on or about May 1, 2022. The aggregate initial elected commitments of the lenders under the Exit Credit Facility were $1.75 billion of revolving Tranche A Loans and $221 million of fully funded Tranche B Loans.
The Exit Credit Facility provides for a $200 million sublimit of the aggregate commitments that are available for the issuance of letters of credit. The Exit Credit Facility bears interest at the ABR (alternate base rate) or LIBOR, at our election, plus an applicable margin (ranging from 2.25–3.25% per annum for ABR loans and 3.25–4.25% per annum for LIBOR loans, subject to a 1.00% LIBOR floor), depending on the percentage of the borrowing base then being utilized. The Tranche A Loans mature 3 years after the Effective Date and the Tranche B Loans mature 4 years after the Effective Date. The Tranche B Loans can be repaid if no Tranche A Loans are outstanding.
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On February 2, 2021, the Company issued $500 million aggregate principal amount of its 5.50% Senior Notes due 2026 (the “2026 Notes”) and $500 million aggregate principal amount of its 5.875% Senior Notes due 2029 (the “2029 Notes and, together with the 2026 Notes, the “Notes”). The offering of the Notes was part of a series of exit financing transactions undertaken in connection with the Debtors’ Chapter 11 Cases and meant to provide the exit financing originally intended to be provided by the Exit Term Loan Facility pursuant to the Commitment Letter.
Assumption and Repayment of Vine Debt
In conjunction with the Vine Acquisition, Vine’s Second Lien Term Loan was repaid and terminated for $163 million inclusive of a $13 million make whole premium with cash on hand, due to the agreement containing a change in control provision making the term loan callable upon closing. Vine’s reserve based loan facility, which had no borrowings as of November 1, 2021, was terminated at the time of the completion of the Vine Acquisition. Additionally, Vine’s 6.75% Senior Notes with a principal amount of $950 million, were assumed by the Company at the time of the completion of the Vine Acquisition.
Pending Acquisition and Divestiture
On January 24, 2022, we entered into a definitive agreement to acquire Chief and associated non-operated interests held by affiliates of Tug Hill, for $2.0 billion in cash and approximately 9.44 million common shares. On January 24, 2022, we also entered into an agreement to sell our Powder River Basin assets to Continental Resources, Inc. for approximately $450 million in cash. We currently expect to fund the Chief Acquisition with cash on hand, borrowings under our Exit Credit Facility and the proceeds from the planned Powder River Basin divestiture.
Capital Expenditures
For the year ending December 31, 2022, we currently expect to bring or have online approximately 190 to 220 gross wells across 11 to 14 rigs and plan to invest between approximately $1.5 – $1.8 billion in capital expenditures, approximately $150 – $200 million of which is contingent upon the closing of the proposed Chief Acquisition. We expect that approximately 75% of our 2022 capital expenditures will be directed toward our natural gas assets. We currently plan to fund our 2022 capital program through cash on hand, expected cash flow from our operations and borrowings under our Exit Credit Facility. We may alter or change our plans with respect to our capital program and expected capital expenditures based on developments in our business, our financial position, our industry or any of the markets in which we operate.
Sources of Funds
The following table presents the sources of our cash and cash equivalents for the Successor and Predecessor Periods:
SuccessorPredecessor
 Period from February 10, 2021 through December 31, 2021Period from January 1, 2021 through February 9, 2021Year Ended December 31, 2020Year Ended December 31, 2019
Net cash provided by (used in) operating activities$1,809 $(21)$1,164 $1,623 
Proceeds from issuances of debt, net— 1,000 — 1,563 
Proceeds from issuance of common stock— 600 — — 
Proceeds from warrant exercise— — — 
Proceeds from divestitures of property and equipment13 — 150 136 
Proceeds from pre-petition revolving credit facility borrowings, net— — 339 496 
Total sources of cash and cash equivalents
$1,824 $1,579 $1,653 $3,818 
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Cash Flow from Operating Activities
Cash provided by operating activities was $1.809 billion, $1.164 billion and $1.623 billion in the 2021 Successor Period, 2020 Predecessor Period and 2019 Predecessor Period, respectively. Cash used in operating activities was $21 million for the 2021 Predecessor Period. The increase in the 2021 Successor Period is primarily the result of higher prices for the oil, natural gas and NGL we sold coupled with a decrease in cash interest and GP&T costs following our emergence from bankruptcy. The cash used in the 2021 Predecessor Period was primarily in connection with the payment of professional fees related to the Chapter 11 Cases. The decrease in the 2020 Predecessor Period is primarily the result of lower prices for the oil, natural gas and NGL we sold. Changes in cash flow from operations are largely due to the same factors that affect our net income, excluding various non-cash items, such as depreciation, depletion and amortization, certain impairments, gains or losses on sales of fixed assets, deferred income taxes and mark-to-market changes in our derivative instruments. See further discussion below under Results of Operations.
Proceeds from Issuance of Common Stock and Senior Notes
In the 2021 Predecessor Period, we issued $500 million aggregate principal amount of 5.50% 2026 Notes and $500 million aggregate principal amount of 5.875% 2029 Notes for total proceeds of $1.0 billion. Additionally, upon emergence from Chapter 11, we issued 62,927,320 shares of New Common Stock in exchange for $600 million of cash, as agreed upon in the Plan. In the 2019 Predecessor Period we obtained a $1.5 billion term loan and issued $120 million of senior secured second lien notes for net proceeds of $1.563 billion See Note 6 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion.
Divestitures of Property and Equipment
In the 2021 Successor Period we divested certain non-core assets for approximately $13 million. In the 2020 Predecessor Period, we divested our Mid-Continent asset for $130 million and certain non-core assets for approximately $6 million. In the 2019 Predecessor Period, we divested certain non-core assets for approximately $130 million. See Note 4 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion.
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Uses of Funds
The following table presents the uses of our cash and cash equivalents for the Successor and Predecessor Periods:
SuccessorPredecessor
 Period from February 10, 2021 through December 31, 2021Period from January 1, 2021 through February 9, 2021Year Ended December 31, 2020Year Ended December 31, 2019
Oil and Natural Gas Expenditures:
Capital expenditures$669 $66 $1,142 $2,263 
Other Uses of Cash and Cash Equivalents:
Business combination, net194 — — 353 
Payments on Exit Credit Facility - Tranche A Loans, net50 479 — — 
Payments on DIP Facility borrowings, net— 1,179 — — 
Debt issuance and other financing costs109 — 
Cash paid to purchase debt— — 94 1,073 
Cash paid for common stock dividends119 — — — 
Cash paid for preferred stock dividends— — 22 91 
Other— 13 36 
Total other uses of cash and cash equivalents
367 1,666 238 1,553 
Total uses of cash and cash equivalents
$1,036 $1,732 $1,380 $3,816 
Capital Expenditures
Our drilling and completion costs decreased in the combined 2021 Successor and Predecessor Periods compared to the 2020 Predecessor Period primarily as a result of decreased drilling and completion activity mainly in our liquids-rich plays. Our drilling and completion costs decreased in the 2020 Predecessor Period compared to the 2019 Predecessor Period primarily as a result of decreased drilling and completion activity mainly in our liquids-rich plays. In the combined 2021 Successor and Predecessor Periods, our average operated rig count was 7 rigs and 121 spud wells, compared to an average operated rig count of 8 rigs and 167 spud wells in the 2020 Predecessor Period and 18 rigs and 333 spud wells in the 2019 Predecessor Period. We completed 127 operated wells in the combined 2021 Successor and Predecessor Periods compared to 188 in the 2020 Predecessor Period and 370 in the 2019 Predecessor Period.
Business Combination
In the 2021 Successor Period, we acquired Vine for approximately 18.7 million shares of our New Common Stock and $253 million cash, less $59 million of cash held by Vine as of the acquisition date. In the 2019 Predecessor Period, we acquired WildHorse for approximately 3.6 million reverse stock split adjusted shares of our Predecessor common stock and $381 million cash, less $28 million of cash held by WildHorse as of the acquisition date. See Note 4 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion of these acquisitions.