UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X]☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 20172021
[  ]    ☐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. 1-13726001-13726
chk-20211231_g1.jpg
CHESAPEAKE ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
Oklahoma73-1395733
(State or other jurisdiction of incorporation or organization)(I.R.S. Employer Identification No.)
6100 North Western Avenue,Oklahoma City, OklahomaOklahoma73118
(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 $0.01per shareNew YorkCHKThe Nasdaq Stock ExchangeMarket LLC
7.25% Senior Notes due 2018Class A Warrants to purchase Common StockNew YorkCHKEWThe Nasdaq Stock ExchangeMarket LLC
Floating Rate Senior Notes due 2019Class B Warrants to purchase Common StockNew YorkCHKEZThe Nasdaq Stock ExchangeMarket LLC
6.625% Senior Notes due 2020Class C Warrants to purchase Common StockNew YorkCHKELThe Nasdaq Stock Exchange
6.875% Senior Notes due 2020New York Stock Exchange
6.125% Senior Notes due 2021New York Stock Exchange
5.375% Senior Notes due 2021New York Stock Exchange
4.875% Senior Notes due 2022New York Stock Exchange
5.75% Senior Notes due 2023New York Stock Exchange
2.25% Contingent Convertible Senior Notes due 2038New York Stock Exchange
4.5% Cumulative Convertible Preferred StockNew York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
NoneMarket 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 if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES [X]     NO [ ]
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. YES [ ]    NO [X] 
 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 [X]     NO [ ] 
 Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files). YES [X]     NO [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   [X] 
 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 [X] 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 is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES [ ]      NO [X]
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, 2017,2021, was approximately $4.5$1.6 billion. As of February 15, 2018,21, 2022, there were 909,242,558118,558,307 shares of our $0.01 par value common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement for the 20182022 Annual Meeting of Shareholders are incorporated by reference in Part III.




CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
2017 ANNUAL REPORT ON FORM 10-K
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PART I
Page
Item 1.
Business
711
Item 1A.
Risk Factors
2226
Item 1B.
Unresolved Staff Comments
3446
Item 2.
Properties
3446
Item 3.
Legal Proceedings
3546
Item 4.
Mine Safety Disclosures
3647
PART II
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
3748
Item 6.
Selected Financial Data
3949
Item 7.
Management’s Discussion and Analysis of Financial Condition
and Results of Operations
4050
Liquidity and Capital Resources
4252
Results of Operations, for the Years Ended
Period from February 10, 2021 through December 31, 2017, 20162021, the Period from January 1, 2021 through February 9, 2021, and 2015the Year Ended December 31, 2020
4858
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
5870
Item 8.
Financial Statements and Supplementary Data
6371
Item 9.
Changes In and Disagreements With Accountants on Accounting
and Financial Disclosure
126146
Item 9A.
Controls and Procedures
126146
Item 9B.
Other Information
126147
Item 9C.
Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
147
PART III
Item 10.
Directors, Executive Officers and Corporate Governance
127147
Item 11.
Executive Compensation
127147
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
127147
Item 13.
Certain Relationships and Related Transactions and Director Independence
127147
Item 14.
Principal Accountant Fees and Services
127147
PART IV
Item 15.
ExhibitsExhibit and Financial Statement Schedules
128148
Item 16.
Form 10-K Summary
135152
Signatures
136153


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Definitions
GlossaryUnless 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 OilU.S. dollars unless otherwise specified. In addition, the following are other abbreviations and Gas Termsdefinitions of certain terms used within this Annual Report on Form 10-K:
The terms defined“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 this sectionaccordance with its terms.
“Backstop Parties” means the members of the FLLO Ad Hoc Group that are used throughout this report.signatories to the Backstop Commitment Agreement and Franklin Advisers, Inc., as investment manager on behalf of certain funds and accounts.
Bbl. One stock tank“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 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.barrels.
Bboe. One“Bcf” means billion barrelscubic feet.
“Boe” means barrel of oil equivalent.
Bcf. Billion cubic feet 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.
Bcfe. Billion cubic feetgas is produced, at the rate of six Mcf of gas per Bbl of oil, based upon the approximate relative energy content of natural gas equivalent.and oil. NGL proved reserves and production are converted to Boe on a one-to-one basis with oil.
Btu. British thermal unit,“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 heat requiredfirst quarter of 2022.
“Class A Warrants” means warrants to raisepurchase 10 percent of the temperatureNew 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 a one-pound mass$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 waterthe 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 58.5the Effective Date until February 9, 2026.
“Class C Warrants” means warrants to 59.5 degrees Fahrenheit.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.
Boe. Barrel of oil equivalent. Oil equivalent is based on six mcf of natural gas to one barrel of oil or one barrel of NGL. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Despite holding this ratio constant at six mcf to one bbl, prices have historically often been higher or substantially higher for oil than natural gas on an energy equivalent basis, although there have been periods in which they have been lower or substantially lower.
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Completion. The“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. The number ofAcreage” 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. AWell” 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. AWell” 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.
Formation.“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.
Full Cost. The“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 cost methodduring the Chapter 11 Cases pursuant to an order of accounting, as governed by SEC Regulation S-X 4-10(c), consists of capitalizing all costs associated with property acquisition, explorationthe Bankruptcy Court and development activities intois not an Administrative Claim, a full cost pool. The full cost pool is tested for impairment quarterly using the “ceiling test” described in Regulation S-X 4-10(c). Additionally, any internal costs that can be directly identified with acquisition, exploration and development activities are included. Any costs related to production, general corporate overheadPriority 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 similar activities are not included.a Section 510(b) Claim.
GAAP. Generally Accepted Accounting Principles in the United States.
“Gross Acres or Gross Wells. TheWells” means the total acres or wells, as the case may be, in which a working interest is owned.
Mboe. One“MBbls” means thousand barrels of oil equivalent.barrels.
Mcf. One“MMBbls” means million barrels.
“MBoe” means thousand Boe.
“MMBoe” means million Boe.
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“Mcf” means thousand cubic feet.
Mmbbl. One million barrels of crude oil or other liquid hydrocarbons.
Mmboe. One million barrels of oil equivalent.
Mmbtu. One million btus.
Mmcf. One“MMcf” means million cubic feet.
Natural Gas Liquids (NGL). Hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation, adsorption or other methods in gas processing or cycling plants. Natural gas liquids primarily include ethane, propane, butane, isobutene, pentane, hexane and natural gasoline.
“Net Acres or Net Wells. TheWells” means the sum of the fractional working interests owned in gross acres or gross wells.
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“New Common Stock” means the single class of common stock issued by Reorganized Chesapeake on the Effective Date.

“NGL” means natural gas liquids.
NYMEX.“NYMEX” means New York Mercantile Exchange.
Play.“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 term applied 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). When used with respect to oil, natural gas and NGL reserves, present value of estimated future net revenues, or PV-10,” 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. TheDifferential” means the difference in the price of oil, natural gas or NGL received at the sales point and the NYMEX price.
“Productive Well. AWell” 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. ProvedReserves” 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. PropertiesProperties” means properties with proved reserves.
“Proved Reserves.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). Proved” 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.
Realized and Unrealized Gains and Losses on Oil, Natural Gas and NGL Derivatives. Realized gains and losses includes the following items:(i) settlements and accruals for settlements“Put Option Premium” means a nonrefundable aggregate fee of non-designated derivatives related to current period notional production revenues, (ii) prior period settlements for option premiums and for early-terminated derivatives originally scheduled to settle against current period notional production revenues, and (iii) gains and losses related to de-designated cash flow hedges originally designated to settle against current period notional production revenues. Unrealized gains and losses include the change in fair value of open derivatives scheduled to settle against future period notional production revenues (including current period settlements for option premiums and early-terminated derivatives) offset by amounts reclassified as realized gains and losses during the period. Although we no longer designate our derivatives as cash flow hedges for accounting purposes, we believe these definitions are useful to management and investors in determining the effectiveness of our price risk management program.
Realized and Unrealized Gains and Losses on Interest Rate Derivatives. Realized gains and losses include interest rate derivative settlements related to current period interest and the effect of gains and losses on early-terminated trades. Settlements of early-terminated trades are reflected in realized gains and losses over the original life$60 million, which represents 10 percent of the hedged item. Unrealized gainsRights Offering Amount, payable to the Backstop Parties in accordance with, and losses include changes insubject to the fair valueterms of open interest rate derivatives offset by amounts reclassified to realized gains and losses duringthe
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Backstop Commitment Agreement based on their respective backstop commitment percentages at the period.time such payment is made.
Reservoir. A“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.
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“Rights Offering” means the New Common Stock rights offering for the Rights Offering Amount consummated by the Debtors on the Effective Date.

Royalty Interest. An interest in an oil and natural gas property entitling the owner to a share of oil, natural gas or NGL production free of costs of production.
Seismic. An exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of subsurface rock formations.
Shale. Fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most frequently occurring sedimentary rock.
SEC. The“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. TheMeasure” 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.
Tbtu. One trillion British thermal units.“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. AcreageAcreage” 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. PropertiesProperties” 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). As we use the term, a volumetric production payment represents” 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. TheInterest” 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.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, and 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;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;
effects•legislative, regulatory and environmental, social and governance (“ESG”) initiatives, including as a result of the change in the U.S. presidential administration, addressing environmental protection laws and regulation on our business;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 acquisitionspurchase price adjustments and dispositions;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.
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
ItemITEM 1.Business
Unless the context otherwise requires, references to “Chesapeake”,“Chesapeake,” the “Company”, “us”,“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 for the production ofto produce oil, natural gas and NGLsNGL 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 17,3008,200 gross oil and natural gas wells. We have leading positions
On June 28, 2020, we and certain of our subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the liquids-rich resource playsBankruptcy 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 Eagle Ford Shalenotes to our consolidated financial statements included in South Texas,Item 8 of Part II of this report for further discussion of our bankruptcy, the Anadarko Basin in northwestern Oklahomaresulting reorganization and fresh start accounting.
On November 1, 2021, we completed our acquisition of Vine, an energy company focused on the stacked paydevelopment of natural gas properties in the Powder River Basinover-pressured stacked Haynesville and Mid-Bossier shale plays in Wyoming. OurNorthwest Louisiana. The Vine Acquisition strengthens Chesapeake’s competitive position, meaningfully increasing our Free Cash Flow outlook and deepening our inventory of premium natural gas resource plays arelocations, 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 northern Appalachian Basin in Pennsylvania, the Haynesville/Bossier Shales in northwestern Louisiana and East TexasChief Acquisition will be financed with cash on hand and the Utica Shaleuse 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 Ohio.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
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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Business StrategyThe 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 through theby generating sustainable Free Cash Flow from our oil and natural gas development of our significant resource plays. Our substantial inventory of hydrocarbon resources, including our undeveloped acreage position in each of our key basins, provides a strong foundation to create future value. Concentrated blocks of undeveloped acreage give us the opportunity to apply what we believe are best in class well spacing analysis, completion techniques and lateral lengths to maximize capital efficiency. We have greatly improved our capital and operating efficiency metrics over the last several years and today have what we believe is a leading cost structure in each of our major resource plays. We believe our cost structure provides a significant competitive advantage in the current commodity price environment and it is our strategy to continue to seek capital and operating efficiencies to grow this advantage.
production activities. We continue to focus on reducing debt, increasing cash provided by operating activities, and improving margins through operating efficiencies and financial discipline and operating efficiencies.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 divest additional assetsto take advantage of acquisition and divestiture opportunities to strengthen our cost structure andportfolio. We also intend to continue to dedicate capital to projects that reduce the environmental impact of our portfolio. Increasing our margins means not only increasing our absolute level of cash flow from operations, but also increasing our cash flow from operations generated per barrel of oil equivalent production. Our capital program is focused on investments that can improve our cash flow generating ability regardless of the commodity price environment. Although we expect our forecasted capital expenditures in 2018 to be lower compared to 2017, we anticipate modest production growth from both our oil-producing and natural gas-producing assets, adjusted for asset sales. Our ability to reduce capital expenditures while still growing production is primarily the result of improved operating efficiencies, including improved well performance.gas producing activities. We continue to seek opportunities to reduce cash costs (production, general and administrative, gathering, processing and transportation and interest expenses)general and improveadministrative) 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 dedicationemergence from Chapter 11 bankruptcy, we believe that maintaining low net leverage is integral to financial discipline,our business strategy and will allow us to maintain lower fixed costs, improve our margins and maintain the flexibility and efficiency 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 cost structureis designed to manage our exposure to commodity price volatility, ensure the stability of our cash flows and mitigate our continued focusrisks to realizing attractive cash returns on safetycapital invested. As of February 21, 2022, we have 11 mmbbls and environmental stewardship will provide opportunities899 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 create value$4.26/mcf, respectively, for uscollars. Additionally, as of February 21, 2022, we have hedged 6 mmbbl and our shareholders.
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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 acquisition and production efforts in the six geographic operating areas described below.
Marcellus - Northern Appalachian Basin in Pennsylvania.
Haynesville - Haynesville/Bossier Shales in Northwestern Louisiana and East Texas (Gulf Coast).Louisiana.
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Eagle Ford - Eagle Ford Shale in South Texas.
Utica - Southern Appalachian Basin in Ohio.
Mid-Continent - Anadarko Basin in northwestern Oklahoma.
Powder River Basin - Stacked pay in Wyoming.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, 2017,2021, we held an interest in approximately 17,3008,200 gross (7,200 net) productive wells, including 14,000 properties6,500 wells in which we held a working interest and 3,300 properties1,700 wells in which we held an overriding or royalty interest. Of the 6,500 (4,100 net) wells in which we hadheld a working interest, 9,400 gross (5,0003,000 (1,700 net) wells were classified as productive natural gas productive wells and 4,600 gross (2,2003,500 (2,400 net) wells were classified as productive oil productivewells. During 2021, excluding sold properties, we operated 5,700 gross wells and held a non-operating working interest in 800 gross wells. We operated approximately 9,500 of our 14,000 productive wells in which we had a working interest. During 2017, we drilled or participated in 401also completed 126 gross (292(74 net) wells as operator and participated in another 6713 gross (4(1 net) wells completed by other operators. We operate approximately 97%98% of our current daily production volumes.
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Drilling Activity
The following table sets forth the wells we drilledcompleted 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:
 2017 2016 2015202120202019
 Gross % Net % Gross % Net % Gross % Net %Gross%Net%Gross%Net%Gross%Net%
Development:                        Development:
Productive 462
 99
 292
 99
 431
 99
 236
 99
 806
 99
 423
 100
Productive137 100 74 100 203 100 126 100 414 100 271 100 
Dry 4
 1
 2
 1
 1
 1
 1
 1
 1
 1
 —
 —
Dry— — — — — — — — — — — — 
Total 466
 100
 294
 100
 432
 100
 237
 100
 807
 100
 423
 100
Total137 100 74 100 203 100 126 100 414 100 271 100 
                        
Exploratory:                        Exploratory:
Productive 2
 100
 2
 100
 3
 100
 2
 100
 7
 100
 5
 100
Productive2 100 1 100 — — — — 1 20 1 20 
Dry —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Dry— — — — 2 100 2 100 4 80 4 80 
Total 2
 100
 2
 100
 3
 100
 2
 100
 7
 100
 5
 100
Total2 100 1 100 2 100 2 100 5 100 5 100 
The following table shows the wells we drilledcompleted or participated in by operating area:
 2017 2016 2015
  Gross Wells Net Wells Gross Wells Net Wells Gross Wells Net Wells202120202019
             Gross WellsNet WellsGross WellsNet WellsGross WellsNet Wells
Marcellus 43
 21
 19
 9
 44
 22
Marcellus83 34 79 33 44 22 
Haynesville 37
 34
 41
 34
 68
 49
Haynesville40 31 21 19 22 16 
Eagle Ford 180
 106
 199
 116
 244
 138
Eagle Ford12 7 86 65 233 164 
Utica 69
 56
 34
 17
 178
 114
Powder River BasinPowder River Basin4 3 12 9 75 57 
Mid-Continent 114
 58
 135
 62
 212
 63
Mid-Continent— — 5 — 40 12 
Powder River Basin 25
 21
 1
 1
 41
 34
Other —
 —
 6
 —
 27
 8
Other— — 2 2 5 5 
Total 468
 296
 435
 239
 814
 428
Total139 75 205 128 419 276 
As of December 31, 2017,2021, we had 25555 gross (148(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, our average sales price of our production combined with our realized gains or losses fromon 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)7 111 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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  Years Ended December 31,
  2017 2016 2015
Net Production:      
Oil (mmbbl) 33
 33
 42
Natural gas (bcf) 878
 1,049
 1,070
NGL (mmbbl) 21
 24
 28
Oil equivalent (mmboe) 200
 233
 248
       
Average Sales Price of Production:      
Oil ($ per bbl) $51.03
 $40.65
 $45.77
Natural gas ($ per mcf) $2.76
 $2.05
 $2.31
NGL ($ per bbl) $23.18
 $14.76
 $14.06
Oil equivalent ($ per boe) $22.88
 $16.63
 $19.23
       
Average Sales Price (including realized gains (losses) on derivatives):    
Oil ($ per bbl) $53.19
 $43.58
 $66.91
Natural gas ($ per mcf) $2.75
 $2.20
 $2.72
NGL ($ per bbl) $22.98
 $14.43
 $14.06
Oil equivalent ($ per boe) $23.17
 $17.66
 $24.54
       
Expenses ($ per boe):      
Oil, natural gas and NGL production $2.81
 $3.05
 $4.22
Oil, natural gas and NGL gathering, processing and transportation $7.36
 $7.98
 $8.55
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Oil, Natural Gas and NGL Reserves
The tables below set forth information as of December 31, 2017,2021, 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”). NeitherNone of the estimated future net revenue, PV-10 nor the standardized measure isare 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 
  December 31, 2017
  Oil Natural Gas NGL Total
  (mmbbl) (bcf) (mmbbl) (mmboe)
Proved developed 151
 4,980
 135
 1,116
Proved undeveloped 109
 3,620
 84
 796
Total proved(a)
 260
 8,600
 219
 1,912


  
Proved
Developed
 
Proved
Undeveloped
 
Total
Proved
  ($ in millions)
Estimated future net revenue(b)
 $9,637
 $4,754
 $14,391
Present value of estimated future net revenue (PV-10)(b)
 $5,757
 $1,733
 $7,490
Standardized measure(b)
 $7,490
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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)Utica, Marcellus, Haynesville and Eagle Ford accounted for approximately 25%, 24%, 21% and 19%, respectively, of our estimated proved reserves by volume as of December 31, 2017.
(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 prices and costs under existing economic conditions as of December 31, 2017. 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, 2017. The prices used in our PV-10 measure were $51.34 of oil and $2.98 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, 2017. 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. However, as we estimate no future income tax expense, the two measures are the same as of December 31, 2017.
(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 reconciliationcomparison 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, 2017,2021, our proved reserve estimates included 796661 mmboe of reserves classified as proved undeveloped, compared to 51960 mmboe as of December 31, 2016.2020. Presented below is a summary of changes in our proved undeveloped reserves (PUDs)(“PUDs”) for 2017:
2021:
Total
(mmboe)
Proved undeveloped reserves, beginning of period (Predecessor)51960 
Extensions and discoveries604321 
Revisions of previous estimates(202145 )
DevelopedConversion to proved developed reserves(125(60))
Sale of reserves-in-place—
Purchase of reserves-in-place—195 
Proved undeveloped reserves, end of period (Successor)796661 

As of December 31, 2017,2021, all PUDs were planned to be developed within a five-year period.five years of original recording. In 2017,2021, we invested approximately $793$97 million to convert 12560 mmboe of PUDs to proved developed reserves. In 2018,2022, we estimate that we will invest approximately $880$794 million for PUD conversion. OurWe added 321 mmboe of proved undeveloped reserves through extensions and discoveries increased by 604 mmboefollowing our emergence from bankruptcy on February 9, 2021 and certainty regarding our ability to finance the development of our proved reserves asover a result of longer planned lateral lengths and additional allocated capital in our five-year development plan. Weperiod. In addition, during 2021, we recorded a downwardan upward revision of 203145 mmboe from previous estimates due to an updatedlateral length adjustments, performance and updates to our five-year development plan in the Eagle Ford aligning up-spacing and our activity schedule. Additionally, PUDs were removed from properties in the Mid-Continent in the process of being divested. In addition, approximately 1plan. We also added 195 mmboe of PUDs were added dueproved undeveloped reserves through purchase of reserves-in-place related to higher commodity prices.
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the Vine Acquisition.
The future net revenue attributable to our estimated PUDs was $4.8$8.776 billion and the present value was $1.7$5.057 billion as of December 31, 2017.2021. These values were calculated assuming that we will expend approximately $4.3$2.7 billion to develop these reserves ($880794 million in 2018, $1.0 billion in 2019, $1.1 billion in 2020, $8582022, $814 million in 2021 and $4622023, $539 million in 2022)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.
Our annual net decline rate on current proved producing properties is projected to be 35% in 2018, 23% in 2019, 18% in 2020, 15% in 2021 and 13% in 2022. Of our 1.116 bboe1,596 mmboe of proved developed reserves as of December 31, 2017,2021, approximately 8920 mmboe, or 8%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, 2017, 20162021, 2020 and 2015,2019, 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. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of these estimates, and these revisions may be material. 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 17%9% by volume, and approximately 12%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 1519 years of practical experience in the oil and gas industry, with 11over 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•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 reservesreserve estimates. Each of our Corporate Reserves AdvisorsEngineers 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.
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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 Advisors.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 our business units,each operating area and the Vice President of Corporate and Strategic Planning and the Executive Vice President – Exploration and Production 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 of– Corporate Reserves and the Vice President of Corporate and Strategic Planning.
We engaged Software Integrated Solutions, Division of Schlumberger Technology Corporation,LaRoche Petroleum Consultants, Ltd., a third-party engineering firm, to prepare approximately 83%91% by volume, and approximately 88%96% by value, of our estimated proved reserves as of December 31, 2017.2021. 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 30•Over 40 years of practical experience in the estimation and evaluation of reserves;
registered•licensed professional geologist licenseengineer in the CommonwealthState of Pennsylvania;Texas; and
member in good standing of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers; and
•Bachelor of Science degreeand Master of Science degrees in Geological Sciences.Petroleum Engineering.

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Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development
The following table sets forth historical costs incurred in oil and natural gas property acquisition, exploration and development activities during the periods indicated:
  Years Ended December 31,
  2017 2016 2015
  ($ in millions)
Acquisition of Properties:      
Proved properties $23
 $403
 $—
Unproved properties 271
 403
 454
Exploratory costs 21
 52
 112
Development costs 2,146
 1,312
 2,941
Costs incurred(a)(b)
 $2,461
 $2,170
 $3,507

(a)Exploratory and development costs are net of joint venture drilling and completion cost carries of $51 million in 2015.Acreage
(b)Includes capitalized interest and asset retirement obligations as follows:
Capitalized interest $194
 $242
 $410
Asset retirement obligations(c)
 $(34) $(57) $(15)
(c) Includes revisions as a result of lower plugging and abandonment costs in certain of our operating areas.
A summary of our exploration and development, acquisition and divestiture activities in 2017 by operating area is as follows:
  Gross Wells Drilled  Net Wells Drilled Exploration and Development Acquisition of Unproved Properties Acquisition of Proved Properties  Sales of Unproved Properties 
Sales of
 Proved
Properties(a)
 
Total(b)
  ($ in millions)
Marcellus 43
 21
 $124
 $17
 $4
 $(13) $(57) $75
Haynesville 37
 34
 411
 23
 (3) (674) (241) (484)
Eagle Ford 180
 106
 754
 2
 —
 —
 —
 756
Utica 69
 56
 375
 95
 1
 (91) (9) 371
Mid-Continent 114
 58
 281
 103
 20
 (88) (156) 160
Powder River Basin 25
 21
 220
 26
 —
 (5) —
 241
Other —
 —
 2
 5
 1
 —
 (38) (30)
Total 468
 296
 $2,167
 $271
 $23
 $(871) $(501) $1,089

(a)Includes asset retirement disposal of $66 million related to divestitures.
(b)Includes capitalized internal costs of $136 million and capitalized interest of $194 million.

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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, 2017. "Gross"2021. Gross acres are the total number of acres in which we own a working interest. "Net"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 Leasehold Undeveloped Leasehold Fee Minerals TotalDeveloped LeaseholdUndeveloped LeaseholdTotal
 
Gross
Acres
 
Net
Acres
 
Gross
Acres
 
Net
Acres
 
Gross
Acres
 
Net
Acres
 
Gross
Acres
 
Net
Acres
Gross
Acres
Net
Acres
Gross
Acres
Net
Acres
Gross
Acres
Net
Acres
 (in thousands)(in thousands)
Marcellus 538
 346
 383
 215
 17
 16
 938
 577
Marcellus556 339 216 172 772 511 
Haynesville 401
 309
 158
 47
 11
 2
 570
 358
Haynesville359 323 33 23 392 346 
Eagle Ford 313
 176
 129
 69
 —
 —
 442
 245
Eagle Ford678 478 235 133 913 611 
Utica 315
 248
 1,102
 686
 4
 4
 1,421
 938
Mid-Continent 1,815
 847
 396
 158
 227
 39
 2,438
 1,044
Powder River Basin 57
 45
 325
 229
 14
 1
 396
 275
Powder River Basin106 86 126 95 232 181 
Other(a)
 220
 145
 1,470
 992
 662
 399
 2,352
 1,536
Other(a)
231 212 1,256 1,195 1,487 1,407 
Total 3,659
 2,116
 3,963
 2,396
 935
 461
 8,557
 4,973
Total1,930 1,438 1,866 1,618 3,796 3,056 

(a)Includes 1.6 million gross (1.3 million net) acres retained in the 2016 fourth quarter divestiture of our Devonian Shale assets, in which we retained all rights below the base of the Kope formation.
(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 noncorenon-core divestitures to high-grade our lease inventory and letting some leases expire that are no longer part of our development plans. The followingacreage in the table sets forthabove includes a total of 0.1 million net acres subject to expiration in the expiration periods of gross and net undeveloped leasehold acres as of December 31, 2017:next three years.

  Acres Expiring
  
Gross
Acres
 
Net
Acres
  (in thousands)
Years Ending December 31:    
2018 485
 189
2019 259
 145
2020 188
 142
After 2020 155
 112
Held-by-production(a)
 2,876
 1,808
Total 3,963
 2,396

(a)Held-by-production acres will remain in force as production continues on the subject leases.Marketing
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Marketing, Gathering and Compression
Previously, we have presented two reportable operating segments: (i) exploration and production and (ii) marketing, gathering and compression. In the fourth quarter of 2017, we completed the realignmentThe principal function of our marketing gathering and compression operations to serve as an ancillary service integral to our exploration and production activities. Our marketing, gathering and compression operations now principally operateis 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 gathering, and compression 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. In addition, we periodically enter into a variety of oil, natural gas and NGL purchase and sale contracts with third parties for various commercial purposes, including credit risk mitigation and satisfaction of our pipeline delivery commitments.
Following this realignment, we have a single, company-wide management team that administers all activities as a whole rather than through discrete operating units, with an emphasis on allocating capital focused on the expansion of our exploration and production assets. As a result, we have concluded that we have only one reportable operating segment, which is exploration and production. Prior year financial information for our previous Marketing, Gathering and Compression reportable segment has been eliminated. See further discussion in Note 1 of the notes to our consolidated financial statements included in Item 8 of Part II of this report.
Generally, our oil production is sold under market-sensitive short-term or spot price contracts. Natural gas and NGL production isare 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.
Sales
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Major Customers
For the 2021 Successor Period, sales to Royal Dutch Shell PLC constitutedValero Energy Corporation and Energy Transfer Crude Marketing accounted for approximately 10%14% and 11%, respectively, of our total revenues (before the effects of hedging). For the 2021 Predecessor Period, sales to Valero Energy Corporation accounted for the year ended December 31, 2017. Sales to BP PLC constituted approximately 10% and 14%19% of our 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 years ended December 31, 2016 and 2015, respectively.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.
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Regulation – General
Public Policy and Government Regulation
All of our operations are conducted onshore in the United States. The U.S. oil and natural gasOur industry is regulated at the federal, statesubject to a wide range of regulations, laws, rules, taxes, fees and local levels,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 thewhich carry substantial penalties for failure to comply. These laws and regulations that govern our operations carry substantial administrative, civil and criminal penalties for non-compliance. Although we believe we are in material compliance with all applicable laws and regulations, and thatincrease the cost of compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations, such lawsdoing business and regulations could be, and frequently are, amended or reinterpreted.consequently affect profitability. Additionally, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. Therefore, we are unable to predict the future costs or impact of compliance or non-compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, state and local governments, the courts and federal agencies, such as the U.S. Environmental Protection Agency (EPA), the Federal Energy Regulatory Commission, the Department of Transportation, the Department of Interior and the U.S. Army Corps of Engineers (USACE). 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, OperationsEnvironmental, Health and Safety and Occupational Laws and Regulations
TheOur operations are subject to federal, tribal, state, and local laws and regulations. These laws and regulations applicablerelate to our explorationmatters that include, but are not limited to, the following:
•reporting of workplace injuries and production operations include requirements forillnesses;
•industrial hygiene monitoring;
•worker protection and workplace safety;
•approval or permits or approvals to drill and to conduct other operations and for operations;
•provision of financial assurances (such as bonds) covering drilling and well operations. Other activities subject to such lawsoperations;
•calculation and regulations include, but are not limited to, the following:disbursement of royalty payments and production taxes;
•seismic operations;operations/data;
the •location, drilling, cementing and casing of wells;
•well design and construction of pad and equipment;
•construction and operations activities including in sensitive areas, such as wetlands, coastal regions or areas that contain endangered or threatened species, their habitats, or their habitats;sites of cultural significance;
the •method of drillingwell completion and completing wells;hydraulic fracturing;
•water withdrawal;
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•well production and operations, including the installation of flowlinesprocessing and gathering systems;
air •emergency response, contingency plans and spill prevention plans;
•emissions and hydraulic fracturing;discharges permitting;
the •climate change;
•use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations;
•surface useusage, maintenance, monitoring and the restoration of properties upon which oil and natural gas facilities are located, including the construction ofassociated with well pads, pipelines, impoundments and associated access roads;
water withdrawal;
the •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 generation, storage, transportation treatment, recyclingTrump administration, as well as a memorandum to departments and agencies to refrain from proposing or disposalissuing 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 hazardous waste, fluidsthe 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 substancesstates 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 connectionsome 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 operations;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.
the construction and operation of underground injection wellsPermitting activities on federal lands are also subject to dispose of produced water and other liquid oilfield wastes;
the construction and operation of surface pits to contain drilling muds and other fluids associated with drilling operations;
the marketing, transportation and reporting of production; and
the valuation and payment of royalties.
frequent delays. Delays in obtaining permits or an inability to obtain new permits or permit renewalscould 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.
Our exploration and production activities are also subject to various resource conservation regulations. These include the regulation of the size of drilling and spacing units (regarding the density of wells that may be drilled in a particular area) and the unitization or pooling of oil and natural gas properties. In this regard, some states, such as Oklahoma, allow the forced pooling or integration of tracts to facilitate exploration, while other states, such as Texas, West Virginia and Pennsylvania, rely on voluntary pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units and, therefore, more difficult to fully develop a project if the operator owns or controls less than 100% of the leasehold. In addition, some states’ resource conservation laws establish maximum rates of production from oil and natural gas wells, generally limit the venting or flaring of natural gas and impose certain
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requirements regarding the ratability of production. The effect of these regulations is to limit the amount of oil and natural gas we can produce and to limit the number of wells and the locations at which we can drill.
Hydraulic Fracturing
Hydraulic fracturing is regulated by state and federal oil and gas regulatory authorities, including specifically the requirement to disclose certain information related to hydraulic fracturing operations. We follow applicable legal requirements for groundwater protection in our operations that are subject to supervision by state and federal regulators (including the Bureau of Land Management on federal acreage). Furthermore, our well construction practices require the installation of multiple layers of protective steel casing surrounded by cement that are specifically designed and installed to protect freshwater aquifers by preventing the migration of fracturing fluids into aquifers. 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 impacts of hydraulic fracturing, which could spur further action toward federal and/or state legislation and regulation of hydraulic fracturing activities. In addition, in light of concerns about seismic activity being triggered by the injection of produced waters into underground wells and hydraulic fracturing, certain regulators are also considering additional requirements related to seismic safety for hydraulic fracturing activities. For example, the Oklahoma Corporation Commission (OCC) has released guidance to operators in the SCOOP and STACK areas for management of certain seismic activity that may be related to hydraulic fracturing activities. Further restrictions on hydraulic fracturing could make it prohibitive to conduct our operations, and also reduce the amount of oil, natural gas and NGL that we are ultimately able to produce in commercial quantities from our properties. For further discussion, see Item 1A. Risk Factors – Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Regulation – Environment, Health and Safety
Our operations are subject to stringent and complex federal, state and local laws and regulations relating to the protection of human health and safety, the environment and natural resources. These laws and regulations can restrict or impact our business activities in many ways, such as:
requiring the installation of pollution-control equipment or otherwise restricting the way we can handle or dispose of wastes and other substances associated with operations;
limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas that contain endangered or threatened species and/or species of special statewide concern or their habitats;
requiring investigatory and remedial actions to address pollution caused by our operations or attributable to former operations;
requiring noise, lighting, visual impact, odor and/or dust mitigation, setbacks, landscaping, fencing, and other measures;
restricting access to certain equipment or areas to a limited set of employees or contractors who have proper certification or permits to conduct work (e.g., confined space entry and process safety maintenance requirements); and
restricting or even prohibiting water use based upon availability, impacts or other factors.
Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial or restoration obligations, and the issuance of orders enjoining future operations or imposing additional compliance requirements. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or wastes have been disposed or otherwise released. Moreover, local restrictions, such as state or local moratoria, city ordinances, zoning laws and traffic regulations, may restrict or prohibit the execution of our drilling and production plans. In addition, third parties, such as neighboring landowners, may file claims alleging property damage, nuisance or personal injury arising from our operations or from the release of hazardous substances, hydrocarbons or other waste products into the environment.
We monitor developments at the federal, state and local levels to inform our actions pertaining to future regulatory requirements that might be imposed to mitigate the costs of compliance with any such requirements. We also participate in industry groups that help formulate recommendations for addressing existing or future regulations and that share best practices and lessons learned in relation to pollution prevention and incident investigations.
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Below is a discussion of the major environmental, health and safety laws and regulations that relate to our business. We believe we are in material compliance with these laws and regulations. We do not believe compliance with existing environmental, health and safety laws or regulations will have a material adverse effect on our financial condition, results of operations or cash flow. At this point, however, we cannot reasonably predict what applicable laws, regulations or guidance may eventually be adopted with respect to our operations or the ultimate cost to comply with such requirements.
Hazardous Substances and Waste
Federal and state laws, in particular the federal Resource Conservation and Recovery Act (RCRA) regulate hazardous and non-hazardous wastes. In the course of our operations, we generate petroleum hydrocarbon wastes, such as drill cuttings, produced water and ordinary industrial wastes. Under a longstanding legal framework, certain of these wastes are currently not subject to federal regulations governing hazardous wastes, although they are regulated under other federal and state waste laws. At various times in the past, most recently in December 2016, proposals have been made to amend RCRA or otherwise eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose and would cause us, as well as our competitors, to incur significantly increased operating expenses.
Federal, state and local laws may also require us to remove or remediate wastes or hazardous substances that have been previously disposed or released into the environment. This can include removing or remediating wastes or hazardous substances disposed or released by us (or prior owners or operators) in accordance with then current laws, suspending or ceasing operations at contaminated areas, or performing remedial well plugging operations or response actions to reduce the risk of future contamination. Federal laws, including the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) and analogous state laws impose joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered legally responsible for releases of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, persons who disposed or arranged for the disposal of hazardous substances at the site, and any person who accepted hazardous substances for transportation to the site. CERCLA and analogous state laws also authorize the EPA, state environmental agencies and, in some cases, third parties to take action to prevent or respond to threats to human health or the environment and/or seek recovery of the costs of such actions from responsible classes of persons.
The Underground Injection Control (UIC) Program authorized by the Safe Drinking Water Act prohibits any underground injection unless authorized by a permit. We recycle and reuse some produced water and we also dispose of produced water in Class II UIC wells, which are designed and permitted to place the water into deep geologic formations, isolated from fresh water sources. Permits for Class II UIC wells may be issued by the EPA or by a state regulatory agency if EPA has delegated its UIC Program authority. Because some states have become concerned that the disposal of produced water could under certain circumstances contribute to seismicity, they have adopted or are considering adopting additional regulations governing such disposal.
Air Emissions
Our operations are subject to the federal Clean Air Act (CAA) and comparable state laws and regulations. Among other things, these laws and regulations regulate emissions of air pollutants from various industrial sources, including compressor stations and production equipment, and impose various control, monitoring and reporting requirements. Permits and related compliance obligations under the CAA, each state's development and promulgation of regulatory programs to comport with federal requirements, as well as changes to state implementation plans for controlling air emissions in regional non-attainment or near-non-attainment areas, may require oil and gas exploration and production operators to incur future capital expenditures in connection with the addition or modification of existing air emission control equipment and strategies.
Discharges into Waters
The federal Water Pollution Control Act, or the Clean Water Act (CWA), and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters as well as waters of the United States. Spill prevention, control and countermeasure regulations require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a release of hydrocarbons. In addition,
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the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities and construction activities.
The Oil Pollution Act of 1990 (OPA) establishes strict liability for owners and operators of facilities that release oil into waters of the United States. The OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. A ''responsible party'' under the OPA includes owners and operators of certain onshore facilities from which a release may affect waters of the United States.
Health and Safety
The Occupational Safety and Health Act (OSHA) and comparable state laws regulate the protection of the health and safety of our employees. The federal Occupational Safety and Health Administration has established workplace safety standards that provide guidelines for maintaining a safe workplace in light of potential hazards, such as employee exposure to hazardous substances. OSHA also requires employee training and maintenance of records, and the OSHA hazard communication standard and EPA community right-to-know regulations under the Emergency Planning and Community Right-to-Know Act of 1986 require that we organize and/or disclose information about hazardous materials used or produced in our operations.
Endangered Species
The Endangered Species Act (ESA) prohibits the taking of endangered or threatened species or their habitats. While some of our assets and lease acreage may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in material compliance with the ESA. However, the designation of previously unidentified endangered or threatened species in areas where we intend to conduct construction activity or the imposition of seasonal restrictions on our construction or operational activities could materially limit or delay our plans.
Global Warming and Climate Change
At the federal level, EPA regulations require us to establish and report a prescribed inventory of greenhouse gas emissions. Legislative and regulatory proposals for restricting greenhouse gas emissions or otherwise addressing climate change could require us to incur additional operating costs and could adversely affect demand for the oil and natural gas that we sell. In recent years, the EPA has considered additional standards of performance to limit methane emissions from oil and gas sources. In 2017, the EPA announced that it is reconsidering these standards and has proposed to stay their requirements. However, the standards currently remain in effect. The potential increase in our operating costs could include new or increased costs to (i) obtain permits, (ii) operate and maintain our equipment and facilities (through the reduction or elimination of venting and flaring of methane), (iii) install new emission controls on our equipment and facilities, (iv) acquire allowances authorizing our greenhouse gas emissions, (v) pay taxes related to our greenhouse gas emissions, and (vi) administer and manage a greenhouse gas emissions program. In addition to these federal actions, state governments and/or regional agencies are considering enacting new legislation and/or promulgating new regulations governing or restricting the emission of greenhouse gases from stationary sources such as our equipment and operations.
In addition, the United States was actively involved in the United Nations Conference on Climate Change in Paris, which led to the creation of the Paris Agreement. The Paris Agreement requires countries to review and “represent a progression” in their nationally determined contributions, which set emissions reduction goals, every five years. In August of 2017, the United States informed the United Nations of its intent to withdraw from the Paris Agreement. The earliest possible effective withdrawal date from the Paris Agreement is November 2020. For further discussion, see Item 1A. Risk Factors - Potential legislativeOil and regulatory actions addressing climate change could significantly impact our industrynatural gas operations are uncertain and the Company, causing increasedinvolve substantial costs and reduced demand for oil and natural gas.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 $100$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 OfficersChairman and Director
Robert D. Lawler,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
Robert D.Domenic J. (“Doug”Nick”) LawlerDell'Osso, Jr., 51,45, has served as President and Chief Executive Officer since June 2013.October 2021. Prior to joining Chesapeake,being named as CEO, Mr. LawlerDell’Osso served in multiple engineering and leadership positions at Anadarko Petroleum Corporation. His positions at Anadarko included Senior Vice President, International and Deepwater Operations and member of Anadarko’s Executive Committee from July 2012 to May 2013; Vice President, International Operations from December 2011 to July 2012; Vice President, Operations for the Southern and Appalachia Region from March 2009 to July 2012; and Vice President, Corporate Planning from August 2008 to March 2009. Mr. Lawler began his career with Kerr-McGee Corporation in 1988 and joined Anadarko following its acquisition of Kerr-McGee in 2006.
Domenic J. Dell'Osso, Jr., Executive Vice President and Chief Financial Officer
Domenic J. (“Nick”) Dell'Osso, Jr., 41, has 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.
Frank J. Patterson, ExecutiveVice President – Exploration and Production
Frank Patterson, 59, has served as Executive Vice President - Exploration and Production since August 2016. Previously, he served as Executive Vice President – Exploration and Northern Division since April 2016 and as Executive Vice President – Exploration, Technology & Land since May 2015. Before joining Chesapeake, Mr. Patterson served in various roles at AnadarkoDell’Osso was an energy investment banker with Jefferies & Co. from 2006 to 2015,2008 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 – International Exploration.North Business Unit. Prior to thatjoining 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 was Vice President – Deepwaterbegan his career at Shell Exploration at Kerr-McGee& Production Company where he held business planning, reservoir engineering and Manager – Geology at Sun E&P/Oryx Energy.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.
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M. Jason Pigott, Josh Viets, Executive Vice President – Operations and Technical ServicesChief Operating Officer
M. Jason Pigott, 44,has served asJosh Viets, 43, was appointed Executive Vice President – Operations and Technical Services since August 2016. Previously, heChief 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 – Operations, Southern Division since January 2015 and Senior Vice President – Operations, Southern Division since August 2013. Before joining Chesapeake, Mr. Pigott served in various positions at Anadarko and focused on all aspects of developing unconventional resources. His positions at Anadarko included General Manager Eagle Ford from June to August 2013; General Manager East Texas and North Louisiana from October 2010 to June 2013; Southern & Appalachia Planning Manager from October 2009 to October 2010; Reservoir Engineering Manager East Texas and North Louisiana from July to October 2009; and Reservoir Engineering Manager Bossier from 2007 to July 2009.
James R. Webb, Executive Vice President –- General Counsel and Corporate Secretary
James R. Webb, 50, has served asBenjamin E. (“Ben”) Russ, 47, was appointed Executive Vice President – General Counsel and Corporate Secretary since January 2014. Previously,in June 2021. Prior to that time, he served as Associate General Counsel – Corporate from May 2014 to June 2021; Division Counsel/Senior Vice President – LegalDivision 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 since October 2012 and as Corporate Secretary since August 2013. Mr. Webb first joined Chesapeake in May 2012 on a contract basis as Chief Legal Counsel.from 2006 to 2008. Prior to joining Chesapeake, Mr. WebbGulfport, he was an attorney withassociate at the law firm of McAfeeMcKinney & TaftStringer, P.C. Mr. Russ received a B.S. in Finance from 1995 to October 2012.
William M. Buergler – Senior Vice PresidentOklahoma State University in 1996 and Chief Accounting Officer
William Buergler, 45, has served as Senior Vice President and Chief Accounting Officer since August 2017. Previously, he served as Vice President - Tax since July 2014. Before joining Chesapeake, he worked for Ernst & Young LLP, where he served as a Partner since 2009.
Other Senior Officer
Cathlyn L. Tompkins, Senior Vice President – Information Technology and Chief Information Officer
Cathlyn L. Tompkins, 57, has served as Senior Vice President – Information Technology and Chief Information Officer since 2006. Ms. Tompkins served as Vice President – Information TechnologyJ.D. from 2005 to 2006.
Employees
We had approximately 3,200 employees as of December 31, 2017. Subsequent to December 31, 2017, we underwent a reduction in workforce that affected approximately 13% of our employees across all functions, primarily at our Oklahoma City campus.University in 2004.
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ITEMHuman 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 intensityto 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 operating results of operations, many of which are beyond our control. The following is a description of significant 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, operating 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, operating 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 such as those experienced in 2015 and continuing into the first quarter of 2017, may result in ceiling test write-downsa 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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Historically, the markets for oil, natural gas and NGL have been volatile, and they are likely to continue to be volatile. Wide fluctuationsVolatility 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;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 with any certainty. As of February 22, 2018, including January and February derivative contracts that have settled, approximately 74% and 68% of our forecasted 2018 oil production and natural gas production, respectively, was hedged through swaps and collars. Even with oil, natural gas and NGL derivatives currently in place to mitigate price risks associated with a portion of our 2018 cash flows, we have substantial exposure to oil, natural gas and NGL prices in 2019 and beyond.movements. In addition, aany prolonged extensionperiod of lower prices could reduce the quantities of reserves that we may economically produce.
WeThe ongoing COVID-19 pandemic and related economic turmoil have a significant amount of indebtedness. Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects, and we may have difficulty paying our debts as they become due.
As of December 31, 2017, we had approximately $10.0 billion in principal amount of debt outstanding (including $52 million of current maturities and $781 million drawn under our senior secured revolving credit facility). We had approximately $116 million of letters of credit issued and borrowing capacity of approximately $2.9 billion under our $3.8 billion senior secured revolving credit facility.
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The level of and terms and conditions governing our debt:
require us to dedicate a substantial portion of our cash flow from operations to service our existing debt obligationsaffected, and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate;
increase our vulnerability to the cyclical nature of our business, economic downturns or other adverse developments in our business;
could limit our ability to access capital markets, refinance our existing indebtedness, raise capital on favorable terms, or obtain additional financing for working capital, capital expenditures, acquisitions, debt service requirements, execution of our business strategy, or for other purposes;
expose us to the risk of increased interest rates as certain of our borrowings, including borrowings under our credit facility, bear interest at floating rates;
place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations;
place us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size, or those that have less restrictive terms governing their indebtedness, thereby enabling competitors to take advantage of opportunities that our indebtedness may prevent us from pursuing;
limit management’s discretion in operating our business; and
increase our cost of borrowing.
Any of the above listed factors could have a material adverse effect on our business, financial condition, cash flows and results of operations.
Our ability to pay our expenses and fund our working capital needs and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. We will not be able to control many of these factors, such as commodity prices, other economic conditions and governmental regulation. We have drawn on our credit facility for liquidity, and the borrowing base under our credit facility is subject to redetermination on June 15, 2018. To the extent that the value of the collateral pledged under the credit facility declines as a result of lower oil and natural gas prices, asset dispositions or otherwise, we may be required to pledge additional collateral in order to maintain the current availability of the commitments thereunder, and we cannot assure you that we will be able to maintain a sufficiently high valuation to maintain the current commitments. In addition, we cannot be certain that our cash flow will be sufficient to allow us to pay the principal and interest on our debt and meet our other obligations. If we are unable to service our indebtedness and other obligations, we may be required to restructure or refinance all or part of our existing debt, sell assets, reduce capital expenditures, borrow more money or raise equity, some or all of which may not be available to us on terms acceptable to us, if at all, or such alternative strategies may yield insufficient funds to make required payments on our indebtedness. In addition, our ability to comply with the financial and other restrictive covenants in our indebtedness could be affected by our future performance and events or circumstances beyond our control. Failure to comply with these covenants would result in an event of default under such indebtedness, the potential acceleration of our obligation to repay outstanding debt and the potential foreclosure on the collateral securing such debt, and could cause a cross-default under our other outstanding indebtedness. Any of the above risks could materially adversely affect our business, financial condition, cash flows and results of operations.
We have significant capital needs, and our ability to access the capital and credit markets to raise capital on favorable terms is limited by our debt level and 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. Low commodity prices have caused and may continue to cause lenders to increase interest rates, 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. If we are unable to access the capital and credit markets on favorable terms, it could have a material adverse effect onadversely affect, our business, financial condition, results of operations and cash flowsflows.
The global spread of COVID-19 created significant volatility, uncertainty, and liquidityeconomic 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 abilitybusiness. Moreover, future operations could be negatively affected if a significant number of our employees are quarantined as a result of exposure to repaythe 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 refinancedelays, may also have an adverse impact on our debt.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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If we are unable to generate enough cash flow from operations to service our indebtedness or are unable to use future borrowings to refinance our indebtedness or fund other capital needs, we mayMarch 2021, crude oil prices have to undertake alternative financing plans, which may have onerous terms or may be unavailable.
Our earnings and cash flow could vary significantly from year to year due to the cyclical nature of our industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. Additionally, our future cash flow may be insufficient to meet our debt obligations and commitments. A range of economic, competitive, business and industry factors will affect our future financial performance and,remained depressed as a result our abilityof the oversupply of oil, an increasingly utilized global storage network and the decrease in crude oil demand due to generate cash flow from operationsCOVID-19. Oil and service our debt. Factorsnatural 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 may cause us to generate cash flow that is insufficient to meet our debt obligations includeCOVID-19 or the eventssignificant disruption and risks related to our business, many of which are beyond our control. Any cash flow insufficiency wouldvolatility currently being experienced in the oil and natural gas markets will have a material adverse impact on our business, financial condition and results of operations, cash flowsoperations.
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 liquidityits rapidly evolving and our abilityspreading variants, the consequences of governmental and other measures designed to repay or refinance our debt.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 we do not generate sufficient cash flow from operations to service our outstanding indebtedness,commodity prices fall or if future borrowingsdrilling efforts are not available to us in an amount sufficient to enable us to pay or refinance our indebtedness,unsuccessful, we may be required to undertake various alternative financing plans, which may include:
refinancing or restructuring all or a portion of our debt;
seeking alternative financing or additional capital investment;
selling strategic assets;
reducing or delaying capital investments; or
revising or delaying our strategic plans.
We cannot assure you that we would be able to implement any of the above alternative financing plans, if necessary, on commercially reasonable terms or at all. If we are unable to generate sufficient cash flow to satisfy our debt obligations or to obtain alternative financing, our business, financial condition, results of operations, cash flows and liquidity could be materially and adversely affected. Any failure to make scheduled payments of interest and principal on our outstanding indebtedness would likely result in a reduction of our credit rating, which could significantly harm our ability to incur additional indebtedness on acceptable terms. Further, if for any reason we are unable to meet our debt service and repayment obligations, we would be in default under the terms of the agreements governing our debt, which would allow our creditors under those agreements to declare all outstanding indebtedness thereunder to be due and payable (which would in turn trigger cross-acceleration or cross-default rights between the relevant agreements), the lenders under our credit facility could terminate their commitments to extend credit, and the lenders could foreclose against our assets securing their borrowings and we could be forced into bankruptcy or liquidation. In addition, the lenders under our credit facility could compel us to apply our available cash to repay our borrowings. If the amounts outstanding under the credit facility or any of our other significant indebtedness were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full the amounts owed to the lenders or to our other debt holders.
Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase.
Borrowings under our revolving credit facility, term loan facility and floating rate senior notes due 2019 bear interest at variable rates and expose us to interest rate risk. If interest rates increase and we are unable to hedge our interest rate risk, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same.
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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.
Certain of 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 to engage in other business activities that would be in our interest.
Also, our credit facility requires us to maintain compliance with specified financial ratios and satisfy certain financial condition tests. Declines in oil, NGL and natural gas prices, or a prolonged period of low oil, NGL and natural gas prices and other events, some of which are beyond our control, could eventually result in our failing to meet one or more of the financial covenants under our credit facility, which could require us to refinance or amend such obligations resulting in the payment of consent fees or higher interest rates, or require us to raise additional capital at an inopportune time or on terms not favorable to us.

A breach of any of these covenants or our inability to comply with the required financial ratios or financial condition tests could result in a default under our credit facility that, if not cured or waived, could result in acceleration of all indebtedness outstanding thereunder and cross-default rights under our other debt. In addition, in the event of an event of default under the credit facility, term loan or second lien notes, the affected lenders could foreclose on the collateral securing the credit facility and require repayment of all borrowings outstanding thereunder. If the amounts outstanding under the credit facility or any of our other indebtedness were to be accelerated, our assets may not be sufficient to repay in full the amounts owed to the lenders or to our other debt holders.

Our credit rating could negatively impact our availability and cost of capital and could require us to post more collateral under certain commercial arrangements.
Some of our counterparties have requested or required us to post collateral as financial assurance of our performance under certain contractual arrangements, such as gathering, transportation, processing and hedging agreements. These collateral requirements depend, in part, on our credit ratings. As of February 20, 2018, we have received requests and posted approximately $151 million of collateral related to certain of our marketing and other contracts. We may be requested or required by other counterparties to post additional collateral in an aggregate amount of approximately $486 million, which may be in the form of additional letters of credit, cash or other acceptable collateral. Any downgrade to our credit ratings could impact the posting of collateral consisting of cash or letters of credit, which would reduce availability under our credit facility, and negatively impact our liquidity.
Declines in commodity prices could result inrecord write downs of the carrying value of our oil and natural gas properties.
UnderWe have been required to write down the full cost methodcarrying value of accounting for costs related tocertain of our oil and natural gas properties in the past, and there is a risk that we arewill be required to write downtake 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 assets if capitalized costs exceedproperties for possible impairment. Impairment is recognized for the presentexcess of book value over fair value when the book value of a proven property is greater than the expected undiscounted future net revenues of our proved reserves, whichcash flows from that property and on acreage when conditions indicate the carrying value is based on the average of commodity prices on the first day of the month
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over the trailing 12-month period. Such write-downs couldnot recoverable. We may be material. As of December 31, 2017, the present value of estimated future net revenue of our proved reserves, discounted at an annual rate of 10%, was $7.5 billion, which exceedsrequired to write down the carrying value of oura property based on oil and natural gas properties.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. Our reserve estimates as of December 31, 2017 reflect an expected decline in the production rate on our producing properties of approximately 35% in 2018 and 23% in 2019. 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, 2017,2021, approximately 42%41% of our estimated proved reserves (by volume) were undeveloped. These reserve estimates reflect our plans to make significantfor capital expenditures to convert our PUDs into proved developed reserves, including approximately $4.3$2.7 billion during the next five years ending in 2022.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, 20172021 present value is based on a $51.34$66.56 per bbl of oil price and a $2.98$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
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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 asif 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. All costs of development and exploratory drilling activities are capitalized under the full cost method, even if the activities do not result in commercially productive discoveries, which may result in a future impairment of our oil and natural gas properties if commodity prices decrease.
We rely to a significant extent on seismic data and other advanced 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.
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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.
In order toTo 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 not deemed to be favorable.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 bi-lateralbilateral hedging arrangements. Under a majority of our arrangements, the collateral provided for our obligations is secured by the same hydrocarbon interests that secure our senior secured revolving credit facility. Under other arrangements, our obligations under the bi-lateral hedging arrangements must be secured by cash or letters of credit to the extent that any mark-to-market amounts owed to us or by us exceed defined thresholds. Under certain circumstances, the cash collateral value posted could fall below the coverage designated, and we would be required to post additional cash or letter of credit collateral under our hedging arrangements.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 itstheir 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.
The ultimate outcome of pending legal and governmental proceedings is uncertain, and there are significant costs associated with these matters.
We are defending against claims by royalty owners alleging, among other things, that we used below-market prices, made improper deductions, used improper measurement techniques, entered into arrangements with affiliates that resulted in underpayment of royalties in connection with the production and sales of natural gas and NGL and similar theories. Numerous cases are pending. The resolution of disputes regarding past payments could cause our future obligations to royalty owners to increase and would negatively impact our future results of operations.
In addition, there are ongoing governmental regulatory investigations and inquiries into such matters as our royalty practices and possible antitrust violations. The outcome of any pending or future litigation or governmental regulatory matter is uncertain and may adversely affect our results of operations. In addition, we have incurred substantial legal expenses in the past three years, and such expenses may continue to be significant in the future. Further, attention to these matters by members of our senior management has been required, reducing the time they have available to devote to managing our business.

We may continue to incur cash and noncash charges that would negatively impact our future results of operations and liquidity.
While executing our strategic priorities to reduce financial leverage and complexity and to lower our capital expenditures in the face of lower commodity prices, we have incurred certain cash charges, including contract termination charges, restructuring and other termination costs, financing extinguishment costs and charges for unused natural gas transportation and gathering capacity. As we continue to focus on our strategic priorities, we may incur additional cash and noncash charges in 2018 and in future years. If incurred, these charges could materially adversely impact our future results of operations and liquidity.
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Oil and natural gas drilling and producing operations can be hazardous and may expose us to liabilities.
Oil and natural gas operations are uncertain and involve substantial costs and risks.
Our operating activities are subject to manynumerous costs and risks, including well blowouts, cratering, explosions, pipe failures, fires, formations with abnormal pressures, uncontrollable flows ofthe risk that we will not encounter commercially productive oil or gas reservoirs. Drilling for oil, natural gas brineand 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 well fluids,high costs. Substantial costs are required to locate, acquire and develop oil spills, severe weather, natural disasters, groundwater contamination and other environmental hazardsgas properties, and risks. Somewe 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 hazards could materiallyfailure to find commercial quantities of hydrocarbons. In addition, our oil and adversely affectgas properties can become damaged, our revenuesoperations may be curtailed, delayed or canceled and expenses by reducing or shutting in production from wells or otherwise negatively impacting the projected economic performancecosts of our prospects. For our non-operated properties, we are dependent on the operator for operational and regulatory compliance. If any of these risks occurs, we could sustain substantial lossessuch operations may increase as a result of:of a variety of factors, including, but not limited to:
injury•unexpected drilling conditions, pressure conditions or irregularities in reservoir formations;
•equipment failures or accidents;
•fires, explosions, blowouts, cratering or loss of life;well control;
severe damage•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 destructiondisposal 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, natural resources or equipment;
pollution or other environmental damage;
clean-up responsibilities;    
regulatory investigations and administrative, civil and criminal penalties; and
injunctions resulting in limitation or suspension of operations.
A material event such as those described above could expose us to liabilities, monetary penalties or interruptions in our business operations. Whilewell 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.
We are subject to complex laws and regulations relating to environmental protection that can adversely affect the cost, manner and feasibilityMoreover, certain of doing business, and further regulation in the future could increase costs, impose additional operating restrictions and cause delays.
Our operations and properties are subject to numerous federal, regional, state and local laws and regulations governing the release of pollutants or otherwise relating to environmental protection. These laws and regulations govern the following, among other things:
conduct of our exploration, drilling, completion, production and midstream activities;
amounts and types of emissions and discharges;
generation, management, and disposition of hazardous substances and waste materials;
reclamation and abandonment of wells and facility sites; and
remediation of contaminated sites.
In addition, these laws and regulations may impose substantial liabilities for our failure to comply or for any contamination resulting from our operations, including the assessment of administrative, civil and criminal penalties; the imposition of investigatory, remedial, and corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the development of projects; and the issuance of injunctions restricting or prohibiting some or all of our activities in a particular area. Future environmental laws and regulations imposing further restrictions on the emission of pollutants into the air, discharges into state or U.S. waters, wastewater disposal and hydraulic fracturing, or the designation of previously unprotected species as threatened or endangered in areas where we operate, may negatively impact our industry. We cannot predict the actions that future regulation will require or prohibit, but our business and operations could be subject to increased operating and compliance costs if certain regulatory proposals are adopted. In addition, such regulations may have an adverse impact on our ability to develop and produce our reserves.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturingevents could result in increased costsenvironmental pollution and additional operating restrictions or delays.
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. In additionimpact to state laws, some local municipalities have adopted or are considering adopting land use restrictions, such as city ordinances, that may restrict or prohibit the performance of well drillingthird parties, including persons living in general and/or hydraulic fracturing in particular. There have
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also been certain governmental reviews that focus on deep shale and other formation completion and production practices, including hydraulic fracturing. These studies assess, among other things, the risks of groundwater contamination and earthquakes caused by hydraulic fracturing and other exploration and production activities. Based on the results of these studies, federal and state legislatures and agencies may seekproximity to further regulate or even ban such activities, as some state and local governments have already done. In addition, a number of lawsuits have been filed in Oklahoma alleging damage from earthquakes relating to disposal well 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 fracturingour operations, our businessemployees and operations could be subjectemployees of our contractors, leading to delays, increased operatingpossible injuries, death or significant damage to property and compliance costs and process prohibitions. Additional regulation could also lead to greater opposition to hydraulic fracturing, including litigation.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, require the use of water. For example,particularly hydraulic fracturing, requiresrequire 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 new environmental initiatives and regulations such as the OCC’s volume reduction plans for oil and natural gas disposal wells injecting wastewater into the Arbuckle formation and the EPA’s June 2016 pretreatment standards for wastewater, 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.
Potential legislative and regulatory actions addressing climate change could significantly impact our industry and us, causing increased costs and reduced demand for oil and natural gas.
Various state governments and regional organizations are considering enacting new legislation and promulgating new regulations governing or restricting the emission of greenhouse gases from stationary sources such as our equipment and operations. At the federal level, the EPA has already made findings and issued regulations that require us to establish and report a prescribed inventory of greenhouse gas emissions. Additional legislative and/or regulatory proposals for restricting greenhouse gas emissions or otherwise addressing climate change could require us to incur additional operating costs and could adversely affect demand for the oil and natural gas that we sell. The potential increase in our operating costs could include new or increased costs to obtain permits, operate and maintain our equipment and facilities, install new emission controls on our equipment and facilities, acquire allowances to authorize our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program. Even without federal legislation or regulation of greenhouse gas emissions, states may pursue the issue either directly or indirectly.
In addition, the United States was actively involved in the United Nations Conference on Climate Change in Paris, which led to the creation of the Paris Agreement. The Paris Agreement will require countries to review and “represent a progression” in their nationally determined contributions, which set emissions reduction goals, every five years. In August 2017, the United States informed the United Nations of its intent to withdraw from the Paris Agreement. The earliest possible effective withdrawal date from the Paris Agreement is November 2020. The Paris Agreement could further drive regulation in the United States. Restrictions on emissions of methane or carbon dioxide that have been or may be imposed in various states, or at the federal level could adversely affect the oil and gas industry. Moreover, incentives to conserve energy or use alternative energy sources as a means of addressing climate change could reduce demand for oil and natural gas. Finally, we note that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth's atmosphere may produce climate changes that have significant physical effects, such as higher sea levels, increased frequency and severity of storms, droughts, floods, and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.
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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 taxing authorities at the federal, state and local levels where we do business. New legislation increasing our tax burden could be enacted by any of these governmental authorities. Recently, legislative changes imposing additional taxes or increases to existing taxes were considered in Louisiana, Ohio, Oklahoma, Pennsylvania and Wyoming. It is possible that any of these states could enact new tax legislation making it more costly for us to explore for oil and natural gas resources.
Additionally, on December 22, 2017, the President of the United States signed into law tax reform legislation informally known as the Tax Cuts and Jobs Act (the “Tax Act”) that substantially revised numerous areas of U.S. federal income tax law. Although we do not expect there to be an immediate adverse impact on our federal income taxes from the Tax Act, new restrictions on items such as the utilization of net operating loss (NOL) carryforwards and the deductibility of business interest could adversely impact our federal income taxes in future years. Furthermore, the extent to which state and local taxing authorities will adopt tax laws that conform with or differ from provisions of the Tax Act is unclear. Any change in state or local tax law in response to the Tax Act could affect our tax burden and make it more costly for us to explore for oil and natural gas resources.
Further, our ability to utilize our federal NOL carryforwards to reduce future taxable income and federal income tax is subject to various limitations under the Internal Revenue Code of 1986, as amended (the “Code”). The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the acquisition or disposition of our stock by 5% shareholders and our offering of stock during any three-year period resulting in a cumulative shift of more than 50% in our beneficial ownership. In the event of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of NOL carryforwards (accumulated prior to the change date) that can be used to offset our future taxable income. The limitation is generally equal to the product of (a) the fair market value of our equity multiplied by (b) the long-term tax-exempt rate in effect for the month in which the ownership change occurs. In addition, if we are in a net unrealized built-in gain position at the time of an ownership change then the limitation may be increased if there are recognized built-in gains during a certain recognition period following the ownership change. If we are in a net unrealized built-in loss position at the time of an ownership change then the limitation may apply to tax attributes other than just NOL carryforwards such as depreciable basis.  Some states impose similar limitations on tax attribute utilization upon experiencing an ownership change.  We do not believe that an ownership change has occurred as of December 31, 2017 that would limit future utilization of our NOL carryforwards or other tax attributes. 
The oil and gas exploration and production industry is very competitive, and some of our competitors have greater financial and other resources than we do.
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 and, due to our debt levels and other factors, may have greater access to the capital and credit markets. As a result, these competitors may be able to address these competitive factors 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 will be diminished.
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 wouldwill be successfully integrated into our operations and internal controls;
•the due diligence conducted prior to an acquisition wouldwill uncover situations that could result in financial or legal exposure, such as title defects and potential environmental and other liabilities;
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•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 wouldwill be accurate;
•any investment, acquisition, disposition or integration wouldwill not divert management resources from the operation of our business; and
•any investment, acquisition, or disposition or integration wouldwill 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.
A deterioration in general economic, 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 have had a significant impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which 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.
Terrorist activities could materially and adversely affect our business and results of operations.
Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign attacks, as well as military or other actions taken in response to these acts, could cause instability in the global financial and energy markets. Continued hostilities 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.
Negative public perception regarding us and/or our industry could have an adverse effect on our operations.
Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, waste disposal, oil spills, and explosions of natural gas transmission lines may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. 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.
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 shaleresource 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 providingprovision 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, and/or sell oil, natural gas or NGL production at significantly lower prices than those quoted on NYMEX or than we currently project, 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.
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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.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 but these incidents did not havein the past. As an energy company, we expect to continue to be a material adverse impact ontarget 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 results of operations. Nevertheless, unauthorizedthird-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 expendspend significant additional resources to continue 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.
An interruption inAny 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 atcould be disrupted by natural or human causes beyond our headquarters could adversely affect our business.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 do not anticipate paying dividendshave 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 common stockbusiness, financial condition, results of operations, cash flows and liquidity and our ability to repay or refinance our debt. Additionally, challenges in the near future.
In July 2015, our Boardeconomy have led and could further lead to reductions in the demand for oil and gas, or further reductions in the prices of Directors determined to eliminate quarterly cash dividendsoil and gas, or both, which could have a negative impact on our common stock. Accordingly, we do not intend to payfinancial position, results of operations and cash dividends on our common stockflows.
Restrictive covenants in the foreseeable future. We currently intend to retain any earnings for the future operation and developmentcertain 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 including exploration, developmentactivities that may be in our best interests.
Our debt agreements impose operating and acquisition activitiesfinancial restrictions on us. These restrictions limit our ability and that of our restricted subsidiaries to, among other things:
•incur additional indebtedness;
•make investments or to retire outstanding debt and/or preferred stock. Any future dividend payments will require approvalloans;
•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 Board of Directors. In addition, dividends may be restricted by the termsrestrictive covenants under certain of our debt agreements. Additionally,The restrictions contained in the covenants could:
•limit our Boardability 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 Directorsdetermining the London Interbank Offered Rate (LIBOR), or the replacement of LIBOR with an alternative reference rate, may determineadversely affect interest expense related to suspend dividend paymentsoutstanding 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 preferredfinancial 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 future. 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 failwill be subject to a number of risks, including the following:
•we may be required to pay dividends on our preferred stock with respectcertain costs relating to six or more quarterly periods (whetherthe Chief Acquisition, which are substantial, such as legal, accounting, financial advisory and printing fees, whether or not consecutive), the holderstransactions 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 preferredcommon stock, voting asincluding to the extent that the current market price reflects a single class,market assumption that the Chief Acquisition will be entitled atcompleted;
•we may experience negative reactions from employees, customers or vendors; and
•we may not have been able to take certain actions during the next regular or special meeting of shareholders to elect two additional directorspendency of the Company. We had previously failedChief Acquisition that would have benefitted us as an independent company and the opportunity to pay dividends on our outstanding preferred stock with respect to four quarterly periods duringtake such actions may no longer be available.
In addition, any delay in completing the fiscal year ended December 31, 2016, before resuming payment, in arrears, inChief Acquisition may significantly reduce the first quarter of 2017.
Certain anti-takeoversynergies and other provisionsbenefits that we expect that the combined company may affect your rights as a shareholder.achieve if the Chief Acquisition is completed within the expected timeframe.
Our certificate
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 incorporation authorizes our Boardthe Chief Acquisition is conditioned upon the expiration or termination of Directorsany waiting period applicable to setthe 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 issue preferred stockthe 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 acquisitionsand 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 Acquisitionand 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 shareholder approval. Our Boardmerit, 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 Directors could use the preferred stock as a meansconditions to delay, defer or prevent a takeover attemptthe closing of the Chief Acquisition is that a shareholder might considerno 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 best interest. In addition,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 revolving credit facility, term loan facility, preferred stockbusiness, financial condition, results of operations and certaincash flows.

Our integration of our notes contain termsthe 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 restrictbe 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 enterrealize 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 change of control transactions, including requirementsour existing business in an efficient and timely manner, to repay borrowings under our revolving credit facilitycombine systems and management controls and to offer to purchase our term loanintegrate relationships with customers, vendors, industry contacts and to offer to repurchase such notes on a change in control. These provisions, along with specified provisionsbusiness partners.

The anticipated benefits and cost savings of the Oklahoma General Corporation ActVine 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 certificate of incorporation and bylaws,common stock may discourage or impede transactions involving actual or potential changes in our control, including transactionsbe affected by factors different from those that otherwise could involve payment of a premium over prevailing market prices to holdershistorically 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.
ITEM 1B.Unresolved Staff CommentsLegal and Regulatory Risks
Not applicable.
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.
ITEM 2.PropertiesGeneral 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 11. Business and in the Supplementary Information included in Item 8 of Part II of this report.
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ITEMItem 3.Legal Proceedings
LitigationChapter 11 Proceedings
Commencement of the Chapter 11 Cases automatically stayed the proceedings and Regulatory Proceedings
Weactions against us that are involvedreferenced below, in a numberaddition to actions seeking to collect pre-petition indebtedness or to exercise control over the property of litigation and regulatory proceedingsthe 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 those described below. Many of these proceedings are in early stages, and many of them seekpre-petition liabilities that had not been satisfied or may seek damages and penalties,addressed during the amount of which is currently indeterminate.Chapter 11 Cases. See Note 42 of the notes to our consolidated financial statements included in Item 8 of Part III 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.
Regulatory and Related Proceedings. We have received U.S. Postal Service and state subpoenas seeking information on our royalty payment practices. We have engaged in discussions with the U.S. Postal Service and state agency representatives and continue to respond to related subpoenas and demands.
Business Operations. We are involved in various other lawsuits and disputes incidental to our business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions.
Regarding royalty claims, we and other natural gas producers have been named in various lawsuits alleging royalty underpayments. The lawsuits against us allege, among other things, that we used below-market prices, made improper deductions, utilized improper measurement techniques, entered into arrangements with affiliates that resulted in underpaymentmajority of royaltiesthese prepetition legal proceedings were settled during the Chapter 11 Cases or will be resolved in connection with the production and saleclaims 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 natural gas and NGL, or similar theories. These lawsuits include cases filed by individual royalty owners and putative class actions, some of which seek to certify a statewide class. The lawsuits seek compensatory, consequential, treble, and punitive damages, restitution and disgorgement of profits, declaratory and injunctive relief regarding our royalty payment practices, pre-and post-judgment interest, and attorney’s fees and costs. Plaintiffs have varying royalty provisions in their respective leases,the oil and gas law variesbusiness 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 statethe transaction, require the seller to state, and royalty owners and producers differremediate the property to our satisfaction in their interpretationan acquisition or agree to assume liability for the remediation of the legal effect of lease provisions governing royalty calculations. property.
We have resolved a number of these claims through negotiated settlements of past and future royalties and has prevailed in various other lawsuits. We are currently defendingwere recently dismissed from numerous lawsuits seeking damages with respect to underpayment of royalties in multiple states where we have operated, including the matters set forth below.
On December 9, 2015, the Commonwealth of Pennsylvania, by the Office of Attorney General, filed a lawsuit in the Bradford County Court of Common Pleas related to royalty underpayment and lease acquisition and accounting practices with respect to properties in Pennsylvania. The lawsuit, which primarily relates to the Marcellus Shale and Utica Shale, alleges that we violated the Pennsylvania Unfair Trade Practices and Consumer Protection Law (UTPCPL) by making improper deductions and entering into arrangements with affiliates that resulted in underpayment of royalties. The lawsuit includes other UTPCPL claims and antitrust claims, including that a joint exploration agreement to which we are a party established unlawful market allocation for the acquisition of leases. The lawsuit seeks statutory restitution, civil penalties and costs, as well as a temporary injunction from exploration and drilling activities in Pennsylvania until restitution, penalties and costs have been paid, and a permanent injunction from further violations of the UTPCPL.
Putative statewide class actions in Pennsylvania and Ohio and purported class arbitrations in Pennsylvania have been filed on behalf of royalty owners asserting various claims for damages related to alleged underpayment of royalties as a result of our divestiture of substantially all of our midstream business and most of our gathering assets in 2012 and 2013. These cases include claims for violation of and conspiracy to violate the federal Racketeer Influenced and Corrupt Organizations Act and for an unlawful market allocation agreement for mineral rights, intentional interference with contractual relations, and violations of antitrust laws related to purported markets for gas mineral rights, operating rights and gas gathering sources. These lawsuits seek in aggregate compensatory, consequential, treble, and punitive damages, restitution and disgorgement of profits, declaratory and injunctive relief regarding our royalty payment practices, pre-and post-judgment interest, and attorney’s fees and costs. On December 20, 2017, we reached a tentative settlement to resolve substantially all Pennsylvania civil royalty cases for approximately $30 million.
We are also defending lawsuits alleging various violations of the Sherman Antitrust Act and state antitrust laws. In 2016, putative class action lawsuits were filed in the U.S. District Court for the Western District of Oklahoma and in Oklahoma state courts, and an individual lawsuit was filed in the U.S. District Court of Kansas, in each case against us and other defendants. The lawsuits generally allege that, since 2007 and continuing through April 2013, the defendants conspired to rig bids and depress the market for the purchases of oil and natural gas leasehold interests and properties in the Anadarko Basin containing producing oil and natural gas wells. The lawsuits seek damages, attorney’s fees, costs and interest, as well as enjoinment from adopting practices or plans that would restrain competition in a similar manner as alleged in the lawsuits.
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Environmental Proceedings
Our subsidiary Chesapeake Appalachia, LLC (CALLC) is engaged in discussions with the EPA, the USACE and the Pennsylvania Department of Environmental Protection (PADEP) regarding potential violations of the permitting requirements of the federal CWA, the Pennsylvania Clean Streams Law and the Pennsylvania Dam Safety and Encroachments Act in connection with the placement of dredge and fill material during construction of certain sites in Pennsylvania. CALLC identified the potential violations in connection with an internal review of its facilities siting and construction processes and voluntarily reported them to the regulatory agencies. Resolution of the matter may result in monetary sanctions of more than $100,000.
We are also in discussions with PADEP regarding gas migration in the vicinity of certain of our wells in Bradford County, Pennsylvania. We believe we are close to identifying agreed-upon steps to resolve PADEP’s concerns regarding the issue. In addition to these steps, we anticipate making a donation of $300,000 to the PADEP’s well plugging fund.
On December 27, 2016, we received a Finding of Violation from the EPA alleging violations of the CAA at a number of locations in Ohio. We have exchanged information with the EPA and are engaged in discussions aimed at resolving the allegations. Resolution of the matter may result in monetary sanctions of more than $100,000.
We are named as a defendant in numerous lawsuits and putative class actions in Oklahoma alleging that we and other companies have engaged in activities that have caused earthquakes. TheseThe lawsuits seeksought 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 seeksought 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.
ITEMItem 4.Mine Safety Disclosures
Not applicable.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.
Item 5.		Market for Registrant'sRegistrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Price Range of Common Stock
Our
Common Stock
Upon our emergence from Chapter 11 bankruptcy on February 9, 2021, our then-authorized common stock tradesand 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 New YorkNasdaq Stock ExchangeMarket LLC under the symbol "CHK". The following table sets forth,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 periods indicated, the highinitial exercise prices of $27.63, $32.13 and low sales prices$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 common stock as reported by the New York Stock Exchange:consolidated financial statements included in Item 8 of Part II of this report.
  Common Stock
  High Low
Year Ended December 31, 2017:    
Fourth Quarter $4.38
 $3.41
Third Quarter $5.20
 $3.55
Second Quarter $6.59
 $4.38
First Quarter $7.32
 $4.88
     
Year Ended December 31, 2016:    
Fourth Quarter $8.20
 $5.14
Third Quarter $8.15
 $4.13
Second Quarter $7.59
 $3.53
First Quarter $5.76
 $1.50
Shareholders
As of February 20, 2018, there were approximately 1,850 holders of record of our common stock and approximately 595,000 beneficial owners.
Dividends
We ceased paying dividendsdeclared the first quarterly dividend on our common stockNew Common Stock in the 2015second quarter of 2021 of $0.34375 per share (an initial annual rate of $1.375 per share). In the third quarter and do not anticipate paying any dividends on our common stockof 2021, we announced an increase in the foreseeable future. Our revolving credit facility,base quarterly dividend to $0.4375 per share (an annual rate of $1.75 per share) and announced our term loan facility and the certificates of designation for our preferred stock contain restrictions on our abilityintent to declare and pay cash dividends on our common or preferred stock if an event of default has occurred. The certificates of designation for our preferred stock prohibit payment of cash dividends on our common stock unless we have declared and paid (or set apart for payment) full accumulated dividends on the preferred stock. After suspendingadopt a variable return program that will result in the payment of dividends onan 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 outstanding convertible preferred stock during fiscal year 2016, we reinstatedintent to increase the paymentbase dividend to $0.50 per share (an annual rate of dividends on each series of our outstanding convertible preferred stock$2.00 per share) beginning with the dividends payable in the 2017 firstsecond quarter and paid all dividends in arrears.of 2022.
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Repurchases of Equity Securities; Unregistered Sales of Equity Securities and Use of Proceeds

Unregistered Sales of Equity Securities and Use of Proceeds
The following table presents information aboutThere were no repurchases or unregistered sales of our common stock during the quarter ended December 31, 2017:2021.
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.
Period 
Total
Number
of Shares
Purchased(a)
 
Average
Price
Paid
Per
Share(a)
 
Total Number
of Shares
Purchased as
Part of
Publicly
Announced
Plans or
Programs
 
Maximum
Approximate
Dollar Value
of Shares
That May Yet
Be Purchased
Under
the Plans
or Programs(b)
        ($ in millions)
October 1, 2017 through October 31, 2017 11,666
 $4.36
 —
 $1,000
November 1, 2017 through November 30, 2017 —
 $—
 —
 $1,000
December 1, 2017 through December 31, 2017 —
 $—
 —
 $1,000
Total 11,666
 $4.36
 —
  

(a)Includes shares of common stock purchased on behalf of our deferred compensation plan related to participant deferrals and Company matching contributions.Shareholders
As of February 21, 2022, there were approximately 146 holders of record of our common stock.
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(b)Item 6.In December 2014, our Board of Directors authorized the repurchase of up to $1 billion of our common stock from time to time. The repurchase program does not have an expiration date. As of December 31, 2017, there have been no repurchases under the program.Selected Financial Data
We have adopted the SEC’s Disclosure Modernization Final Rule, effective February 10, 2021, for Item 301 of Regulation S-K. As such, Item 6 Selected Financial Data has not been provided.
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ITEM 6.
Item 7.		Selected Financial Data
The following table sets forth selected consolidated financial data of Chesapeake as of and for the years ended December 31, 2017, 2016, 2015, 2014 and 2013. The data are derived from our audited consolidated financial statements. The table below should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations and our consolidated financial statements, including the notes thereto, appearing in Items 7 and 8, respectively, of this report.
  Years Ended December 31,
  2017 2016 2015 2014 2013
  ($ in millions, except per share data)
STATEMENT OF OPERATIONS DATA:          
Total revenues $9,496
 $7,872
 $12,764
 $23,125
 $19,080
Net income (loss) available to common stockholders(a)
 $813
 $(4,915) $(14,738) $1,273
 $474
           
EARNINGS (LOSS) PER COMMON SHARE:          
Basic $0.90
 $(6.43) $(22.26) $1.93
 $0.73
Diluted $0.90
 $(6.43) $(22.26) $1.87
 $0.73
           
CASH DIVIDEND DECLARED PER COMMON SHARE $—
 $—
 $0.0875
 $0.35
 $0.35
           
BALANCE SHEET DATA (AT END OF PERIOD):          
Total assets $12,425
 $13,028
 $17,314
 $40,655
 $41,663
Long-term debt, net of current maturities $9,921
 $9,938
 $10,311
 $11,058
 $12,767
Total equity (deficit) $(372) $(1,203) $2,397
 $18,205
 $18,140

(a)Includes $2.564 billion and $18.238 billion of full cost ceiling test write-downs on our oil and natural gas properties for the years ended December 31, 2016 and 2015, respectively. In 2017, 2014 and 2013, we did not have any ceiling test impairments on our oil and natural gas properties.
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ITEM 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Overview
Introduction
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. Financial Statements and Supplementary Data”Item 8 of Part II of this report.
Overview of 2017 Results
Introduction
The transformation of Chesapeake overWe are an independent exploration and production company engaged in the past four years has been significant and our progress continued in 2017. Our progress has been guided by our strategies of financial discipline, pursuing profitable and efficient growth from our captured resources, leveraging technology and our operational expertise to unlock additional domestic resources throughacquisition, exploration and development of properties to produce oil, natural gas and optimizing ourNGL from underground reservoirs. We own a large and geographically diverse portfolio through business development. Our strategies have not changed through the price cycles of the past several years,onshore U.S. unconventional natural gas and we believe our recent accomplishments and achievementsliquids assets, including interests in 2017 have made our company stronger. Highlights include the following:
grew estimated proved reserves volumes by 16% in 2017, net of divestitures;
improved cash flow from operations by $949 million;
grew production by 3%, adjusted for asset sales, and met our targeted goal of reaching 100,000 barrels of average net oil production per day in the fourth quarter of 2017, a significant accomplishment representing 11% growth from our 2016 fourth quarter oil volumes;
improved our cost structure by reducing our production, general and administrative, and gathering, processing and transportation expenses by $510 million, or 18%;
generated approximately $1.3 billion in net proceeds from the disposition of certain non-core assets and other property sales;
reduced outstanding secured term debt by approximately $1.3 billion, or 32%;
continued to reduce legal obligations;
exchanged approximately 10.0 million shares of common stock for approximately $100 million of liquidation value of our preferred stock, eliminating approximately $6 million of annual dividend obligations; and
achieved company record health, safety and environmental performance by lowering total recordable incident rates to 0.045 and reducing reportable spills by 15% compared to 2016.
  Years Ended December 31,
  2017 change 2016 change 2015
  ($ in millions)
Net income (loss) available to common stockholders $813
 n/m
 $(4,915) 67 % $(14,738)
Net earnings (loss) per diluted common share $0.90
 n/m
 $(6.43) 71 % $(22.26)
Adjusted production(a) (mboe per day)
 541
 3 % 525
 3 % 511
Total production (mboe per day) 548
 (14)% 635
 (6)% 679
Average sales price (per boe) $22.88
 38 % $16.63
 (14)% $19.23
Oil, natural gas and NGL production expenses $562
 (21)% $710
 (32)% $1,046
Oil, natural gas and NGL gathering, processing and transportation expenses $1,471
 (21)% $1,855
 (12)% $2,119
General and administrative expenses $262
 9 % $240
 2 % $235
Total debt (principal amount) $9,981
 — % $9,989
 3 % $9,706
Estimated proved reserves (mmboe) 1,912
 12 % 1,708
 14 % 1,504

(a)Adjusted for assets sold.
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Business and Industry Outlook
Over the past decade, the landscape of energy production has changed dramatically in the United States. Domestic energy production capabilities have increased the nation’s supply of both crude8,200 oil and natural gas primarily drivenwells. 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 advances in technology, horizontal drilling and hydraulic fracture stimulation techniques. As a result of this increase in domestic supply of crudegenerating sustainable Free Cash Flow from our oil and natural gas commodity prices for these products are meaningfully lower than they were a decade ago, but may remain volatile for the foreseeable future. To this end, we will always strive to protect a portion of our projected cash flow through our commodity hedging program as we see appropriate.

As of February 22, 2018, including Januarydevelopment and February derivative contracts that are settled, approximately 74% of our projected full year 2018 crude oil production was hedged through swaps and open collars at an average of $52.41 per barrel and approximately 68% of our projected full year 2018 natural gas production was hedged through swaps and collars at an average of $3.10 per mcf. Our crude oil hedges are below current 2018 NYMEX crude oil strip prices of approximately $60.00 per barrel, and our natural gas hedges currently sit in a profitable position, above current 2018 NYMEX natural gas strip prices of approximately $2.80 per mcf. While we cannot predict the future movements of commodity prices with complete accuracy, we believe it is prudent to protect a portion of our projected cash flow through hedging and plan toactivities. We continue to do so in the future.
In 2018, our focus is concentrated on three strategic priorities:
reduce total debt by $2 - $3 billion;
increase net cash provided by operating activities to fund capital expenditures; and
improveimproving margins through operating efficiencies and financial discipline and operating efficiencies.
With regard toimproving our debt, we are committed to decreasing the amount of debt outstanding.Environmental, Social, and Governance (“ESG”) performance. To accomplish this objective,these goals, we intend to allocate our human resources and capital expenditures to projects we believe offer the highest-return projects,highest cash return on capital invested, to deploy leading drilling and completion technology throughout our portfolio, and to profitablytake advantage of acquisition and efficiently grow, and divest additional large assetsdivestiture opportunities to strengthen our cost structureportfolio. We also intend to continue to dedicate capital to projects that reduce the environmental impact of our oil and our portfolio. Increasing our margins means not only increasing our level of cash flow from operations, but also increasing our cash flow from operations generated per barrel of equivalent production.natural gas producing activities. We are seekingcontinue to seek opportunities to reduce cash costs (production, general and administrative and gathering, processing and transportation expenses), improveand 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 achieve additional operatingenterprise-wide by 2025;
•Reduce our methane intensity to 0.09% by 2025 (achieved 0.08% in 2021); and capital efficiencies with a focus on growing
•Reduce our oil volumes. Finally,GHG intensity to 5.5 by 2025 (achieved 5.0 in 2021).
In July 2021, we seekannounced our plan to maintainreceive independent certification of our high levelnatural 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 health, safety,the end of 2021, and environmental performance and stewardship.
We have already made significant progress towards achieving our strategic priorities to date in 2018. So far we have:
signed agreements for the sale of properties in the Mid-Continent, including our Mississippian Lime assets, for an expected aggregate amount of approximately $500 million in proceeds that we expect it to closebe available in our legacy Marcellus assets by the end of the 2018 second quarter; and
received net proceedsquarter of approximately $74 million from the sale of approximately 4.3 million shares of FTS International, Inc. (NYSE: FTSI). After the sale, we own approximately 22 million shares of FTSI.
2022. The proceeds from these divestituresMiQ certification will be usedprovide a verified approach to repay debt and fundtracking our development program, based on market conditions.
Over the last four years, we have fundamentally transformed substantially all aspects of our business, removing financial and operational complexity, significantly improving our balance sheet and addressing numerous legacy issues. Our 2018 capital expenditures program, while planned to be approximately 12% lower than our 2017 program, is expected to generate greater capital efficiency as we focus on expanding our margins by investing in the highest-return projects. In January, we reduced our workforce by approximately 13% as part of an overall plancommitment to reduce costs and better align our workforcemethane intensity to the needs0.09% by 2025, as well as support our overall objective of our business. We are committed to reducing our debt and improving cash flow from operations, and believe we can make material advances in both of these areas in 2018.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.
Liquidity
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 Capital Resourcesdeepening 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
Our ability to grow, makeFor the 2021 Successor Period, our primary sources of capital expendituresresources and serviceliquidity have consisted of internally generated cash flows from operations, and our debt depends primarily upon the prices we receiveprimary uses of cash have been for the oil, natural gas and NGL we sell. Substantial expenditures are required to replace reserves, sustain production and funddevelopment of our business plans. Historically, oil and natural gas pricesproperties, 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 been very volatile,consisted of internally generated cash flows from operations, borrowings under certain credit agreements and may be subjectdispositions of non-core assets. Our ability to wide fluctuationsissue 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 future. The substantial decline2021 and 2020 Predecessor Periods depended mainly on cash generated from operations and available funds under certain credit agreements including the DIP Facility in oil, natural gasthe 2021 Predecessor Period and NGL pricesrevolving credit facility in the 2020 Predecessor Period.
We believe we have emerged from 2014 levels has negatively,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 will continue to have, affected the amount of cash we generate and have available for capital expenditures and debt service and has had a material impact on our financial position, results of operations, cash flows and on the quantities of reserves that we can economically produce. Other risks and uncertainties that could affect our liquidity include, but are not limited to, counterparty credit risk for our receivables, access to capital markets, regulatory risks, our ability to meet financial ratios and covenants in our financing agreements and the availability of lenders’ commitments ascontinuously improving ESG performance. As a result of regulatory pressuresthe Chapter 11 Cases, we reduced our total indebtedness by $9.4 billion by issuing equity in a reorganized entity to the lending market.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, 2017,2021, we had a$2.625 billion of liquidity available, including $905 million of cash balanceon hand and $1.720 billion of $5 million compared to $882 million as of December 31, 2016, and we had a net working capital deficit of $831 million as of December 31, 2017, compared to a net working capital deficit of $1.506 billion as of December 31, 2016.aggregate unused borrowing capacity available under the Exit Credit Facility. As of December 31, 2017,2021, we had total principal debt of $9.981 billion, compared to $9.989 billion as of December 31, 2016. As of December 31, 2017, we had $2.888 billion of borrowing capacity availableno outstanding borrowings under our senior secured revolving credit facility, with outstandingExit Credit Facility – Tranche A Loans, and $221 million in borrowings of $781 million and $116 million utilized for various letters of credit. Based on our cash balance, forecasted cash flows from operating activities and availability under our revolving credit facility, we expect to be able to fund our planned capital expenditures, meet our debt service requirements and fund our other commitments and obligations for the next 12 months.Exit Credit Facility – Tranche B Loans. See Note 36 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.
Even though we have taken measures to mitigate the liquidity concerns facing us for the next 12 months, as outlined above in Overview of 2017 Results and Business and Industry Outlook, there can be no assurance that these measures will be sufficient for periods beyond the next 12 months. If needed, we may seek to access the capital markets or otherwise refinance a portion of our outstanding indebtedness to improve our liquidity. We closely monitor the amounts and timing of our sources and uses of funds, particularly as they affect our ability to maintain compliance with the financial covenants of our revolving credit facility. Furthermore, our ability to generate operating cash flow in the current commodity price environment, sell assets, access capital markets or take any other action to improve our liquidity and manage our debt is subject to the risks discussed above and the other risks and uncertainties that exist in our industry, some of which we may not be able to anticipate at this time or control.
Capital Expenditures
We have significant control and flexibility over the timing and execution of our development plan, enabling us to reduce our capital spending as needed. Our forecasted 2018 capital expenditures, inclusive of capitalized interest, are $2.0 – $2.4 billion compared to our 2017 capital spending level of $2.5 billion. Management continues to review operational plans for 2018 and beyond, which could result in changes to projected capital expenditures and projected revenues from sales of oil, natural gas and NGL.
We may continue to use a combination of cash, borrowings and issuances of our common stock or other securities to retire our outstanding debt and/or preferred stock through privately negotiated transactions, open market repurchases, redemptions, tender offers or otherwise, but we are under no obligation to do so.

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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. ToWe enter into various derivative instruments to mitigate a portion of theour exposure to adverse market changes, we have entered into various derivative instruments.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 NGLs,NGL, allow us to better predict with greater certainty the total revenue we willexpect 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.
We utilizeContractual 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 derivative instruments to protect a portionmove certain of our cash flow against downside risk.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 February 22, 2018, we have downside price protection in 2018liquidity will be sufficient to fund our near and 2019 through the following oil, natural gaslong-term contractual obligations. See Notes 6, 7, 9, 15 and NGL derivative instruments:
Oil Derivatives(a)
Year Type of Derivative Instrument Notional Volume % of Forecasted Production (if applicable) Average NYMEX Price
    (mbbls)    
2018 Swaps 21,710
 68% $52.87
2018 Three-way collars 1,825
 6% $39.15/$47.00/$55.00
2018 Calls 1,840
 6% $52.87
2018 Basis protection swaps 10,769
 34% $3.32
2019 Swaps 3,273
 Not disclosed $56.04
         
Natural Gas Derivatives(a)
Year Type of Derivative Instrument Notional Volume % of Forecasted Production (if applicable) Average NYMEX Price
    (mmcf)    
2018 Swaps 531,613
 63% $3.11
2018 Two-way collars 47,450
 6% $3.00/$3.25
2018 Calls 65,700
 8% $6.27
2018 Basis protection swaps 64,589
 8% ($0.52)
         
NGL Derivatives(a)
Year Type of Derivative Instrument Notional Volume % of Forecasted Production (if applicable) Average NYMEX Price
    (mmgal)    
2018 Butane swaps 5
 1% $0.88
2018 Butane % of WTI swaps 5
 1% 70.5% of WTI
2018 Propane swaps 15
 2% $0.73
2018 Ethane swaps 8
 1% $0.28

(a)Includes amounts settled in January and February 2018.
See Note 1123 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussiondiscussion.
Post-Emergence Debt
On the Effective Date, pursuant to the terms of derivativesthe 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 hedging activities.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.
Contractual ObligationsAssumption and Off-Balance Sheet ArrangementsRepayment of Vine Debt
From timeIn 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 time, we enter into arrangements and transactions that can give rise to contractual obligations and off-balance sheet commitments. The table below summarizes our contractual cash obligations for both recorded obligations and certain off-balance sheet arrangements and commitmentsthe 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 $450 million in cash. We currently expect to fund the Chief Acquisition with cash on hand, borrowings under our Exit Credit Facility and the proceeds from the planned Powder River Basin divestiture.
Capital Expenditures
For the year ending December 31, 2017:
  Payments Due By Period
  Total 
Less Than
1 Year
 1-3 Years 3-5 Years 
More Than
5 Years
  ($ in millions)
Long-term debt:          
Principal(a)
 $9,981
 $53
 $1,825
 $3,915
 $4,188
Interest 3,774
 653
 1,258
 924
 939
Operating lease obligations(b)
 14
 6
 7
 1
 —
Operating commitments(c)
 9,190
 1,102
 2,030
 1,654
 4,404
Unrecognized tax benefits(d)
 101
 —
 4
 97
 —
Standby letters of credit 116
 116
 —
 —
 —
Other 22
 4
 8
 8
 2
Total contractual cash obligations(e)
 $23,198
 $1,934
 $5,132
 $6,599
 $9,533

(a)See Note 3 of the notes2022, 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 consolidated financial statements included in Item 8 of this report for a description of our long-term debt.
(b)See Note 4 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our operating lease obligations.
(c)See Note 4 of the notes to our consolidated financial statements included in Item 8 of this report for a description of gathering, processing and transportation agreements, drilling contracts and pressure pumping contracts.
(d)See Note 6 of the notes to our consolidated financial statements included in Item 8 of this report for an analysis of unrecognized tax benefits.
(e) This table does not include derivative liabilities or the estimated discounted liability for future dismantlement, abandonment and restoration costs of oil and natural gas properties. See Notes 11assets. We currently plan to fund our 2022 capital program through cash on hand, expected cash flow from our operations and 19, respectively,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 notes to our consolidated financial statements includedmarkets in Item 8 of this report for more information on our derivatives and asset retirement obligations. This table also does not include our costs to produce reserves attributable to non-expense-bearing royalty and other interests in our properties, including VPPs, which are discussed in Note 12 of the notes to our consolidated financial statements included in Item 8 of this report.
Credit Risk
Derivative instruments that enable us to manage our exposure to oil, natural gas and NGL prices expose us to credit risk from our counterparties. To mitigate this risk, we enter into oil, natural gas and NGL derivative contracts only with counterparties that we deem to have acceptable credit strength and are deemed by management to be competent and competitive market-makers, and we attempt to limit our exposure to non-performance by any single counterparty. As of December 31, 2017, our oil, natural gas and NGL derivative instruments were spread among 11 counterparties. Additionally, the counterparties under these arrangements are required to secure their obligations in excess of defined thresholds.operate.
Our accounts receivable are primarily from purchasers of oil, natural gas and NGL ($959 million as of December 31, 2017) and exploration and production companies that own interests in properties we operate ($209 million as of December 31, 2017). This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We generally require letters of credit or parent guarantees for receivables from parties deemed to have sub-standard credit, unless the credit risk can otherwise be mitigated. During 2017, 2016 and 2015, we recognized $9 million, $10 million and $4 million, respectively, of bad debt expense related to potentially uncollectible receivables.
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Some of our counterparties have requested or required us to post collateral as financial assurance of our performance under certain contractual arrangements, such as gathering, processing, transportation and hedging agreements. As of February 20, 2018, we have received requests and posted approximately $151 million of collateral related to certain of our marketing and other contracts. We may be requested or required by other counterparties to post additional collateral in an aggregate amount of approximately $486 million, which may be in the form of additional letters of credit, cash or other acceptable collateral. However, we have substantial long-term business relationships with each of these counterparties, and we may be able to mitigate any collateral requests through ongoing business arrangements and by offsetting amounts that the counterparty owes us. Any posting of collateral consisting of cash or letters of credit reduces availability under our revolving credit facility and negatively impacts our liquidity.
Sources of Funds
The following table presents the sources of our cash and cash equivalents for the years ended December 31, 2017, 2016Successor and 2015. See Note 12 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of divestitures of oil and natural gas assets.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 exercise2 — — — 
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 $3,818 
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  Years Ended December 31,
  2017 2016 2015
  ($ in millions)
Cash provided by (used in) operating activities $745
 $(204) $1,234
Proceeds from credit facility borrowings, net 781
 —
 —
Proceeds from issuance of a term loan, net —
 1,476
 —
Proceeds from issuances of senior notes, net 1,585
 2,210
 —
Proceeds from divestitures of proved and unproved properties, net 1,249
 1,406
 189
Proceeds from sales of other property and equipment, net 55
 131
 89
Other —
 —
 52
Total sources of cash and cash equivalents $4,415
 $5,019
 $1,564
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Cash Flow from Operating Activities
Cash provided by operating activities was $745 million$1.809 billion, $1.164 billion and $1.623 billion in 2017 compared to cashthe 2021 Successor Period, 2020 Predecessor Period and 2019 Predecessor Period, respectively. Cash used in operating activities of $204was $21 million in 2016 and cash provided by operating activities of $1.234 billion in 2015.for the 2021 Predecessor Period. The increase in 2017the 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 decreasesGP&T costs following our emergence from bankruptcy. The cash used in certain of our operating expenses, partially offset by lower volumes of oil, natural gas and NGL sold,the 2021 Predecessor Period was primarily in connection with the payment of professional fees related to the litigation involving the early redemption of our 6.775% Senior Notes due 2019 and payments for terminations of transportation contracts.Chapter 11 Cases. The decrease from 2015in the 2020 Predecessor Period is primarily the result of lower prices for the oil, and natural gas we sold, lower volumes of oil, natural gas and NGL sold, less gain from our commodity derivatives, partially offset by decreases in certain of our operating expenses.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.
Revolving Credit FacilityProceeds from Issuance of Common Stock and Senior Notes
We haveIn 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 revolving credit facility currently subject to a $3.8second lien notes for net proceeds of $1.563 billion borrowing base that matures in December 2019. As of December 31, 2017, we had $2.888 billion of borrowing capacity available under our revolving credit facility. Our next borrowing base redetermination is scheduled for the second quarter of 2018. As of December 31, 2017, we had outstanding borrowings of $781 million under the revolving credit facility and had used $116 million of the revolving credit facility for various letters of credit. Borrowings under the facility bear interest at a variable rate. See Note 3 6 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussiondiscussion.
Divestitures of Property and Equipment
In the terms of2021 Successor Period we divested certain non-core assets for approximately $13 million. In the revolving credit facility. As of December 31, 2017,2020 Predecessor Period, we were in compliance with all applicable financial covenants underdivested our Mid-Continent asset for $130 million and certain non-core assets for approximately $6 million. In the credit agreement. Our first lien secured leverage ratio was2019 Predecessor Period, we divested certain non-core assets for approximately 0.52 to 1.00, our interest coverage ratio was approximately 2.51 to 1.00 and our debt to capitalization ratio was approximately 0.38 to 1.00.
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We currently plan to use cash flow from operations to fund our capital expenditures for 2018. We expect to generate additional liquidity with proceeds from future sales of assets that do not fit our strategic priorities. Under our revolving credit facility, we borrowed $7.771 billion and repaid $6.990 billion in 2017, we borrowed and repaid $5.146 billion in 2016 and we had no borrowings or repayments in 2015.
Debt issuances
The following table reflects the proceeds received from issuances of debt in 2017, 2016 and 2015.$130 million. See Note 34 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion.
  Years Ended December 31,
  2017 2016 2015
  
Principal Amount
of Debt
Issued
 
Net
Proceeds
 
Principal Amount
of Debt
Issued
 
Net
Proceeds
 
Principal Amount
of Debt
Issued
 Net
Proceeds
  ($ in millions)
Convertible senior notes $—
 $—
 $1,250
 $1,235
 $—
 $—
Senior notes 1,600
 1,585
 1,000
 975
 —
 —
Term loans —
 —
 1,500
 1,476
 —
 —
Total $1,600
 $1,585
 $3,750
 $3,686
 $—
 $—
Divestitures of Proved and Unproved Properties
During 2017, we divested certain non-core assets for approximately $1.249 billion. Proceeds from these transactions were used to repay debt and fund our development program. See Note 12 of the notes to our consolidated financial statements included in Item 8Part 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 years ended December 31, 2017, 2016Successor and 2015: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 costs3 8 109 — 
Cash paid to purchase debt— — 94 1,073 
Cash paid for common stock dividends119 — — — 
Cash paid for preferred stock dividends— — 22 91 
Other1 — 13 36 
Total other uses of cash and cash equivalents367 1,666 238 1,553 
Total uses of cash and cash equivalents$1,036 $1,732 $1,380 $3,816 
  Years Ended December 31,
  2017 2016 2015
  ($ in millions)
Oil and Natural Gas Expenditures:      
Drilling and completion costs $2,186
 $1,295
 $3,095
Acquisitions of proved and unproved properties 101
 552
 123
Interest capitalized on unproved leasehold 184
 236
 410
Total oil and natural gas expenditures 2,471
 2,083
 3,628
Other Uses of Cash and Cash Equivalents:      
Cash paid to repurchase debt 2,592
 2,734
 508
Cash paid for title defects —
 69
 —
Cash paid to repurchase noncontrolling interest —
 —
 143
Additions to other property and equipment 21
 37
 143
Dividends paid 183
 —
 289
Distributions to noncontrolling interest owners 8
 10
 85
Other 17
 29
 51
Total other uses of cash and cash equivalents 2,821
 2,879
 1,219
Total uses of cash and cash equivalents $5,292
 $4,962
 $4,847


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Oil and Natural GasCapital Expenditures
Our drilling and completion costs increaseddecreased in 2017the combined 2021 Successor and Predecessor Periods compared to 2016the 2020 Predecessor Period primarily as a result of increaseddecreased 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 well as higher servicea result of decreased drilling and supply costs. During 2017,completion activity mainly in our liquids-rich plays. In the combined 2021 Successor and Predecessor Periods, our average operated rig count was 177 rigs and 121 spud wells, compared to an average operated rig count of ten8 rigs and 167 spud wells in 2016the 2020 Predecessor Period and we18 rigs and 333 spud wells in the 2019 Predecessor Period. We completed 401127 operated wells in 2017the combined 2021 Successor and Predecessor Periods compared to 382188 in 2016. Our acquisitions of provedthe 2020 Predecessor Period and unproved properties were higher370 in 2016 compared to 2017 and 2015, primarily resulting from purchases of oil and natural gas interests previously sold to third parties in connection with fivethe 2019 Predecessor Period.
Business Combination
In the 2021 Successor Period, we acquired Vine for approximately 18.7 million shares of our VPP transactions for approximately $387 million.
Repurchase of Debt
In 2017, we used $2.592 billion ofNew Common Stock and $253 million cash, to repurchase $2.389 billion principal amount of debt. In 2016, we used $2.734 billion of cash to repurchase $2.884 billion principal amount of debt. In 2015, we used $508less $59 million of cash to repurchase $513held by Vine as of the acquisition date. In the 2019 Predecessor Period, we acquired WildHorse for approximately 3.6 million principal amountreverse stock split adjusted shares of debt.
Dividends
We paid dividends of $183our Predecessor common stock and $381 million on our preferred stock during 2017, including $92cash, less $28 million of dividends in arrears that had been suspended throughout 2016. We did not pay dividends on our preferred stock in 2016 and paid $171 million of preferred stock dividends in 2015. We paid dividends of $118 million on our common stock in 2015. We eliminated common stock dividends in the 2015 third quarter and do not anticipate paying any common stock dividends in the foreseeable future.
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Results of Operations
Oil, Natural Gas and NGL Production and Average Sales Prices
  2017
  Oil Natural Gas NGL Total
  
mbbl
per day
 $/bbl 
mmcf
per day
 $/mcf 
mbbl
per day
 $/bbl 
mboe
per day
 % $/boe
Marcellus —
 —
 810
 2.44
 —
 —
 135
 25
 14.65
Haynesville —
 —
 785
 2.85
 —
 —
 131
 24
 17.12
Eagle Ford 58
 52.34
 142
 3.30
 18
 22.95
 100
 18
 39.24
Utica 10
 46.04
 427
 3.00
 26
 23.06
 107
 19
 21.80
Mid-Continent 16
 49.66
 163
 2.78
 10
 22.89
 53
 10
 27.55
Powder River Basin 6
 49.97
 37
 3.01
 3
 27.33
 15
 3
 32.58
Retained assets 90
 51.04
 2,364
 2.76
 57
 23.20
 541
 99
 22.97
Divested assets —
 46.25
 42
 2.63
 —
 13.36
 7
 1
 16.24
Total 90
 51.03
 2,406
 2.76
 57
 23.18
 548
 100% 22.88
                   
  2016
  Oil Natural Gas NGL Total
  
mbbl
per day
 $/bbl 
mmcf
per day
 $/mcf 
mbbl
per day
 $/bbl 
mboe
per day
 % $/boe
Marcellus —
 —
 759
 1.59
 —
 —
 126
 20
 9.56
Haynesville —
 —
 681
 2.31
 —
 —
 114
 18
 13.87
Eagle Ford 56
 42.19
 140
 2.61
 17
 14.85
 97
 15
 30.97
Utica 13
 34.17
 480
 2.34
 32
 14.44
 125
 20
 16.17
Mid-Continent 13
 41.60
 163
 2.21
 8
 16.87
 48
 8
 21.48
Powder River Basin 6
 39.58
 37
 2.36
 3
 17.27
 15
 2
 24.78
Retained assets 88
 40.78
 2,260
 2.09
 60
 15.01
 525
 83
 17.54
Divested assets 3
 36.62
 607
 1.92
 7
 12.41
 110
 17
 12.26
Total 91
 40.65
 2,867
 2.05
 67
 14.76
 635
 100% 16.63
                   
  2015
  Oil Natural Gas NGL Total
  mbbl
per day		 $/bbl mmcf
per day		 $/mcf mbbl
per day		 $/bbl mboe
per day		 % $/boe
Marcellus —
 —
 739
 1.89
 —
 —
 123
 18
 11.32
Haynesville —
 —
 524
 2.66
 —
 —
 88
 13
 15.97
Eagle Ford 65
 47.01
 148
 2.73
 16
 14.13
 106
 16
 34.70
Utica 13
 36.82
 423
 2.35
 33
 14.93
 116
 17
 16.92
Mid-Continent 16
 47.37
 199
 2.60
 10
 15.08
 59
 9
 24.14
Powder River Basin 9
 43.34
 49
 2.77
 3
 14.09
 20
 3
 28.15
Retained assets 103
 45.44
 2,082
 2.32
 62
 14.70
 512
 76
 20.35
Divested assets 11
 48.78
 849
 2.26
 15
 11.38
 167
 24
 15.77
Total 114
 45.77
 2,931
 2.31
 77
 14.06
 679
 100% 19.23
Natural gas and NGL production decreased primarilycash held by WildHorse as a result of the sale of certain of our Barnett, Mid-Continent and Devonian assets in 2016 and the sale of certain of our Haynesville assets in 2017.
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Oil, Natural Gas and NGL Sales
  Years Ended December 31,
  2017 change 2016 change 2015
  ($ in millions)
Oil $1,668
 23% $1,351
 (29)% $1,904
Natural gas 2,422
 12% 2,155
 (13)% 2,470
NGL 484
 34% 360
 (8)% 393
Oil, natural gas and NGL sales $4,574
 18% $3,866
 (19)% $4,767
2017 vs. 2016. The increase in the price received per boe in 2017 resulted in a $1.25 billion increase in revenues, and decreased sales volumes resulted in a $542 million decrease in revenues, for a total net increase in revenues of $708 million.
2016 vs. 2015. The decrease in the price received per boe in 2016 resulted in a $606 million decrease in revenues, and decreased sales volumes resulted in a $295 million decrease in revenues, for a total net decrease in revenues of $901 million.
Oil, Natural Gas and NGL Derivatives
  Years Ended December 31,
  2017 change 2016 change 2015
  ($ in millions)
Oil derivatives – realized gains (losses) $70
 (28)% $97
 (89)% $880
Oil derivatives – unrealized gains (losses) (134) 58 % (318) 41 % (536)
Total gains (losses) on oil derivatives (64)   (221)   344
           
Natural gas derivatives – realized gains (losses) (9) n/m
 151
 (65)% 437
Natural gas derivatives – unrealized gains (losses) 489
 n/m
 (500) n/m
 (157)
Total gains (losses) on natural gas derivatives 480
   (349)   280
           
NGL derivatives – realized gains (losses) (4) 50 % (8) — % —
NGL derivatives – unrealized gains (losses) (1) — % —
 — % —
Total gains (losses) on NGL derivatives (5)   (8)   —
Total gains (losses) on oil, natural gas and NGL derivatives $411
   $(578)   $624
acquisition date. See Note 114 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for a completefurther discussion of our derivative activity.these acquisitions.
A changePayments on DIP Facility Borrowings
On the Effective Date, the DIP Facility was terminated, and the holders of obligations under the DIP Facility received payment in oil, natural gasfull in cash; provided that to the extend such lender under the DIP Facility was also a lender under the Exit Credit Facility, such lender’s allowed DIP claims were first reduced dollar-for-dollar and NGL prices has a significant impact on our revenues and cash flows. Assuming our 2017 production levels and without consideringsatisfied by the effectamount of derivatives, an increase or decreaseits Exit RBL Loans provided as of $1.00 per barrel of oil sold would have resulted in an increase or decrease in 2017 revenues and cash flows from operations of approximately $33 million and $31 million, respectively, an increase or decrease of $0.10 per mcf of natural gas sold would have resulted in an increase or decrease in 2017 revenues and cash flows from operations of approximately $88 million and $87 million, respectively, and an increase or decrease of $1.00 per barrel of NGL sold would have resulted in an increase or decrease in 2017 revenues and cash flows from operations of approximately $21 million and $20 million, respectively.

the Effective Date.
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Debt Issuance and Other Financing Costs
Marketing, GatheringIn the 2020 Predecessor Period, we paid $109 million of one-time fees to lenders to establish our DIP Credit Facility and Compression RevenuesExit Credit Facility.
Cash Paid to Purchase Debt
In the 2020 Predecessor Period, we repurchased approximately $160 million aggregate principal amount of our senior notes for $94 million. In the 2019 Predecessor Period, we repurchased $698 million aggregate principal amount of our BVL Senior Notes for $693 million and Expenses. Marketing, gatheringretired our BVL revolving credit facility for $1.028 billion. We also repaid upon maturity $380 million principal amount of our Floating Rate Senior Notes due April 2019.
Cash Paid for Common Stock Dividends
As part of our dividend program, we paid dividends of $119 million on our New Common Stock in the 2021 Successor Period. See Note 12 for further discussion.
Cash Paid for Preferred Stock Dividends
We paid dividends of $22 million and compression revenues primarily consist$91 million on our Predecessor preferred stock during the 2020 and 2019 Predecessor Periods, respectively. On April 17, 2020, we announced that we were suspending payment of marketing services, including commodity price structuring, securing and negotiating gathering, hauling, processing and transportation services, contract administration and nomination services for Chesapeake and other interest owners in Chesapeake-operated wells. Expenses related todividends on each series of our marketing, gathering and compression operations consist of third-party expenses and exclude depreciation and amortization, general and administrative expenses, impairments of fixed assets and other, net gains or losses on sales of fixed assets and interest expense.
  Years Ended December 31,
  2017 change 2016 change 2015
  ($ in millions)
Marketing, gathering and compression revenues $4,511
 (2)% $4,584
 (38)% $7,373
Marketing, gathering and compression expenses 4,598
 (4)% 4,778
 (33)% 7,130
Marketing, gathering and compression gross margin $(87) 55 % $(194) 180 % $243
2017 vs. 2016. Gross margin increased primarily as a resultoutstanding convertible preferred stock. On the Effective Date of the reversalChapter 11 Cases, each holder of cumulative unrealized gains associated with the termination of a supply contract derivativean equity interest in 2016 as well as the sale of a significant portion of our gatheringChesapeake had such interest canceled, released, and compression assets in 2016.
2016 vs. 2015. Gross margin decreased primarily as a result of lower oil, natural gas and NGL prices paid and received in our marketing operations. Additionally, the 2015 amount included unrealized gains of $296 million on the fair value of our supply contract derivative.
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Oil, Natural Gas and NGL Production Expenses
  Years Ended December 31,
  2017 change 2016 change 2015
Oil, natural gas and NGL production expenses ($ in millions)
Marcellus $20
 11 % $18
 (18)% $22
Haynesville 53
 36 % 39
 (24)% 51
Eagle Ford 187
 28 % 146
 (19)% 181
Utica 37
 (16)% 44
 (24)% 58
Mid-Continent 180
 15 % 157
 (29)% 221
Powder River Basin 27
 35 % 20
 (35)% 31
Retained Assets(a)
 504
 19 % 424
 (25)% 564
Divested Assets 14
 (94)% 243
 (42)% 422
Total 518
 (22)% 667
 (32)% 986
           
Ad valorem tax(b)
 44
 2 % 43
 (28)% 60
           
Total oil, natural gas and NGL production expenses $562
 (21)% $710
 (32)% $1,046
           
Oil, natural gas and NGL production expenses ($ per boe)
Marcellus $0.41
 5 % $0.39
 (20)% $0.49
Haynesville $1.10
 17 % $0.94
 (41)% $1.59
Eagle Ford $5.12
 24 % $4.13
 (12)% $4.71
Utica $0.94
 (2)% $0.96
 (29)% $1.36
Mid-Continent $9.39
 6 % $8.87
 (14)% $10.31
Powder River Basin $4.90
 35 % $3.64
 (15)% $4.27
Retained Assets(a)
 $2.55
 15 % $2.21
 (27)% $3.02
Divested Assets $5.44
 (10)% $6.02
 (13)% $6.90
Total $2.59
 (10)% $2.87
 (28)% $3.98
           
Ad valorem tax(b)
 $0.23
 5 % $0.22
 (31)% $0.32
           
Total oil, natural gas and NGL production expenses per boe $2.81
 (8)% $3.05
 (28)% $4.22

(a) Includes assets retained as of December 31, 2017.
(b) Excludes ad valorem tax expense on divested assets.
2017 vs. 2016. The absolute and per unit decrease was the result of the sale of certain oil and natural gas properties in 2016, partially offset by increased workover costs in the Eagle Ford and increased water disposal costs in the Eagle Ford and Mid-Continent. Production expenses in 2017 and 2016 included approximately $19 million and $44 million associated with VPP production volumes. We anticipate a continued decrease in production expenses associated with VPP production volumes as the contractually scheduled volumes under our remaining VPP agreement decrease and operating efficiencies generally improve.
2016 vs. 2015. The absolute and per unit decrease was the result of a reduction in repairs and maintenance expense as well as operating efficiencies across most of our operating areas.
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Oil, Natural Gas, and NGL Gathering, Processing and Transportation Expenses
  Years Ended December 31,
  2017 2016 2015
  ($ in millions, except per unit)
Oil, natural gas and NGL gathering, processing and transportation expenses $1,471
 $1,855
 $2,119
Oil ($ per bbl) $3.94
 $3.61
 $3.38
Natural gas ($ per mcf) $1.34
 $1.47
 $1.66
NGL ($ per bbl) $7.88
 $7.83
 $7.37
Total ($ per boe) $7.36
 $7.98
 $8.55
2017 vs. 2016. The absolute decrease was primarily due to lower volumes. The per unit decrease was due to contract improvements and asset sales.
2016 vs. 2015. The absolute decrease was primarily due to lower volumes. The per unit decrease was primarily due to contract improvements and asset sales.
Production Taxes
  Years Ended December 31,
  2017 change 2016 change 2015
  ($ in millions, except per unit)
Production taxes $89
 20% $74
 (25)% $99
Production taxes per boe $0.44
 38% $0.32
 (20)% $0.40
2017 vs. 2016. The absolute and per unit increase in production taxes was primarily due to higher prices received for our oil, natural gas and NGL production, offset by lower production volumes.
2016 vs. 2015. The absolute and per unit decrease in production taxes was primarily due to lower production volumes and lower prices received for our oil, natural gas and NGL production.
General and Administrative Expenses
  Years Ended December 31,
  2017 change 2016 change 2015
  ($ in millions, except per unit)
Gross overhead $791
 (12)% $900
 (18)% $1,102
Allocated to production expenses (177) (15)% (209) (16)% (248)
Allocated to marketing, gathering and compression expenses (29) (47)% (55) (32)% (81)
Capitalized (137) (8)% (149) (23)% (193)
Reimbursed from third parties (186) (25)% (247) (28)% (345)
General and administrative expenses, net $262
 9 % $240
 2 % $235
           
General and administrative expenses, net per boe $1.31
 27 % $1.03
 8 % $0.95
2017 vs. 2016. Gross overhead decreased primarily due to lower compensation costs and lower legal fees. The absolute and per unit net expense increase was primarily due to less overhead allocated to production expenses, marketing, gathering, and compression expenses and capitalized general and administrative costs, as well as less overhead billed to third party working interest owners, due to certain divestitures in 2016 and 2017.
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2016 vs. 2015. Gross overhead decreased primarily due to lower compensation costs. The absolute and per unit increase was primarily due to less overhead allocated to production expenses, marketing, gathering, and compression expenses and capitalized general and administrative costs, as well as less overhead billed to third party working interest owners, due to certain divestitures in 2016.
Restructuring and Other Termination Costs. We recorded expenses of $6 million and $36 million in 2016 and 2015, respectively.extinguished without any distribution. See Note 152 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for furtheradditional information about the Chapter 11 Cases.
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Results of Operations
Year ended December 31, 2021 compared to the year ended December 31, 2020
Below is a discussion of changes in our restructuringresults of operations for the combined 2021 Successor and termination costs.Predecessor Periods compared to the 2020 Predecessor Period. A discussion of changes in our results of operations for the 2020 Predecessor Period compared to the 2019 Predecessor Period has been omitted from this Form 10-K, but may be found in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of our Annual Report on Form 10-K for the year ended December 31, 2020 as filed with the SEC on March 1, 2021.
Provision for Legal Contingencies, NetOil, Natural Gas and NGL Production and Average Sales Prices
Successor
Period from February 10, 2021 through December 31, 2021
 OilNatural GasNGLTotal
 
mbbl
per
day
$/bblmmcf
per day		$/mcf
mbbl
per
day
$/bbl
mboe
per day
$/boe
Marcellus— — 1,296 3.25 — — 216 19.52 
Haynesville— — 750 4.10 — — 125 24.57 
Eagle Ford60 69.25 137 4.02 19 29.76 101 51.91 
Powder River Basin9 67.90 53 4.33 3 40.00 21 46.09 
Total69 69.07 2,236 3.61 22 31.37 463 29.19 
Predecessor
Period from January 1, 2021 through February 9, 2021
OilNatural GasNGLTotal
mbbl
per
day
$/bblmmcf
per day		$/mcf
mbbl
per
day
$/bbl
mboe
per day
$/boe
Marcellus— — 1,233 2.42 — — 206 14.49 
Haynesville— — 543 2.44 — — 90 14.62 
Eagle Ford74 53.37 165 2.57 18 23.94 120 40.27 
Powder River Basin10 51.96 61 2.92 4 34.31 24 34.25 
Total84 53.21 2,002 2.45 22 25.92 440 22.63 
Predecessor
Year Ended December 31, 2020
 OilNatural GasNGLTotal
 
mbbl
per
day
$/bblmmcf
per day		$/mcf
mbbl
per
day
$/bbl
mboe
per day
$/boe
Marcellus— — 1,052 1.64 — — 175 9.82 
Haynesville— — 543 1.83 — — 90 10.99 
Eagle Ford86 38.38 185 1.90 24 10.93 141 27.72 
Powder River Basin13 36.64 58 1.92 4 14.94 26 24.22 
Mid-Continent4 38.17 34 1.98 3 12.36 13 20.18 
Total103 38.16 1,872 1.73 31 11.55 445 16.84 
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  Years Ended December 31,
  2017 change 2016 change 2015
  ($ in millions)
Provision for legal contingencies, net $(38) (131)% $123
 (65)% $353
Oil, Natural Gas and NGL Sales
2017 vs. 2016.
Successor
Period from February 10, 2021 through December 31, 2021
OilNatural GasNGLTotal
Marcellus$— $1,370 $— $1,370 
Haynesville— 998 — 998 
Eagle Ford1,354 179 179 1,712 
Powder River Basin202 75 44 321 
Total oil, natural gas and NGL sales$1,556 $2,622 $223 $4,401 
Predecessor
Period from January 1, 2021 through February 9, 2021
OilNatural GasNGLTotal
Marcellus$— $119 $— $119 
Haynesville— 53 — 53 
Eagle Ford159 17 17 193 
Powder River Basin20 7 6 33 
Total oil, natural gas and NGL sales$179 $196 $23 $398 
Non-GAAP Combined
Year Ended December 31, 2021
OilNatural GasNGLTotal
Marcellus$— $1,489 $— $1,489 
Haynesville— 1,051 — 1,051 
Eagle Ford1,513 196 196 1,905 
Powder River Basin222 82 50 354 
Total oil, natural gas and NGL sales$1,735 $2,818 $246 $4,799 
Predecessor
Year Ended December 31, 2020
 OilNatural GasNGLTotal
Marcellus$— $631 $— $631 
Haynesville— 362 — 362 
Eagle Ford1,202 129 97 1,428 
Powder River Basin170 41 20 231 
Mid-Continent55 25 13 93 
Total oil, natural gas and NGL sales$1,427 $1,188 $130 $2,745 

Oil, natural gas and NGL sales in the combined 2021 Successor and Predecessor Periods increased $2.054 billion compared to the 2020 Predecessor Period. The 2017 amount consists of the recovery ofincrease was primarily attributable to a legal settlement,$1.901 billion increase in revenues from higher average prices received. Additionally, increased volumes in Marcellus and Haynesville, partially offset by accruals for loss contingencies primarily related to royalty claims.decreased volumes in Eagle Ford, Powder River Basin and Mid-Continent, following the divestiture of our Mid-Continent assets in 2020, resulted in a $153 million increase in revenues. See Note 410 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for furthera complete discussion of royalty claims.oil, natural gas and NGL sales.
2016 vs. 2015.

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Production Expenses
SuccessorPredecessorNon-GAAP CombinedPredecessor
Period from February 10, 2021 through
December 31, 2021		Period from
January 1, 2021 through
February 9, 2021		Year Ended
December 31, 2021		Year Ended
December 31, 2020
$/Boe$/Boe$/Boe$/Boe
Marcellus$34 0.49 $4 0.50 $38 0.49 $32 0.50 
Haynesville59 1.44 4 1.12 63 1.42 41 1.28 
Eagle Ford173 5.25 21 4.24 194 5.13 201 3.89 
Powder River Basin31 4.45 3 3.37 34 4.32 42 4.41 
Mid-Continent— — — — — — 57 12.56 
Total production expenses$297 1.97 $32 1.80 $329 1.95 $373 2.29 
Production expenses in the combined 2021 Successor and Predecessor Periods decreased $44 million as compared to the 2020 Predecessor Period. The decrease was primarily the result of the resolution of litigation we were defending against the state of Michigan and $339due to a $57 million related to litigation involving the early redemption of our 6.775% Senior Notes due 2019.
Oil, Natural Gas and NGL Depreciation, Depletion and Amortization
  Years Ended December 31,
  2017 change 2016 change 2015
  ($ in millions, except per unit)
Oil, natural gas and NGL depreciation, depletion and amortization $913
 (9)% $1,003
 (52)% $2,099
Oil, natural gas and NGL depreciation, depletion and amortization per boe $4.56
 6 % $4.31
 (49)% $8.47
2017 vs. 2016. The absolute decrease was primarily the result ofreduction from the sale of certainMid-Continent properties in the 2020 Predecessor Period, in combination with the effects of our Barnettworkforce reductions in late 2020 and Mid-Continent assetsearly 2021. The decrease was partially offset by a $12 million increase related to the Vine Acquisition in 2016the Haynesville operating area.
Gathering, Processing and Transportation Expenses
SuccessorPredecessorNon-GAAP CombinedPredecessor
Period from February 10, 2021 through
December 31, 2021		Period from
January 1, 2021 through
February 9, 2021		Year Ended December 31, 2021Year Ended December 31, 2020
$/Boe$/Boe$/Boe$/Boe
Marcellus$287 4.09 $34 4.17 $321 4.10 $292 4.55 
Haynesville118 2.91 11 2.93 129 2.91 188 5.69 
Eagle Ford290 8.79 45 9.32 335 8.85 475 9.23 
Powder River Basin85 12.20 12 12.53 97 12.24 100 10.52 
Mid-Continent— — — — — — 27 5.76 
Total gathering, processing and transportation expenses$780 5.17 $102 5.78 $882 5.24 $1,082 6.64 

Gathering, processing and transportation expenses in the combined 2021 Successor and Predecessor Periods decreased $200 million as compared to the 2020 Predecessor Period. Haynesville decreased $84 million as a result of contract negotiations in the Chapter 11 Cases, partially offset by a $25 million increase associated with Vine acquired wells. Eagle Ford decreased $140 million primarily as a result of reduced production as well as contract negotiations in the Chapter 11 Cases. Additionally, the sale of certainMid-Continent properties in 2020 resulted in a $27 million reduction. These decreases were partially offset by a $29 million increase in Marcellus primarily due to increased production.
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Severance and Ad Valorem Taxes
SuccessorPredecessorNon-GAAP CombinedPredecessor
Period from February 10, 2021 through
December 31, 2021		Period from
January 1, 2021 through
February 9, 2021		Year Ended December 31, 2021Year Ended December 31, 2020
$/Boe$/Boe$/Boe$/Boe
Marcellus$9 0.12 $1 0.07 $10 0.12 $6 0.09 
Haynesville22 0.55 2 0.54 24 0.55 23 0.69 
Eagle Ford96 2.91 13 2.69 109 2.88 92 1.79 
Powder River Basin31 4.48 2 2.88 33 4.29 23 2.41 
Mid-Continent— — — — — — 5 1.16 
Total severance and ad valorem taxes$158 1.05 $18 1.03 $176 1.05 $149 0.91 
Severance and ad valorem taxes in the combined 2021 Successor and Predecessor Periods increased $27 million as compared to the 2020 Predecessor Period. The severance tax increase of $23 million was primarily driven by increased revenue as a result of improved pricing.
Gross Margin by Operating Area
The table below presents the gross margin for each of our Haynesville assets in 2017.
2016 vs. 2015. The absolute and per unit decrease was primarily the result of a lower amortization base, whichoperating areas. Gross margin by operating area is due to the 2016 and 2015 impairments of ourdefined as oil, and natural gas properties.and NGL sales less production expenses, gathering, processing and transportation expenses, and severance and ad valorem taxes.
Depreciation and Amortization of Other Assets
SuccessorPredecessorNon-GAAP CombinedPredecessor
Period from February 10, 2021 through
December 31, 2021		Period from
January 1, 2021 through
February 9, 2021		Year Ended December 31, 2021Year Ended December 31, 2020
$/Boe$/Boe$/Boe$/Boe
Marcellus$1,040 14.82 $80 9.75 $1,120 14.28 $301 4.68 
Haynesville799 19.67 36 10.03 835 18.88 110 3.33 
Eagle Ford1,153 34.96 114 24.02 1,267 33.56 660 12.81 
Powder River Basin174 24.96 16 15.47 190 23.81 66 6.88 
Mid-Continent— — — — — — 4 0.70 
Gross margin by operating area$3,166 21.00 $246 14.02 $3,412 20.27 $1,141 7.00 
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  Years Ended December 31,
  2017 change 2016 change 2015
  ($ in millions, except per unit)
Depreciation and amortization of other assets $82
 (21)% $104
 (20)% $130
Depreciation and amortization of other assets per boe $0.41
 (9)% $0.45
 (15)% $0.53
Oil and Natural Gas Derivatives
SuccessorPredecessor
Period from February 10, 2021 through December 31, 2021Period from January 1, 2021 through February 9, 2021Year Ended
December 31, 2020
Oil derivatives – realized gains (losses)$(453)$(19)$694 
Oil derivatives – unrealized losses(29)(190)(140)
Total gains (losses) on oil derivatives(482)(209)554 
Natural gas derivatives – realized gains (losses)(715)6 161 
Natural gas derivatives – unrealized gains (losses)70 (179)(119)
Total gains (losses) on natural gas derivatives(645)(173)42 
Total gains (losses) on oil and natural gas derivatives$(1,127)$(382)$596 
The absolute and per unit decrease for each year was primarily the result of the sale of other assets. See Note 1315 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for furthera complete discussion of other assets.our derivative activity.
ImpairmentMarketing Revenues and Expenses
SuccessorPredecessor
Period from February 10, 2021 through December 31, 2021Period from January 1, 2021 through February 9, 2021Year Ended
December 31, 2020
Marketing revenues$2,263 $239 $1,869 
Marketing expenses2,257 237 1,889 
Marketing margin$6 $2 $(20)
Marketing revenues and expenses increased in the 2021 Successor Period as a result of Oil and Natural Gas Properties
  Years Ended December 31,
  2017 change 2016 change 2015
  ($ in millions)
Impairment of oil and natural gas properties $—
 (100)% $2,564
 (86)% $18,238
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In 2017, we did not have an impairment for ourincreased oil, and natural gas properties. In 2016 and 2015, capitalized costsNGL prices received in our marketing operations.
Exploration Expense
SuccessorPredecessor
Period from February 10, 2021 through December 31, 2021Period from January 1, 2021 through February 9, 2021Year Ended December 31, 2020
Impairments of unproved properties$1 $2 $411 
Dry hole expense1 — 7 
Geological and geophysical expense and other5 — 9 
Total exploration expense$7 $2 $427 
The 2020 Predecessor Period exploration expense is the result of oilnon-cash impairment charges in unproved properties, primarily in our Eagle Ford, Haynesville, Powder River Basin and natural gas properties exceeded the ceiling, resulting in an impairment in the carrying value of our oil and natural gas properties of $2.564 billion and $18.238 billion, respectively.Mid-Continent operating areas. See Note 1420 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion of our impairments.discussion.
Impairments of Fixed Assets and Other
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  Years Ended December 31,
  2017 change 2016 change 2015
  ($ in millions)
Impairment of fixed assets and other $421
 (50)% $838
 332% $194
General and Administrative Expenses
SuccessorPredecessor
Period from February 10, 2021 through December 31, 2021Period from January 1, 2021 through February 9, 2021Year Ended
December 31, 2020
Gross compensation and benefits$231 $32 $383 
Non-labor86 12 195 
Allocations and reimbursements(220)(23)(311)
Total general and administrative expenses, net$97 $21 $267 
General and administrative expenses, net per Boe$0.64 $1.19 $1.63 
The amounts consist of costs incurredCompensation and benefits before reimbursements and allocations during the combined 2021 Successor and Predecessor Periods decreased $120 million compared to terminate various gatheringthe 2020 Predecessor Period due to reductions in workforce in the 2020 and transportation agreements, including those associated with oil2021 Predecessor Periods. Non-labor before reimbursements and gas asset divestitures,allocations during the combined 2021 Successor and Predecessor Periods decreased $97 million compared to the 2020 Predecessor Period due to cost reduction initiatives for professional services as well as impairments$43 million in fees for legal, financial and restructuring advisors incurred in preparation for the Chapter 11 Cases in the 2020 Predecessor Period. The decrease in allocations and reimbursements during the combined 2021 Successor and Predecessor Periods compared to the 2020 Predecessor Period was the result of buildingreduced drilling, staffing reductions and the sale of Mid-Continent properties in 2020.
Separation and Other Termination Costs
SuccessorPredecessor
Period from February 10, 2021 through December 31, 2021Period from January 1, 2021 through February 9, 2021Year Ended
December 31, 2020
Separation and other termination costs$11 $22 $44 
Separation and other fixed assets.termination costs relate to one-time termination benefits for certain employees.
Depreciation, Depletion and Amortization
SuccessorPredecessor
Period from February 10, 2021 through December 31, 2021Period from January 1, 2021 through February 9, 2021Year Ended
December 31, 2020
Depreciation, depletion and amortization$919 $72 $1,097 
Depreciation, depletion and amortization per Boe$6.10 $4.11 $6.72 
The absolute and per unit decrease in depreciation, depletion and amortization for the 2021 Successor Period compared to the 2020 Predecessor Period was primarily the result of the revaluation of the depletable asset base occurring in connection with our emergence from bankruptcy. Fresh start accounting requires that new fair values be established for our assets as of the Effective Date. See Note 143 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussiondiscussion.
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Impairments
SuccessorPredecessor
Period from February 10, 2021 through December 31, 2021Period from January 1, 2021 through February 9, 2021Year Ended
December 31, 2020
Impairments of proved oil and natural gas properties$— $— $8,446 
Impairments of other fixed assets and other1 — 89 
Total impairments$1 $— $8,535 
In the 2020 Predecessor Period, we recorded impairments of our impairments and other expense.
Interest Expense
  Years Ended December 31,
  2017 2016 2015
  ($ in millions)
Interest expense on senior notes $551
 $588
 $682
Interest expense on term loan 127
 46
 —
Amortization of loan discount, issuance costs and other 40
 33
 62
Amortization of premium (138) (165) (3)
Interest expense on revolving credit facility 39
 35
 12
Realized gains on interest rate derivatives(a)
 (3) (11) (6)
Unrealized (gains) losses on interest rate derivatives(b)
 4
 21
 (6)
Capitalized interest (194) (251) (424)
Total interest expense $426
 $296
 $317
       
Average senior notes borrowings $7,714
 $8,749
 $11,705
Average credit facilities borrowings $443
 $195
 $—
Average term loan borrowings $1,446
 $537
 $—

(a)Includes settlements related to the interest accrual for the period and the effect of (gains) losses on early-terminated trades. Settlements of early-terminated trades are reflected in realized (gains) losses over the original life of the hedged item.
(b)Includes changes in the fair value of interest rate derivatives offset by amounts reclassified to realized (gains) losses during the period.
The 2017 increase in interest expense is primarily due to an increase in term loan interest expense and a decrease in capitalized interest as a result of lower average balances of unprovedproved oil and natural gas properties the primary asset onrelated to Eagle Ford, Powder River Basin, Mid-Continent and other non-core assets, all of which interest is capitalized. The overall increase in interest expense is offset in part by a decrease in interest expense on senior noteswere due to the decreaselower forecasted commodity prices. Additionally, in the average outstanding principal amount2020 Predecessor Period, we recorded a $76 million impairment of senior notes. The 2016 decreases in capitalized interest resulted from lower average balancesour sand mine assets that support our Eagle Ford operating area for the difference between fair value and the carrying value of unproved oil and natural gas properties, the primary asset on which interest is capitalized. The 2016 decrease in interest expense on senior notes is due to the decrease in the average outstanding principal amountassets as well as a $13 million impairment of senior notes. The 2016 increase in the amortization of premium associated with troubled debt restructuring iscompressor inventory due to a full yearlack of amortization on our second lien notes.a current market for compressors. See Note 319 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for a discussion of our debt refinancing. Interest expense, excluding unrealized gains or losses on interest rate derivatives and net of amounts capitalized, was $2.11 per boe in 2017 compared to $1.18 per boe in 2016 and $1.30 per boe in 2015.further discussion.
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Other Operating Expense (Income), Net
SuccessorPredecessor
Period from February 10, 2021 through December 31, 2021Period from January 1, 2021 through February 9, 2021Year Ended
December 31, 2020
Other operating expense (income), net$84 $(12)$80 

Impairment of Investments. In 2016 and 2015,the 2021 Successor Period we recognized impairmentsapproximately $59 million of investmentscosts related to our acquisition of $119 million and $53 million, respectively. The 2016 amount consisted of an other-than-temporary impairment of our Sundrop investment. The 2015 amount consisted of an other-than-temporary impairment of our FTSI International, Inc. (FTSI) investment due to the extended decrease in the oil and natural gas pricing environment.
Gains (Losses) on Purchases or Exchanges of Debt. In 2017, we retired $2.389 billion principal amount of our outstanding senior notes, senior secured second lien notes and contingent convertible notes through purchases in the open market, tender offers, redemptions or repayment upon maturity for $2.592 billion,Vine, which included the maturity of our 6.25% Euro-denominated Senior Notes due 2017consulting fees, financial advisory fees and the corresponding cross currency swap. We recorded an aggregate gain of approximately $233 million associated with the repurchases and tender offers.
In 2016, we used the proceeds from our term loan facility, convertible notes issuance and senior notes issuance, together with cash on hand, to purchase and retire $2.884 billion principal amount of our outstanding senior notes and contingent convertible senior notes through purchases in the open market, tender offers or repayment upon maturity for $2.734 billion.legal fees. Additionally, we privately negotiated an exchangerecognized approximately $36 million of approximately $577 million principal amount of our outstanding senior notes and contingent convertible senior notes for 109,351,707 common shares. We recorded an aggregate gain of approximately $236 million associated with the repurchases and exchanges.
In December 2015, we privately exchanged newly issued 8.00% Senior Secured Second Lien Notes due 2022 for certain outstanding senior unsecured notes and contingent convertible notes. For certain of the notes exchanged, we are accounting for these exchanges as a trouble debt restructuring (TDR). For exchanges classified as TDR, if the future undiscounted cash flows of the newly issued debt are less than the net carrying value of the original debt, a gain is recorded for the difference and the carrying value of the newly issued debt is adjusted to the future undiscounted cash flow amount, with no interestseverance expense recorded going forward. For the remaining TDR exchanges, where the future undiscounted cash flows are greater than the net carrying value of the original debt, no gain is recognized and a new effective interest rate is established. Accordingly, we recognized a gain of $304 million in our consolidated statement of operations. Direct costs incurred of $29 million related to the notes exchange were also recognized. Additionally, we purchased in the open market approximately $119 million aggregate principal amount of our 3.25% Senior Notes due 2016 for cash. We recorded a gain of approximately $5 million associated with this repurchase.
Income Tax Expense (Benefit). We recorded income tax expense of $2 million in 2017, and income tax benefits of $190 million and $4.463 billion in 2016 and 2015, respectively. Our effective income tax rate was 0.2% in 2017 compared to 4.1% in 2016 and 23.4% in 2015. The decrease in the effective income tax rate from 2016 to 2017 is primarily due to the intraperiod tax allocation provisions under GAAP applicable to 2016 which are not applicable in 2017. Further, our effective tax rate can fluctuate as a result of the impactVine Acquisition, which included $15 million of statecash severance and $21 million of non-cash severance, primarily related to the issuance of New Common Stock for the acceleration of certain Vine restricted stock unit awards. A majority of Vine executives and employees were terminated on the date the Vine Acquisition was completed. These executives and employees were entitled to severance benefits in accordance with existing employment agreements. In the 2020 Predecessor Period, we terminated certain gathering, processing and transportation contracts and recognized a non-recurring $80 million expense related to the contract terminations, $9 million expense related to the impairment of sand mine inventory and $42 million of other operating expense primarily related to royalty settlements and other legal matters, partially offset by $51 million of income taxesfrom the amortization of VPP deferred revenue. In the 2020 Predecessor Period, we sold the assets related to our remaining volumetric production payment and permanent differences.extinguished the liability related to the production volume delivery obligation.
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Interest Expense
SuccessorPredecessor
Period from February 10, 2021 through December 31, 2021Period from January 1, 2021 through February 9, 2021Year Ended
December 31, 2020
Interest expense on debt$79 $11 $402 
Amortization of premium, discount, issuance costs and other5 — (56)
Capitalized interest(11)— (15)
Total interest expense$73 $11 $331 
The decrease in total interest expense in the 2021 Successor Period compared to the 2020 Predecessor Period resulted from the decrease in outstanding debt obligations between periods. Upon emergence from the Chapter 11 Cases, all outstanding obligations under our Predecessor senior notes and term loan were canceled in exchange for shares of New Common Stock and Warrants. See Note 6 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion.
Other Income (Expense)
SuccessorPredecessor
Period from February 10, 2021 through December 31, 2021Period from January 1, 2021 through February 9, 2021Year Ended
December 31, 2020
Other income (expense)$31 $2 $(4)
In the 2021 Successor Period, we recorded a gain of $22 million for a refund from a midstream provider.
Reorganization Items, Net
SuccessorPredecessor
Period from February 10, 2021 through December 31, 2021Period from January 1, 2021 through February 9, 2021Year Ended
December 31, 2020
Gains on the settlement of liabilities subject to compromise$— $6,443 $12 
Accrual for allowed claims— (1,002)(879)
Write off of unamortized debt premiums (discounts) on Predecessor debt— — 518 
Write off of unamortized debt issuance costs on Predecessor debt— — (61)
Gain on fresh start adjustments— 201 — 
Gain from release of commitment liabilities— 55 — 
Debt and equity financing fees— — (145)
Loss on divested assets— — (128)
Professional service provider fees and other— (60)(113)
Success fees for professional service providers— (38)— 
Surrender of other receivable— (18)— 
FLLO alternative transaction fee— (12)— 
Total reorganization items, net$— $5,569 $(796)
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In the 2021 and 2020 Predecessor Periods, we recorded a net gain of $5.569 billion and a net loss of $796 million, respectively, in reorganization items, net, related to the Chapter 11 Cases. 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 a discussion of the Chapter 11 Cases and for discussion of adoption of fresh start accounting.
Income Tax Expense (Benefit). We recorded an income tax benefit of $49 million in the 2021 Successor Period. In the 2021 and 2020 Predecessor Periods, we recorded an income tax benefit of $57 million and $19 million, respectively. The income tax benefit recorded in the 2021 Successor Period is related to a $49 million partial release of the valuation allowance maintained against our net deferred tax asset position. The partial release was a consequence of recording a net deferred tax liability of $49 million resulting from the business combination accounting for Vine. The $57 million income tax benefit for the 2021 Predecessor Period consists of the removal of the income tax effects in other comprehensive income related to hedging settlements due to the fair value adjustments made upon emergence from bankruptcy. The income tax benefit for the 2020 Predecessor Period consists of a reversal of the income tax expense recorded in 2019 of $10 million relating to Texas no longer being in a net deferred tax asset position for the period ended December 31, 2019. Texas reverted back to being in a net deferred tax asset position which was offset by a valuation allowance for the period ended December 31, 2020, which resulted in the reversal. The $19 million also includes a current state income tax benefit of $6 million and a $3 million benefit for amounts which were previously sequestered or anticipated to be sequestered by the Internal Revenue Service (IRS) against certain refunds of alternative minimum tax (AMT) credits. The IRS announced on January 16, 2020, that refunds of AMT credits should not have been subject to sequestration. All previously sequestered funds have been received. See Note 11 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for a discussion of income tax expense (benefit).
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Critical Accounting Policies and Estimates
The preparation of financial statements in accordance with accounting principles generally accepted in the United States require us to make estimates and assumptions. The accounting estimates and assumptions we considerthat involve a significant level of estimation uncertainty and have or are reasonably likely to be most significant tohave a material impact on our financial statementscondition or results of operations are discussed below. Our management has discussed each critical accounting estimatesestimate with the Audit Committee of our Board of Directors.
ImpairmentReorganization and Fresh Start Accounting. Effective June 28, 2020, as a result of Oilthe filing of the Chapter 11 Cases we began accounting and Natural Gas Properties. Thereporting according to FASB ASC Topic 852 – Reorganizations (“ASC 852”), which specifies the accounting and financial reporting requirements for our business is subject to special accounting rules that are unique to the oilentities reorganizing through Chapter 11 bankruptcy proceedings. These requirements include distinguishing and natural gas industry. There are two allowable methods of accounting for oil and natural gas business activities: the successful efforts method and the full cost method. We follow the full cost method of accounting under which all costspresenting transactions associated with property acquisition, explorationthe reorganization and developmentimplementation of the plan of reorganization separately from activities are capitalized. We also capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not capitalize any costs related to production, general corporate overhead or similar activities.
Underongoing operations of the full cost method, capitalized costs are amortized on a composite unit-of-production methodbusiness. Additionally, upon emergence from the Chapter 11 Cases, ASC 852 required us to allocate our reorganization value to our individual assets based on proved oiltheir estimated fair values, resulting in a new entity for financial reporting purposes. After the Effective Date, the accounting and natural gas reserves. If we maintain the same levelreporting requirements of production year over year, the depreciation, depletionASC 852 are no longer applicable and amortization expense may be significantly different if our estimate of remaining reserves or future development costs changes significantly.
We review the carrying value of our oil and natural gas properties under the full cost method of accounting prescribed by the SEC on a quarterly basis. This quarterly review is referred to as a ceiling test. Under the ceiling test,
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capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for oil and natural gas cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects.
Two primary factors impacting this test are reserve levels and oil and natural gas prices, and their associatedhave no impact on the present value of estimated future net revenues. Revisions to estimates of oil and natural gas reserves and/or an increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value, less deferred income taxes, is generally written off as an expense. See Oil and Natural Gas Properties in Note 1 of the notes to our consolidated financial statements included in Item 8 of this report for further information on the full cost method of accounting.Successor periods.
Oil and Natural Gas Reserves. Estimates of oil and natural gas reserves and their values, future production rates, and future development costs and expenses requirecommodity pricing differentials are the most significant estimation and assumption.of our estimates. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. These revisions could materially affect our financial statements. The volatility of commodity prices results in increased uncertainty inherent in these estimates and assumptions. Changes in oil, natural gas or NGL prices could result in actual results differing significantly from our estimates. See Supplemental Disclosures About Oil, Natural Gas, and NGL Producing Activities included in Item 8 of Part II of this report for further information.
Derivatives.Accounting for Business Combinations. We use commodity price and financial risk management instruments to mitigate a portion of our exposure to price fluctuations in oil, natural gas and NGL prices. Results of commodity derivative contracts are reflected in oil, natural gas and NGL revenues and results of interest rate and foreign exchange rate derivative contracts are reflected in interest expense.
One ofaccount for business combinations using the primary factors that can have an impact on our results of operationsacquisition method, which is the only method used to value our derivatives. We have establishedpermitted under FASB ASC Topic 805 – Business Combinations, and involves the fair valueuse of our derivative instruments utilizing established index prices, volatility curves and discount factors. These estimates are compared to counterparty valuationssignificant judgment. Under the acquisition method of accounting, a business combination is accounted for reasonableness. Derivative transactions are also subject to the risk that counterparties will be unable to meet their obligations. This non-performance risk is considered in the valuation of our derivative instruments, but to date has not hadat a material impactpurchase price based on the values of our derivatives. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. Additionally, in accordance with accounting guidance for derivatives and hedging, to the extent that a legal right of set-off exists, we net the value of our derivative instruments with the same counterparty in the accompanying consolidated balance sheets.
Another factor that can impact our results of operations each period is our ability to estimate the level of correlation between future changes in the fair value of the derivative instrumentsconsideration given. The assets and liabilities acquired are measured at their fair values, and the transactions being hedged, both at inceptionpurchase price is allocated to the assets and liabilities based upon these fair values. The excess, if any, of the consideration given to acquire an entity over the net amounts assigned to its assets acquired and liabilities assumed is recognized as goodwill. The excess, if any, of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity is recognized immediately to earnings as a gain from bargain purchase.
The Company’s principal assets are its oil and natural gas properties, which are accounted for under the successful efforts accounting method. The Company determines the fair value of acquired oil and natural gas properties based on an ongoing basis. This correlation is complicated since energythe discounted future net cash flows expected to be generated from these assets. Discounted cash flow models by operating area are prepared using the estimated future revenues and operating costs for all proved developed properties and undeveloped properties comprising the proved and unproved reserves. Significant inputs associated with the calculation of discounted future net cash flows include estimates of (i) recoverable reserves, (ii) production rates, (iii) future operating and development costs, (iv) future commodity prices escalated by an inflationary rate after five years, adjusted for differentials, and (v) a market-based weighted average cost of capital by operating area. The Company utilizes NYMEX strip pricing, adjusted for differentials, to value the primary risk we hedge, have quality and location differences that can be difficult to hedge effectively.reserves. The factors underlying our estimates ofNYMEX strip pricing inputs used are classified as Level 1 fair value assumptions and ourall other inputs are classified as Level 3 fair value assumptions. The discount rates utilized are derived using a weighted average cost of capital computation, which includes an estimated cost of debt and equity for market participants with similar geographies and asset development type by operating area.
Impairments. Long-lived assets used in operations, including proved oil and gas properties, are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows expected to be generated by an asset group. Individual assets are grouped for impairment purposes based on a judgmental assessment of correlationthe lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. If there is an indication the carrying amount of an asset may not be
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recovered, the asset is assessed by management through an established process in which changes to significant assumptions such as prices, volumes, and future development plans are reviewed. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value by discounting using a weighted average cost of capital. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is assessed by management using the income approach. Level 3 inputs associated with the calculation of discounted cash flows used in the impairment analysis include our derivative instruments are impacted by actual resultsestimate of future crude oil and changes in conditions that affect these factors, many of which are beyond our control.
Due to the volatility of oil, natural gas prices, production costs, development expenditures, anticipated production of proved reserves and NGL prices and,other relevant data. Additionally, we utilize NYMEX strip pricing, adjusted for differentials, to a lesser extent, interest rates and foreign exchange rates, our financial condition and results of operations may be significantly impacted by changes invalue the market value of our derivative instruments. As of December 31, 2017 and 2016, the fair values of our derivatives were net liabilities of $35 million and net liabilities of $577 million, respectively.reserves.
Income Taxes. The amount of income taxes recorded requires interpretations and application of complex rules and regulations pertaining to federal, state and local taxing jurisdictions. Income taxes are accounted for using the asset and liability method as required by GAAP. We recognize deferredDeferred tax assets and liabilities forarise from temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements. Deferred tax assets for tax attributes such as NOL carryforwards and tax creditdisallowed business interest carryforwards haveare also been recognized. We routinely assess the realizability of our deferredDeferred tax assets represent potential future tax benefits, and reduce such assetsare reduced by a valuation allowance if it is more-likely-than-notmore likely than not that all or some portion of the deferred tax assetssuch benefits will not be realized.
In assessing the need for additionala valuation allowancesallowance or adjustments to existing valuation allowances, we consider the weight of all available evidence, both positive and negative, concerning the realization of the deferred tax asset. Among the more significant types of evidence that we consider are:
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•taxable income projections in future years;
•reversal of existing deferred tax liabilities against deferred tax assets and whether the carryforward period is so brief that it would limit realization of the tax benefit;
•future sales and operating cost projections that will produce more than enough taxable income to realize the deferred tax asset based on existing sales prices and cost structures; and
•our earnings history exclusive of theany loss that created thecreates a future deductible amount coupled with evidence indicating that the loss is an aberration rather than a continuing condition.
Our judgments and assumptions in estimating future taxable income include such factors as future operating conditions and commodity prices when determining ifjudgement regarding the realizability of deferred tax assets are not more-likely-than-not to be realized. Asis thus significantly informed by our assessment of December 31, 2017 and 2016, we had deferredforecasted financial information.
In interim quarters our tax assets totaling $2.826 billion and $4.690 billionprovision is based upon an estimated annual effective tax rate, which we hadis determined through the usage of full year estimates. Thus, our quarterly income tax expense or benefit can fluctuate throughout the year as a valuation allowanceresult of $2.674 billion and $4.389 billion, respectively.changing financial forecasts.
We also routinely assess potential uncertain tax positions and, if required, establish accruals for such positions. Accounting guidance for recognizing and measuring uncertain tax positions requires that a more-likely-than-notmore likely than not threshold condition be met on a tax position, based solely on its technical merits of being sustained, before any benefit of the uncertain tax position can be recognized in the financial statements. GuidanceIf it is also provided regarding de-recognition, classification and disclosure of these uncertain tax positions. Ifmore likely than not a tax position does not meet or exceedwill be sustained, we measure and recognize the more-likely-than-not threshold thenposition following a cumulative probability estimate.
Contingencies. We are subject to various legal proceedings, claims, and liabilities that arise in the ordinary course of business. Except for contingencies acquired in a business combination, which are recorded at fair value at the time of acquisition, we accrue losses when such losses are probable and reasonably estimable. If we determine that a loss is probable and cannot estimate a specific amount for that loss, but can estimate a range of loss, the best estimate within the range is accrued. If no benefit can be recorded. We accrueamount within the range is a better estimate than any applicable interest related to uncertain tax positions as a component of interest expense. Penalties, if any, related to uncertain tax positions would be recorded in other, expense. Additional information about uncertain tax positions appears in Note 6the minimum amount of the notesrange is accrued. Our in-house legal personnel regularly assess contingent liabilities and, in certain circumstances, consult with third-party legal counsel or consultants to assist in the evaluation of our consolidated financial statements included in Item 8liability for these contingencies.
We make judgments and estimates when we establish liabilities for litigation and other contingent matters. Estimates of this report.
Disclosures About Effects of Transactions with Related Parties
Our equity method investeeslitigation-related liabilities are considered related parties. See Note 7based on the facts and circumstances of the notesindividual case and on information currently available to us. The extent of information available varies based on the status of the litigation and our consolidated financial statements included in Item 8evaluation of this report for further discussionthe claim and legal arguments. In future periods, a number of transactionsfactors could significantly change our estimate of litigation-related liabilities, including discovery activities; briefings filed with our equity method investees.the relevant court; rulings from the court made pre-trial, during trial, or at the conclusion of any trial; and similar cases involving other plaintiffs and defendants that may set or change legal precedent. As events unfold throughout the litigation
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process, we evaluate the available information and may consult with third-party legal counsel to determine whether liability accruals should be established or adjusted.
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ITEMItem 7A.Quantitative and Qualitative Disclosures About Market Risk
Oil, Natural GasThe primary objective of the following information is to provide forward-looking quantitative and qualitative information about our exposure to market risk. The term market risk relates to our risk of loss arising from adverse changes in oil, natural gas, and NGL Derivativesprices and interest rates. These disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. The forward-looking information provides indicators of how we view and manage our ongoing market risk exposures.
Commodity Price Risk
Our results of operations and cash flows are impacted by changes in market prices for oil, natural gas and NGL.NGL, which have historically been volatile. To mitigate a portion of our exposure to adverse price changes, we have enteredenter into various derivative instruments. Our oil, natural gas and NGL derivative activities, when combined with our sales of oil, natural gas and NGLs,NGL, allow us to predict with greater certainty the revenue we will receive. We believe our derivative instruments continue to be highly effective in achieving our risk management objectives.
Our general strategy for protecting short-term cash flow and attempting to mitigate exposure to adverse oil, natural gas and NGL price changes is to hedge into strengthening oil and natural gas futures markets when prices reach levels that management believes are unsustainable for the long term, have material downside risk in the short term or provide reasonable rates of return on our invested capital. Information we consider in forming an opinion about future prices includes general economic conditions, industrial output levels and expectations, producer breakeven cost structures, liquefied natural gas trends, oil and natural gas storage inventory levels, industry decline rates for base production and weather trends. Executive management is involved in all risk management activities and the Board of Directors reviews our derivative program at its quarterly board meetings. We believe we have sufficient internal controls to prevent unauthorized trading.
We use derivative instruments to achieve our risk management objectives, including swaps, collars and options. All of these are described in more detail below. We typically use swaps and collars for a large portion of the oil and natural gas price risk we hedge. We have also sold calls, taking advantage of premiums associated with market price volatility.
We determine the notional volume potentially subject to derivative contracts by reviewing our overall estimated future production levels, which are derived from extensive examination of existing producing reserve estimates and estimates of likely production from new drilling. Production forecasts are updated at least monthly and adjusted if necessary to actual results and activity levels. We do not enter into derivative contracts for volumes in excess of our share of forecasted production, and if production estimates were lowered for future periods and derivative instruments are already executed for some volume above the new production forecasts, the positions would be reversed. The actual fixed price on our derivative instruments is derived from the reference NYMEX price, as reflected in current NYMEX trading. The pricing dates of our derivative contracts follow NYMEX futures. All of our commodity derivative instruments are net settled based on the difference between the fixed price as stated in the contract and the floating-price, resulting in a net amount due to or from the counterparty.
We review our derivative positions continuously and if future market conditions change and prices are at levels we believe could jeopardize the effectiveness of a position, we will mitigate this risk by either negotiating a cash settlement with our counterparty, restructuring the position or entering into a new trade that effectively reverses the current position. The factors we consider in closing or restructuring a position before the settlement date are identical to those we review when deciding to enter into the original derivative position. Gains or losses related to closed positions will be recognized in the month specified in the original contract.
We have determined the fair value of our derivative instruments utilizing established index prices, volatility curves and discount factors. These estimates are compared to counterparty valuations for reasonableness. Derivative transactions are also subject to the risk that counterparties will be unable to meet their obligations. This non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives. Future risk related to counterparties not being able to meet their obligations has been partially mitigated under our commodity hedging arrangements that require counterparties to post collateral if their obligations to us are in excess of defined thresholds. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. See Note 1115 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion of the fair value measurements associated with our derivatives.
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As of December 31, 2017, our oil, natural gasFor the combined 2021 Successor and NGL derivative instruments consisted of the following types of instruments:
Swaps: We receive a fixed price and pays a floating market price to the counterparty for the hedged commodity. In exchange for higher fixed prices on certain of our swap trades, we may sell call options and call swaptions.
Options: We sell, and occasionally buy, call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, we pay the counterparty the excess on sold call options, and we receive the excess on bought call options. If the market price settles below the fixed price of the call option, no payment is due from either party.
Call Swaptions: We sell call swaptions to counterparties that allow the counterparty, on a specific date, to extend an existing fixed-price swap for a certain period of time
Collars: These instruments contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pays the market price. If the market price is between the put and the call strike prices, no payments are due from either party. Three-way collars include the sale by us of an additional put option in exchange for a more favorable strike price on the call option. This eliminates the counterparty’s downside exposure below the second put option strike price.
Basis Protection Swaps: These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point. We receive the fixed price differential and pays the floating market price differential to the counterparty for the hedged commodity.
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As of December 31, 2017, we had the following open oil, natural gas and NGL derivative instruments:
    Weighted Average Price Fair Value
  Volume Fixed Call Put Differential��Asset
(Liability)
  (mmbbl) ($ per bbl) ($ in millions)
Oil:            
Swaps:            
Short-term 20
 $51.99
 $—
 $—
 $—
 $(147)
Long-term 1
 $53.60
 $—
 $—
 $—
 (4)
Three Way Collars:            
Short-term 2
 $—
 $55.00
 $39.15 / $47.00 $—
 $(10)
Call Swaptions:            
Short-term 2
 $52.87
 $—
 $—
 $—
 $(13)
Basis Protection Swaps:            
Short-term 11
 $—
 $—
 $—
 $3.32
 (9)
Total Oil (183)
  (bcf) ($ per mcf) 
Natural Gas:            
Swaps(a):
            
Short-term 532
 $3.11
 $—
 $—
 $—
 149
Collars:            
Short-term 47
 $—
 $3.25
 $3.00
 $—
 11
Call Options (sold):            
Short-term 66
 $—
 $6.27
 $—
 $—
 (3)
Long-term 44
 $—
 $12.00
 $—
 $—
 —
Basis Protection Swaps:            
Short-term 65
 $—
 $—
 $—
 $(0.52) (7)
Total Natural Gas 150
  (mmgal) ($ per gal)  
NGL:            
Propane Swaps            
Short-term 15
 $0.73
 $—
 $—
 $—
 (2)
Butane Swaps            
Short-term 5
 $0.88
 $—
 $—
 $—
 —
Short-term % of WTI 5
 70.5%
 $—
 $—
 $—
 —
Ethane Swaps            
Short-term 8
 $0.28
 $—
 $—
 $—
 —
Total NGL (2)
Total Estimated Fair Value $(35)

(a)This amount includes a sold option to enhance the swap price at an average price of $3.40/mmbtu covering 44 tbtu, included in the sold call options.

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In addition to the open derivative positions disclosed above, as of December 31, 2017, we had $81 million of net derivative losses related to settled contracts for future periods that will be recorded withinPredecessor Periods, oil, natural gas, and NGL revenues, as realized gains (losses)excluding any effect of our derivative instruments, were $1.735 billion, $2.818 billion, and $246 million, respectively. Based on derivatives once they are transferred from either accumulated other comprehensive incomeproduction, oil, natural gas, and NGL revenue for the combined 2021 Successor and Predecessor Periods would have increased or unrealized gains (losses) on derivativesdecreased by approximately $173 million, $282 million, and $25 million, respectively, for each 10% increase or decrease in prices. As of December 31, 2021, the month of related production, based on the terms specified in the original contract as noted below:
  December 31,
2017
  ($ in millions)
Short-term $(24)
Long-term (57)
Total $(81)
The table below reconciles the changes in fair valuevalues of our oil and natural gas derivatives during 2017. Ofwere net liabilities of $358 million and net liabilities of $785 million, respectively. A 10% increase in forward oil prices would decrease the $35valuation of oil derivatives by $95 million while a 10% decrease would increase the valuation by $95 million. A 10% increase in forward natural gas prices would decrease the valuation of natural gas derivatives by approximately $270 million while a 10% decrease would increase the valuation by $269 million. This fair value liability as of change assumes volatility based on prevailing market parameters at December 31, 2017, a $31 million liability relates2021. See Note 15 of the notes to contracts maturingour consolidated financial statements included in the next 12 months and a $4 million liability relates to contracts maturing after 12 months. AllItem 8 of Part II of this report for further information on our open derivative instruments as of December 31, 2017 are expected to mature by December 31, 2020.
  December 31,
2017
  ($ in millions)
Fair value of contracts outstanding, as of January 1, 2017 $(504)
Change in fair value of contracts 445
Contracts realized or otherwise settled 24
Fair value of contracts outstanding, as of December 31, 2017 $(35)
positions.
Interest Rate Risk
The table below presents principal cash flowsOur exposure to interest rate changes relates primarily to borrowings under our Exit Credit Facility for the 2021 Successor Period and related weighted average interest rates by expected maturity dates, usingpre-petition revolving credit facility and DIP Facility for the earliest demand repurchase date2021, 2020 and 2019 Predecessor Periods. Interest is payable on borrowings under the Exit Credit Facility, pre-petition revolving credit facility and DIP Credit Facility based on a floating rate. See Note 6 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for contingent convertible senior notes.additional information. As of December 31, 2017,2021, we had total debt of $9.981 billion, including $7.588 billion of fixed rate debt at interest rates averaging 6.95%no outstanding borrowings under our Exit Credit Facility - Tranche A Loans, and $2.393 billion of floating rate debt at an interest rate of 6.53%.
 Years of Maturity  
 2018 2019 2020 2021 2022 Thereafter Total
 ($ in millions)
Liabilities:             
Debt – fixed rate(a)
$53
 $—
 $665
 $814
 $1,868
 $4,188
 $7,588
Average interest rate6.42% —% 6.71% 5.88% 7.25% 7.07% 6.95%
Debt – variable rate$—
 $1,160
 $—
 $1,233
 $—
 $—
 $2,393
Average interest rate—% 4.10% —% 8.81% —% —% 6.53%

(a)This amount excludes $9 million of premium, discount and deferred financing costs included in debt and $2 million of interest rate derivatives.
Changes$221 million under our Exit Credit Facility - Tranche B Loans. A 1.0% increase in interest rates affectbased on the amountvariable borrowings as of December 31, 2021 would result in an increase in our interest we earn on our cash, cash equivalents and short-term investments and the interest rate we pay on borrowings under our revolving credit facility, term loan and our floating rate senior notes. Allexpense of our other indebtedness is fixed rate and, therefore, does not expose us to the risk of fluctuations in earnings or cash flow due to changes in market interest rates. However, changesapproximately $2 million per year. Changes in interest rates do affect the fair value of our fixed-rate debt.
From time to time, we enter into interest rate derivatives, including fixed-to-floating interest rate swaps (we receive a fixed interest rate and pay a floating market rate) to mitigate our exposure to changes in the fair value of our senior notes and floating-to-fixed interest rate swaps (we receive a floating market rate and pay a fixed interest rate) to manage our interest rate exposure related to our revolving credit facility borrowings. As of December 31, 2017, we had no interest rate derivatives outstanding.
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As of December 31, 2017, we had $7 million of net gains related to settled derivative contracts that will be recorded within interest expense as realized gains or losses once they are transferred from our senior note liability or within interest expense as unrealized gains or losses over the remaining six-year term of our related senior notes.
Realized and unrealized (gains) or losses from interest rate derivative transactions are reflected as adjustments to interest expense on the consolidated statements of operations.
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ITEM 8.     Financial Statements and Supplementary Data
Item 8.Financial Statements and Supplementary Data
INDEX TO FINANCIAL STATEMENTS

CHESAPEAKE ENERGY CORPORATION
Page
64
ReportReports of Independent Registered Public Accounting Firm (PCAOB ID 238)
6573
Consolidated Financial Statements:
Consolidated Balance Sheetsas of December 31, 20172021 and 20162020
6779
Consolidated Statements of Operations
for the Period from February 10, 2021 through December 31, 2021, the Period from January 1, 2021 through February 9, 2021, and the Years Ended December 31, 2017, 20162020 and 20152019
6981
Consolidated Statements of Comprehensive Income (Loss)
for the Period from February 10, 2021 through December 31, 2021, the Period from January 1, 2021 through February 9, 2021, and the Years Ended December 31, 2017, 20162020 and 20152019
7082
Consolidated Statements of Cash Flows
for the Period from February 10, 2021 through December 31, 2021, the Period from January 1, 2021 through February 9, 2021, and the Years Ended December 31, 2017, 20162020 and 20152019
7183
Consolidated Statements of Stockholders’ Equity
for the Period from February 10, 2021 through December 31, 2021, the Period from January 1, 2021 through February 9, 2021, and the Years Ended December 31, 2017, 20162020 and 20152019
7385
Notes to the Consolidated Financial Statements:
Note 1. Basis of Presentation and Summary of Significant Accounting Policies
7588
Note 2. Earnings per Share Chapter 11 Proceedings
8193
Note 3. DebtFresh Start Accounting
8296
Note 4. Contingencies and Commitments
864
Note 5. Other Liabilities
89
Note 6. Income Taxes
90
Note 7. Related Party Transactions
92
Note 8. Equity
93
Note 9. Share-Based Compensation
97
Note 10. Employee Benefit Plans
102
Note 11. Derivative and Hedging Activities
103
Note 12.. Oil and Natural Gas Property Transactions
108104
Note 13.5. Earnings per Share
109
Note 6. Debt
110
Note 7. Contingencies and Commitments
114
Note 8. Other Liabilities
116
Note 9. Leases
117
Note 10. Revenue Recognition
119
Note 11. Income Taxes
121
Note 12. Equity
126
Note 13. Share-Based Compensation
127
Note 14. Employee Benefit Plans
131
Note 15. Derivative and Hedging Activities
131
Note 16. Capitalized Exploratory Well Costs
134
Note 17. Other Property and Equipment
110135
Note 14. Impairments18. Investments
111135
Note 15. Restructuring19. Impairments
136
Note 20. Exploration Expense
137
Note 21. Other Operating Expense
137
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Note 22. Separation and Other Termination Costs
112138
Note 16. Fair Value Measurements2
1133
Note 17.. Asset Retirement Obligations
113138
Note 18.24. Major Customers
114139
Note 19. Condensed Consolidating Financial Information25. Subsequent Events
114139
Note 20. Subsequent Events
118
Supplementary Information:
Quarterly Financial Data (unaudited)
119
Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities (unaudited) (unaudited)
120140
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MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
It is the responsibility of the management of Chesapeake Energy Corporation to establish and maintain adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). Management utilized the Committee of Sponsoring Organizations of the Treadway Commission's Internal Control-Integrated Framework (2013) in conducting the required assessment of effectiveness of the Company's internal control over financial reporting.
Management has performed an assessment of the effectiveness of the Company's internal control over financial reporting and has determined the Company’s internal control over financial reporting was effective as of December 31, 2017.
The effectiveness of the Company's internal control over financial reporting, as of December 31, 2017, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report, which appears herein.
/s/ ROBERT D. LAWLER      
Robert D. Lawler
President and Chief Executive Officer
/s/ DOMENIC J. DELL'OSSO, JR.
Domenic J. Dell'Osso, Jr.
Executive Vice President and Chief Financial Officer
February 22, 2018

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Report of Independent Registered Public Accounting Firm



Tothe Board of Directors and ShareholdersStockholders of Chesapeake Energy Corporation

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidatedfinancial statements, including the related notes balance sheet of Chesapeake Energy Corporation and its subsidiaries (Successor) (the “Company”) as listed inof December 31, 2021, and the accompanying indexrelated consolidated statements of operations, of comprehensive income (loss), of stockholders’ equity and of cash flows for the period from February 10, 2021 through December 31, 2021, including the related notes (collectively referred to as the “consolidatedfinancial statements”).We also have audited the Company's internal control over financial reporting as of December 31, 2017,2021, based on criteria established in Internal Control - Integrated Framework(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidatedfinancial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016,2021, and the results of theirits operations and theirits cash flows for each of the three years in the period endedfrom February 10, 2021 through December 31, 20172021 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017,2021, based on criteria established in Internal Control - Integrated Framework(2013) issued by the COSO.

Basis of Accounting

As discussed in Note 2 to the consolidated financial statements, Chesapeake Energy Corporation and certain of its subsidiaries (collectively the “Debtors”) filed voluntary petitions on June 28, 2020 with the United States Bankruptcy Court for the Southern District of Texas for relief under the provisions of Chapter 11 of the Bankruptcy Code. The Bankruptcy Court confirmed the Debtors’ joint plan of reorganization on January 16, 2021 and the Debtors emerged from bankruptcy on February 9, 2021. In connection with its emergence from bankruptcy, the Company adopted fresh start accounting as of February 9, 2021.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Overover Financial Reporting.Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits.audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB")(PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our auditsaudit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the auditsaudit to obtain reasonable assurance about whether the consolidatedfinancial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our auditsaudit of the consolidatedfinancial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidatedfinancial statements. Our auditsaudit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidatedfinancial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our auditsaudit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provideaudit provides a reasonable basis for our opinions.
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As described in Management’s Report on Internal Control over Financial Reporting, management has excluded Vine Energy Inc. from its assessment of internal control over financial reporting as of December 31, 2021, because it was acquired by the Company in a purchase business combination during 2021. We have also excluded Vine Energy Inc. from our audit of internal control over financial reporting. Vine Energy Inc. is a wholly-owned subsidiary whose total assets and total revenues excluded from management’s assessment and our audit of internal control over financial reporting represent 20% and 7%, respectively, of the related consolidated financial statement amounts as of December 31, 2021 and for the period from February 10, 2021 through December 31, 2021.

Definition and Limitations of Internal Control over Financial Reporting

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

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

Critical Audit Matters

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

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

As described in Note 1 to the consolidated financial statements, the Company’s property and equipment, net balance was approximately $8.8 billion as of December 31, 2021, and depreciation, depletion, and amortization (DD&A) expense for the period from February 10, 2021 through December 31, 2021 was approximately $919 million, both of which substantially related to proved oil and natural gas properties. The Company follows the successful efforts method of accounting for its oil and natural gas properties. Under this method, all capitalized well costs and leasehold costs of proved oil and natural gas properties are depreciated by the units-of-production (UOP) method based on total estimated proved developed reserves and proved reserves, respectively. As disclosed by management, estimates of oil and natural gas reserves and their values, future production rates, future development costs and commodity pricing differentials are the most significant of management’s estimates. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves volumes may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. The estimates of proved oil and natural gas reserves have been developed by specialists, specifically petroleum engineers.

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

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s estimates of proved oil and natural gas reserves. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved oil and natural gas reserves volumes. As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists, and an evaluation of the specialists’ findings. These procedures also included, among others, testing the completeness and accuracy of the data related to commodity pricing differentials and future development costs. Additionally, these procedures included evaluating whether the assumptions applied to the aforementioned data were reasonable considering the past performance of the Company.

Acquisition of Vine Energy, Inc. - Valuation of Proved and Unproved Oil and Natural Gas Properties

As described in Note 4 to the consolidated financial statements, on November 1, 2021, the Company acquired Vine Energy, Inc. (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. Accordingly, the Company recorded the estimated fair values of the acquired proved and unproved oil and natural gas properties of approximately $2.2 billion and approximately $1.1 billion for proved oil and gas properties and unproved properties, respectively. As disclosed by management, managementdetermines the fair value of acquired oil and natural gas properties based on the discounted future net cash flows expected to be generated from these assets. Discounted cash flow models by operating area are prepared using the estimated future revenues and operating costs for all proved developed properties and undeveloped properties comprising the proved and unproved reserves. Significant inputs associated with the calculation of discounted future net cash flows include estimates of (i) recoverable reserves, (ii) production rates, (iii) future operating and development costs, (iv) future commodity prices escalated by an inflationary rate after five years, adjusted for differentials, and (v) a market-based weighted average cost of capital by operating area. The estimates of proved oil and natural gas reserves have been developed by specialists, specifically petroleum engineers.

The principal considerations for our determination that performing procedures relating to the valuation of the acquired Vine proved and unproved oil and natural gas properties is a critical audit matter are (i) the significant judgment by management, including the use of specialists, when developing the fair value of proved and unproved oil and natural gas properties; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence obtained related to the data, methods, and assumptions used by management and its specialists related to recoverable reserves; production rates; future operating and development costs; future commodity prices escalated by an inflationary rate after five years, adjusted for differentials; and a market-based weighted average cost of capital by operating area; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included, among others, testing the effectiveness of controls relating to management’s estimates of the fair value of proved and unproved oil and natural gas properties. These procedures also included, among others, (i) testing management’s process for developing the fair value of proved and unproved oil and natural gas properties; (ii) evaluating the appropriateness of the discounted cash flow models; (iii) testing the completeness and accuracy of underlying data used in the models; and (iv) evaluating the data, methods, and significant assumptions used by management related to recoverable reserves, production rates, future operating and development costs, future commodity prices escalated by an inflationary rate after five years, adjusted for differentials, and a market-based weighted average cost of capital by operating area. Evaluating the reasonableness of management’s assumptions related to future commodity prices adjusted for differentials involved comparing the prices against observable market data and evaluating differentials through inspection of the underlying contracts. Evaluating future operating and development costs involved evaluating the reasonableness of the costs as compared to the past performance of the acquired business,
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comparing to the current performance of the Company, consistency with external market and industry data, and whether the assumptions were consistent with evidence obtained in other areas of the audit. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the recoverable reserves and production rates. As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the data, methods, and assumptions used by the specialists, tests of the data used by the specialists, and an evaluation of the specialists’ findings. Professionals with specialized skill and knowledge were used to assist in the evaluation of the Company’s discounted cash flow models and market-based weighted average cost of capital by operating area.

/s/ PricewaterhouseCoopers LLP

Oklahoma City, Oklahoma
February 22, 201824, 2022

We have served as the Company’s auditor since 1992.



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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Chesapeake Energy Corporation
Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheet of Chesapeake Energy Corporation and its subsidiaries (Predecessor) (the “Company”) as of December 31, 2020, and the related consolidated statements of operations, of comprehensive income (loss), of stockholders’ equity and of cash flows for the period from January 1, 2021 through February 9, 2021 and for the years ended December 31, 2020 and 2019, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020, and the results of its operations and its cash flows for the period from January 1, 2021 through February 9, 2021 and for the years ended December 31, 2020 and 2019 in conformity with accounting principles generally accepted in the United States of America.
Basis of Accounting

As discussed in Note 2 to the consolidated financial statements, Chesapeake Energy Corporation and certain of its subsidiaries (collectively the “Debtors”) filed voluntary petitions on June 28, 2020 with the United States Bankruptcy Court for the Southern District of Texas for relief under the provisions of Chapter 11 of the Bankruptcy Code. The Bankruptcy Court confirmed the Debtors’ joint plan of reorganization on January 16, 2021 and the Debtors emerged from bankruptcy on February 9, 2021. In connection with its emergence from bankruptcy, the Company adopted fresh start accounting. This matter is also described in the “Critical Audit Matters” section of our report.
Basis for Opinion

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

We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud.

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

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

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Valuation of Proved and Unproved Oil and Natural Gas Properties in Connection with the Application of Fresh Start Accounting

As described in Note 3 to the consolidated financial statements, in connection with the Company’s emergence from bankruptcy, management applied fresh start accounting on February 9, 2021 and recorded the estimated fair values of its proved and unproved oil and natural gas properties of approximately $4.7 billion and approximately $483 million, respectively. Management determined the fair value of its oil and natural gas properties based on the discounted future net cash flows expected to be generated from these assets. Discounted cash flow models by operating area were prepared using the estimated future revenues and operating costs for all developed properties and undeveloped properties comprising the proved and unproved reserves. Significant inputs associated with the calculation of discounted future net cash flows include estimates of (i) recoverable reserves, (ii) production rates, (iii) future operating and development costs, (iv) future commodity prices escalated by an inflationary rate after five years, adjusted for differentials, and (v) a market-based weighted average cost of capital by operating area.

The principal considerations for our determination that performing procedures relating to the valuation of proved and unproved oil and natural gas properties in connection with the application of fresh start accounting is a critical audit matter are (i) the significant judgment by management, including the use of specialists, when developing the fair value of proved and unproved oil and natural gas properties; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence obtained related to the data, methods, and assumptions used by management and its specialists related to recoverable reserves, production rates, future operating and development costs, future commodity prices escalated by an inflationary rate after five years, adjusted for differentials, and a market-based weighted average cost of capital by operating area; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included, among others, (i) testing management’s process for developing the fair value of proved and unproved oil and natural gas properties; (ii) evaluating the appropriateness of the discounted cash flow models; (iii) testing the completeness and accuracy of underlying data used in the models; and (iv) evaluating the data, methods, and significant assumptions used by management related to recoverable reserves, production rates, future operating and development costs, future commodity prices escalated by an inflationary rate after five years, adjusted for differentials, and a market-based weighted average cost of capital by operating area. Evaluating the reasonableness of management’s assumptions related to future commodity prices adjusted for differentials involved comparing the prices against observable market data and evaluating differentials through inspection of the underlying contracts. Evaluating future operating costs involved evaluating the reasonableness of the costs as compared to the past performance of the Company. Evaluating future development costs involved evaluating whether the costs were reasonable considering the current performance of the Company, the consistency with external market and industry data, and whether the assumption was consistent with evidence obtained in other areas of the audit. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the recoverable reserves and production rates. As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the data, methods, and assumptions used by the specialists, tests of the data used by the specialists, and an evaluation of the specialists’ findings. Professionals with specialized skill and knowledge were used to assist in the evaluation of the Company’s discounted cash flow models and market-based weighted average cost of capital by operating area.

/s/ PricewaterhouseCoopers LLP

Oklahoma City, Oklahoma
February 24, 2022

We have served as the Company’s auditor since 1992.
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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

SuccessorPredecessor
December 31,
2021		December 31,
2020
Assets
Current assets:
Cash and cash equivalents$905 $279 
Restricted cash9 — 
Accounts receivable, net1,115 746 
Short-term derivative assets5 19 
Other current assets69 64 
Total current assets2,103 1,108 
Property and equipment:
Oil and natural gas properties, successful efforts method
Proved oil and natural gas properties7,682 25,734 
Unproved properties1,530 1,550 
Other property and equipment495 1,754 
Total property and equipment9,707 29,038 
Less: accumulated depreciation, depletion and amortization(908)(23,806)
Property and equipment held for sale, net3 10 
Total property and equipment, net8,802 5,242 
Other long-term assets104 234 
Total assets$11,009 $6,584 
The accompanying notes are an integral part of these consolidated financial statements.
79
  December 31,
  2017 2016
  ($ in millions)
CURRENT ASSETS:    
Cash and cash equivalents ($2 and $1 attributable to our VIE) $5
 $882
Accounts receivable, net 1,322
 1,057
Short-term derivative assets 27
 —
Other current assets 171
 203
Total Current Assets 1,525
 2,142
PROPERTY AND EQUIPMENT:    
Oil and natural gas properties, at cost based on full cost accounting:    
Proved oil and natural gas properties
($488 and $488 attributable to our VIE)
 68,858
 66,451
Unproved properties 3,484
 4,802
Other property and equipment 1,986
 2,053
Total Property and Equipment, at Cost 74,328
 73,306
Less: accumulated depreciation, depletion and amortization
(($461) and ($458) attributable to our VIE)
 (63,664) (62,726)
Property and equipment held for sale, net 16
 29
Total Property and Equipment, Net 10,680
 10,609
LONG-TERM ASSETS:    
Other long-term assets 220
 277
TOTAL ASSETS $12,425
 $13,028
     
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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS – (Continued)

SuccessorPredecessor
December 31,
2021		December 31,
2020
Liabilities and stockholders’ equity (deficit)
Current liabilities:
Accounts payable$308 $346 
Current maturities of long-term debt, net— 1,929 
Accrued interest38 3 
Short-term derivative liabilities899 93 
Other current liabilities1,202 723 
Total current liabilities2,447 3,094 
Long-term debt, net2,278 — 
Long-term derivative liabilities249 44 
Asset retirement obligations, net of current portion349 139 
Other long-term liabilities15 5 
Liabilities subject to compromise— 8,643 
Total liabilities5,338 11,925 
Contingencies and commitments (Note 7)
00
Stockholders’ equity (deficit):
Predecessor preferred stock, $0.01 par value, 20,000,000 shares authorized: 0 and 5,563,458 shares outstanding— 1,631 
Predecessor common stock, $0.01 par value, 22,500,000 shares authorized: 0 and 9,780,547 shares issued— — 
Predecessor additional paid-in capital— 16,937 
Predecessor accumulated other comprehensive income— 45 
Successor common stock, $0.01 par value, 450,000,000 shares authorized: 117,917,349 and 0 shares issued1 — 
Successor additional paid-in capital4,845 — 
Retained earnings (accumulated deficit)825 (23,954)
Total stockholders’ equity (deficit)5,671 (5,341)
Total liabilities and stockholders’ equity (deficit)$11,009 $6,584 

The accompanying notes are an integral part of these consolidated financial statements.
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  December 31,
  2017 2016
  ($ in millions)
CURRENT LIABILITIES:    
Accounts payable $654
 $672
Current maturities of long-term debt, net 52
 503
Accrued interest 137
 113
Short-term derivative liabilities 58
 562
Other current liabilities ($3 and $3 attributable to our VIE) 1,455
 1,798
Total Current Liabilities 2,356
 3,648
LONG-TERM LIABILITIES:    
Long-term debt, net 9,921
 9,938
Long-term derivative liabilities 4
 15
Asset retirement obligations, net of current portion 162
 247
Other long-term liabilities 354
 383
Total Long-Term Liabilities 10,441
 10,583
CONTINGENCIES AND COMMITMENTS (Note 4) 
 
EQUITY:    
Chesapeake Stockholders’ Equity:    
Preferred stock, $0.01 par value, 20,000,000 shares authorized:
5,603,458 and 5,839,506 shares outstanding		 1,671
 1,771
Common stock, $0.01 par value,
2,000,000,000 and 1,500,000,000 shares authorized:
908,732,809 and 896,279,353 shares issued
 9
 9
Additional paid-in capital 14,437
 14,486
Accumulated deficit (16,525) (17,474)
Accumulated other comprehensive loss (57) (96)
Less: treasury stock, at cost;
2,240,394 and 1,220,504 common shares
 (31) (27)
Total Chesapeake Stockholders’ Equity (Deficit) (496) (1,331)
Noncontrolling interests 124
 128
Total Equity (Deficit) (372) (1,203)
TOTAL LIABILITIES AND EQUITY $12,425
 $13,028
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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS



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
Revenues and other:
Oil, natural gas and NGL$4,401 $398 $2,745 $4,517 
Marketing2,263 239 1,869 3,967 
Oil and natural gas derivatives(1,127)(382)596 5 
Gains on sales of assets12 5 30 43 
Total revenues and other5,549 260 5,240 8,532 
Operating expenses:
Production297 32 373 520 
Gathering, processing and transportation780 102 1,082 1,082 
Severance and ad valorem taxes158 18 149 224 
Exploration7 2 427 84 
Marketing2,257 237 1,889 4,003 
General and administrative97 21 267 315 
Separation and other termination costs11 22 44 12 
Depreciation, depletion and amortization919 72 1,097 2,264 
Impairments1 — 8,535 11 
Other operating expense (income), net84 (12)80 48 
Total operating expenses4,611 494 13,943 8,563 
Income (loss) from operations938 (234)(8,703)(31)
Other income (expense):
Interest expense(73)(11)(331)(651)
Gains on purchases or exchanges of debt— — 65 75 
Other income (expense)31 2 (4)(32)
Reorganization items, net— 5,569 (796)— 
Total other income (expense)(42)5,560 (1,066)(608)
Income (loss) before income taxes896 5,326 (9,769)(639)
Income tax benefit(49)(57)(19)(331)
Net income (loss)945 5,383 (9,750)(308)
Net loss attributable to noncontrolling interests— — 16 — 
Net income (loss) attributable to Chesapeake945 5,383 (9,734)(308)
Preferred stock dividends— — (22)(91)
Loss on exchange of preferred stock— — — (17)
Net income (loss) available to common stockholders$945 $5,383 $(9,756)$(416)
Earnings (loss) per common share:
Basic$9.29 $550.35 $(998.26)$(49.97)
Diluted$8.12 $534.51 $(998.26)$(49.97)
Weighted average common shares outstanding (in thousands):
Basic101,754 9,781 9,773 8,325 
Diluted116,341 10,071 9,773 8,325 

The accompanying notes are an integral part of these consolidated financial statements.
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  Years Ended December 31,
  2017 2016 2015
   ($ in millions except per share data)
REVENUES:      
Oil, natural gas and NGL $4,985
 $3,288
 $5,391
Marketing, gathering and compression 4,511
 4,584
 7,373
Total Revenues 9,496
 7,872
 12,764
OPERATING EXPENSES:      
Oil, natural gas and NGL production 562
 710
 1,046
Oil, natural gas and NGL gathering, processing and transportation 1,471
 1,855
 2,119
Production taxes 89
 74
 99
Marketing, gathering and compression 4,598
 4,778
 7,130
General and administrative 262
 240
 235
Restructuring and other termination costs —
 6
 36
Provision for legal contingencies, net (38) 123
 353
Oil, natural gas and NGL depreciation, depletion and amortization 913
 1,003
 2,099
Depreciation and amortization of other assets 82
 104
 130
Impairment of oil and natural gas properties —
 2,564
 18,238
Impairments of fixed assets and other 421
 838
 194
Net (gains) losses on sales of fixed assets (3) (12) 4
Total Operating Expenses 8,357
 12,283
 31,683
INCOME (LOSS) FROM OPERATIONS 1,139
 (4,411) (18,919)
OTHER INCOME (EXPENSE):      
Interest expense (426) (296) (317)
Losses on investments —
 (8) (96)
Loss on sale of investment —
 (10) —
Impairments of investments —
 (119) (53)
Gains on purchases or exchanges of debt 233
 236
 279
Other income 9
 19
 8
Total Other Expense (184) (178) (179)
INCOME (LOSS) BEFORE INCOME TAXES 955
 (4,589) (19,098)
INCOME TAX EXPENSE (BENEFIT):      
Current income taxes (9) (19) (36)
Deferred income taxes 11
 (171) (4,427)
Total Income Tax Expense (Benefit) 2
 (190) (4,463)
NET INCOME (LOSS) 953
 (4,399) (14,635)
Net (income) loss attributable to noncontrolling interests (4) 9
 68
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE 949
 (4,390) (14,567)
Preferred stock dividends (85) (97) (171)
Loss on exchange of preferred stock (41) (428) —
Earnings allocated to participating securities (10) —
 —
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS $813
 $(4,915) $(14,738)
EARNINGS (LOSS) PER COMMON SHARE:      
Basic $0.90
 $(6.43) $(22.26)
Diluted $0.90
 $(6.43) $(22.26)
CASH DIVIDEND DECLARED PER COMMON SHARE $—
 $—
 $0.0875
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in millions):		      
Basic 906
 764
 662
Diluted 906
 764
 662
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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)





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 income (loss)$945 $5,383 $(9,750)$(308)
Other comprehensive income, net of income tax:
Reclassification of losses on settled derivative instruments(a)
— 3 33 35 
Other comprehensive income— 3 33 35 
Comprehensive income (loss)945 5,386 (9,717)(273)
Comprehensive loss attributable to noncontrolling interests— — 16 — 
Comprehensive income (loss) attributable to Chesapeake$945 $5,386 $(9,701)$(273)

(a)Deferred tax activity incurred in other comprehensive income was offset by a valuation allowance.

The accompanying notes are an integral part of these consolidated financial statements.
82
  Years Ended December 31,
  2017 2016 2015
  ($ in millions)
NET INCOME (LOSS) $953
 $(4,399) $(14,635)
OTHER COMPREHENSIVE INCOME (LOSS), NET OF INCOME TAX:      
Unrealized gains (losses) on derivative instruments, net of income tax expense (benefit) of $0, ($14) and $12 5
 (13) 20
Reclassification of losses on settled derivative instruments, net of income tax expense of $0, $18 and $15 34
 16
 24
Other Comprehensive Income 39
 3
 44
COMPREHENSIVE INCOME (LOSS) 992
 (4,396) (14,591)
COMPREHENSIVE (INCOME) LOSS ATTRIBUTABLE TO
NONCONTROLLING INTERESTS
 (4) 9
 68
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE $988
 $(4,387) $(14,523)


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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS







 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
Cash flows from operating activities:
Net income (loss)$945 $5,383 $(9,750)$(308)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization919 72 1,097 2,264 
Deferred income tax benefit(49)(57)(10)(305)
Derivative (gains) losses, net1,127 382 (596)(3)
Cash receipts (payments) on derivative settlements, net(1,142)(17)884 202 
Share-based compensation9 3 21 30 
Gains on sales of assets(12)(5)(30)(43)
Impairments1 — 8,535 11 
Non-cash reorganization items, net— (6,680)(213)— 
Exploration2 2 417 49 
Gains on purchases or exchanges of debt— — (65)(79)
Other46 45 (41)59 
Changes in assets and liabilities(37)851 915 (254)
Net cash provided by (used in) operating activities1,809 (21)1,164 1,623 
Cash flows from investing activities:
Capital expenditures(669)(66)(1,142)(2,263)
Business combination, net(194)— — (353)
Proceeds from divestitures of property and equipment13 — 150 136 
Net cash used in investing activities(850)(66)(992)(2,480)
Cash flows from financing activities:
Proceeds from Exit Credit Facility - Tranche A Loans30 — — — 
Payments on Exit Credit Facility - Tranche A Loans(80)(479)— — 
Proceeds from pre-petition revolving credit facility borrowings— — 3,656 10,676 
Payments on pre-petition revolving credit facility borrowings— — (3,317)(10,180)
Proceeds from DIP Facility borrowings— — 60 — 
Payments on DIP Facility borrowings— (1,179)(60)— 
Proceeds from issuance of senior notes, net— 1,000 — 108 
Proceeds from issuance of term loan, net— — — 1,455 
Proceeds from issuance of common stock— 600 — — 
Proceeds from warrant exercise2 — — — 
Debt issuance and other financing costs(3)(8)(109)— 
Cash paid to purchase debt— — (94)(1,073)
Cash paid for common stock dividends(119)— — — 
Cash paid for preferred stock dividends— — (22)(91)
Other(1)— (13)(36)
Net cash provided by (used in) financing activities(171)(66)101 859 
Net increase (decrease) in cash, cash equivalents and restricted cash788 (153)273 2 
Cash, cash equivalents and restricted cash, beginning of period126 279 6 4 
Cash, cash equivalents and restricted cash, end of period$914 $126 $279 $6 
The accompanying notes are an integral part of these consolidated financial statements.
83
  Years Ended December 31,
  2017 2016 2015
  ($ in millions)
CASH FLOWS FROM OPERATING ACTIVITIES:      
NET INCOME (LOSS) $953
 $(4,399) $(14,635)
ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO CASH
PROVIDED BY (USED IN) OPERATING ACTIVITIES:
      
Depreciation, depletion and amortization 995
 1,107
 2,229
Deferred income tax expense (benefit) 11
 (171) (4,427)
Derivative (gains) losses, net (409) 739
 (932)
Cash receipts (payments) on derivative settlements, net (18) 448
 1,123
Stock-based compensation 49
 52
 78
Impairment of oil and natural gas properties —
 2,564
 18,238
Net (gains) losses on sales of fixed assets (3) (12) 4
Renegotiation of natural gas gathering contracts —
 (115) —
Impairments of fixed assets and other 4
 467
 175
Losses on investments —
 8
 96
Loss on sale of investment —
 10
 —
Impairments of investments —
 119
 53
Gains on purchases or exchanges of debt (235) (236) (304)
Restructuring and other termination costs —
 3
 (14)
Provision for legal contingencies, net (42) 87
 340
Other (89) (114) 244
(Increase) decrease in accounts receivable and other assets (163) (4) 1,186
Decrease in accounts payable, accrued liabilities and other (308) (757) (2,220)
Net Cash Provided By (Used In) Operating Activities 745
 (204) 1,234
CASH FLOWS FROM INVESTING ACTIVITIES:      
Drilling and completion costs (2,186) (1,295) (3,095)
Acquisitions of proved and unproved properties (285) (788) (533)
Proceeds from divestitures of proved and unproved properties 1,249
 1,406
 189
Additions to other property and equipment (21) (37) (143)
Proceeds from sales of other property and equipment 55
 131
 89
Cash paid for title defects —
 (69) —
Additions to investments —
 —
 (1)
Decrease in restricted cash —
 —
 52
Other —
 (8) (9)
Net Cash Used In Investing Activities (1,188) (660) (3,451)
       
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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS – (Continued)





 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
Cash and cash equivalents$905 $40 $279 $6 
Restricted cash9 86 — — 
Total cash, cash equivalents and restricted cash$914 $126 $279 $6 
Supplemental disclosures to the consolidated statements of cash flows are presented below:
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
Supplemental cash flow information:
Cash paid for reorganization items, net$65 $66 $140 $— 
Interest paid, net of capitalized interest$34 $13 $224 $691 
Income taxes paid, net of refunds received$(9)$— $— $(6)
Supplemental disclosure of significant non-cash investing and financing activities:
Change in accrued drilling and completion costs$30 $(5)$(216)$(19)
Put option premium on equity backstop agreement$— $60 $60 $— 
Operating lease obligations recognized$— $— $32 $— 
Common stock issued for business combination$1,232 $— $— $2,037 
Debt exchanged for common stock$— $— $— $693 
Preferred stock exchanged for common stock$— $— $— $40 
Change in senior notes exchanged$— $— $— $971 

The accompanying notes are an integral part of these consolidated financial statements.
84
  Years Ended December 31,
  2017 2016 2015
  ($ in millions)
CASH FLOWS FROM FINANCING ACTIVITIES:      
Proceeds from revolving credit facility borrowings 7,771
 5,146
 —
Payments on revolving credit facility borrowings (6,990) (5,146) —
Proceeds from issuance of senior notes, net 1,585
 2,210
 —
Proceeds from issuance of term loan, net —
 1,476
 —
Cash paid to purchase debt (2,592) (2,734) (508)
Cash paid for common stock dividends —
 —
 (118)
Cash paid for preferred stock dividends (183) —
 (171)
Cash paid to repurchase noncontrolling interest of CHK C-T —
 —
 (143)
Distributions to noncontrolling interest owners (8) (10) (85)
Other (17) (21) (41)
Net Cash Provided By (Used In) Financing Activities (434) 921
 (1,066)
Net increase (decrease) in cash and cash equivalents (877) 57
 (3,283)
Cash and cash equivalents, beginning of period 882
 825
 4,108
Cash and cash equivalents, end of period $5
 $882
 $825
       
Supplemental disclosures to the consolidated statements of cash flows are presented below:  
       
  Years Ended December 31,
  2017 2016 2015
  ($ in millions)
SUPPLEMENTAL CASH FLOW INFORMATION:      
Interest paid, net of capitalized interest $492
 $344
 $235
Income taxes paid, net of refunds received $(16) $(27) $44
       
SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:      
Change in accrued drilling and completion costs $14
 $(23) $(148)
Change in accrued acquisitions of proved and unproved properties $9
 $(13) $55
Change in divested proved and unproved properties $(57) $52
 $35
Divestiture of proved and unproved CHK-C-T properties $—
 $—
 $1,024
Debt exchanged for common stock $—
 $471
 $—
Repurchase of noncontrolling interest in CHK C-T $—
 $—
 $(872)

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY







Attributable to Chesapeake
Preferred StockCommon StockAdditional Paid-in CapitalRetained Earnings (Accumulated Deficit)Accumulated Other Comprehensive IncomeTreasury StockNon-controlling InterestTotal Stockholders’ Equity (Deficit)
SharesAmountSharesAmount
Balance as of December 31, 2020 (Predecessor)5,563,358 $1,631 9,780,547 $— $16,937 $(23,954)$45 $— $— $(5,341)
Share-based compensation— — 67 — 3 — — — — 3 
Hedging activity— — — — — — 3 — — 3 
Net income— — — — — 5,383 — — — 5,383 
Cancellation of Predecessor equity(5,563,358)(1,631)(9,780,614)— (16,940)18,571 (48)— — (48)
Issuance of Successor common stock— — 97,907,081 1 3,330 — — — — 3,331 
Issuance of Successor Class A warrants— — — — 93 — — — — 93 
Issuance of Successor Class B warrants— — — — 94 — — — — 94 
Issuance of Successor Class C warrants— — — — 68 — — — — 68 
Balance as of February 9, 2021 (Predecessor)— $— 97,907,081 $1 $3,585 $— $— $— $— $3,586 
Balance as of February 10, 2021 (Successor)— $— 97,907,081 $1 $3,585 $— $— $— $— $3,586 
Share-based compensation— — 248,487 — 21 — — — — 21 
Issuance of common stock for Vine acquisition— — 18,709,399 — 1,237 — — — — 1,237 
Issuance of common stock for warrant exercise— — 188,292 — 2 — — — — 2 
Issuance of reserved common stock and warrants— — 864,090 — — — — — — — 
Net income— — — — — 945 — — — 945 
Dividends on common stock— — — — — (120)— — — (120)
Balance as of December 31, 2021 (Successor)— $— 117,917,349 $1 $4,845 $825 $— $— $— $5,671 






The accompanying notes are an integral part of these consolidated financial statements.
85
  Years Ended December 31,
  2017 2016 2015
  ($ in millions)
PREFERRED STOCK:      
Balance, beginning of period $1,771
 $3,062
 $3,062
Exchange/conversions of 236,048, 1,412,009 and 0 shares of
preferred stock for common stock
 (100) (1,291) —
Balance, end of period 1,671
 1,771
 3,062
COMMON STOCK:      
Balance, beginning of period 9
 7
 7
Exchange of senior notes, contingent convertible notes
and preferred stock
 —
 1
 —
Conversion of preferred stock —
 1
 —
Balance, end of period 9
 9
 7
ADDITIONAL PAID-IN CAPITAL:      
Balance, beginning of period 14,486
 12,403
 12,531
Stock-based compensation 54
 64
 71
Exchange of contingent convertible notes for 0 and 55,427,782 and 0 shares of common stock —
 241
 —
Exchange of senior notes for 0 and 53,923,925 and 0 shares of common stock —
 229
 —
Exchange/conversion of preferred stock for 9,965,835,
120,186,195 and 0 shares of common stock
 100
 1,290
 —
Issuance of 5.5% convertible senior notes due 2026 —
 445
 —
Tax effect on the issuance of 5.5% convertible senior notes due 2026 —
 (165) —
Equity component of contingent convertible notes repurchased, net of tax (20) (16) —
Dividends on preferred stock (183) —
 (128)
Dividends on common stock —
 —
 (59)
Issuance costs —
 (5) —
Increase (decrease) in tax benefit from stock-based compensation —
 —
 (12)
Balance, end of period 14,437
 14,486
 12,403
RETAINED EARNINGS (ACCUMULATED DEFICIT):      
Balance, beginning of period (17,474) (13,084) 1,483
Net income (loss) attributable to Chesapeake 949
 (4,390) (14,567)
Balance, end of period (16,525) (17,474) (13,084)
ACCUMULATED OTHER COMPREHENSIVE LOSS:      
Balance, beginning of period (96) (99) (143)
Hedging activity 39
 3
 44
Balance, end of period (57) (96) (99)
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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY - (Continued)



Attributable to Chesapeake
Preferred StockCommon StockAdditional Paid-in CapitalAccumulated DeficitAccumulated Other Comprehensive IncomeTreasury StockNon-controlling InterestTotal Stockholders’ Equity (Deficit)
SharesAmountSharesAmount
Balance as of December 31, 2019 (Predecessor)5,563,458 $1,631 9,772,793 $— $16,973 $(14,220)$12 $(32)$37 $4,401 
Share-based compensation— — 7,753 — (14)— — — — (14)
Dividends on preferred stock— — — — (22)— — — — (22)
Hedging activity— — — — — — 33 — — 33 
Net loss attributable to Chesapeake— — — — — (9,734)— — — (9,734)
Exchange of preferred stock into common stock(100)— 1 — — — — — — — 
Purchase of shares for company benefit plans— — — — — — — (2)— (2)
Release of shares for company benefit plans— — — — — — — 34 — 34 
Net loss attributable to noncontrolling interests— — — — — — — — (16)(16)
Divestiture of underlying assets— — — — — — — — (21)(21)
Balance as of December 31, 2020 (Predecessor)5,563,358 $1,631 9,780,547 $— $16,937 $(23,954)$45 $— $— $(5,341)

Attributable to Chesapeake
Preferred StockCommon StockAdditional Paid-in CapitalAccumulated DeficitAccumulated Other Comprehensive IncomeTreasury StockNon-controlling InterestTotal Stockholders’ Equity
SharesAmountSharesAmount
Balance as of December 31, 2018 (Predecessor)5,603,458 $1,671 4,568,581 $— $14,387 $(13,912)$(23)$(31)$41 $2,133 
Common shares issued for WildHorse Merger— — 3,586,880 — 2,037 — — — — 2,037 
Share-based compensation— — 20,731 — 27 — — — — 27 
Dividends on preferred stock— — — — (91)— — — — (91)
Hedging activity— — — — — — 35 — — 35 
Net loss attributable to Chesapeake— — — — — (308)— — — (308)
Exchange of contingent convertible notes into common stock— — 366,945 — 135 — — — — 135 
Exchange of senior notes into common stock— — 1,177,817 — 440 — — — — 440 
Exchange of preferred stock into common stock(40,000)(40)51,839 — 40 — — — — — 
Equity component of contingent convertible notes repurchased— — — — (2)— — — — (2)
Purchase of shares for company benefit plans— — — — — — — (7)— (7)
Release of shares for company benefit plans— — — — — — — 6 — 6 
Distributions to noncontrolling interest owners— — — — — — — — (4)(4)
Balance as of December 31, 2019 (Predecessor)5,563,458 $1,631 9,772,793 $— $16,973 $(14,220)$12 $(32)$37 $4,401 

The accompanying notes are an integral part of these consolidated financial statements.
86
  Years Ended December 31,
  2017 2016 2015
  ($ in millions)
TREASURY STOCK – COMMON:      
Balance, beginning of period (27) (33) (37)
Purchase of 1,206,419, 37,871 and 54,493 shares for
company benefit plans
 (7) —
 (1)
Release of 186,529, 255,091 and 231,081 shares from
company benefit plans
 3
 6
 5
Balance, end of period (31) (27) (33)
TOTAL CHESAPEAKE STOCKHOLDERS’ EQUITY (DEFICIT) (496) (1,331) 2,256
NONCONTROLLING INTERESTS:      
Balance, beginning of period 128
 141
 1,302
Net income attributable to noncontrolling interests 4
 (9) (68)
Distributions to noncontrolling interest owners (8) (4) (78)
Repurchase of noncontrolling interest of CHK C-T —
 —
 (1,015)
Balance, end of period 124
 128
 141
TOTAL EQUITY (DEFICIT) $(372) $(1,203) $2,397
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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS OF STOCKHOLDERS’ EQUITY - (Continued)




1.Basis of Presentation and Summary of Significant Accounting Policies
Description of Company
Chesapeake Energy Corporation ("Chesapeake",Chesapeake," “we,” “our”,“our,” “us” or the "Company") is an oil and natural gas exploration and production company engaged in the acquisition, exploration and development of properties for the production of oil, natural gas and natural gas liquids (NGL)NGL from underground reservoirs. Our operations are located onshore in the United States. As discussed in Note 2 below, we filed the Chapter 11 Cases on the Petition Date and subsequently operated as a debtor-in-possession, in accordance with applicable provisions of the Bankruptcy Code, until emergence on February 9, 2021. To facilitate our financial statement presentations, we refer to the post-emergence reorganized Company in these consolidated financial statements and footnotes as the “Successor” for periods subsequent to February 9, 2021, and to the pre-emergence Company as “Predecessor” for periods on or prior to February 9, 2021.
Basis of Presentation
The accompanying consolidated financial statements of Chesapeake were prepared in accordance with GAAP and include the accounts of our direct and indirect wholly owned subsidiaries and entities in which Chesapeake has a controlling financial interest. Intercompany accounts and balances have been eliminated. The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern.
This Annual Report on Form 10-K (this “Form 10-K”) relates to the financial position of the Successor as of December 31, 2021 and Predecessor as of December 31, 2020, and the periods of February 10, 2021 through December 31, 2021 (“2021 Successor Period”), January 1, 2021 through February 9, 2021 (“2021 Predecessor Period”), and the years ended December 31, 2020 (“2020 Predecessor Period”) and December 31, 2019 (“2019 Predecessor Period”).
Accounting During Bankruptcy
We have applied Accounting Standards Codification (ASC) 852, Reorganizations, in preparing the consolidated financial statements. ASC 852 requires that the financial statements, for periods subsequent to the filing of a petition of Chapter 11 Cases, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain revenues, expenses, realized gains and losses and provisions for losses that were realized or incurred during the bankruptcy proceedings, including losses related to executory contracts that were approved for rejection by the Bankruptcy Court, and unamortized debt issuance costs, premiums and discounts associated with debt classified as liabilities subject to compromise, are recorded as reorganization items, net on our accompanying consolidated statements of operations. In addition, pre-petition obligations that could have been impacted by the Chapter 11 process have been classified on the consolidated balance sheet as of December 31, 2020, as liabilities subject to compromise. See Note 2 for more information regarding reorganization items.
Accounting Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the related disclosures in the financial statements. Management evaluates its estimates and related assumptions regularly, including those related to the impairment of oil and natural gas properties, oil and natural gas reserves, derivatives, income taxes, collectibility of accounts receivable,unevaluated properties not subject to evaluation, impairment of other property and equipment, environmental remediation costs, asset retirement obligations, litigation and regulatory proceedings and fair values. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ significantly from these estimates.
The accompanying notes are an integral part of these consolidated financial statements.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Consolidation
We consolidate entities in which we have a controlling financial interest. We consolidate subsidiaries in which we hold, directly or indirectly, more than 50% of the voting rights and variable interest entities (VIEs)(“VIEs”) in which we are the primary beneficiary. We use the equity method of accounting to record our net interests where we have the ability to exercise significant influence through our investment. Under the equity method, our share of net income (loss) is included in our consolidated statements of operations according to our equity ownership or according to the terms of the applicable governing instrument. Undivided interests in oil and natural gas properties are consolidated on a proportionate basis.
Segments
Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating an enterprise’s resources and assessing its operating performance.
We have historically presented two reportable operating segments: (i) exploration and production and (ii) marketing, gathering and compression. In the fourth quarter of 2017, we completed the realignment of our marketing, gathering and compression operations to serve as an ancillary service integral to our exploration and production activities. Following this realignment, we have a single, company-wide management team that administers all activities as a whole rather than through discrete operating units, with an emphasis on allocating capital focused on the expansion of our exploration and production assets. As a result, we have concluded that we have only one reportable operating segment, which is exploration and production. Prior year financial information for our previous marketing, gathering and compression reportable operating segment has been eliminated.
Noncontrolling Interests
Noncontrolling interests represent third-party equity ownership in certain of our consolidated subsidiaries and are presented as a component of equity. See Note 8 for further discussion of noncontrolling interests.
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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Variable Interest Entities
VIEs are entities that, by design, either (i) lack sufficient equity to permit the entity to finance its activities independently, or (ii) have equity holders that do not have the power to direct the activities of the entity that most significantly impact its economic performance, the obligation to absorb the entity’s losses, or the right to receive the entity’s residual returns. We consolidate a VIE when we are the primary beneficiary, which is the party that has both (i) the power to direct the activities that most significantly impact the VIE’s economic performance and (ii) through its interests in the VIE, the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. In order to determine whether we own a variable interest in a VIE, we perform a qualitative analysis of the entity’s design, organizational structure, primary decision makers and relevant agreements. We continually monitor our consolidated VIE to determine if any events have occurred that could cause the primary beneficiary to change. See Note 812 for further discussion of our previous VIE. We use the equity method of accounting to record our net interests where we have the ability to exercise significant influence through our investment but lack a controlling financial interest. Under the equity method, our share of net income (loss) is included in our consolidated statements of operations according to our equity ownership or according to the terms of the applicable governing instrument. Undivided interests in oil and natural gas properties are consolidated on a proportionate basis.
Segments
Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating an enterprise’s resources and assessing its operating performance. We have concluded that we have only 1 reportable operating segment, due to the similar nature of the exploration and production business across Chesapeake and its consolidated subsidiaries and the fact that our marketing activities are ancillary to our operations.
Noncontrolling Interests
Noncontrolling interests represent third-party equity ownership in certain of our consolidated subsidiaries and are presented as a component of equity. See Note 12 for further discussion of noncontrolling interests.
Cash and Cash Equivalents
For purposes of the consolidated financial statements, we consider investments in all highly liquid instruments with original maturities of three months or less at the date of purchase to be cash equivalents.
Restricted Cash
As of December 31, 2021, we had restricted cash of $9 million. The restricted funds are maintained primarily to pay certain convenience class unsecured claims following our emergence from bankruptcy.
Accounts Receivable
Our accounts receivable are primarily from purchasers of oil, natural gas and NGL and from exploration and production companies that own interests in properties we operate. This industry concentration could affect our overall exposure to credit risk, either positively or negatively, because our purchasers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We monitor the creditworthiness of all our counterparties and we generally require letters of credit or parent guarantees for receivables from parties deemed to have sub-standard credit, unless the credit risk can otherwise be mitigated. We utilize an allowance method in accounting for bad debt based on historical trends in addition to specifically identifying receivables that we believe may be uncollectible. Accounts receivable asSee Note 10 for further discussion of December 31, 2017 and 2016 are detailed below:
  December 31,
  2017 2016
  ($ in millions)
Oil, natural gas and NGL sales $959
 $840
Joint interest 209
 156
Other 184
 93
Allowance for doubtful accounts (30) (32)
Total accounts receivable, net $1,322
 $1,057
our accounts receivable.
Oil and Natural Gas Properties
We follow the full costsuccessful efforts method of accounting under which all costs associated withfor our oil and natural gas property acquisition,properties. Under this method, exploration costs such as exploratory geological and development activitiesgeophysical costs, expiration of unproved leasehold, delay rentals and exploration overhead are capitalized. We capitalize internal costs that can be directly identified with these activities and do not capitalize anyexpensed as incurred. All costs related to production, general corporate overhead orand similar activities (see Supplementary Information – Supplemental Disclosures About Oil, Natural Gasare also expensed as incurred. All property acquisition costs and NGL Producing Activities). Capitalizeddevelopment costs are amortized on a composite unit-of-production method based oncapitalized when incurred.
Exploratory drilling costs are initially capitalized, or suspended, pending the determination of proved oil and natural gas reserves. Estimates of ourIf proved reserves are found, drilling costs remain capitalized and are classified as of December 31, 2017 were prepared by an independent engineering firm and our internal staff. In addition, our internal engineers review and update our reserves on a quarterly basis.
Proceeds from the sale of oil and natural gas properties are accounted for as reductions of capitalized costs unless these sales involve a significant change in proved reserves and significantly alter the relationship between costs and proved reserves, in which case a gain or loss is recognized.properties. Costs of
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Theunsuccessful wells are charged to exploration expense. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory drilling costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operational viability of the project. If we determine that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed. In some instances, this determination may take longer than one year. We review the status of all suspended exploratory drilling costs quarterly. Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of oil and natural gas are capitalized.
Costs of drilling and equipping successful wells, costs to construct or acquire facilities, and associated asset retirement costs are depreciated using the unit-of-production (“UOP”) method based on total estimated proved developed oil and gas reserves. Costs of acquiring proved properties, including leasehold acquisition costs transferred from unproved properties, are excluded from amortization untildepleted using the properties are evaluated. We review all of our unproved properties quarterly to determine whether or notUOP method based on total estimated proved developed and to what extent proved reserves have been assigned to the properties and otherwise if impairment has occurred. Unproved properties are grouped by major prospect area in circumstances where individual property costs are not significant. In addition, we analyze our unproved leasehold and transfer to proved properties that portion of our leasehold that expired in the quarter, or leasehold that is no longer part of our development strategy and will be abandoned.undeveloped reserves. 
The table below sets forth the cost of unproved properties excludedProceeds from the amortization base assales of December 31, 2017 and the year in which the associated costs were incurred:
  Year of Acquisition  
  2017 2016 2015 Prior Total
  ($ in millions)
Leasehold cost $70
 $89
 $87
 $2,368
 $2,614
Exploration cost 50
 9
 33
 11
 103
Capitalized interest 154
 116
 120
 377
 767
Total $274
 $214
 $240
 $2,756
 $3,484
We also review, on a quarterly basis, the carrying value of ourindividual oil and natural gas properties underand the full cost accounting rulescapitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depreciation, depletion and amortization, if doing so does not materially impact the depletion rate of an amortization base. Generally, no gain or loss is recognized until an entire amortization base is sold. However, a gain or loss is recognized from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the SEC. This quarterly review is referred to as a ceiling test. Underremaining properties in the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal tobase.
When circumstances indicate that the sum of the presentcarrying value of estimated future net revenues (adjusted forproved oil and natural gas derivatives designated as cash flow hedges) less estimated future expenditures toproperties may not be incurred in developing and producing the proved reserves, less any related income tax effects. The ceiling test calculation usesrecoverable, we compare unamortized capitalized costs as of the end of the applicable quarterly period and the unweighted arithmetic average of oil, natural gas and NGL prices on the first day of each month within the 12-month period prior to the ending date of the quarterly period. These prices are utilized except where different prices are fixed and determinable from applicable contractsexpected undiscounted pre-tax future cash flows for the remaining termassociated assets grouped at the lowest level for which identifiable cash flows are independent of those contracts, includingcash flows of other assets. If the effectsexpected undiscounted pre-tax future cash flows, based on our estimate of derivatives designated as cash flow hedges. As of December 31, 2017, none of our open derivative instruments were designated as cash flow hedges. Ourfuture crude oil and natural gas hedging activities are discussed in Note 11.
Two primary factors impacting the ceiling test are reserve levels and oil, natural gas and NGL prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of oil and natural gas reserves and/or an increase or decrease in prices can have a material impact on the present value of our estimated future net revenues. Any excess of the net book value over the ceiling is written off as an impairment expense.
We account for seismic costs as part of our oil and natural gas properties. Exploration costs may be incurred both before acquiring the related property and after acquiring the property. Further, exploration costs include, among other things, geological and geophysical studies and salaries and other expenses of geologists, geophysical crews and others conducting those studies. These costs are capitalized as incurred. We review our unproved properties and associated seismic costs quarterly to determine whether impairment has occurred. To the extent that seismic costs cannot be directly associated with specific unproved properties, they are included in the amortization base as incurred.
Estimates of oil and natural gas reserves and their values, future production rates and future costs and expenses are the most significant of our estimates. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs, anticipated production from proved reserves and other factors. These revisions could materially affect our financial statements.relevant data, are lower than the unamortized capitalized costs, the capitalized costs are reduced to fair value. Fair value is generally estimated using the income approach described in the ASC 820, Fair Value Measurements. If applicable, we utilize prices and other relevant information generated by market transactions involving assets and liabilities that are identical or comparable to the item being measured as the basis for determining fair value. The volatilityexpected future cash flows used for impairment reviews and related fair value measurements are typically based on judgmental assessments of commodity prices, resultspricing adjustments for differentials, operating costs, capital investment plans, future production volumes, and estimated proved reserves, considering all available information at the date of review. These assumptions are applied to develop future cash flow projections that are then discounted to estimated fair value, using a market-based weighted average cost of capital. We have classified these fair value measurements as Level 3 in increased uncertainty inherent in these estimates and assumptions. Changes in oil, natural gas or NGL prices could result in significant changes to the quarterly ceiling test calculation.fair value hierarchy.
Other Property and Equipment
Other property and equipment consists primarily of natural gas compressors, buildings and improvements, land, vehicles, computers and office equipment. Major renewals and betterments are capitalized while the costs of repairs and maintenance are charged to expense as incurred. The costs of assets retired or otherwise disposed of and the applicable accumulated depreciation are removed from the accounts, and the resulting gain or loss is reflected in operating expenses. Other property and equipment costs, excluding land, are depreciated on a straight-line basis.basis and recorded within depreciation, depletion and amortization in the consolidated statement of operations.
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Realization of the carrying value of other property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including any disposal value, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets and discounted cash flow. See Note 17 for further discussion of other property and equipment.
Capitalized Interest
Interest from external borrowings is capitalized on significant investments in unproved properties and major development projects until the asset is ready for service using the weighted average borrowing rate of outstanding borrowings. Capitalized interest is determined by multiplying our weighted-averageweighted average borrowing cost on debt by the average amount of
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qualifying costs incurred. Capitalized interest is depreciated over the useful lives of the assets in the same manner as the depreciation of the underlying asset.
Accounts Payable
Included in accounts payable as of December 31, 2017 and 20162021 are liabilities of approximately $92$23 million and $77 million, respectively, representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in applicable bank accounts. There were no corresponding liabilities as of December 31, 2020.
Debt Issuance Costs
IncludedCosts associated with the arrangement of our Exit Credit Facility are included in other long-term assets and are costs associated withamortized over the issuance and amendmentslife of our revolving credit facility.the facility using the straight-line method. The remainingExit Credit Facility unamortized issuance costs as of December 31, 2017 and 2016, totaled $22 million and $32 million, respectively, and are being amortized over the life of credit facility using the straight-line method. Included in debt are costs2021 were $23 million. Costs associated with the issuance of ourthe Successor senior notes are included in long-term debt and term loan. Thethe remaining unamortized issuance costs as of December 31, 2017 and 2016, totaled $63 million and $64 million, respectively, and are being amortized over the life of the senior notes using the effective interest method. Unamortized issuance costs associated with the Successor senior notes as of December 31, 2021 totaled $9 million.
Costs associated with the issuance and amendments of our pre-petition revolving credit facility were included in other long-term assets and the remaining unamortized issuance costs were being amortized over the life of the facility using the straight-line method. Costs associated with the issuance of our Predecessor senior notes were included in long-term debt and the remaining unamortized issuance costs were being amortized over the life of the Predecessor senior notes using the effective interest method. In 2020, our Chapter 11 Cases constituted an event of default under our pre-petition revolving credit facility and our senior notes, and non-cash adjustments were made to write off all related unamortized debt issuance costs which are included in reorganization items, net in the accompanying consolidated statements of operations for the year ended December 31, 2020. See Note 2 and Note 6 herein for further discussion of our Chapter 11 Cases and debt issuance costs, respectively.
Litigation Contingencies
We are subject to litigation and regulatory proceedings, claims and liabilities that arise in the ordinary course of business. We accrue losses associated with litigation and regulatory claims when such losses are probable and reasonably estimable. If we determine that a loss is probable and cannot estimate a specific amount for that loss but can estimate a range of loss, our best estimate within the range is accrued. Estimates are adjusted as additional information becomes available or circumstances change. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or third-party recoveries. Legal defense costs associated with loss contingencies are expensed in the period incurred. See Note 7 for further discussion of litigation contingencies.
Environmental Remediation Costs
We record environmental reserves for estimated remediation costs related to existing conditions from past operations when the responsibility to remediate is probable and the costs can be reasonably estimated. Expenditures that create future benefits or contribute to future revenue generation are capitalized. See Note 7 for discussion of environmental contingencies.
Asset Retirement Obligations
We recognize liabilities for obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which an oil or natural gas well is acquired or drilled. The liability is then accreted each period until the liability is settled or the well is sold, at which time the liability is removed. The related asset retirement cost is capitalized as part of the carrying amount of our oil and natural gas properties. See Note 1723 for further discussion of asset retirement obligations.
Revenue Recognition
Oil, Natural Gas and NGL Sales. Revenue from the sale of oil, natural gas and NGL is recognized when title passes, net of royalties due to third parties.
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Revenue Recognition
Natural Gas Imbalances. We followRevenue from the sales methodsale of accounting for ouroil, natural gas revenue wherebyand NGL is recognized upon the transfer of control of the products, which is typically when the products are delivered to customers. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration we recognize sales revenue on allexpect to receive in exchange for those products.
Revenue from contracts with customers includes the sale of our oil, natural gas sold to our purchasers, regardless of whether the sales are proportionate to our ownershipand NGL production (recorded as oil, natural gas and NGL revenues in the property. An asset or a liability is recognized toconsolidated statements of operations) as well as the extent thatsale of certain of our joint interest holders’ production which we have an imbalancepurchase under joint operating arrangements (recorded in excessmarketing revenues in the consolidated statements of the remaining estimated natural gas reserves on the underlying properties. The natural gas imbalance net liability position as of December 31, 2017 and 2016, was $5 million and $9 million, respectively.
Marketing, Gathering and Compression Sales.operations). In connection with the marketing of our production,these products, we take title toobtain control of the oil, natural gas and NGL we purchase from other interest owners at defined delivery points and deliver the product to third parties, at which time revenues are recorded. In addition, we periodically enter into
Payment terms and conditions vary by contract type, although terms generally include a requirement of payment within 30 days. There are no significant judgments that significantly affect the amount or timing of revenue from contracts with customers.
We also generate revenue from other sources, including from a variety of derivative and hedging activities to reduce our exposure to fluctuations in future commodity prices and to protect our expected operating cash flow against significant market movements or volatility, as well as a variety of oil, natural gas and NGL purchase and sale contracts with third parties for various commercial purposes, primarily forincluding credit risk mitigation and to help meet certainsatisfaction of our pipeline delivery commitments. commitments (recorded within marketing revenues in the consolidated statements of operations).
In circumstances where we act as a principalan agent rather than an agent,a principal, our results of operations related to oil, natural gas and NGL marketing activities are presented on a grossnet basis. Gathering and compression revenues consistSee Note 10 for further discussion of fees billed to other interest owners in operated wells or third-party producers for the gathering, treating and compression of natural gas. Revenues are recognized when the service is performed and are based upon non-regulated rates and the related gathering, treating and compression volumes. All significant intercompany accounts and transactions have been eliminated.revenue recognition.
Fair Value Measurements
Certain financial instruments are reported on a recurring basis at fair value on our consolidated balance sheets. We also use fair value measurements on a nonrecurring basis when a qualitative assessment of our assets indicates a potential impairment. Under fair value measurement accounting guidance, fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants (i.e., an exit price). To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 inputs are inputs other than quoted prices within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability and have the lowest priority.
The valuation techniques that may be used to measure fair value include a market approach, an income approach and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).
The carrying values of financial instruments comprising cash and cash equivalents, accounts payable and accounts receivable approximate fair values due to the short-term maturities of these instruments. See Notes 6 and 15 for further discussion of fair value measurements.
Derivatives
Derivative instruments are recorded at fair value, and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are followed. For qualifying commodityAs of December 31, 2021, none of our open derivative instruments were designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. Locked-in gains and losses of settled cash flow hedges are recorded in accumulated other comprehensive income and are transferred to earnings in the month of production. Changes in the fair value of interest rate derivative instruments designated as fair value hedges are recorded on the consolidated balance sheets as assets or liabilities, and the debt's carrying value amount is adjusted by the change in the fair value of the debt subsequent to the initiation of the derivative. Differences between the changes in the fair values of the hedged item and the derivative instrument, if any, represent hedge ineffectiveness and are recognized currently in earnings. Locked-in gains and losses related to settled fair value hedges are amortized as an adjustment to interest expense over the remaining term of the related debt instrument. We have elected not to designate any of our qualifying commodity and interest rate derivatives as cash flow or fair value hedges. Therefore, changes in fair value of these derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are recognized in our consolidated statements of operations within oil, natural gas and NGL sales and interest expense, respectively.
Derivative instruments reflected as current in the consolidated balance sheets represent the estimated fair value of derivatives scheduled to settle over the next twelve months based on market prices/rates as of the respective balance sheet dates. Cash settlements of our derivative instruments are generally classified as operating cash flows unless
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cash flows unless the derivatives are deemed to contain, for accounting purposes, a significant financing element at contract inception, in which case these cash settlements are classified as financing cash flows in the accompanying consolidated statement of cash flows. All of our derivative instruments are subject to master netting arrangements by contract type which provide for the offsetting of asset and liability positions within each contract type, as well as related cash collateral if applicable, by counterparty. Therefore, we net the value of our derivative instruments by contract type with the same counterparty in the accompanying consolidated balance sheets.
We have established the fair value of our derivative instruments using established index prices, volatility curves and discount factors. These estimates are compared to our counterparty values for reasonableness. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. Derivative transactions are subject to the risk that counterparties will be unable to meet their obligations. This non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives. See Note 1115 for further discussion of our derivative instruments.
Share-Based Compensation
Our share-based compensation program consists of restricted stock, stock optionsperformance share units and performance sharecash restricted stock units granted to employees and restricted stock granted to non-employee directors under our Long Term Incentive Plan. We recognize the cost of employee services received in exchange for restricted stock and stock options based on the fair value of the equity instruments as of the grant date. For employees, thisThis value is amortized over the vesting period, which is generally three or four years from the grant date. For directors, although restricted stock grants vest over three years, this value is recognized immediately as there is a non-substantive service condition for vesting. Because performance share units can only beare settled in cash,shares, they are classified as a liability in our consolidated financial statementsequity and are measured at fair value as of the grant date and re-measured at fair value at the end of each reporting period. These fair value adjustments are recognized as general and administrative expense in the consolidated statements of operations.date.
To the extent compensation expense relates to employees directly involved in the acquisition of oil and natural gas leasehold and exploration and development activities, these amounts are capitalized to oil and natural gas properties. Amounts not capitalized to oil and natural gas properties are recognized as general and administrative expenses, oil, natural gas and NGLexpense, production expenses,expense, exploration expense, or marketing gathering and compression expenses,expense, based on the employees involved in those activities. See Note 913 for further discussion of share-based compensation.
Recently Issued Accounting StandardsLiability Management
In May 2014,Liability management expense includes third party legal and professional service fees incurred for our activities to restructure our debt and in preparation for our bankruptcy petition. As a result of our Chapter 11 Cases, such expenses, to the Financial Accounting Standards Board (FASB) issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) extent that supersedes virtually all existing revenue recognition guidance. The new standard includes a five-step revenue recognition model that requires the recognition of revenuethey were incremental and directly related to depict the transfer of promised goods to customersour bankruptcy reorganization, are reflected in an amount reflecting the consideration we expect to be entitled in exchange for those goods. The standard is required to be adopted using either the full retrospective approach or the modified retrospective approach. We will adopt this new standard in the first quarter of 2018 using the modified retrospective approach. Among other things, the standard requires enhanced disclosures about revenue and provides guidance for transactions that were not previously addressed comprehensively. As of December 31, 2017, we have completed our evaluation of the new standard and have concluded that the cumulative effect of adoption will not have a material impact on our consolidated financial statements. The adoption will result in a change in the gross versusreorganization items, net presentation of certain revenue transactions in our consolidated statements of operations, but any such presentation changes would not have an impact on income (loss) from operations, earnings per share or cash flows.operations.
In January 2016,
2.Chapter 11 Proceedings
On June 28, 2020 (the “Petition Date”), the FASB issued amendments on certain aspects of recognition, measurement, presentation, and disclosure of financial instruments through ASU 2016-01, Financial Instruments-Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities. ASU 2016-01 will require equity investments (except those accountedDebtors filed voluntary petitions for relief under the equity method of accounting, or those that resultBankruptcy Code in consolidationthe Bankruptcy Court. On June 29, 2020, the Bankruptcy Court entered an order authorizing the joint administration of the investee)Chapter 11 Cases under the caption In re Chesapeake Energy Corporation, Case No. 20-33233. The Non-Filing Entities were not part of the Chapter 11 Cases. The Debtors and the Non-Filing Entities continued to be measured at fair value with changesoperate in fair value recognizedthe ordinary course of business during the Chapter 11 Cases.
The Bankruptcy Court confirmed the Plan in net income. In addition, ASU 2016-01 changes certain disclosure requirements and other aspects of GAAP. We will adopt ASU 2016-01a bench ruling on January 1, 2018. As of December 31, 2017, we13, 2021 and entered the Confirmation Orderon January 16, 2021.The Debtors emerged from bankruptcy on February 9, 2021 (the “Effective Date”). The Company’s bankruptcy proceedings and related matters have completed our evaluationbeen summarized below.
Debtor-In-Possession
During the pendency of the new standard and have concludedChapter 11 Cases, we operated our business as debtors-in-possession in accordance with the applicable provisions of the Bankruptcy Code. The Bankruptcy Court granted the first day relief we requested that was designed primarily to mitigate the effectimpact of the Chapter 11 Cases on our financial statements is not material, but may be materialoperations, vendors, suppliers, customers and employees. As a result, we were able to conduct normal business activities and pay all associated obligations for the period following the Petition Date and were also authorized to pay mineral interest owner royalties, employee wages and benefits, and certain vendors and suppliers in the future if we wereordinary course for goods and services provided prior to sell a portionthe Petition Date. During the pendency of our equitythe Chapter 11 Cases, all transactions outside the ordinary course of business required the prior approval of the Bankruptcy Court.
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Automatic Stay
method investments such that we no longer hadSubject to certain specific exceptions under the ability to exercise significant influence overBankruptcy Code, the operating and financial activitiesfiling of the investee.
In February 2016,Chapter 11 Cases automatically stayed all judicial or administrative actions against us and efforts by creditors to collect on or otherwise exercise rights or remedies with respect to pre-petition claims. Absent an order from the FASB issued ASU 2016-02, Leases (Topic 842) which updated lease accounting guidance requiring lesseesBankruptcy Court, substantially all of the Debtors’ pre-petition liabilities were subject to recognize most leases, including operating leases,compromise and discharge under the Bankruptcy Code. The automatic stay was lifted on the balance sheet as a rightEffective Date.
Plan of use assetReorganization
In accordance with the Plan confirmed by the Bankruptcy Court, the following significant transactions occurred upon the Company’s emergence from bankruptcy on February 9, 2021:
•On the Effective Date, we issued 97,907,081 shares of the reorganized company (“New Common Stock”), reserved 2,092,918 shares of New Common Stock for future issuance to eligible holders of Allowed Unsecured Notes Claims and lease liability. The accounting standards update is effectiveAllowed General Unsecured Claims and reserved 37,174,210 shares of New Common Stock for fiscal years, and interim periods within those years, beginning after December 15, 2018 and will be adopted using a modified retrospective transition method,issuance upon exercise of the Warrants, which requires applyingwere the new standard to leases that exist or areresult of the transactions described below. We also entered into aftera registration rights agreement, a warrants agreement and amended our articles of incorporation and bylaws for the beginningauthorization of the earliest period in the financial statements. Early adoption is permitted, but we do not planNew Common Stock and to early adopt. The standard will not apply to our leases of mineral rights. We are continuing to evaluate the impact of this standard on our consolidated financial statements and related disclosures.
In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815) which makes significant changes to the current hedge accounting guidance. The new standard eliminates the requirement to separately measure and report hedge ineffectiveness and generally requires the entire change in the fair value of a hedging instrument to be presented in the same income statement line as the hedged item. The new standard also eases certain documentation and assessment requirements and modifies the accounting for components excluded from the assessment of hedge effectiveness. The new standard update is effective for annual and interim periods beginning after December 15, 2018, including interim periods within those annual periods. Early adoption is permitted, but we do not plan to early adopt. We are currently evaluating the impact of this standard on our consolidated financial statements and related disclosures.
Reclassifications
Certain reclassifications have been made to the consolidated financial statements for 2016 and 2015 to conform to the presentation used for the 2017 consolidated financial statements.
2.Earnings Per Share
Basic earnings per share (EPS) is calculated using the weighted average number of common shares outstanding during the period and includes the effect of any participating securities as appropriate. Participating securities consist of unvested restricted stock issued to our employees and non-employee directors that provide dividend rights.
Diluted EPS is calculated assuming the issuance of common shares for all potentially dilutive securities, provided the effect is not antidilutive. For all periods presented, our contingent convertible senior notes did not have a dilutive effect and therefore were excluded from the calculation of diluted EPS.registration rights thereunder, among other corporate governance actions. See Note 312 for further discussion of our convertible senior notespost-emergence equity.
•Each holder of a Predecessor equity interest in Chesapeake, including our common and contingent convertible senior notes.preferred stock, had such interest canceled, released, and extinguished without any distribution.
Shares•Each holder of common stockobligations under the pre-petition revolving credit facility received, at such holder's prior determined allocation, its pro rata share of either Tranche A Loans or Tranche B Loans, on a dollar for dollar basis.
•Each holder of obligations under the following dilutive securitiesFLLO Term Loan Facility received its pro rata share of 23,022,420 shares of New Common Stock.
•Each holder of an Allowed Second Lien Notes Claim received its pro rata share of 3,635,118 shares of New Common Stock, 11,111,111 Class A Warrants to purchase 11,111,111 shares of New Common Stock, 12,345,679 Class B Warrants to purchase 12,345,679 shares of New Common Stock, and 6,858,710 Class C Warrants to purchase 6,858,710 shares of New Common Stock.
•Each holder of an Allowed Unsecured Notes Claim received its pro rata share of 1,311,089 shares of New Common Stock and 2,473,757 Class C Warrants to purchase 2,473,757 shares of New Common Stock.
•Each holder of an Allowed General Unsecured Claim received its pro rata share of 231,112 shares of New Common Stock and 436,060 Class C Warrants to purchase 436,060 shares of New Common Stock; provided that to the extent such Allowed General Unsecured Claim is a Convenience Claim, such holder instead received its pro rata share of $10 million, which pro rata share shall not exceed five percent of such Convenience Claim.
•Participants in the Rights Offering extending to the applicable classes under the Plan received 62,927,320 shares of New Common Stock.
•In connection with the rights offering described above, the Backstop Parties under the Backstop Commitment Agreement received 6,337,031 shares of New Common Stock in respect to the Put Option Premium, and 442,991 shares of New Common Stock were excluded fromissued in connection with the calculationbackstop obligation thereunder to purchase unsubscribed shares of diluted EPS as the effect was antidilutive.New Common Stock.
•2,092,918 shares of New Common Stock and 3,948,893 Class C Warrants were reserved for future issuance to eligible holders of Allowed Unsecured Notes Claims and Allowed General Unsecured Claims.The reserved New Common Stock and Class C Warrants will be issued on a pro rata basis upon the
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  Years Ended December 31,
  2017 2016 2015
  (in millions)
Common stock equivalent of our preferred stock outstanding 60
 63
 113
Common stock equivalent of our convertible senior notes outstanding 146
 146
 —
Common stock equivalent of our preferred stock outstanding
prior to exchange
 1
 37
 —
Participating securities 1
 1
 1

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3.Debt
Our long-term debt consisteddetermination of the followingallowed portion of all disputed General Unsecured Claims and Unsecured Notes Claims.
•The 2021 Long Term Incentive Plan (the “LTIP”) was approved with a share reserve equal to 6,800,000 shares of New Common Stock.
•Each holder of an Allowed Other Secured Claim will receive, at the Company's option and in consultation with the Required Consenting Stakeholders (as defined in the Plan): (a) payment in full in cash; (b) the collateral securing its secured claim; (c) reinstatement of its secured claim; or (d) such other treatment that renders its secured claim unimpaired in accordance with Section 1124 of the Bankruptcy Code.
•Each holder of an Allowed Other Priority Claim (as defined in the Plan) will receive cash up to the allowed amount of its claim.
Additionally, pursuant to the Plan confirmed by the Bankruptcy Court, the Company’s post-emergence Board of Directors is comprised of seven directors, including the Company’s Chief Executive Officer, Domenic J. Dell’Osso Jr., the Company’s Executive Chairman, Michael Wichterich, and five non-employee directors, Timothy S. Duncan, Benjamin C. Duster, IV, Sarah Emerson, Matthew M. Gallagher and Brian Steck.
DIP and Exit Credit Facilities
On June 28, 2020, prior to the commencement of the Chapter 11 Cases, the Company entered into a commitment letter (the “Commitment Letter”) with certain of the lenders under the pre-petition revolving credit facility and/or their affiliates (collectively, the “Commitment Parties”), pursuant to which, and subject to the satisfaction of certain customary conditions, including the approval of the Bankruptcy Court, the Commitment Parties agreed to provide the Debtors with a post-petition senior secured super-priority debtor-in-possession revolving credit facility in an aggregate principal amount of up to approximately $2.104 billion (the “DIP Credit Facility”), consisting of a revolving loan facility of new money in an aggregate principal amount of up to $925 million, which includes a sub-facility of up to $200 million for the issuance of letters of credit, and an up to approximately $1.179 billion term loan that reflects the roll-up of a portion of outstanding borrowings under the pre-petition revolving credit facility. Pursuant to the Commitment Letter, the Commitment parties have also committed to provide, subject to certain conditions, an up to $2.5 billion exit credit facility, consisting of an up to $1.75 billion revolving credit facility (the “Exit Revolving Facility”) and an up to $750 million senior secured term loan facility (the “Exit Term Loan Facility” and, together with the Exit Revolving Facility, the “Exit Credit Facilities”). The terms and conditions of the DIP Credit Facility are set forth in the Senior Secured Super-Priority Debtor-in-Possession Credit Agreement (the “DIP Credit Agreement”) attached to the Commitment Letter. The proceeds of the DIP Credit Facility may be used for, among other things, post-petition working capital, permitted capital investments, general corporate purposes, letters of credit, administrative costs, premiums, expenses and fees for the transactions contemplated by the Chapter 11 Cases, payment of court approved adequate protection obligations, and other such purposes consistent with the DIP Credit Facility. On the Effective Date, the DIP Credit Facility was terminated and the holders of obligations under the DIP Credit Facility received payment in full in cash; provided that to the extent such lender under the DIP Credit Facility is also a lender under the Exit Revolver, such lender’s allowed DIP claims were first reduced dollar-for-dollar and satisfied by the amount of its Exit RBL Loans provided as of December 31, 2017 and 2016:the Effective Date.
 December 31, 2017 December 31, 2016
 
Principal
Amount
 Carrying
Amount		 Principal
Amount		 Carrying
Amount
 ($ in millions)
6.25% euro-denominated senior notes
due 2017
$—
 $—
 $258
 $258
6.5% senior notes due 2017—
 —
 134
 134
7.25% senior notes due 201844
 44
 64
 64
Floating rate senior notes due 2019380
 380
 380
 380
6.625% senior notes due 2020437
 437
 780
 780
6.875% senior notes due 2020227
 227
 279
 278
6.125% senior notes due 2021548
 548
 550
 550
5.375% senior notes due 2021267
 267
 270
 270
4.875% senior notes due 2022451
 451
 451
 451
8.00% senior secured second lien notes due 2022(a)
1,416
 1,895
 2,419
 3,409
5.75% senior notes due 2023338
 338
 338
 338
8.00% senior notes due 20251,300
 1,290
 1,000
 985
5.5% convertible senior notes due 2026(b)(c)(d)
1,250
 837
 1,250
 811
8.00% senior notes due 20271,300
 1,298
 —
 —
2.75% contingent convertible senior notes due 2035(d)
—
 —
 2
 2
2.5% contingent convertible senior notes due 2037(d)
—
 —
 114
 112
2.25% contingent convertible senior notes due 2038(b)(d)
9
 8
 200
 180
Term loan due 20211,233
 1,233
 1,500
 1,500
Revolving credit facility781
 781
 —
 —
Debt issuance costs—
 (63) —
 (64)
Interest rate derivatives—
 2
 —
 3
Total debt, net9,981
 9,973
 9,989
 10,441
Less current maturities of long-term debt, net(e)
(53) (52) (506) (503)
Total long-term debt, net$9,928
 $9,921
 $9,483
 $9,938
94

(a)The carrying amounts as of December 31, 2017 and 2016, include premium amounts of $479 million and $990 million, respectively, associated with a troubled debt restructuring. The premium is being amortized based on the effective yield method.
(b)We are required to account for the liability and equity components of our convertible debt instruments separately and to reflect interest expense through the first demand repurchase date, as applicable, at the interest rate of similar nonconvertible debt at the time of issuance. The applicable rates for our 2.25% Contingent Convertible Senior Notes due 2038 and our 5.5% Convertible Senior Notes due 2026 are 8.0% and 11.5%, respectively.
(c)The conversion and redemption provisions of our convertible senior notes are as follows:
Optional Conversion by Holders. Prior to maturity under certain circumstances and at the holder’s option, the notes are convertible. The notes may be converted into cash, our common stock, or a combination of cash and common stock, at our election. One triggering circumstance is when the price of our common stock exceeds
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


a threshold amount during a specified period
3.Fresh Start Accounting
Fresh Start Accounting
In connection with our emergence from bankruptcy and in a fiscal quarter. Convertibilityaccordance with ASC 852, we qualified for and applied fresh start accounting on the Effective Date. We were required to apply fresh start accounting because (i) the holders of existing voting shares of the Company prior to its emergence received less than 50% of the voting shares of the Company outstanding following its emergence from bankruptcy and (ii) the reorganization value of our assets immediately prior to confirmation of the Plan of approximately $6.8 billion was less than the post-petition liabilities and allowed claims of $13.2 billion.
In accordance with ASC 852, with the application of fresh start accounting, the Company allocated its reorganization value to its individual assets based on common stock pricetheir estimated fair value in conformity with FASB ASC Topic 820 - Fair Value Measurements and FASB ASC Topic 805 - Business Combinations. Accordingly, the consolidated financial statements after February 9, 2021 are not comparable with the consolidated financial statements as of or prior to that date. The Effective Date fair values of the Successor’s assets and liabilities differ materially from their recorded values as reflected on the historical balance sheet of the Predecessor.
Reorganization Value
Reorganization value is measured quarterly. Duringderived from an estimate of enterprise value, or fair value of the fourth quarterCompany’s interest-bearing debt and stockholders’ equity. Under ASC 852, reorganization value generally approximates fair value of 2017, the priceentity before considering liabilities and is intended to approximate the amount a willing buyer would pay for the assets immediately after the effects of our common stock was below the threshold level and, as a result, the holders do not have the option to convert their notesrestructuring. As set forth in the first quarter of 2018 under this provision. The notes are also convertible, atdisclosure statement, amended for updated pricing, and approved by the holder’s option, during specified five-day periods ifBankruptcy Court, the trading priceenterprise value of the notes isSuccessor was estimated to be between $3.5 billion and $4.9 billion. With the assistance of third-party valuation advisors, we determined the enterprise value and corresponding implied equity value of the Successor using various valuation approaches and methods, including: (i) income approach using a calculation of present value of future cash flows based on our financial projections, (ii) the market approach using selling prices of similar assets and (iii) the cost approach. For GAAP purposes, the Company valued the Successor’s individual assets, liabilities and equity instruments and determined an estimate of the enterprise value within the estimated range. Management concluded that the best estimate of enterprise value was $4.85 billion. Specific valuation approaches and key assumptions used to arrive at reorganization value, and the value of discrete assets and liabilities resulting from the application of fresh start accounting, are described below certain levels determined by reference toin greater detail within the trading pricevaluation process.
The enterprise value and corresponding implied equity value are dependent upon achieving the future financial results set forth in our valuation using an asset-based methodology of our common stock. The notes were not convertible under this provision during the year ended December 31, 2017. Upon conversion of a convertible senior note, the holder will receive cash, common stock orestimated proved reserves, undeveloped properties, and other financial information, considerations and projections, applying a combination of cashthe income, cost and common stock, atmarket approaches as of the fresh start reporting date of February 9, 2021. All estimates, assumptions, valuations and financial projections, including the fair value adjustments, the financial projections, the enterprise value and equity value projections, are inherently subject to significant uncertainties and the resolution of contingencies beyond our election, accordingcontrol. Accordingly, there is no assurance that the estimates, assumptions, valuations or financial projections will be realized, and actual results could vary materially.
The following table reconciles the enterprise value to the conversion rate specified in the indenture.
The common stock price conversion threshold amount for the convertible senior notes is 130%implied fair value of the conversion price of $8.568.
Optional Redemption by the Company. We may redeem the convertible senior notes for cash on or after September 15, 2019, if the price of our common stock exceeds 130%Successor’s equity as of the conversion price during a specified period at a redemption price of 100% of the principal amount of the notes.Effective Date:
Holders’ Demand Repurchase Rights. The holders of our convertible senior notes may require us to repurchase, in cash, all or a portion of their notes at 100% of the principal amount of the notes upon certain fundamental changes.
(d)The carrying amounts as of December 31, 2017 and 2016, are reflected net of discounts of $414 million and $461 million, respectively, associated with the equity component of our convertible and contingent convertible senior notes. This amount is being amortized based on the effective yield method through the first demand repurchase date as applicable.February 9, 2021
Enterprise value$4,851 
(e)
Plus: Cash and cash equivalents(a)
As48 
Less: Fair value of December 31, 2017, current maturities of long-term debt net includes our 7.25% Senior Notes due December 2018 and our 2.25% Contingent Convertible Notes due 2038 Notes.(1,313)
Successor equity value$3,586 
Debt maturities for the next five years and thereafter are as follows:____________________________________________
95
  
Principal Amount
of Debt Securities
  ($ in millions)
2018 $53
2019 1,161
2020 664
2021 2,048
2022 1,867
Thereafter 4,188
Total $9,981
Debt Issuances and Retirements - 2017
We issued through two private placements $1.300 billion aggregate principal amount of unsecured 8.00% Senior Notes due 2027 for net proceeds of approximately $1.285 billion. The first private placement was issued at par and the second private placement was issued at 99.75% of par. Some or all of the notes may be redeemed at any time prior to June 15, 2022, subject to a make-whole premium. We also may redeem some or all of the notes at any time on or after June 15, 2022, at the applicable redemption price in accordance with the terms of the notes and the indenture and supplemental indenture governing the notes. In addition, subject to certain conditions, we may redeem up to 35% of the aggregate principal amount of the notes at any time prior to June 15, 2020, at a price equal to 108% of the principal amount of the notes to be redeemed using the net proceeds of certain equity offerings.
We also issued in a private placement $300 million aggregate principal amount of additional 8.00% Senior Notes due 2025 (New 2025 Notes) at 101.25% of par for net proceeds of $301 million. The New 2025 Notes are an additional issuance of our outstanding 8.00% Senior Notes due 2025, which we issued in 2016 in an original aggregate principal amount of $1.0 billion at 98.52% of par. The New 2025 Notes issued and the previously issued senior notes due 2025 will be treated as a single class of notes under the indenture.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(a)Cash and cash equivalents includes $8 million that was initially classified as restricted cash as of the Effective Date but subsequently released from escrow and returned to the Successor. Restricted cash exclusive of the $8 million is not included in the table above.
We retired $2.389 billion principal amountThe following table reconciles the enterprise value to the reorganization value as of the Effective Date:
February 9, 2021
Enterprise value$4,851 
Plus: Cash and cash equivalents(a)
48 
Plus: Current liabilities1,582 
Plus: Asset retirement obligations (non-current portion)236 
Plus: Other non-current liabilities97 
Reorganization value of Successor assets$6,814 

(a)Cash and cash equivalents includes $8 million that was initially classified as restricted cash as of the Effective Date but subsequently released from escrow and returned to the Successor. Restricted cash exclusive of the $8 million is not included in the table above.
Valuation Process
The fair values of our outstanding senior notes, senior secured second lien notes, contingent convertible notesoil and term loan through purchases innatural gas properties, other property and equipment, other long-term assets, long-term debt, asset retirement obligations and warrants were estimated as of the open market, tender offers or repayment upon maturityEffective Date.
Oil and natural gas properties. The Company’s principal assets are its oil and natural gas properties, which are accounted for $2.592 billionunder the successful efforts accounting method. The Company determined the fair value of its oil and natural gas properties based on the discounted future net cash flows expected to be generated from these assets. Discounted cash flow models by operating area were prepared using proceeds from the issuances described above. Forestimated future revenues and operating costs for all proved developed properties and undeveloped properties comprising the open market repurchasesproved and tender offers, we recorded an net aggregate gain of approximately $233 million, including $374 million of premiumunproved reserves. Significant inputs associated with our 8.00% Senior Secured Second Lien Notes due 2022.the calculation of discounted future net cash flows include estimates of (i) recoverable reserves, (ii) production rates, (iii) future operating and development costs, (iv) future commodity prices escalated by an inflationary rate after five years, adjusted for differentials, and (v) a market-based weighted average cost of capital by operating area. The Company utilized NYMEX strip pricing, adjusted for differentials, to value the reserves. The NYMEX strip pricing inputs used are classified as Level 1 fair value assumptions and all other inputs are classified as Level 3 fair value assumptions. The discount rates utilized were derived using a weighted average cost of capital computation, which included an estimated cost of debt and equity for market participants with similar geographies and asset development type by operating area.
Debt IssuancesOther property and Retirements - 2016
During 2016, we issuedequipment. The fair value of other property and equipment such as buildings, land, computer equipment, and other equipment was determined using replacement cost method under the cost approach which considers historical acquisition costs for the assets adjusted for inflation, as well as factors in a private placement $1.0 billion principal amount of unsecured 8.00% Senior Notes due 2025 at a discount for net proceeds of approximately $975 million. Some or allany potential obsolescence based on the current condition of the notes may be redeemed at any time priorassets and the ability of those assets to January 15, 2020, subjectgenerate cash flow.
Long-term debt. A market approach, based upon quotes from major financial institutions, was used to a make-whole premium. In addition, we may redeem some or allmeasure the fair value of the notes at any time on or after January 15, 2020, at the applicable redemption price in accordance with the terms of the notes and the indenture and supplemental indenture governing the notes. In addition, subject to certain conditions, we may redeem up to 35% of the$500 million aggregate principal amount of the notes at any time prior to January 15, 2020, at a price equal to 108% of the principal amount of the notes to be redeemed using the net proceeds of certain equity offerings.
During 2016, we issued in a private placement $1.25 billion principal amount of unsecured 5.5% Convertible5.50% Senior Notes due 2026 at par for net proceeds of approximately $1.235 billion. The notes are convertible, under certain specified circumstances, into cash, common stock, or a combination of cash(the “2026 Notes”) and common stock, at our election. We accounted for the liability and equity components separately and reflected interest expense at the interest rate of similar nonconvertible debt at the time of issuance. The allocation to the equity component of the convertible notes was $445$500 million ($165 million tax expense). Additionally, debt issuance costs were allocated in proportion to the liability and equity components and accounted for as debt issuance costs and equity issuance costs, respectively. The accretion of the resulting discount on the debt is recognized through the convertible note’s maturity date as a component of interest expense, thereby increasing the amount of interest expense required to be recognized with respect to such instruments.
We retired $2.884 billionaggregate principal amount of our outstanding senior notes5.875% Senior Notes due 2029 (the “2029 Notes” and, contingent convertible senior notes through purchases in the open market, tender offers or repayment upon maturity for $2.734 billion. Additionally, we privately negotiated an exchange of approximately $577 million principal amount of our outstanding senior notes and contingent convertible senior notes for 109,351,707 common shares.
We recorded an aggregate net gain of approximately $236 million associatedtogether with the tender offers, debt repurchases and exchanges discussed above, which was net2026 Notes, the “Notes”). The carrying value of $26 million ($10 million tax benefit) associated with the equity component of the retired contingent convertible senior notes.
Senior Secured Second Lien Notes
Our second lien notes are secured second lien obligations and are effectively junior to our current and future secured first lien indebtedness, including indebtedness incurredborrowings under our revolving credit facilityExit Credit Facility approximated fair value as the terms and our term loan facility, to the extent of theinterest rates are based on prevailing market rates.
Asset retirement obligations. The fair value of the collateral securing such indebtedness, effectively seniorCompany’s asset retirement obligations was revalued based upon estimated current reclamation costs for our assets with reclamation obligations, an appropriate long-term inflation adjustment, and our revised credit adjusted risk-free rate. The credit adjusted risk-free rate was based on an evaluation of an interest rate that equates to alla risk-free interest rate adjusted for the effect of our existing and future unsecured indebtedness, including our outstanding senior notes, to the extent of the value of the collateral, and senior to any future subordinated indebtedness that we may incur. We have the option to redeem the second lien notes, in whole or in part, at specified make-whole or redemption prices. Our second lien notes are governed by an indenture containing covenants that may limit our ability and our subsidiaries’ ability to create liens securing certain indebtedness, enter into certain sale-leaseback transactions, consolidate, merge or transfer assets and dispose of certain collateral and use proceeds from dispositions of certain collateral. As a holding company, Chesapeake owns no operating assets and has no significant operations independent of its subsidiaries. Our obligations under the second lien notes are fully and unconditionally guaranteed, jointly and severally, by certain of our direct and indirect wholly owned subsidiaries.
Senior Notes, Contingent Convertible Senior Notes and Convertible Senior Notes
Our senior notes and our contingent convertible senior notes are unsecured senior obligations of Chesapeake and rank equally in right of payment with all of our other existing and future senior unsecured indebtedness and rank senior in right of payment to all of our future subordinated indebtedness. Our obligations under the senior notes and the contingent convertible senior notes are jointly and severally, fully and unconditionally guaranteed by certain of our direct and indirect wholly owned subsidiaries. See Note 19 for consolidating financial information regarding our guarantor and non-guarantor subsidiaries.credit standing.
96
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Warrants. The fair values of the Warrants issued upon the Effective Date were estimated using a Black-Scholes model, a commonly used option-pricing model. The Black-Scholes model was used to estimate the fair value of the warrants with an implied stock price of $20.52; initial exercise price per share of $27.63, $32.13 and $36.18 for Class A, Class B and Class C Warrants, respectively; expected volatility of 58% estimated using volatilities of similar entities; risk-free rate using a 5-year Treasury bond rate; and an expected annual dividend yield which was estimated to be zero.
Condensed Consolidated Balance Sheet
The following consolidated balance sheet is as of February 9, 2021. This consolidated balance sheet includes adjustments that reflect the consummation of the transactions contemplated by the Plan (reflected in the column “Reorganization Adjustments”) as well as fair value adjustments as a result of the adoption of fresh start accounting (reflected in the column “Fresh Start Adjustments”) as of the Effective Date. The explanatory notes following the table below provide further details on the adjustments, including the assumptions and methods used to determine fair value for its assets, liabilities and warrants.
PredecessorReorganization AdjustmentsFresh Start AdjustmentsSuccessor
Assets
Current assets:
Cash and cash equivalents$243 $(203)(a)$— $40 
Restricted cash— 86 (b)— 86 
Accounts receivable, net861 (18)(c)— 843 
Short-term derivative assets— — — — 
Other current assets66 (5)(d)— 61 
Total current assets1,170 (140)— 1,030 
Property and equipment:
Oil and natural gas properties, successful efforts method
Proved oil and natural gas properties25,794 — (21,108)(o)4,686 
Unproved properties1,546 — (1,063)(o)483 
Other property and equipment1,755 — (1,256)(o)499 
Total property and equipment29,095 — (23,427)(o)5,668 
Less: Accumulated depreciation, depletion and amortization(23,877)— 23,877 (o)— 
Property and equipment held for sale, net9 — (7)(o)2 
Total property and equipment, net5,227 — 443 (o)5,670 
Other long-term assets198 — (84)(p)114 
Total assets$6,595 $(140)$359 $6,814 
97
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
PredecessorReorganization AdjustmentsFresh Start AdjustmentsSuccessor
Liabilities and stockholders’ equity (deficit)
Current liabilities:
Accounts payable$391 $24 (e)$— $415 
Current maturities of long-term debt, net1,929 (1,929)(f)— — 
Accrued interest4 (4)(g)— — 
Short-term derivative liabilities398 — — 398 
Other current liabilities645 124 (h)— 769 
Total current liabilities3,367 (1,785)— 1,582 
Long-term debt, net— 1,261 (i)52 (q)1,313 
Long-term derivative liabilities90 — — 90 
Asset retirement obligations, net of current portion139 — 97 (r)236 
Other long-term liabilities5 2 (j)— 7 
Liabilities subject to compromise9,574 (9,574)(k)— — 
Total liabilities13,175 (10,096)149 3,228 
Contingencies and commitments (Note 7)
0000
Stockholders’ equity (deficit):
Predecessor preferred stock1,631 (1,631)(l)— — 
Predecessor common stock— — — — 
Predecessor additional paid-in capital16,940 (16,940)(l)— — 
Successor common stock— 1 (m)— 1 
Successor additional paid-in-capital— 3,585 (m)— 3,585 
Accumulated other comprehensive income48 — (48)(s)— 
Accumulated deficit(25,199)24,941 (n)258 (t)—��
Total stockholders’ equity (deficit)(6,580)9,956 210 3,586 
Total liabilities and stockholders’ equity (deficit)$6,595 $(140)$359 $6,814 
Reorganization Adjustments
(a)The table below reflects the sources and uses of cash on the Effective Date from implementation of the Plan:
Sources:
Proceeds from issuance of the Notes$1,000 
Proceeds from Rights Offering600 
Proceeds from refunds of interest deposit for the Notes5 
Total sources of cash$1,605 
Uses:
Payment of roll-up of DIP Facility balance$(1,179)
Payment of Exit Credit Facility - Tranche A Loan(479)
Transfers to restricted cash for professional fee reserve(76)
Transfers to restricted cash for convenience claim distribution reserve(10)
Payment of professional fees(31)
Payment of DIP Facility interest and fees(12)
Payment of FLLO alternative transaction fee(12)
Payment of the Notes fees funded out of escrow(8)
Payment of RBL interest and fees(1)
Total uses of cash$(1,808)
Net cash used$(203)
(b)Represents the transfer of funds to a restricted cash account for purposes of funding the professional fee reserve and the convenience claim distribution reserve.
(c)Reflects the removal of an insurance receivable associated with a discharged legal liability.
(d)Reflects the collection of an interest deposit for the senior unsecured notes.
(e)Changes in accounts payable include the following:
Accrual of professional service provider success fees$38 
Accrual of convenience claim distribution reserve10 
Accrual of professional service provider fees5 
Reinstatement of accounts payable from liabilities subject to compromise2 
Payment of professional fees(31)
Net impact to accounts payable$24 
(f)Reflects payment of the pre-petition credit facility for $1.179 billion and transfer of the Tranche A and Tranche B Loans to long-term debt for $750 million.
(g)Reflect payments of accrued interest and fees on the DIP Facility.
(h)Changes in other current liabilities include the following:
Reinstatement of other current liabilities from liabilities subject to compromise$191 
Accrual of the Notes fees2 
Settlement of Put Option Premium through issuance of Successor Common Stock(60)
Payment of DIP Facility fees(9)
Net impact to other current liabilities$124 
98
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(i)Changes in long-term debt include the following:
Issuance of the Notes$1,000 
Issuance of Tranche A and Tranche B Loans750 
Payments on Tranche A Loans(479)
Debt issuance costs for the Notes(10)
Net impact to long-term debt, net$1,261 
(j) Reflects reinstatement of a long-term lease liability.
(k) On the Effective Date, liabilities subject to compromise were settled in accordance with the Plan as follows:
Liabilities subject to compromise pre-emergence$9,574 
To be reinstated on the Effective Date:
Accounts payable$(2)
Other current liabilities(191)
Other long-term liabilities(2)
Total liabilities reinstated$(195)
Consideration provided to settle amounts per the Plan or Reorganization:
Issuance of Successor common stock associated with the Rights Offering and Backstop Commitment and settlement of the Put Option Premium$(2,311)
Proceeds from issuance of Successor common stock associated with the Rights Offering and Backstop Commitment600 
Issuance of Successor common stock to FLLO Term Loan holders, incremental to the Rights Offering and Backstop Commitment(783)
Issuance of Successor common stock to second lien note holders, incremental to the Rights Offering and Backstop Commitment(124)
Issuance of Successor common stock to unsecured note holders(45)
Issuance of Successor common stock to general unsecured claims(8)
Fair value of Class A Warrants(93)
Fair value of Class B Warrants(94)
Fair value of Class C Warrants(68)
Proceeds to holders of general unsecured claims(10)
Total consideration provided to settle amounts per the Plan$(2,936)
Gain on settlement of liabilities subject to compromise$6,443 
(l)Pursuant to the Plan, as of the Effective Date, all equity interests in Predecessor, including Predecessor’s common and preferred stock, were canceled without any distribution.
99
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(m)Reflects the Successor equity including the issuance of 97,907,081 shares of New Common Stock, 11,111,111 shares of Class A Warrants, 12,345,679 shares of Class B Warrants and 9,768,527 shares of Class C Warrants pursuant to the Plan.
Issuance of Successor equity associated with the Rights Offering and Backstop Commitment$2,371 
Issuance of Successor equity to holders of the FLLO Term Loan, incremental to the Rights Offering and Backstop Commitment783 
Issuance of Successor equity to holders of the Second Lien Notes, incremental to the Rights Offering and Backstop Commitment124 
Issuance of Successor equity to holders of the unsecured senior notes45 
Issuance of Successor equity to holders of allowed general unsecured claims8 
Fair value of Class A warrants93 
Fair value of Class B warrants94 
Fair value of Class C warrants68 
Total change in Successor common stock and additional paid-in capital3,586 
Less: Par value of Successor common stock(1)
Change in Successor additional paid-in capital$3,585 
(n) Reflects the cumulative net impact of the effects on accumulated deficit as follows:
Gain on settlement of liabilities subject to compromise$6,443 
Accrual of professional service provider success fees(38)
Accrual of professional service provider fees(5)
Surrender of other receivable(18)
Payment of FLLO alternative transaction fee(12)
Total reorganization items, net6,370 
Cancellation of predecessor equity18,571 
Net impact on accumulated deficit$24,941 
Fresh Start Adjustments
(o)Reflects fair value adjustments to our (i) proved oil and natural gas properties, (ii) unproved properties, (iii) other property and equipment and (iv) property and equipment held for sale, and the elimination of accumulated depletion, depreciation and amortization.
(p)Reflects the fair value adjustment to record historical contracts at their fair values.
(q)Reflects the fair value adjustments to the 2026 Notes and 2029 Notes for $22 million and $30 million, respectively.
(r)Reflects the adjustment to our asset retirement obligations using assumptions as of the Effective Date, including an inflation factor of 2% and an average credit-adjusted risk-free rate of 5.18%.
(s)Reflects the fair value adjustment to eliminate the accumulated other comprehensive income of $9 million related to hedging settlements offset by the elimination of $57 million of income tax effects which has resulted in the recording of an income tax benefit of $57 million. See Note 11 for a discussion of income taxes.
100
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(t)Reflects the net cumulative impact of the fresh start adjustments on accumulated deficit as follows:
Fresh start adjustments to property and equipment$443 
Fresh start adjustments to other long-term assets(84)
Fresh start adjustments to long-term debt(52)
Fresh start adjustments to long-term asset retirement obligations(97)
Fresh start adjustments to accumulated other comprehensive income(9)
Total fresh start adjustments impacting reorganizations items, net201 
Income tax effects on accumulated other comprehensive income57 
Net impact to accumulated deficit$258 
Reorganization Items, Net
We have incurred significant expenses, gains and losses associated with the reorganization, primarily the gain on settlement of liabilities subject to compromise, write-off of unamortized debt issuance costs and related unamortized premiums and discounts, debt and equity financing fees, provision for allowed claims and legal and professional fees incurred subsequent to the Chapter 11 filings for the restructuring process. The accrual for allowed claims primarily represents damages from contract rejections and settlements attributable to the midstream savings requirement as stipulated in the Plan. While the claims reconciliation process is ongoing, we do not believe any existing unresolved claims will result in a material adjustment to the financial statements. The amount of these items, which were incurred in reorganization items, net within our accompanying consolidated statements of operations, have significantly affected our statements of operations.
The following table summarizes the components in reorganization items, net included in our consolidated statements of operations:
SuccessorPredecessor
Period from February 10, 2021 through December 31, 2021Period from January 1, 2021 through February 9, 2021Year Ended December 31, 2020Year Ended December 31, 2019
Gains on the settlement of liabilities subject to compromise$— $6,443 $12 $— 
Accrual for allowed claims— (1,002)(879)— 
Write off of unamortized debt premiums (discounts) on Predecessor debt— — 518 — 
Write off of unamortized debt issuance costs on Predecessor debt— — (61)— 
Gain on fresh start adjustments— 201 — — 
Gain from release of commitment liabilities— 55 — — 
Debt and equity financing fees— —��(145)— 
Loss on divested assets— — (128)— 
Professional service provider fees and other— (60)(113)— 
Success fees for professional service providers— (38)— — 
Surrender of other receivable— (18)— — 
FLLO alternative transaction fee— (12)— — 
Total reorganization items, net$— $5,569 $(796)$— 

101
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
4.Oil and Natural Gas Property Transactions
Vine Acquisition
On November 1, 2021, we acquired Vine Energy, Inc. (“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 pursuant to a definitive agreement with Vine dated August 10, 2021, for total consideration of approximately $1.5 billion, consisting of approximately 18.7 million shares of our common stock and $90 million in cash. 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 acquisition. Additionally, Vine’s 6.75% Senior Notes with a principal amount of $950 million were assumed by the Company. See Note 6 for additional discussion of the assumed debt. We funded the cash portion of the consideration with cash on hand.
Preliminary Vine Purchase Price Allocation
We have accounted for the acquisition of Vine as a business combination, using the acquisition method. The following table represents the preliminary allocation of the total purchase price of Vine to the identifiable assets acquired and the liabilities assumed based on the fair values as of the acquisition date. Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, valuation of pre-acquisition contingencies, final tax returns that provide the underlying tax basis of Vine’s assets and liabilities and final appraisals of assets acquired and liabilities assumed. We expect to complete the purchase price allocation during the 12-month period following the acquisition date, during which time the value of the assets and liabilities may redeembe revised as appropriate.
102
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Preliminary
Purchase Price Allocation
Consideration:
Cash$253 
Fair value of Chesapeake’s common stock issued in the merger1,231 
Restricted stock unit replacement awards6 
Total consideration$1,490 
Fair Value of Liabilities Assumed:
Current liabilities$765 
Long-term debt1,021 
Deferred tax liabilities49 
Other long-term liabilities272 
Amounts attributable to liabilities assumed$2,107 
Fair Value of Assets Acquired:
Cash and cash equivalents$59 
Other current assets206 
Proved oil and natural gas properties2,181 
Unproved properties1,118 
Other property and equipment1 
Other long-term assets32 
Amounts attributable to assets acquired$3,597 
Total identifiable net assets$1,490 
Oil and Natural Gas Properties
For the senior notes,Vine Acquisition, we applied applicable guidance, under which an acquirer should recognize the identifiable assets acquired and the liabilities assumed on the acquisition date at fair value. The fair value estimate of proved and unproved oil and natural gas properties as of the acquisition date was based on estimated oil and natural gas reserves and related future net cash flows discounted using a weighted average cost of capital, including estimates of future production rates and future development costs. We utilized NYMEX strip pricing adjusted for inflation to value the reserves. We then applied various discount rates depending on the classification of reserves and other thanrisk characteristics. Management utilized the assistance of a third-party valuation expert to estimate the value of the oil and natural gas properties acquired. Additionally, the fair value estimate of proved and unproved oil and natural gas properties was corroborated by utilizing the market approach, which considers recent comparable transactions for similar assets.
The inputs used to value oil and natural gas properties require significant judgment and estimates made by management and represent Level 3 inputs.
Financial Instruments and Other
The fair value measurements of long-term debt were estimated based on a market approach using estimates provided by an independent investment data services firm and represent Level 2 inputs.
Restricted Stock Unit Replacement Awards
Included in consideration for the Vine Acquisition is approximately $6 million related to pre-combination service recognized on Vine’s restricted stock unit awards. For restricted stock units that were accelerated or transitioned at
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the time of the merger, we recognized expense for the portion of the award that was accelerated and included in consideration the portion of the award related to pre-combination service.
Vine Revenues and Expenses Subsequent to Acquisition
We included in our consolidated statements of operations oil, natural gas and NGL revenues of $290 million, net gains on oil and natural gas derivatives of $144 million, direct operating expenses of $177 million, including depreciation, depletion and amortization, and other expense of $12 million related to the Vine business for the period from November 1, 2021 to December 31, 2021.
Vine Pro Forma Financial Information
The following unaudited pro forma financial information for the 2021 Successor Period is based on our historical consolidated financial statements adjusted to reflect as if the Vine Acquisition had occurred on February 10, 2021. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including adjustments to conform the classification of expenses in Vine’s statements of operations to our classification for similar expenses and the estimated tax impact of pro forma adjustments.
Successor
Period from February 10, 2021 through December 31, 2021
Revenues$5,448 
Net income available to common stockholders$128 
Earnings per common share:
Basic$1.09 
Diluted$0.97 
Mid-Continent Divestiture
On October 13, 2020, we filed a notice with the Bankruptcy Court that we reached an agreement with Tapstone Energy in a Section 363 transaction under the Bankruptcy Code. An auction supervised by the Bankruptcy Court was held on November 10, 2020 in which other pre-qualified buyers submitted bids for the asset. We presented the results of the auction process to the Bankruptcy Court and the sale was approved on November 13, 2020. On December 11, 2020, we closed the transaction with Tapstone Energy for $130 million, subject to post-closing adjustments which resulted in the recognition of a gain of approximately $27 million.
Haynesville Exchange
On November 22, 2020, we filed notice with the Bankruptcy Court that we had reached an agreement with Williams Companies to transfer certain Haynesville assets, including interests in 144 producing wells and approximately 50,000 net acres, in exchange for improved midstream contract terms with respect to assets we retained. On December 15, 2020, the Court approved the transaction with Williams Companies and the exchange resulted in the recognition of loss of approximately $128 million based on the difference between the carrying value of the assets and the fair value of the assets surrendered. The exchange was executed to obtain sufficient savings on midstream obligations as required by the Plan. Therefore, the loss was recorded to reorganization items, net in our consolidated statements of operations.
WildHorse Acquisition
On February 1, 2019, we acquired WildHorse Resource Development Corporation (“WildHorse”), an oil and gas company with operations in the Eagle Ford Shale and Austin Chalk formations in southeast Texas, for approximately 3.6 million shares of our reverse stock split adjusted Predecessor common stock and $381 million in cash. We funded the cash portion of the consideration through borrowings under the pre-petition revolving credit facility. In connection with the closing, we acquired all of WildHorse’s debt.
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WildHorse Purchase Price Allocation
We have accounted for the acquisition of WildHorse and its corresponding merger with and into our wholly owned subsidiary, Brazos Valley Longhorn, L.L.C. (“Brazos Valley Longhorn” or “BVL”), as a business combination, using the acquisition method. The following table represents the final allocation of the total purchase price of WildHorse to the identifiable assets acquired and the liabilities assumed based on the fair values as of the acquisition date.
Purchase Price Allocation
Consideration:
Cash$381 
Fair value of Chesapeake’s common stock issued in the merger2,037 
Total consideration$2,418 
Fair Value of Liabilities Assumed:
Current liabilities$166 
Long-term debt1,379 
Deferred tax liabilities314 
Other long-term liabilities36 
Amounts attributable to liabilities assumed$1,895 
Fair Value of Assets Acquired:
Cash and cash equivalents$28 
Other current assets128 
Proved oil and natural gas properties3,264 
Unproved properties756 
Other property and equipment77 
Other long-term assets60 
Amounts attributable to assets acquired$4,313 
Total identifiable net assets$2,418 
Oil and Natural Gas Properties
For the acquisition of WildHorse, we applied applicable guidance, under which an acquirer should recognize the identifiable assets acquired and the liabilities assumed on the acquisition date at fair value. The fair value estimate of proved and unproved oil and natural gas properties as of the acquisition date was based on estimated oil and natural gas reserves and related future net cash flows discounted using a weighted average cost of capital, including estimates of future production rates and future development costs. Management utilized the assistance of a third-party valuation expert to estimate the value of the oil and natural gas properties acquired. Additionally, the fair value estimate of proved and unproved oil and natural gas properties was corroborated by utilizing the market approach which considers recent comparable transactions for similar assets.
The inputs used to value oil and natural gas properties require significant judgment and estimates made by management and represent Level 3 inputs.
Financial Instruments and Other
The fair value measurements of long-term debt were estimated based on a market approach using estimates provided by an independent investment data services firm and represent Level 2 inputs.
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WildHorse Revenues and Expenses Subsequent to Acquisition
We included in our consolidated statements of operations revenues of $752 million, direct operating expenses of $810 million, including depreciation, depletion and amortization, and other expense of $83 million related to the WildHorse business for the period from February 1, 2019 to December 31, 2019.
WildHorse Pro Forma Financial Information
The following unaudited pro forma financial information for the years ended December 31, 2019 and 2018, respectively, is based on our historical consolidated financial statements adjusted to reflect as if the WildHorse acquisition had occurred on January 1, 2018. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including adjustments to conform the classification of expenses in WildHorse’s statements of operations to our classification for similar expenses and the estimated tax impact of pro forma adjustments.
Predecessor
Years Ended December 31,
20192018
Revenues$8,587 $11,211 
Net income (loss) available to common stockholders$(431)$195 
Earnings (loss) per common share:
Basic$(51.77)$42.89 
Diluted$(51.77)$42.89 
This unaudited pro forma information has been derived from historical information. The unaudited pro forma financial information is not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the periods presented, nor is it necessarily indicative of future results.
2019 Transactions
In 2019, we received proceeds of approximately $130 million, net of post-closing adjustments, and recognized a gain of approximately $46 million, primarily for the sale of non-core oil and natural gas properties.

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5.Earnings Per Share
Basic earnings (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted earnings (loss) per common share is calculated in the same manner, but includes the impact of potentially dilutive securities. Potentially dilutive securities during the Successor Period consist of issuable shares related to warrants, unvested restricted stock units, and unvested performance share units and during the Predecessor Period have historically consisted of unvested restricted stock, contingently issuable shares related to preferred stock and convertible senior notes unless their effect was antidilutive.
The reconciliations between basic and diluted earnings (loss) per share are as follows:
SuccessorPredecessor
Period from February 10, 2021 through December 31, 2021Period from January 1, 2021 through February 9, 2021Year Ended
December 31, 2020		Year Ended
December 31, 2019
Numerator
Net income (loss), basic and diluted$945 $5,383 $(9,756)$(416)
Denominator (in thousands)
Weighted average common shares outstanding, basic101,754 9,781 9,773 8,325 
Effect of potentially dilutive securities
Preferred stock— 290 — — 
Warrants14,376 — — — 
Restricted stock200 — — — 
Performance share units11 — — — 
Weighted average common shares outstanding, diluted116,341 10,071 9,773 8,325 
Earnings (loss) per common share
Earnings (loss) per common share, basic$9.29 $550.35 $(998.26)$(49.97)
Earnings (loss) per common share, diluted$8.12 $534.51 $(998.26)$(49.97)
Successor
During the 2021 Successor Period, the diluted earnings (loss) per share calculation excludes the effect of 1,228,828 reserved shares of common stock and 2,318,446 reserved Class C Warrants related to the settlement of General Unsecured Claims associated with the Chapter 11 Cases as all necessary conditions had not been met to be considered dilutive shares for the 2021 Successor Period.
Predecessor
The diluted earnings (loss) per share calculation for the 2020 Predecessor Period excludes the antidilutive effect of 290,716 shares of common stock equivalent of our preferred stock.
The diluted earnings (loss) per share calculation for the 2019 Predecessor Period excludes the antidilutive effect of 295,731 shares of common stock equivalent of our preferred stock and 2,210 shares of restricted stock.
We had the option to settle conversions of the 5.50% convertible senior notes due 2026 with cash, shares or common stock or any combination thereof. As the price of our common stock was below the conversion threshold level for any time during the conversion period, there was no impact to diluted earnings (loss) per share.

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6.Debt
Our long-term debt consisted of the following as of December 31, 2021 and 2020:
SuccessorPredecessor
December 31, 2021December 31, 2020
Carrying Amount
Fair Value(a)
Carrying Amount
Fair Value(a)
Exit Credit Facility - Tranche A Loans$— $— $— $— 
Exit Credit Facility - Tranche B Loans221 221 — — 
5.50% senior notes due 2026500 526 — — 
5.875% senior notes due 2029500 535 — — 
6.75% senior notes due 2029(b)
950 1,031 — — 
DIP Facility— — — — 
Pre-petition revolving credit facility— — 1,929 1,929 
Term loan due 2024— — 1,500 1,220 
11.50% senior secured second lien notes due 2025— — 2,330 373 
6.625% senior notes due 2020— — 176 8 
6.875% senior notes due 2020— — 73 3 
6.125% senior notes due 2021— — 167 7 
5.375% senior notes due 2021— — 127 5 
4.875% senior notes due 2022— — 272 12 
5.75% senior notes due 2023— — 167 8 
7.00% senior notes due 2024— — 624 29 
6.875% senior notes due 2025— — 2 2 
8.00% senior notes due 2025— — 246 10 
5.50% convertible senior notes due 2026— — 1,064 42 
7.50% senior notes due 2026— — 119 5 
8.00% senior notes due 2026— — 46 2 
8.00% senior notes due 2027— — 253 11 
Premiums on senior notes116 — — — 
Debt issuance costs(9)— — — 
Total debt, net2,278 2,313 9,095 3,666 
Less current maturities of long-term debt, net— — (1,929)(1,929)
Less amounts reclassified to liabilities subject to compromise— — (7,166)(1,737)
Total long-term debt, net$2,278 $2,313 $— $— 

(a)The carrying value of borrowings under our Exit Credit Facility approximate fair value as the interest rates are based on prevailing market rates; therefore, they are a Level 1 fair value measurement. For all other debt, a market approach, based upon quotes from major financial institutions, which are Level 2 inputs, is used to measure the fair value.
(b)On November 1, 2021, we acquired the debt of Vine, which consisted of 6.75% senior notes due 2029. See further discussion below.

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Successor Debt
Our post-emergence exit financing consists of the Exit Credit Facility, which includes a reserve-based revolving credit facility and a non-revolving loan facility, and the Notes.
Exit Credit Facility. 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 a reserve-based credit facility with 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 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 three years after the Effective Date and the Tranche B Loans mature four years after the Effective Date. The Tranche B Loans can be repaid if no Tranche A Loans are outstanding.
The Credit Agreement contains financial covenants that require the Company and its guarantors, on a consolidated basis, to maintain (i) a first lien leverage ratio of not more than 2.75 to 1:00, (ii) a total leverage ratio of not more than 3.50 to 1:00, (iii) a current ratio of not less than 1.00 to 1:00 and (iv) at any time additional secured debt is outstanding, an asset coverage ratio of not less than 1.50 to 1:00, defined as PV10 of PDP reserves to total secured debt.The Company has no additional secured debt outstanding as of December 31, 2021.
The Credit Agreement also contains customary affirmative and negative covenants, including, among other things, as to compliance with laws (including environmental laws and anti-corruption laws), delivery of quarterly and annual financial statements, conduct of business, maintenance of property, maintenance of insurance, restrictions on the incurrence of liens, indebtedness, asset dispositions, fundamental changes, restricted payments, and other customary covenants.
The Company is required to pay a commitment fee of 0.50% per annum on the average daily unused portion of the current aggregate commitments under the Tranche A Loans. The Company is also required to pay customary letter of credit and fronting fees.
Outstanding Senior Notes. On February 2, 2021, Chesapeake Escrow Issuer LLC, then an indirect wholly owned subsidiary of the Company, issued $500 million aggregate principal amount of its 2026 Notes and $500 million aggregate principal amount of its 2029 Notes. The Notes included a $52 million premium to reflect fair value adjustments at specified make-whole or redemption prices. Ourthe date of emergence.
The Notes are guaranteed on a senior unsecured basis by each of the Company’s subsidiaries that guarantee the Exit Credit Facility.
The Notes were issued pursuant to an indenture, dated as of February 5, 2021, among the Issuer, the Guarantors and Deutsche Bank Trust Company Americas, as trustee.
Interest on the Notes is payable semi-annually, on February 1 and August 1 of each year, commencing on August 1, 2021, to holders of record on the immediately preceding January 15 and July 15.
The Notes are the Company’s senior unsecured obligations. Accordingly, they rank (i) equal in right of payment to all existing and future senior indebtedness, including borrowings under the Exit Credit Facility, (ii) effectively subordinate in right of payment to all of existing and future secured indebtedness, including indebtedness under the Exit Credit Facility, to the extent of the value of the collateral securing such indebtedness, (iii) structurally subordinate in right of payment to all existing and future indebtedness and other liabilities of any future subsidiaries that do not guarantee the Notes and any entity that is not a subsidiary that does not guarantee the Notes and (iv) senior in right of payment to all future subordinated indebtedness. Each guarantee of the Notes by a guarantor is a general, unsecured, senior obligation of such guarantor. Accordingly, the guarantees (i) rank equally in right of payment with all existing and future senior indebtedness of such guarantor (including such guarantor’s guarantee of indebtedness under the Exit Credit Facility), (ii) are subordinated to all existing and future secured indebtedness of
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such guarantor, including such guarantor’s guarantee of indebtedness under our Exit Credit Facility, to the extent of the value of the collateral of such guarantor securing such secured indebtedness, (iii) are structurally subordinated to all indebtedness and other liabilities of any future subsidiaries of such guarantor that do not guarantee the notes and (iv) rank senior in right of payment to all future subordinated indebtedness of such guarantor.
Vine Senior Notes
As a result of the completion of the Vine Acquisition, the Company and certain of its subsidiaries entered into a supplemental indenture pursuant to which the Company assumed the obligations under Vine’s $950 million aggregate principal amount of 6.75% senior notes due 2029 (the “Vine Notes”) issued under the indenture dated April 7, 2021 with Wilmington Trust, National Association, as Trustee (the “Vine Indenture”). The Vine Notes included a $71 million premium to reflect fair value adjustments at the date of acquisition.
The Company and certain of its subsidiaries have agreed to guarantee such obligations under the Vine Indenture. Additionally, certain subsidiaries of Vine entered into a supplemental indenture to the Company’s existing indenture, dated February 5, 2021 with Deutsche Bank Trust Company Americas as trustee (the “CHK Indenture”), pursuant to which such subsidiaries of Vine have agreed to guarantee obligations under the CHK Indenture.
Interest on the Vine Notes is payable semi-annually, on April 15 and October 15 of each year to holders of record on the immediately preceding April 1 and October 1. Our first interest payment will be on April 15, 2022.
Phase-Out of LIBOR
In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848). The purpose of ASU 2020-04 is to provide optional guidance to ease the potential effects on financial reporting of the market-wide migration away from Interbank Offered Rates such as LIBOR, which is no longer being used on new loans as of December 31, 2021, to alternative reference rates. ASU 2020-04 applies only to contracts, hedging relationships, debt arrangements and other transactions that reference a benchmark reference rate expected to be discontinued because of reference rate reform. The amendments in ASU 2020-04 are governed by indentures containing covenants that may limiteffective for all entities as of March 12, 2020 through December 31, 2022. The adoption of this guidance will not have a material impact on our abilityconsolidated financial statements and related disclosures.
Chapter 11 Proceedings - Predecessor Debt
Filing of the Chapter 11 Cases constituted an event of default with respect to certain of our subsidiaries’ ability to incur certainprevious secured indebtedness, enter into sale-leaseback transactions, and consolidate, merge or transfer assets. unsecured debt obligations. As a result of the Chapter 11 Cases, the principal and interest due under these debt instruments became immediately due and payable. However, Section 362 of the Bankruptcy Code stayed the creditors from taking any action as a result of the default.
The indentures governingprincipal amounts outstanding under the FLLO Term Loan, Second Lien Notes and all of our other unsecured senior notes and the convertible senior notes do not have any financial or restricted payment covenants. Indentureswere reclassified as liabilities subject to compromise on the accompanying consolidated balance sheet as of December 31, 2020.
The agreements for our FLLO Term Loan, Second Lien Notes, and unsecured senior and convertible senior notes contained provisions regarding the calculation of interest upon default. Upon default, the interest rate on the FLLO Term Loan increased from LIBOR plus 8.00% to alternative base rate (ABR) (3.25% during the fourth quarter of the 2020 Predecessor Period) plus Applicable Margin (7.00% during the fourth quarter of the 2020 Predecessor Period) plus 2.00%. For the Second Lien Notes and all of our other unsecured senior notes and convertible senior notes, have cross default provisions that applythe interest rate remained the same upon default. However, interest accrued on the amount of unpaid interest in addition to other indebtedness Chesapeakethe principal balance. We did not pay or any guarantor subsidiary may have from timerecognize interest on the FLLO Term Loan, Second Lien Notes, or unsecured senior and convertible senior notes during the Chapter 11 process.
Debtor-in-Possession Credit Agreement
On June 28, 2020, prior to timethe commencement of Chapter 11 Cases, the Company entered into a commitment letter with certain of the lenders (“New Money Lenders”) under the pre-petition revolving credit facility and/or their affiliates to provide the Debtors with a debtor-in-possession credit agreement in an outstandingaggregate principal amount of up to approximately $2.104 billion in commitments and loans from the New Money Lenders. The DIP Facility consisted of a revolving loan facility of new money in an aggregate principal amount of up to $925 million, which included a sub-facility of up to $200 million for the issuance of letters of credit, and a $1.179 billion term loan that
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reflected the roll-up of a portion of outstanding borrowings under the pre-petition revolving credit facility: (i) a $925 million term loan reflected the roll-up of a portion of outstanding existing borrowings made by the New Money Lenders under the existing revolving credit agreement and (ii) an up to approximately $254 million term loan reflected the roll-up or a portion of outstanding existing borrowings made by certain other lenders under the pre-petition revolving credit facility agreement. The $750 million of outstanding borrowings under the pre-petition revolving credit facility that were not rolled up remained outstanding throughout the Chapter 11 Cases but accrued interest at least $50a lower rate than the rolled-up loans. The proceeds of the DIP Facility were used for, among other things, post-petition working capital, permitted capital investments, general corporate purposes, letters of credit, administrative costs, premiums, expenses and fees for the transactions contemplated by the Chapter 11 Cases, payment of court approved adequate protection obligations and other such purposes consistent with the DIP Facility. On the Effective Date, the DIP Facility was terminated and the holders of obligations under the DIP Facility received payment in full in cash; provided that to the extent such lender under the DIP Facility was also a lender under the Exit Credit Facility, such lender’s allowed DIP claims were first reduced dollar-for-dollar and satisfied by the amount of its Exit RBL Loans provided as of the Effective Date.
Predecessor Debt Issuances and Retirements 2020
In the 2020 Predecessor Period, we repurchased approximately $160 million or $75aggregate principal amount of the following senior notes for $95 million depending on the indenture.and recorded an aggregate gain of approximately $65 million.
Term Loan Facility
Notes Repurchased
6.625% senior notes due 2020$32 
6.875% senior notes due 202020 
4.875% senior notes due 202266 
5.75% senior notes due 202342 
Total$160 
We havePredecessor Debt 2019
In December 2019, we entered into a secured five-year4.5-year term loan facility in an aggregate principal amount of $1.233$1.5 billion asfor net proceeds of December 31, 2017. approximately $1.455 billion. We used the net proceeds to finance tender offers for our unsecured BVL senior notes and to repay amounts outstanding under our BVL revolving credit facility. We recorded an aggregate net gain of approximately $4 million associated with the retirement of our BVL senior notes and the BVL revolving credit facility.
We privately negotiated exchanges of approximately $507 million principal amount of our outstanding senior notes for 235,563,519 shares of common stock and $186 million principal amount of our outstanding convertible senior notes for 73,389,094 shares of common stock. We recorded an aggregate net gain of approximately $64 million associated with the exchanges.
Pre-Petition Revolving Credit Facility
Our obligationspre-petition revolving credit facility was scheduled to mature in September 2023 and the aggregate commitment of the lenders and borrowing base under the facility are unconditionally guaranteed on a joint and several basis by the same subsidiaries that guarantee ourwas $3.0 billion. The pre-petition revolving credit facility second lien notes and senior notes and are secured by first-priority liens onprovided for an accordion feature, pursuant to which the same collateral securing our revolving credit facility (with a position in the collateral proceeds waterfall junioraggregate commitments thereunder may be increased to the revolving credit facility). The term loan bears interest at a rate of London Interbank Offered Rate (LIBOR) plus 7.50% per annum,up to $4.0 billion from time to time, subject to a 1.00% LIBOR floor, or the Alternative Base Rate (ABR) plus 6.50% per annum, subject to a 2.00% ABR floor, at our option. The term loan matures in August 2021 and voluntary prepayments are subject to a make-whole premium prior to the second anniversaryagreement of the closing of the term loan, a premium to par of 4.25% from the second anniversary until but excluding the third anniversary, a premium to par of 2.125% from the third anniversary until but excluding the fourth anniversaryparticipating lenders and at par beginning on the fourth anniversary. The term loan may be subject to mandatory prepayments and offers to purchase with net cash proceeds of certain issuances of debt, certain asset sales and other dispositions of collateral and upon a change of control.
The term loan contains covenants limiting our ability to incur additional indebtedness, incur liens, consummate mergers and similar fundamental changes, make restricted payments, sell collateral and use proceeds from such sales, make investments, repay certain subordinate, unsecured or junior lien indebtedness, and enter into transactions with affiliates.
Revolving Credit Facility
We have a senior secured revolving credit facility currently subject to a $3.8 billion borrowing base that matures in December 2019.customary conditions. As of December 31, 2017,2020, we had outstanding borrowings of $781 million$1.929 billion under theour pre-petition revolving credit facility and had used $116$54 million of the revolving credit facility for various letters of credit.
Borrowings under theour pre-petition revolving credit facility bearbore interest at a variable rate.an alternative base rate (ABR) or LIBOR, at our election, plus an applicable margin ranging from 1.50%-2.50% per annum for ABR loans and 2.50%-3.50% per annum for LIBOR loans, depending on the percentage of the borrowing base then being utilized.
Our pre-petition revolving credit facility was subject to various financial and other covenants. The terms of the pre-petition revolving credit facility includeincluded covenants limiting, among other things, our ability to incur additional
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indebtedness, make investments or loans, createincur liens, consummate mergers and similar fundamental changes, make restricted payments, make investments in unrestricted subsidiaries and enter into transactions with affiliates.
In the fourth quarter of 2017, we completed a scheduled borrowing base redetermination review and our lenders reaffirmed our $3.8 billion borrowing base. Our next borrowing base redetermination is scheduled for the second quarter of 2018.
We entered into a third amendment to our revolving credit facility in 2016, and a fourth amendment in 2017. After giving effect to those amendments, our revolving credit facility currently requires that we maintain a net debt to capitalization ratio of not greater than 65%, a first lien secured leverage ratio of not more than 3.50 to 1.0 on December 31, 2017 and 3.00 to 1.0 thereafter and an interest coverage ratio of at least 1.25 to 1.0. In the third amendment, we agreed to grant liens and security interests on a majority of our assets. The third amendment also gave us the ability to incur first lien indebtedness on a pari passu basis with the existing obligations under the credit agreement, subject to a position in the collateral proceeds waterfall in favor of the revolving lenders and affiliated hedge providers and the other limitations on junior lien debt set forth in the credit agreement. The amount of such additional first lien indebtedness currently permitted by the revolving credit facility is $1.3 billion.
TABLE OF CONTENTS
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

As of December 31, 2017, we were in compliance with all applicable financial covenants under the credit agreement and we were able to borrow up to the full availability under the revolving credit facility.
Fair Value of Debt
We estimate the fair value of our senior notes based on the market value of our publicly traded debt as determined based on the yield of our senior notes (Level 1). The fair value of all other debt is based on a market approach using estimates provided by an independent investment financial data services firm (Level 2). Fair value is compared to the carrying value, excluding the impact of interest rate derivatives, in the table below:
  December 31, 2017 December 31, 2016
  
Carrying
Amount
 
Estimated
Fair Value
 
Carrying
Amount
 
Estimated
Fair Value
    ($ in millions)  
Short-term debt (Level 1) $52
 $53
 $503
 $511
Long-term debt (Level 1) $2,633
 $2,629
 $3,271
 $3,216
Long-term debt (Level 2) $7,286
 $7,301
 $6,664
 $6,654
4.7.Contingencies and Commitments
Contingencies
Chapter 11 Proceedings
Commencement of the Chapter 11 Cases automatically stayed the proceedings and actions against us that are described 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 for additional information.
Litigation and Regulatory Proceedings
We arewere involved in a number of litigation and regulatory proceedings including those described below.as of the Petition Date. Many of these proceedings arewere in early stages, and many of them seek or may seeksought damages and penalties, the amount of which is indeterminate. Our total accrued liability in respect of litigation and regulatory proceedings is determined on a case-by-case basis and represents an estimate of probable losses after considering, among other factors, the progress of each case or proceeding, our experience and the experience of others in similar cases or proceedings, and the opinions and views of legal counsel. Significant judgment is required in making these estimates and our final liabilities may ultimately be materially different.
Regulatory and Related Proceedings. We have received U.S. Postal Service and state subpoenas seeking information on our royalty payment practices. We have engaged in discussions with the U.S. Postal Service and state agency representatives and continue to respond to related subpoenas and demands.
Business Operations.We are involved in, and expect to continue to be involved in, various other lawsuits and disputes incidental to our business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions.
Regarding royalty claims, we and other natural gas producers The majority of the prepetition legal proceedings have been named in various lawsuits alleging royalty underpayment. The suits against us allege, among other things, that we used below-market prices, made improper deductions, utilized improper measurement techniques entered into arrangements with affiliates that resulted in underpayment of royaltiessettled during the Chapter 11 Cases or will be resolved in connection with the production and sale of natural gas and NGL, or similar theories. These lawsuits include cases filed by individual royalty owners and putative class actions, some of which seek to certify a statewide class. The lawsuits seek compensatory, consequential, treble, and punitive damages, restitution and disgorgement of profits, declaratory and injunctive relief regarding our royalty payment practices, pre-and post-judgment interest, and attorney’s fees and costs. Plaintiffs have varying royalty provisions in their respective leases, oil and gas law varies from state to state, and royalty owners and producers differ in their interpretation ofclaims reconciliation process before the legal effect of lease provisions governing royalty calculations. We have resolved a number of these claims through negotiated settlements of past and future royalties and has prevailed in various other lawsuits. We are currently defending numerous lawsuits seeking damages with respect to underpayment of royalties in multiple states where we have operated, including those discussed below.
On December 9, 2015, the Commonwealth of Pennsylvania, by the Office of Attorney General, filed a lawsuit in the Bradford County Court of Common PleasBankruptcy Court. Any allowed claim related to royalty underpayment and lease acquisition and accounting practicessuch prepetition litigation will be treated in accordance with respect to properties in Pennsylvania. The lawsuit, which primarily relates to the Marcellus Shale and Utica Shale, alleges that we violated the Pennsylvania Unfair Trade Practices and Consumer Protection Law (UTPCPL) by making improper deductions and entering into arrangements with affiliates that resulted in underpayment of royalties. The lawsuit includes other UTPCPL claims and antitrust claims, including that a joint exploration agreement to which we are a party established unlawful market allocation for the acquisition of leases. The lawsuit seeks statutory restitution, civil penalties and costs, as well as a temporary injunction from exploration and drilling activities in Pennsylvania until restitution, penalties and costs have been paid, and a permanent injunction from further violations of the UTPCPL.
Putative statewide class actions in Pennsylvania and Ohio and purported class arbitrations in Pennsylvania have been filed on behalf of royalty owners asserting various claims for damages related to alleged underpayment of royalties as a result of the divestiture of substantially all of our midstream business and most of our gathering assets in 2012 and 2013. These cases include claims for violation of and conspiracy to violate the federal Racketeer Influenced and Corrupt Organizations Act and for an unlawful market allocation agreement for mineral rights, intentional interference with contractual relations, and violations of antitrust laws related to purported markets for gas mineral rights, operating rights and gas gathering sources. These lawsuits seek in aggregate compensatory, consequential, treble, and punitive damages, restitution and disgorgement of profits, declaratory and injunctive relief regarding our royalty payment practices, pre-and post-judgment interest, and attorney’s fees and costs. On December 20, 2017, we reached a tentative settlement to resolve substantially all Pennsylvania civil royalty cases for approximately $30 million.
We believe losses are reasonably possible in certain of the pending royalty cases for which we have not accrued a loss contingency, but we are currently unable to estimate an amount or range of loss or the impact the actions could have on our future results of operations or cash flows. Uncertainties in pending royalty cases generally include the complex nature of the claims and defenses, the potential size of the class in class actions, the scope and types of the properties and agreements involved, and the applicable production years.
We are also defending lawsuits alleging various violations of the Sherman Antitrust Act and state antitrust laws. In 2016, putative class action lawsuits were filed in the U.S. District Court for the Western District of Oklahoma and in Oklahoma state courts, and an individual lawsuit was filed in the U.S. District Court of Kansas, in each case against us and other defendants. The lawsuits generally allege that, since 2007 and continuing through April 2013, the defendants conspired to rig bids and depress the market for the purchases of oil and natural gas leasehold interests and properties in the Anadarko Basin containing producing oil and natural gas wells. The lawsuits seek damages, attorney’s fees, costs and interest, as well as enjoinment from adopting practices or plans that would restrain competition in a similar manner as alleged in the lawsuits.Plan.
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 are namedwere recently dismissed as a defendant infrom numerous lawsuits and putative class actions in Oklahoma alleging that we and other companies have engaged in activities that have caused earthquakes. TheseThe lawsuits seeksought 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 seeksought the reimbursement of insurance premiums and the award of punitive damages, attorneys’ fees, costs, expenses and interest. Any allowed claim related to such prepetition litigation will be treated in accordance with the Plan.
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.
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Commitments
Operating Leases
Future operating lease commitments related to other property and equipment are not recorded as obligations in the accompanying consolidated balance sheets. The aggregate undiscounted minimum future lease payments are presented below:
  December 31, 2017
  ($ in millions)
2018 $6
2019 5
2020 2
2021 1
Total $14
Lease expense for the years ended December 31, 2017, 2016 and 2015, was $3 million, $5 million and $7 million, respectively.
Gathering, Processing and Transportation Agreements
We have contractual commitments with midstream service companies and pipeline carriers for future gathering, processing and transportation of oil, natural gas and NGL to move certain of our production to market. Working interest owners and royalty interest owners, where appropriate, will be responsible for their proportionate share of these costs. Commitments related to gathering, processing and transportation agreements are not recorded as obligations in the accompanying consolidated balance sheets; however, they are reflected in our estimates of proved reserves.
The aggregate undiscounted commitments under our gathering, processing and transportation agreements, excluding any reimbursement from working interest and royalty interest owners, credits for third-party volumes or future costs under cost-of-service agreements, are presented below:
  December 31,
2017
  ($ in millions)
2018 $1,079
2019 1,051
2020 979
2021 883
2022 771
2023 – 2035 4,404
Total $9,167
Successor
 December 31,
2021
2022$564 
2023500 
2024459 
2025356 
2026318 
2027 – 20361,631 
Total$3,828 
In addition, we have entered into long-term agreements for certain natural gas gathering and related services within specified acreage dedication areas in exchange for cost-of-service based fees redetermined annually, or tiered fees based on volumes delivered relative to scheduled volumes. Future gathering fees may vary with the applicable agreement.
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Drilling Contracts
We have contracts with various drilling contractors to utilize drilling services at market-based pricing. These commitments are not recorded as obligations in the accompanying consolidated balance sheets. As of December 31, 2017, the aggregate undiscounted minimum future payments under these drilling service commitments were approximately $23 million.
Oil, Natural Gas and NGL Purchase Commitments
We commit to purchase oil, natural gas and NGL from other owners in the properties we operate, including owners associated with our remaining volumetric production payment (VPP) transaction. Production purchases under these arrangements are based on market prices at the time of production, and the purchased oil, natural gas and NGL are resold at market prices. See Volumetric Production Payments in Note 12 for further discussion of our VPP transactions.
Other Commitments
As part of our normal course of business, we enter into various agreements providing, or otherwise arranging for, financial or performance assurances to third parties on behalf of our wholly owned guarantor subsidiaries. These agreements may include future payment obligations or commitments regarding operational performance that effectively guarantee our subsidiaries’ future performance.
In connection with acquisitions and divestitures, our purchase and sale agreements generally provide indemnification to the counterparty for liabilities incurred as a result of a breach of a representation or warranty by the indemnifying party and/or other specified matters. These indemnifications generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or cannot be quantified at the time of entering into or consummating a particular transaction. For divestitures of oil and natural gas properties, our purchase and sale agreements may require the return of a portion of the proceeds we receive as a result of uncured title or environmental defects.
Certain of our oil and natural gas properties are burdened by non-operating interests, such as royalty and overriding royalty interests, including overriding royalty interests sold through our VPP transactions. As the holder of the working interest from which these interests have been created, we have the responsibility to bear the cost of developing and producing the reserves attributable to these interests. See Volumetric Production Payments in Note 12 for further discussion of our VPP transactions.
While executing our strategic priorities, we have incurred certain cash charges, including contract termination charges, financing extinguishment costs and charges for unused natural gas transportation and gathering capacity. As we continue to focus on our strategic priorities, we may take certain actions that reduce financial leverage and complexity, and we may incur additional cash and noncash charges.
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5.8.Other Liabilities
Other current liabilities as of December 31, 20172021 and 20162020 are detailed below:
SuccessorPredecessor
December 31, 2021December 31, 2020
Revenues and royalties due others$617 $236 
Accrued drilling and production costs142 104 
Accrued hedging costs113 7 
Accrued compensation and benefits91 59 
Other accrued taxes86 82 
Operating leases29 24 
Joint interest prepayments received14 8 
Debt and equity financing fees— 69 
Other110 134 
Total other current liabilities$1,202 $723 


114
  December 31,
  2017 2016
  ($ in millions)
Revenues and royalties due others $612
 $543
Accrued drilling and production costs 216
 169
Joint interest prepayments received 74
 71
Accrued compensation and benefits 214
 239
Other accrued taxes 43
 32
Bank of New York Mellon legal accrual(a)
 —
 440
Other 296
 304
Total other current liabilities $1,455
 $1,798

(a)In 2017, we received notice from the U.S. Supreme Court that it would not review our appeal of the decision by the U.S. District Court for the Southern District of New York regarding the early redemption of our 6.775% Senior Notes due 2019. As a result of the decision, we paid $441 million with cash on hand and borrowings under the credit facility, and the related supersedeas bond was released.
Other long-term liabilities as of December 31, 2017 and 2016 are detailed below:
  December 31,
  2017 2016
  ($ in millions)
CHK Utica ORRI conveyance obligation(a)
 $156
 $160
Unrecognized tax benefits 101
 97
Other 97
 126
Total other long-term liabilities $354
 $383

(a)The CHK Utica, L.L.C. investors’ right to receive proportionately an overriding royalty interest (ORRI) in the first 1,500 net wells drilled on certain of our Utica Shale leasehold runs through 2023. We have the right to repurchase the ORRIs in the remaining net wells once we have drilled a minimum of 1,300 net wells. As of December 31, 2017, we had drilled 572 net wells. The obligation to deliver future ORRIs, which has been recorded as a liability, will be settled through the future conveyance of the underlying ORRIs to the investors on a net-well basis. As of December 31, 2017 and 2016, approximately $30 million and $43 million of the total ORRI obligations are recorded in other current liabilities, respectively.
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6.9.Leases
We are a lessee under various agreements for drilling rigs, compressors, vehicles, office space and gas treating plants. As of December 31, 2021, these leases have remaining terms ranging from one month to three years. Certain of our lease agreements include options to renew the lease, terminate the lease early or purchase the underlying asset at the end of the lease. We determine the lease term at the lease commencement date as the non-cancelable period of the lease, including options to extend or terminate the lease when we are reasonably certain to exercise the option. The company’s vehicles are the only leases with renewal options that we are reasonably certain to exercise. The renewals are reflected in the ROU asset and lease liability balances.
Our operating ROU assets are included in other long-term assets while operating lease liabilities are included in other current and other long-term liabilities on the consolidated balance sheet. Finance ROU assets are reflected in total property and equipment, net, while finance lease liabilities are included in other current and other long-term liabilities on the consolidated balance sheet.
On November 1, 2021, we acquired Vine and, as part of the purchase price allocation, we recognized additional operating lease liabilities of $32 million and a related ROU asset of $32 million related to drilling rig leases, an office space lease and gas treating plant leases.
On February 1, 2019, we acquired WildHorse and, as part of the purchase price allocation, we recognized additional operating lease liabilities of $40 million, a related ROU asset of $38 million, and lease incentives of $2 million related to 2 office space leases, a long-term hydraulic fracturing agreement and other equipment leases. Regarding our long-term hydraulic fracturing agreements, we made a policy election to treat both lease and non-lease components as a single lease component. All of these acquired leases were approved for rejection during our bankruptcy process and subsequently removed from our balance sheet.
In 2018, we sold our wholly owned subsidiary, Midcon Compression, L.L.C., to a third party and subsequently leased back certain natural gas compressors for 38 months. The lease was accounted for as a finance lease liability until the contract was renegotiated as part of our bankruptcy process and the changes to the contract resulted in the reclassification of the finance lease as an operating lease in March 2021.
The following table presents our ROU assets and lease liabilities as of December 31, 2021 and 2020.
SuccessorPredecessor
December 31, 2021December 31, 2020
 FinanceOperatingFinanceOperating
ROU assets$— $38 $9 $29 
Lease liabilities:
Current lease liabilities
$— $29 $9 $27 
Long-term lease liabilities
— 9 — 2 
Total lease liabilities
— 38 9 29 
Less amounts reclassified to liabilities subject to compromise— — (9)(5)
Total lease liabilities, net$— $38 $— $24 
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Additional information for the Company’s operating and finance leases is presented below:
SuccessorPredecessor
 Period from February 10, 2021 through December 31, 2021Period from January 1, 2021 through February 9, 2021Year Ended December 31, 2020Year Ended December 31, 2019
Lease cost:
Amortization of ROU assets$— $1 $9 $8 
Interest on lease liability— — 1 2 
Finance lease cost— 1 10 10 
Operating lease cost33 3 17 26 
Short-term lease cost13 — 32 112 
Total lease cost$46 $4 $59 $148 
Other information:
Operating cash outflows from finance lease$— $— $1 $2 
Operating cash outflows from operating leases$7 $— $9 $11 
Investing cash outflows from operating leases$39 $3 $40 $127 
Financing cash outflows from finance lease$— $1 $9 $8 
SuccessorPredecessor
December 31, 2021December 31, 2020
Weighted average remaining lease term - finance leaseN/A1.00 year
Weighted average remaining lease term - operating leases1.44 years1.12 years
Weighted average discount rate - finance leaseN/A7.50 %
Weighted average discount rate - operating leases3.80 %6.46 %
Maturity analysis of operating lease liabilities are presented below:
Successor
December 31, 2021
2022$29 
20238 
20241 
Total lease payments38 
Less imputed interest— 
Present value of lease liabilities38 
Less current maturities(29)
Present value of lease liabilities, less current maturities$9 

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10.Revenue Recognition
The following table shows revenue disaggregated by operating area and product type, for the periods presented:
Successor
Period from February 10, 2021 through December 31, 2021
OilNatural GasNGLTotal
Marcellus$— $1,370 $— $1,370 
Haynesville— 998 — 998 
Eagle Ford1,354 179 179 1,712 
Powder River Basin202 75 44 321 
Oil, natural gas and NGL revenue$1,556 $2,622 $223 $4,401 
Marketing revenue$1,158 $908 $197 $2,263 
Predecessor
Period from January 1, 2021 through February 9, 2021
OilNatural GasNGLTotal
Marcellus$— $119 $— $119 
Haynesville— 53 — 53 
Eagle Ford159 17 17 193 
Powder River Basin20 7 6 33 
Oil, natural gas and NGL revenue$179 $196 $23 $398 
Marketing revenue$141 $78 $20 $239 
Year Ended December 31, 2020
 OilNatural GasNGLTotal
Marcellus$— $631 $— $631 
Haynesville— 362 — 362 
Eagle Ford1,202 129 97 1,428 
Powder River Basin170 41 20 231 
Mid-Continent55 25 13 93 
Oil, natural gas and NGL revenue$1,427 $1,188 $130 $2,745 
Marketing revenue from contracts with customers$1,195 $494 $110 $1,799 
Other marketing revenue67 3 — 70 
Marketing revenue$1,262 $497 $110 $1,869 
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Year Ended December 31, 2019
 OilNatural GasNGLTotal
Marcellus$— $856 $— $856 
Haynesville— 620 — 620 
Eagle Ford2,010 185 135 2,330 
Powder River Basin369 77 32 478 
Mid-Continent164 44 25 233 
Oil, natural gas and NGL revenue$2,543 $1,782 $192 $4,517 
Marketing revenue from contracts with customers$2,473 $900 $246 $3,619 
Other marketing revenue311 41 — 352 
Losses on marketing derivatives— (4)— (4)
Marketing revenue$2,784 $937 $246 $3,967 
Accounts Receivable
Accounts receivable as of December 31, 2021 and 2020 are detailed below:
SuccessorPredecessor
December 31, 2021December 31, 2020
Oil, natural gas and NGL sales$922 $589 
Joint interest billings158 119 
Other38 68 
Allowance for doubtful accounts(3)(30)
Total accounts receivable, net$1,115 $746 
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11.Income Taxes
The components of the income tax provisionexpense (benefit) for each of the periods presented below are as follows:
 Years Ended December 31,
 2017 2016 2015SuccessorPredecessor
 ($ in millions)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
Current      Current
Federal $(14) $(14) $—
Federal$— $— $(3)$— 
State 5
 (5) (36)State— — (6)(26)
Current Income Taxes (9) (19) (36)Current Income Taxes— — (9)(26)
Deferred      Deferred
Federal 13
 (147) (4,385)Federal(45)(54)— (297)
State (2) (24) (42)State(4)(3)(10)(8)
Deferred Income Taxes 11
 (171) (4,427)Deferred Income Taxes(49)(57)(10)(305)
Total $2
 $(190) $(4,463)Total$(49)$(57)$(19)$(331)
The effective income tax expense (benefit) differedreported in our consolidated statement of operations is different from the computed "expected" federal income tax expense on earnings before income taxes(benefit) computed using the federal statutory rate for the following reasons:
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
Income tax expense (benefit) at the federal statutory rate of 21%$188 $1,119 $(2,051)$(134)
State income taxes (net of federal income tax benefit)(86)238 (41)(21)
Partial release of valuation allowance due to Acquisitions(49)— — (314)
Change in valuation allowance excluding impact of Acquisitions(179)(1,191)2,010 114 
Reorganization items60 (173)41 — 
Transaction costs11 — — — 
Removal of stranded tax effects in accumulated other comprehensive income— (57)— — 
Equity-based compensation (non-officer)— 7 10 4 
Officer compensation limited under Section 162(m)2 — 9 3 
Other4 — 3 17 
Total$(49)$(57)$(19)$(331)
  Years Ended December 31,
  2017 2016 2015
  ($ in millions)
Income tax expense (benefit) at the federal statutory rate (35%) $333
 $(1,606) $(6,684)
State income taxes (net of federal income tax benefit) 66
 (30) (406)
Remeasurement of deferred tax assets and liabilities 1,266
 —
 —
Change in valuation allowance (1,676) 1,423
 2,727
Other 13
 23
 (100)
Total $2
 $(190) $(4,463)
On December 22, 2017,After taking into account the Presidenteffect of the United States signed into law the Tax Act, which substantially revised numerous areasVine Acquisition, we have increased our estimate of U.S. federal income tax law, including lowering thestate apportionment to Louisiana. This results in a shift of our state profile towards a higher overall state tax rate, for corporations from a maximum rate of 35% to a flat rate of 21% and eliminating the corporate alternative minimum tax (AMT). These changes are generally in effect for tax years beginning after December 31, 2017. Although we are still in the process of evaluating the full impact of the Tax Act, the table above reflects the adjustments for remeasurement ofas such our deferred tax assets and liabilities. This remeasurement did not impactassociated with that state have increased resulting in a deferred tax benefit in our incomestate tax provision or balance sheetprovision. Such increase was offset in full by an increase to our valuation allowance. We recognize certain permanent book-to-tax differences relating to reorganization items such as differences in the treatment of the extinguishment of liabilities, differences due to the offsetting effectnon-deductibility of adjustingcertain expenses associated with administering the valuation allowance. Dueplan of reorganization, and the adjustment to various estimates included in determiningdeferred tax assets which are subject to expiration before they are utilizable. In the tax provision,Successor Period, we recognized a difference due to the remeasurement is considered provisionalnon-deductibility of certain transaction costs and may be adjusted through subsequent events such as the filing of our consolidated federal income tax return for the period ended December 31, 2017.other post-combination expenses.
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We reassessed the realizability of our deferred tax assets and continue to maintain a full valuation allowance against a significant portion of our net deferred tax assets excludingasset positions for federal and state purposes. Of the deferred tax assets related to AMT credit carryovers that are expected to be realized in the future. The $1.676 billion net decrease in our valuation allowance, $1.191 billion is reflected as a component of income tax expensebenefit in our consolidated statement of operations for the year ended December 31, 2017. This decrease2021 Predecessor Period, and $228 million is primarily due to offsetting the provisional remeasurement of deferred tax assets and liabilitiesreflected as a resultcomponent of income tax benefit in our consolidated statement of operations for the Tax Act, as well as an offset to current year tax expense.
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2021 Successor Period.
Deferred income taxes are provided to reflect temporary differences in the tax basis of assets and liabilities and their reported amounts in the financial statements. The tax-effected temporary differences, tax credits and net operating loss (“NOL”) carryforwards and excess business interest expense carryforwards that comprise our deferred income taxes are as follows:
 Years Ended December 31,
 2017 2016SuccessorPredecessor
 ($ in millions)December 31,
2021		December 31,
2020
Deferred tax liabilities:    Deferred tax liabilities:
Volumetric production payments $(129) $(223)
Other (20) (62)Other$(3)$(3)
Deferred tax liabilities (149) (285)Deferred tax liabilities(3)(3)
    
Deferred tax assets:    Deferred tax assets:
Property, plant and equipment 1
 593
Property, plant and equipment340 907 
Net operating loss carryforwards 2,248
 2,587
Net operating loss carryforwards784 2,066 
Carrying value of debt 161
 539
Carrying value of debt31 48 
Excess business interest expense carryforwardExcess business interest expense carryforward684 293 
Asset retirement obligations 42
 98
Asset retirement obligations86 34 
Investments 161
 275
Investments66 71 
Accrued liabilitiesAccrued liabilities38 288 
Derivative instruments 17
 161
Derivative instruments289 53 
Accrued liabilities 125
 319
Other 71
 118
Other68 51 
Deferred tax assets 2,826
 4,690
Deferred tax assets2,386 3,811 
Valuation allowance (2,674) (4,389)Valuation allowance(2,383)(3,808)
Net deferred tax assets 152
 301
Net deferred tax assets $3
 $16
Deferred tax assets after valuation allowanceDeferred tax assets after valuation allowance3 3 
Net deferred tax liabilityNet deferred tax liability$— $— 
As of December 31, 2017, we had federal NOL carryforwards of approximately $8.073 billion2021, and state NOL carryforwards of approximately $10.066 billion, which excludes the NOL carryforwards related to unrecognized tax benefits. The associated deferred tax assets related to these federal and state NOL carryforwards were $1.695 billion and $581 million, respectively. The NOL carryforwards expire between 2031 and 2037. The value of these carryforwards depends on our ability to generate taxable income. As of December 31, 2017 and 2016,2020, we had deferred tax assets of $2.826$2.386 billion and $4.690$3.811 billion upon which we had a valuation allowance of $2.674$2.383 billion and $4.389$3.808 billion, respectively. Of the net change in the valuation allowance of $1.715$1.425 billion for both federal and state deferred tax assets, $1.676$1.419 billion is reflected as a component of income tax expensebenefit in the consolidated statement of operations and the remainderdifference is reflected in components of stockholders’ equity.
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A valuation allowance foragainst deferred tax assets, including NOL carryforwards and disallowed business interest carryforwards, is recognized when it is more-likely- than-notmore likely than not that all or some portion of the benefit from the deferred tax assetassets will not be realized. To assess that likelihood, we use estimates and judgment regarding our future taxable income, and we consider the tax consequences in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted, the reversal of deferred tax liabilities, andexisting taxable temporary differences, tax planning strategies, as well as the current and forecasted business economics of our industry. Management assesses all available evidence, both positive and negative, evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. Based on all available positive and negative evidence, including projections of future taxable income, we believe it is more likely than not that our deferred tax assets will not be realized. As such, a full valuation allowance was recorded against our net deferred tax asset position for federal and state purposes. A significant piece of objectively verifiable negative evidence consists of the losses incurred in prior quarters. The current quarter’s pre-tax book income is a source of positive evidence, however given the cumulative loss incurred overabsence of a trend of multiple successive quarters with book income, such evidence does not outweigh the three-year period ending December 31, 2017. Such objective negative evidence limits our ability to consider various formsevidence. Should future results of subjective positiveoperations demonstrate a trend of profitability, additional weight may be placed upon other evidence, such as our projections for future forecasts of taxable income. Accordingly, management hasAdditionally, future events and new evidence, such as the integration of and realization of profit from the recently acquired assets could lead to increased weight being placed upon future forecasts and the conclusion that some or all of the deferred tax assets are more likely than not changed its judgement with respect to be realizable. Therefore, we believe that there is a possibility that some or all of the need for a valuation allowance against substantially allcould be released in the foreseeable future.
Our ability to utilize NOL carryforwards, disallowed business interest carryforwards, tax credits and possibly other tax attributes to reduce future taxable income and federal income tax is subject to various limitations under Section 382 of the Code. The utilization of such attributes may be subject to an annual limitation under Section 382 of the Code should transactions involving our equity result in a cumulative shift of more than 50% in the beneficial ownership of our net deferred tax asset position.stock during any three-year testing period (an “Ownership Change”).
As a result of emergence from bankruptcy on February 9, 2021, the Company did experience an Ownership Change. We did not qualify for the exception under Section 382(l)(5) of the Code, and therefore an annual limitation was determined under Section 382(l)(6) of the Code, which is based on the post-emergence value of our equity multiplied by the adjusted federal long-term rate in effect for the month in which the ownership change occurred. The amount of the annual limitation has been computed to be $54 million and was prorated for the 2021 tax year based on the number of days attributable to the post-Effective Date portion of the year. The limitation applies to our NOL carryforwards, disallowed business interest carryforwards and general business credits until such attributes expire or are fully utilized. As we believe we were in an overall net unrealized built-in loss position at the Effective Date, the limitation also applies to any recognized built-in losses incurred for a period of five years but only to the extent of the overall net unrealized built-in loss. Recognized built-in losses incurred during 2021 include a portion of our tax depreciation, depletion, and amortization deductions along with a portion of our realized hedging losses. We have incurred enough of those items for the 2021 tax year and have thus disallowed deductions up to the net unrealized built-in loss. Accordingly, we estimate no further restriction on the company’s deduction for such items. Some states impose similar limitations on tax attribute utilization upon experiencing an Ownership Change.
In Chapter 11 bankruptcy cases, the cancellation of debt income (“CODI”) realized upon emergence from bankruptcy is excludible from taxable income but results in a reduction of tax attributes in accordance with the attribute reduction and ordering rules of Section 108 of the Code. The amount of our CODI is estimated to be $5 billion, all of which will reduce our NOL carryforwards. This attribute reduction occurs after the close of the tax year, however we have included the estimated effect of such reduction in our ending deferred tax asset considered realizable, however, could be adjusted if estimatesassets as of future taxable incomeDecember 31, 2021. As a result of the Section 382 limitation, $593 million of federal NOLs remaining after the CODI reduction are increased or if objective negative evidenceestimated to expire before they would become utilizable and as such have been removed from our deferred tax assets. The states we operate in generally have similar rules for attribute reduction and Section 382 limitation which results in the formreduction of cumulative lossescertain of our state NOL carryforwards.
On November 1, 2021, we completed the acquisition of Vine. For federal income tax purposes, the transaction qualified as a tax-free merger under Section 368 of the Code and, as a result, we acquired carryover tax basis in Vine’s assets and liabilities. A net deferred tax liability of $49 million determined through business combination accounting includes deferred tax liabilities on plant, property and equipment totaling $298 million, partially offset by deferred tax assets totaling $249 million relating to federal NOL carryforwards, disallowed business interest carryforwards and certain other deferred tax assets. These carryforwards are subject to a base annual Section 382 limitation of approximately $2 million. The base annual limitation is no longer present and additional weight is givenestimated to subjective positive evidence such as future expected growth.be increased over the first five years for recognized
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Our abilitybuilt-in gains of approximately $14 million per year. We determined that no separate valuation allowances were required to utilize NOL carryforwardsbe established against any of the individual deferred tax assets acquired. We determined that the acquired deferred tax liability was a source of evidence to reduce future federal taxable incomerelease valuation allowance, and federal incomeas such $49 million was recorded as a tax is subject to various limitations under the Code. The utilization of these carryforwards may be limited upon the occurrence of certain ownership changes, including the issuance or exercise of rights to acquire stock, the purchase or sale of stock by 5% stockholders, as defined in Treasury regulations, and the offering of stock by us during any three-year period resulting in an aggregate change of more than 50%benefit in the beneficial ownership of Chesapeake.successor period.
As of December 31, 2017, we2021, and after taking into account each of the foregoing matters, the federal NOLs and excess business interest attributes are as follows:
Attributes subject to Section 382 base annual limitationAttributes not subject to Section 382 limitation
$54 million$2 million
Net operating losses, by year of expiration:
2037$858 $10 $— 
Indefinitely lived1,919 112 — 
Total federal net operating losses$2,777 $122 $— 
Excess business interest expense (indefinitely lived)$1,455 $58 $1,459 
We had state NOL carryforwards of approximately $3.541 billion. Several states adopt the federal NOL carryforward period such that our more recent state NOLs do not believe that an ownership change has occurred that would limit our NOL carryforwards. Certain future transactions involving our equity (including relatively small transactions and transactions beyond our control) could cause an ownership change and therefore a limitation on the annual utilization ofexpire. The state NOL carryforwards and possibly other tax attributes.are subject to apportioned amounts of the federal Section 382 limitations.
Accounting guidance for recognizing and measuring uncertain tax positions requires a more-likely-than-notmore likely than not threshold condition be met on a tax position, based solely on the technical merits of being sustained, before any benefit of the tax position can be recognized in the financial statements. Guidance is also provided regarding de-recognition,recognition, classification and disclosure of these uncertain tax positions. As of both December 31, 20172021, and 2016,2020, the amount of unrecognized tax benefits related to NOL carryforwards and tax liabilities associated with uncertain tax positions was $106$74 million, of which, as of both December 31, 2021 and $202 million, respectively. Of the 2017 amount, $74December 31, 2020, $29 million is related to state tax liabilities, $4 million is relatedreceivables not expected to federal tax liabilitiesbe recovered and the remainder is related to NOL carryforwards. Of the 2016 amount, $76 million is related to state tax liabilities while the remainder is related to NOL carryforwards. If recognized, $74$29 million of the uncertain tax positions identified would have an effect on the effective tax rate. No material changes to the current uncertain tax positions are expected within the next 12 months. As of December 31, 20172021, and 2016,2020, we had no amounts accrued liabilities of $23 million and $20 million, respectively, for interest related to these uncertain tax positions. We recognize interest related to uncertain tax positions as a component of interest expense. Penalties, if any, related to uncertain tax positions would be recorded in other expenses. $24 million of the state tax receivable relates to claims for refund of Pennsylvania income taxes. During the fourth quarter of 2021, a court case with similar claims as ours was decided in favor of the taxpayer. We have considered this new information and determined that we have no change to our assessment of the recognition and measurement of our position. Should the state exhaust its appeals so that the taxpayer ultimately prevails we may be successful in applying that precedent to our claims. As such, it is possible that we may reassess that refund claim in the next twelve months and ascertain it to be more likely than not to be sustained. Should this occur, we will record a current tax benefit and income tax receivable for the amount we determine we are likely to sustain.
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A reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows:
 2017 2016 2015SuccessorPredecessor
 ($ in millions)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
Unrecognized tax benefits at beginning of period $202
 $280
 $303
Unrecognized tax benefits at beginning of period$74 $74 $74 $79 
Additions based on tax positions related to the current year —
 —
 27
Additions based on tax positions related to the current year— — — — 
Additions to tax positions of prior years 4
 33
 —
Additions to tax positions of prior years— — — 27 
Settlements (100) (111) —
Settlements— — — (32)
Expiration of the applicable statute of limitationsExpiration of the applicable statute of limitations— — — — 
Reductions to tax positions of prior years —
 —
 (50)Reductions to tax positions of prior years— — — — 
Unrecognized tax benefits at end of period $106
 $202
 $280
Unrecognized tax benefits at end of period$74 $74 $74 $74 
Our federal and state income tax returns are routinely auditedsubject to examination by federal and state fiscaltax authorities. The Internal Revenue Service (IRS) is currently auditing ourNotification was received from the IRS during February 2021 that the examination of the WildHorse 2017 federal income tax returns for 2010return has been closed as a no-change audit. Our tax years 2018 through 2015. During the 2017 fourth quarter, we reached a tentative settlement with the IRS in regards to our 2010 to 2013 federal income tax returns. Even though the audit remains open, we have concluded that uncertain tax positions related to these respective years are effectively settled and the corresponding unrecognized tax benefits have now been recorded. The 2010 through 2017 years and the 2007 through 2017 years2021 remain open for all purposes of examination by the IRS as do the WildHorse 2018 federal income tax return and other taxing authoritiesthe WildHorse short period return for January 1, 2019, through February 1, 2019. However, certain earlier tax years remain open for adjustment to the extent of their NOL carryforwards available for future utilization.
In addition, tax years 2018 through 2021 as well as certain earlier years remain open for examination by state tax authorities. Currently, several state examinations are in material jurisdictions, respectively.progress of various years. We do not anticipate that the outcome of any federal or state audit will have a significant impact on our financial position or results of operations.
7.Related Party Transactions
Our equity method investees are considered related parties. Hydraulic fracturing and other services are provided to us in the ordinary course of business by our equity affiliate FTSI. As well operators, we are reimbursed by other working interest owners through the joint interest billing process for their proportionate share of these costs. For the years ended December 31, 2017, 2016 and 2015, our expenditures for hydraulic fracturing services with FTSI were $111 million, $3 million and $65 million, respectively.
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8.12.Equity
New Common Stock.
As discussed in Note 2, on the Effective Date, we issued an aggregate of 97,907,081 shares of New Common Stock,
A summary of the changes in our common shares issued for the years ended December 31, 2017, 2016 and 2015 is detailed below:
  Years Ended December 31,
  2017 2016 2015
  (in thousands)
Shares issued as of January 1 896,279
 664,796
 664,944
Exchange of convertible notes —
 55,428
 —
Exchange of senior notes —
 53,924
 —
Exchange/conversion of preferred stock 9,966
 120,186
 —
Restricted stock issuances (net of forfeitures and cancellations) 2,488
 1,945
 (163)
Stock option exercises —
 —
 15
Shares issued as of December 31 908,733

896,279
 664,796
During the year ended December 31, 2017, our shareholders approved an amendment to our certificate of incorporation to increase our authorized common stock to 2,000,000,000 shares, par value $0.01 per share.share, to the holders of allowed claims, and approximately 2,092,918 shares of New Common Stock were reserved for future distributions under the Plan. During the 2021 Successor Period, 864,090 reserved shares were issued to resolve allowed unsecured claims.
Preferred StockAs discussed in Note 4, on November 1, 2021, we acquired Vine and issued 18,709,399 shares of New Common Stock.
Following isDividends
In the 2021 Successor Period, we initiated a summary ofnew annual dividend on our preferred stock, includingcommon shares, expected to be paid quarterly. The following table summarizes our dividend payments in the primary conversion terms as2021 Successor Period:
Payment DateStockholders of Record DateDividend PaymentRate Per Share
June 10, 2021May 24, 2021$34 $0.34375 
September 9, 2021August 24, 202133 $0.34375 
December 9, 2021November 24, 202152 $0.43750 
Total dividends paid$119 
Warrants
Class A WarrantsClass B Warrants
Class C Warrants(a)
Issued as of February 10, 202111,111,111 12,345,679 9,768,527 
Converted into New Common Stock(b)
(254,259)(32,406)(10,603)
Issued for General Unsecured Claims— — 1,630,447 
Outstanding as of December 31, 202110,856,852 12,313,273 11,388,371 
_________________________________________
(a)As of December 31, 2017:2021, we had 2,318,446 of reserved Class C Warrants.
(b)As of December 31, 2021, we issued 188,292 common shares as a result of Warrant exercises.
As discussed in Note 2, on the Effective Date, we issued Class A, Class B and Class C Warrants that are initially exercisable for one share of New Common Stock per Warrant at initial exercise prices of $27.63, $32.13 and $36.18 per share, respectively, subject to adjustments pursuant to the terms of the Warrants. The Warrants are exercisable from the Effective Date until February 9, 2026. The Warrants contain customary anti-dilution adjustments in the event of any stock split, reverse stock split, reclassification, stock dividend or other distributions. The exercise prices of the Warrants were adjusted to prevent the dilution of rights for the effects of the quarterly dividend distribution on December 9, 2021, and the adjusted exercise prices are $27.08, $31.49, and $35.46 per share for the Class A, Class B and Class C Warrants, respectively.
Chapter 11 Proceedings
Upon our emergence from Chapter 11 on February 9, 2021, as discussed in Note 2, Predecessor common stock and preferred stock were canceled and released under the Plan without receiving any recovery on account thereof.
Noncontrolling Interests
In the 2019 Predecessor Period and part of the 2020 Predecessor Period, we owned 23,750,000 common units in the Chesapeake Granite Wash Trust (the “Trust”) representing a 51% beneficial interest. We determined that the Trust was a VIE and that we were the primary beneficiary. As a result, the Trust was included in our consolidated financial statements. In the 2020 Predecessor Period, we sold our interests in the Mid-Continent operating area and the units we owned in the Trust. See Note 4 for additional discussion.
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Preferred Stock Series Issue Date 
Liquidation
Preference
per Share
 Holder's Conversion Right Conversion Rate Conversion Price 
Company's
Conversion
Right From
 
Company's Market Conversion Trigger(a)
5.75% cumulative
convertible
non-voting
 May and June 2010 $1,000
 Any time 39.6858 $25.1979
 May 17, 2015 $32.7573
               
5.75% (series A)
cumulative
convertible
non-voting
 May 2010 $1,000
 Any time 38.3508 $26.0751
 May 17, 2015 $33.8976
               
4.50% cumulative convertible September 2005 $100
 Any time 2.4561 $40.7152
 September 15, 2010 $52.9298
               
5.00% cumulative convertible (series 2005B) November 2005 $100
 Any time 2.7745 $36.0431
 November 15, 2010 $46.8560

(a)Convertible at the Company's option if the trading price of the Company's common stock equals or exceeds the trigger price for a specified time period or after the applicable conversion date if there are less than 250,000 shares of 4.50% or 5.00% (Series 2005B) preferred stock outstanding or 25,000 shares of 5.75% or 5.75% (Series A) preferred stock outstanding.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Outstanding shares of our preferred stock for the years ended December 31, 2017, 2016 and 2015 are detailed below:
  5.75% 5.75% (A) 4.50% 
5.00%
(2005B)  
  (in thousands)
Shares outstanding as of January 1, 2017 843
 476
 2,559
 1,962
Preferred stock conversions/exchanges(a)
 (73) (13) —
 (151)
Shares outstanding as of December 31, 2017 770
 463
 2,559
 1,811
         
Shares outstanding as of January 1, 2016 1,497
 1,100
 2,559
 2,096
Preferred stock conversions/exchanges(b)
 (654) (624) —
 (134)
Shares outstanding as of December 31, 2016 843
 476
 2,559
 1,962
         
Shares outstanding as of January 1, 2015
and December 31, 2015
 1,497
 1,100
 2,559
 2,096

(a)13.During 2017, holders of our 5.75% Cumulative Convertible Preferred Stock exchanged 72,600 shares into 7,442,156 shares of common stock, holders of our 5.75% (Series A) Cumulative Convertible Preferred Stock exchanged 12,500 shares into 1,205,923 shares of common stock and holders of our 5.00% (Series 2005B) Cumulative Convertible Preferred Stock exchanged 150,948 shares into 1,317,756 shares of common stock. In connection with the exchanges, we recognized a loss equal to the excess of the fair value of all common stock issued in exchange for the preferred stock over the fair value of the common stock issuable pursuant to the original terms of the preferred stock. The loss of $41 million is reflected as a reduction to net income available to common stockholders for the purpose of calculating earnings per common share.Share-Based Compensation
(b)During 2016, holders of our 5.75% Cumulative Convertible Preferred Stock converted 653,872 shares into 59,141,429 shares of common stock, holders of our 5.75% (Series A) Cumulative Convertible Preferred Stock converted 624,137 shares into 60,032,734 shares of common stock and holders of our 5.00% (Series 2005B) Cumulative Convertible Preferred Stock exchanged or converted 134,000 shares into 1,012,032 shares of common stock. In connection with the exchanges noted above, we recognized a loss equal to the excess of the fair value of all common stock issued in exchange for the preferred stock over the fair value of the common stock issuable pursuant to the original terms of the preferred stock. The loss of $428 million is reflected as a reduction to net income available to common stockholders for the purpose of calculating earnings per common share.
Dividends
Dividends declaredAs discussed in Note 2, on the Effective Date, our Predecessor common stock was canceled and New Common Stock was issued. Accordingly, our then existing share-based compensation awards were also canceled, which resulted in the recognition of any previously unamortized expense related to the canceled awards on the date of cancellation. Share-based compensation for the Predecessor and Successor Periods is not comparable.
Successor Share-Based Compensation
As of the Effective Date, the Board adopted the 2021 Long Term Incentive Plan (the “LTIP”) with a share reserve equal to 6,800,000 shares of New Common Stock. The LTIP provides for the grant of restricted stock units, restricted stock awards, stock options, stock appreciation rights, performance awards and other stock awards to the Company’s employees and non-employee directors.
Restricted Stock Units. In the 2021 Successor Period, we granted restricted stock units to employees and non-employee directors under the LTIP, which will vest over a three-year and one-year period, respectively. The fair value of restricted stock units is based on the closing sales price of our common stock on the date of grant, and compensation expense is recognized ratably over the requisite service period. A summary of the changes in unvested restricted stock units is presented below:
 
Unvested
Restricted Stock Units		Weighted Average
Grant Date
Fair Value Per Share
(in thousands)
Unvested as of February 10, 2021— $— 
Granted (a)
1,202 $52.60 
Vested (a)
(377)$65.66 
Forfeited(50)$44.37 
Unvested as of December 31, 2021775 $46.77 
_________________________________________
(a)Due to the Vine Acquisition, each Vine restricted stock unit was converted into a Company restricted stock unit. As a result, approximately 430 thousand Vine restricted stock units were converted to Company restricted stock units, of which approximately 375 thousand restricted stock units were accelerated. We recognized accelerated share-based compensation expense in other operating expense on our preferredconsolidated statement of operations.
The aggregate intrinsic value of restricted stock are reflected as adjustmentsunits that vested during the 2021 Successor Period was approximately $25 million based on the stock price at the time of vesting.
As of December 31, 2021, there was approximately $27 million of total unrecognized compensation expense related to retained earningsunvested restricted stock units. The expense is expected to be recognized over a weighted average period of approximately 2.28 years.
Performance Share Units. In the extent2021 Successor Period, we granted performance share units (“PSUs”) to senior management under the LTIP, which will generally vest over a surplusthree-year period and will be settled in shares. The performance criteria include share price hurdles, total shareholder return (“TSR”), and relative TSR (“rTSR”). The share price hurdle award could result in a payout between 0% - 100% of retained earnings exists after giving effect to the dividends. Totarget units, and the extent retained earnings are insufficient to fundTSR and rTSR awards could result in a total payout between 0% - 200% of the distributions, payments are reflected in our financial statements astarget units. The fair value of the PSUs was measured on the grant date using a return of contributed capital rather than earningsMonte Carlo simulation, and are accounted for as a reduction to paid-in capital.
Dividendscompensation expense is recognized ratably over the requisite service period because these awards depend on our outstanding preferred stock are payable quarterly. We may pay dividends on our 5.00% Cumulative Convertible Preferred Stock (Series 2005B) and our 4.50% Cumulative Convertible Preferred Stock in cash, common stock or a combination thereof, at our option. Dividends on both series of our 5.75% Cumulative Convertible Non-Voting Preferred Stock are payable only in cash.service and market criteria.
In January 2016, we suspended dividend payments on our convertible preferred stock to provide additional liquidityThe following table presents the assumptions used in the depressed commodity price environment. Invaluation of the first quarter of 2017, we reinstated the payment of dividends on each series of our outstanding convertible preferred stock and paid our dividendsPSUs granted in arrears.2021:
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AssumptionShare Price HurdleTSR, rTSR
Risk-free interest rate0.30 %0.23 %
Volatility68.4 %71.4 %
Accumulated Other Comprehensive Income (Loss)A summary of the changes in unvested PSUs is presented below:
For
Unvested Performance Share UnitsWeighted Average
Grant Date
Fair Value Per Share
(in thousands)
Unvested as of February 10, 2021— $— 
Granted201 $64.41 
Vested(9)$38.95 
Forfeited(9)$55.42 
Unvested as of December 31, 2021183 $66.12 
The aggregate intrinsic value of PSUs that vested during the years ended 2021 Successor Period was approximately $0.6 million based on the stock price at the time of vesting.
As of December 31, 2017 and 2016, changes in accumulated other comprehensive income (loss) for cash flow hedges, net of tax, are detailed below:
  Years Ended December 31,
  2017 2016
  ($ in millions)
Balance, as of January 1 $(96) $(99)
Other comprehensive income (loss) before reclassifications 5
 (13)
Amounts reclassified from accumulated other comprehensive income 34
 16
Net other comprehensive income (loss) 39
 3
Balance, as of December 31 $(57) $(96)
For the years ended December 31, 2017 and 2016, net losses on cash flow hedges for commodity contracts reclassified from accumulated other comprehensive income (loss), net of tax, to oil, natural gas and NGL revenues in the consolidated statements of operations were $34 million and $16 million, respectively.
Noncontrolling Interests
Chesapeake Granite Wash Trust. In 2011, Chesapeake Granite Wash Trust (the Trust) sold 23,000,000 common units representing beneficial interests in the Trust to the public. Prior to June 30, 2017, we owned 12,062,500 common units and as well as 11,687,500 subordinated units representing a 51% beneficial interest in the Trust. On June 30, 2017, the Trust’s subordinated units, all of which were held by us, converted to common units. The Trust has a total of 46,750,000 units outstanding.
Prior to their conversion on June 30, 2017, as holder of the subordinated units, we were entitled to receive pro rata distributions from the Trust each quarter if and to the extent2021, there was sufficient cash. We were also entitled to receive, prior to their termination on June 30, 2017, incentive distributions, to the extent approximately $10 million of sufficient cash, as defined. No subordinated unit or incentive distributions were made by the Trust.
During our review of the carrying amount of the Trust’s noncontrolling interests, we identified errorstotal unrecognized compensation expense related to the allocationunvested PSUs. The expense is expected to be recognized over a weighted average period of impairment expense between Chesapeakeapproximately 2.44 years.
Predecessor Share-Based Compensation
Our Predecessor share-based compensation program consisted of restricted stock, stock options, PSUs and cash restricted stock units (“CRSUs”) granted to employees and restricted stock granted to non-employee directors under our long-term incentive plans. The restricted stock and stock options were equity-classified awards and the Trust’s noncontrolling interests during previously reported periods. We have determined that these errors are immaterial to previously issued financial statementsPSUs and therefore, have revised the previously reported financial statements below. We have also determined that these errors did not relate to periods prior to 2015.CRSUs were liability-classified awards.
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  December 31, 2016
CONSOLIDATED BALANCE SHEETS 
As Previously
Reported
 
Revision
Adjustment
 
As
Revised
  ($ in millions except per share data)
Accumulated deficit $(17,603) $129
 $(17,474)
Total Chesapeake stockholders’ equity (deficit) $(1,460) $129
 $(1,331)
Noncontrolling interests $257
 $(129) $128

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

  Year Ended December 31, 2016
CONSOLIDATED STATEMENTS OF OPERATIONS 
As Previously
Reported
 
Revision
Adjustment
 
As
Revised
  ($ in millions except per share data)
Net (income) loss attributable to noncontrolling interest $(2) $11
 $9
Net income (loss) attributable to Chesapeake $(4,401) $11
 $(4,390)
Net income (loss) available to common stockholders $(4,926) $11
 $(4,915)
Loss per common share basic $(6.45) $0.02
 $(6.43)
Loss per common share diluted $(6.45) $0.02
 $(6.43)
       
  Year Ended December 31, 2015
CONSOLIDATED STATEMENTS OF OPERATIONS 
As Previously
Reported
 
Revision
Adjustment
 
As
Revised
  ($ in millions except per share data)
Net (income) loss attributable to noncontrolling interest $(50) $118
 $68
Net income (loss) attributable to Chesapeake $(14,685) $118
 $(14,567)
Net income (loss) available to common stockholders $(14,856) $118
 $(14,738)
Loss per common share basic $(22.43) $0.17
 $(22.26)
Loss per common share diluted $(22.43) $0.17
 $(22.26)
  Year Ended December 31, 2016
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME 
As Previously
Reported
 
Revision
Adjustment
 
As
Revised
  ($ in millions except per share data)
Comprehensive (income) loss attributable to noncontrolling interests $(2) $11
 $9
Comprehensive income (loss) attributable to Chesapeake $(4,398) $11
 $(4,387)
       
  Year Ended December 31, 2015
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME 
As Previously
Reported
 
Revision
Adjustment
 
As
Revised
  ($ in millions except per share data)
Comprehensive (income) loss attributable to noncontrolling interests $(50) $118
 $68
Comprehensive income (loss) attributable to Chesapeake $(14,641) $118
 $(14,523)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

  Year Ended December 31, 2016
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY 
As Previously
Reported
 
Revision
Adjustment
 
As
Revised
  ($ in millions except per share data)
Accumulated deficit $(17,603) $129
 $(17,474)
Noncontrolling interests $257
 $(129) $128
       
  Year Ended December 31, 2015
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY 
As Previously
Reported
 
Revision
Adjustment
 
As
Revised
  ($ in millions except per share data)
Accumulated deficit $(13,202) $118
 $(13,084)
Noncontrolling interests $259
 $(118) $141
Restricted Stock Units. We have determined that the Trust is a VIE and that we are the primary beneficiary. As a result, the Trust is included in our consolidated financial statements. As of December 31, 2017 and 2016, we had $124 million and $128 million, respectively, of noncontrolling interests on our consolidated balance sheets attributable to the Trust. Net income attributable to the Trust’s noncontrolling interest was $4 million for the year ended December 31, 2017 and net loss attributable to the Trust’s noncontrolling interest was $9 million and $68 million for the years ended December 31, 2016 and 2015, respectively.
The Trust’s legal existence is separate from Chesapeake and our other consolidated subsidiaries, and the Trust is not a guarantor of any of Chesapeake’s debt. The creditors or beneficial holders of the Trust have no recourse to the general credit of Chesapeake. We have presented parenthetically on the face of the consolidated balance sheets the assets of the Trust that can be used only to settle obligations of the Trust and the liabilities of the Trust for which creditors do not have recourse to the general credit of Chesapeake.
Cleveland Tonkawa Financial Transaction. We formed CHK C-T in 2012 to continue development of a portion of our oil and natural gas assets in our Cleveland and Tonkawa plays, in which third-party investors contributed $1.25 billion in cash to CHK C-T in exchange for (i) 1.25 million preferred shares, and (ii) our obligation to deliver a 3.75% overriding royalty interest (ORRI) in the existing wells and up to 1,000 future net wells to be drilled on the contributed play leasehold.
During 2015, CHK C-T sold all of its oil and natural gas properties to FourPoint Energy, LLC. See Note 12 for further discussion of this transaction. In connection with this transaction, we eliminated all related future drilling and ORRI commitments attributable to CHK C-T.
Net income attributable to the noncontrolling interests of CHK C-T was $50 million for the year ended December 31, 2015.
9.Share-Based Compensation
Our share-based compensation program consists of restricted stock, stock options and performance share units (PSUs) granted to employees and restricted stock granted to non-employee directors under our long term incentive plans. The restricted stock and stock options are equity-classified awards and the PSUs are liability-classified awards.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Share-Based Compensation Plans
2014 Long Term Incentive Plan. Our 2014 Long Term Incentive Plan (2014 LTIP), which is administered by the Compensation Committee of our Board of Directors, became effective on June 13, 2014 after it was approved by shareholders at our 2014 Annual Meeting. The 2014 LTIP replaced our Amended and Restated Long Term Incentive Plan which was adopted in 2005. The 2014 LTIP provides for up to 71,600,000 shares of common stock that may be issued as long-term incentive compensation to our employees and non-employee directors; provided, however, that the 2014 LTIP uses a fungible share pool under which (i) each share issued pursuant to a stock option or stock appreciation right (SAR) reduces the number of shares available under the 2014 LTIP by 1.0 share; (ii) each share issued pursuant to awards other than options and SARs reduces the number of shares available by 2.12 shares; (iii) if any awards of restricted stock under the 2014 LTIP, or its predecessor plan, are forfeited, expire, are settled for cash, or are tendered by the participant or withheld by us to satisfy any tax withholding obligation, then the shares subject to the award may be used again for awards; and (iv) PSUs and other performance awards which are payable solely in cash are not counted against the aggregate number of shares issuable. In addition, the 2014 LTIP prohibits the reuse of shares withheld or delivered to satisfy the exercise price of, or to satisfy tax withholding requirements for, an option or SAR. The 2014 LTIP also prohibits “net share counting” upon the exercise of options or SARs.
The 2014 LTIP authorizes the issuance of the following types of awards: (i) nonqualified and incentive stock options; (ii) SARs; (iii) restricted stock; (iv) performance awards, including PSUs; and (v) other stock-based awards. For both stock options and SARs, the exercise price may not be less than the fair market value of our common stock on the date of grant and the maximum exercise period may not exceed ten years from the date of grant. Awards granted under the plan vest at specified dates and/or upon the satisfaction of certain performance or other criteria, as determined by the Compensation Committee. As of December 31, 2017, 40,574,965 shares of common stock remained issuable under the 2014 LTIP.
Equity-Classified Awards
Restricted Stock. We grant restricted stock units to employees and non-employee directors. A summary of the changes in unvestedThe following table provides information related to restricted stock during 2017, 2016 and 2015 is presented below:units activity for the Predecessor periods presented:
Unvested
Restricted Stock Units		Weighted Average
Grant Date
Fair Value Per Share
(in thousands)
Unvested as of January 1, 20211 $616.57 
Granted— $— 
Vested— $— 
Forfeited/canceled(1)$611.47 
Unvested as of February 9, 2021— $— 
Unvested as of January 1, 202052 $709.85 
Granted68 $60.00 
Vested(21)$791.69 
Forfeited(98)$243.13 
Unvested as of December 31, 20201 $616.57 
Unvested as of January 1, 201959 $886.20 
Granted30 $530.44 
Vested(30)$876.18 
Forfeited(7)$744.74 
Unvested as of December 31, 201952 $709.85 
  
Shares of
Unvested
Restricted Stock
 
Weighted Average
Grant Date
Fair Value
  (in thousands)  
Unvested restricted stock as of January 1, 2017 9,092
 $11.39
Granted 9,872
 $5.40
Vested (4,573) $13.73
Forfeited (1,213) $8.32
Unvested restricted stock as of December 31, 2017 13,178
 $6.37
     
Unvested restricted stock as of January 1, 2016 10,455
 $17.31
Granted 4,604
 $4.58
Vested (4,692) $17.23
Forfeited (1,275) $13.91
Unvested restricted stock as of December 31, 2016 9,092
 $11.39
     
Unvested restricted stock as of January 1, 2015 10,091
 $21.20
Granted 7,095
 $13.90
Vested (4,157) $21.70
Forfeited (2,574) $16.98
Unvested restricted stock as of December 31, 2015 10,455
 $17.31
The aggregate intrinsic value of restricted stock that vested during 2017 was approximately $26 million based on the stock price at the time of vesting.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

As of December 31, 2017, there was approximately $47 million of total unrecognized compensation expense related to unvested restricted stock. The expense is expected to be recognized over a weighted average period of approximately 1.88 years.
Stock Options. In 2017, 2016 and 2015,the 2020 Predecessor Period, we granted members of management stock options that vestvested ratably over a three-yearthree-year period. Each stock option award hashad an exercise price equal to the closing price of our common stock on the grant date. Outstanding options expireexpired seven years to ten years from the date of grant.
We utilizeutilized the Black-Scholes option pricingoption-pricing model to measure the fair value of stock options. The expected life of an option iswas determined using the simplified method. Volatility assumptions arewere estimated based on anthe average of historical volatility of Chesapeake stock over the expected life of an option. The risk-free interest rate iswas based on the U.S. Treasury rate in effect at the time of the grant over the expected life of the option. The dividend yield iswas based on an annual dividend yield, taking into account our dividend policy, over the expected life of the option. The Company used the following weighted average assumptions to estimate the grant date fair value of the stock options granted in 2017:
127
Expected option life – years6.0
Volatility62.42%
Risk-free interest rate2.17%
Dividend yield—%
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table provides information related to stock option activity for 2017, 2016 and 2015: the Predecessor periods presented:
Number of
Shares
Underlying  
Options
Weighted
Average
Exercise Price Per Share
Weighted  
Average
Contract Life in Years
Aggregate  
Intrinsic
Value(a)
 
Number of
Shares
Underlying  
Options
 
Weighted
Average
Exercise Price Per Share
 
Weighted  
Average
Contract Life in Years
 
Aggregate  
Intrinsic
Value(a)
(in thousands)($ in millions)
Outstanding as of January 1, 2021Outstanding as of January 1, 202120 $1,429.11 4.27$— 
GrantedGranted— $— 
ExercisedExercised— $— $— 
ExpiredExpired(1)$741.86 
Forfeited/canceledForfeited/canceled(19)$1,452.40 
Outstanding as of February 9, 2021Outstanding as of February 9, 2021— $— — $— 
Exercisable as of February 9, 2021Exercisable as of February 9, 2021— $— — $— 
 (in thousands)   ($ in millions)
Outstanding as of January 1, 2017 8,593
 $11.88
 7.22 $14
Outstanding as of January 1, 2020Outstanding as of January 1, 202090 $1,420.90 5.70$— 
Granted 9,226
 $5.45
  Granted— $— 
Exercised —
 $—
 $—
Exercised— $— $— 
Expired (435) $18.51
  Expired(23)$914.50 
Forfeited (1,099) $9.12
  Forfeited(47)$1,666.21 
Outstanding as of December 31, 2017 16,285
 $8.25
 7.73 $1
Exercisable as of December 31, 2017 4,474
 $15.15
 5.26 $—
Outstanding as of December 31, 2020Outstanding as of December 31, 202020 $1,429.11 4.27$— 
Exercisable as of December 31, 2020Exercisable as of December 31, 202019 $1,439.55 4.35$— 
      
Outstanding as of January 1, 2016 5,377
 $19.37
 5.80 $—
Outstanding as of January 1, 2019Outstanding as of January 1, 201990 $1,440.18 7.15$— 
Granted 4,932
 $3.71
  Granted5 $594.00 
Exercised —
 $—
 $—
Exercised— $— $— 
Expired (771) $19.46
  Expired(2)$1,272.94 
Forfeited (945) $5.66
  Forfeited(3)$793.40 
Outstanding as of December 31, 2016 8,593
 $11.88
 7.22 $14
Exercisable as of December 31, 2016 2,844
 $19.60
 5.53 $—
      
Outstanding as of January 1, 2015 4,599
 $19.55
 7.03 $5
Granted 1,208
 $18.37
  
Exercised (14) $18.13
 $—
Expired (416) $18.46
  
Forfeited —
 $—
  
Outstanding as of December 31, 2015 5,377
 $19.37
 5.80 $—
Exercisable as of December 31, 2015 2,045
 $19.61
 5.07 $—
Outstanding as of December 31, 2019Outstanding as of December 31, 201990 $1,420.90 5.70$— 
Exercisable as of December 31, 2019Exercisable as of December 31, 201965 $1,656.14 4.86$— 

(a)
(a)The intrinsic value of a stock option is the amount by which the current market value or the market value upon exercise of the underlying stock exceeds the exercise price of the option.
As of December 31, 2017, there was $22 milliona stock option is the amount by which the current market value or the market value upon exercise of total unrecognized compensation expense related tothe underlying stock options. The expense is expected to be recognized over a weighted average periodexceeds the exercise price of approximately 2.08 years.the option.
Restricted Stock, and Stock Option, and PSU Compensation. We recognized the following compensation costs, net of actual forfeitures, related to restricted stock, and stock options, and PSUs for the years ended December 31, 2017, 2016 and 2015:periods presented:
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
General and administrative expense$7 $3 $20 $26 
Oil and natural gas properties2 — 1 2 
Oil, natural gas and NGL production expense2 — 1 3 
Exploration expense— — — 1 
Total restricted stock, stock option, and PSU compensation$11 $3 $22 $32 

128
  Years Ended December 31,
  2017 2016 2015
  ($ in millions)
General and administrative expenses $37
 $38
 $43
Oil and natural gas properties 12
 16
 23
Oil, natural gas and NGL production expenses 12
 13
 18
Marketing, gathering and compression expenses —
 1
 5
Total restricted stock and stock option compensation $61
 $68
 $89
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Liability-Classified Awards
Performance Share Units. We have granted PSUs to senior management that vest ratably over a three-year term and are settled in cash on the third anniversary of the awards. The ultimate amount earned is based on achievement of performance metrics established by the Compensation Committee of the Board of Directors, which include total shareholder return (TSR) and, for certain of the awards, operational performance goals, such as finding and development costs and production levels.
For PSUs granted in 2017 and 2016, the TSR component can range from 0% to 100% and the operational component can range from 0% to 100%, resulting in a maximum payout of 200%. For PSUs granted in 2015, the TSR component can range from 0% to 100%, and each of the two operational components can range from 0% to 50% resulting in a maximum total payout of 200%. Compensation expense associated with PSU grants is recognized over the service period based on the graded-vesting method. The value of the PSU awards at the end of each reporting period is dependent upon our estimates of the underlying performance measures. The payout percentage for all PSU grants is capped at 100% if the Company’s absolute TSR is less than zero. We utilized a Monte Carlo simulation for the TSR performance measure and the following assumptions to determine the grant date fair value of the PSUs.
Volatility14.83.97%
Risk-free interest rate1.89%
Dividend yield for value of awards—%
The following table presents a summary of our 2017, 2016 and 2015 PSU awards:
    
Grant Date
Fair Value
 December 31, 2017
  Units  Fair Value Vested Liability
    ($ in millions) ($ in millions)
2017 Awards:        
Payable 2020 1,217,774
 $8
 $5
 $3
2016 Awards:        
Payable 2019 2,348,893
 $10
 $9
 $8
2015 Awards:        
Payable 2018 629,694
 $13
 $1
 $1
PSU Compensation. We recognized the following compensation costs (credits) related to PSUs for the years ended December 31, 2017, 2016 and 2015:
  Years Ended December 31,
  2017 2016 2015
  ($ in millions)
General and administrative expenses $(4) $14
 $(19)
Restructuring and other termination costs —
 1
 (19)
Marketing, gathering and compression —
 —
 (1)
Oil and natural gas properties —
 —
 (2)
Total PSU compensation $(4) $15
 $(41)
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

10.     Employee Benefit Plans
Our qualified 401(k) profit sharing plan (401(k) Plan)(“401(k) Plan”) is the Chesapeake Energy Corporation Savings and Incentive Stock Bonus Plan, which is open to employees of Chesapeake and all our subsidiaries. Eligible employees may elect to defer compensation through voluntary contributions to their 401(k) Plan accounts, subject to plan limits and those set by the IRS. We match employee contributions dollar for dollar (subject to a maximum contribution of 15%6% of an employee's base salary and performance bonus) in cash. In April 2021, the 401(k) match was changed from 15% to 6%. We contributed $35$8 million, $39$2 million, $24 million and $52$29 million to the 401(k) Plan in 2017, 20162021 Successor Period, 2021 Predecessor Period, 2020 Predecessor Period and 2015,2019 Predecessor Period, respectively.
We also maintain a nonqualified deferred compensation plan (DC Plan). To be eligible to participate in the DC Plan, an active employee must have a base salary of at least $150,000, have a hire date on or before December 1, immediately preceding the year in which the employee is able to participate, or be designated as eligible to participate. Only the top 10% of our wage earners are eligible to participate. We match 100% of employee contributions up to 15% of base salary and performance bonus in the aggregate for the DC Plan with Chesapeake common stock, and an employee who is at least age 55 may elect for the matching contributions to be made in any one of the DC Plan’s investment options. The maximum compensation that can be deferred by employees under all of our deferred compensation plans, including the Chesapeake 401(k) Plan, is a total of 75% of base salary and 100% of performance bonus. We contributed $8 million, $9 million and $11 million to the DC Plan during 2017, 2016 and 2015, respectively, to fund the match. Beginning in 2016, the DC Plan was no longer a spillover plan from the 401(k) Plan. The participant may choose separate deferral election percentages for both plans. The deferred compensation company match of 15% has a five-year vesting schedule based on years of service. Any participant who is active on December 31 of the plan year will receive the deferred compensation company match which will be awarded on an annual basis.
Any assets placed in trust by us to fund future obligations of our nonqualified deferred compensation plan is subject to the claims of creditors in the event of insolvency or bankruptcy, and participants are general creditors of the Company as to their deferred compensation in the plan.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

11.15.Derivative and Hedging Activities
We use derivative instruments to reduce our exposure to fluctuations in future commodity prices and to protect our expected operating cash flow against significant market movements or volatility. All of our oil and natural gas and NGL derivative instruments are net settled based on the difference between the fixed-price payment and the floating-price payment, resulting in a net amount due to or from the counterparty. None of our open oil and natural gas and NGL derivative instruments were designated for hedge accounting as of December 31, 20172021 and 2016.2020.
Oil and Natural Gas and NGL Derivatives
As of December 31, 20172021 and 2016,2020, our oil and natural gas and NGL derivative instruments consisted of the following types of instruments:
•Swaps: We receive a fixed price and pay a floating market price to the counterparty for the hedged commodity. In exchange for higher fixed prices on certain of our swap trades, we may sell call options and call swaptions.
swap options.
•Options: We sell, and occasionally buys,buy, call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, we pay the counterparty the excess on sold call options and we receive the excess on bought call options. If the market price settles below the fixed price of the call option, no payment is due from either party.
Call Swaptions: We sell call swaptions to counterparties that allow the counterparty, on a specific date, to extend an existing fixed-price swap for a certain period of time.
•Collars: These instruments contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and payspay the market price. If the market price is between the put and the call strike prices, no payments are due from either party. Three-way collars include the sale by us of an additional put option in exchange for a more favorable strike price on the call option. This eliminates the counterparty’s downside exposure below the second put option strike price.
•Basis Protection Swaps: These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point. We receive the fixed price differential and payspay the floating market price differential to the counterparty for the hedged commodity.
The estimated fair values of our oil, natural gas and NGL derivative instrument assets (liabilities) as of December 31, 2017 and 2016 are provided below: 
129
  December 31, 2017 December 31, 2016
  Notional Volume Fair Value Notional Volume Fair Value
    ($ in millions)     ($ in millions)  
Oil (mmbbl):        
Fixed-price swaps 21
 $(151) 23
 $(140)
Three-way collars 2
 (10) —
 —
Call options —
 —
 5
 (1)
Call swaptions 2
 (13) —
 —
Basis protection swaps 11
 (9) —
 —
Total oil 36
 (183) 28
 (141)
Natural gas (tbtu):        
Fixed-price swaps 532
 149
 719
 (349)
Collars 47
 11
 60
 (9)
Call options 110
 (3) 114
 —
Basis protection swaps 65
 (7) 31
 (5)
Total natural gas 754
 150
 924
 (363)
NGL (mmgal):        
Fixed-price swaps 33
 (2) 53
 —
Total estimated fair value   $(35)   $(504)
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The estimated fair values of our oil and natural gas derivative instrument assets (liabilities) as of December 31, 2021 and 2020 are provided below: 
SuccessorPredecessor
 December 31, 2021December 31, 2020
Notional VolumeFair ValueNotional VolumeFair Value
Oil (mmbbl):
Fixed-price swaps13 $(356)27 $(136)
Basis protection swaps9 (2)7 (1)
Total oil22 (358)34 (137)
Natural gas (bcf):
Fixed-price swaps637 (675)728 10 
Collars205 (82)53 8 
Call options18 (17)— — 
Basis protection swaps252 (11)66 1 
Total natural gas1,112 (785)847 19 
Total estimated fair value$(1,143)$(118)
We have terminated certain commodity derivative contracts that were previously designated as cash flow hedges for which the original contract months are yet to occur. See further discussion below under Effect of Derivative Instruments – Accumulated Other Comprehensive Income (Loss).
Foreign Currency Derivatives
During 2017, both our 6.25% Euro-denominated Senior Notes due 2017 and cross currency swaps for the same principal amount matured. Upon maturity of the notes, the counterparties paid us €246 million and we paid the counterparties $327 million. The terms of the cross currency swaps were based on the dollar/euro exchange rate on the issuance date of $1.3325 to €1.00. The swaps were designated as cash flow hedges and, because they were entirely effective in having eliminated any potential variability in our expected cash flows related to changes in foreign exchange rates, changes in their fair value did not impact earnings. The fair values of the cross currency swaps were recorded on the consolidated balance sheet as a liability of $73 million as of December 31, 2016.
Supply Contract Derivatives

In 2016, we sold a long-term natural gas supply contract to a third party for cash proceeds of $146 million, which is included in marketing, gathering and compression revenues as a realized gain. We reversed the cumulative unrealized gains, resulting in an unrealized loss of $297 million.

Effect of Derivative Instruments – Consolidated Balance Sheets
The following table presents the fair value and location of each classification of derivative instrument included in the consolidated balance sheets as of December 31, 20172021 and 20162020 on a gross basis and after same-counterparty netting:
Gross
Fair Value
Amounts Netted
in the
Consolidated
Balance Sheets
Net Fair Value
Presented in the
Consolidated
Balance Sheets
Successor
As of December 31, 2021
Commodity Contracts:
Short-term derivative asset$56 $(51)$5 
Short-term derivative liability(950)51 (899)
Long-term derivative liability(249)— (249)
Total derivatives$(1,143)$— $(1,143)
Predecessor
As of December 31, 2020
Commodity Contracts:
Short-term derivative asset$84 $(65)$19 
Long-term derivative asset5 (5)— 
Short-term derivative liability(158)65 (93)
Long-term derivative liability(49)5 (44)
Total derivatives$(118)$— $(118)
Balance Sheet Classification 
Gross
Fair Value
 
Amounts Netted
in the
Consolidated
Balance Sheets
 
Net Fair Value
Presented in the
Consolidated
Balance Sheet
  ($ in millions)
As of December 31, 2017      
Commodity Contracts:      
Short-term derivative asset $157
 $(130) $27
Short-term derivative liability (188) 130
 (58)
Long-term derivative liability (4) —
 (4)
Total commodity contracts (35) —
 (35)
Total derivatives $(35) $—
 $(35)
       
As of December 31, 2016      
Commodity Contracts:      
Short-term derivative asset $1
 $(1) $—
Short-term derivative liability (490) 1
 (489)
Long-term derivative liability (15) —
 (15)
Total commodity contracts (504) —
 (504)
Foreign Currency Contracts:(a)
      
Short-term derivative liability (73) —
 (73)
Total foreign currency contracts (73) —
 (73)
Total derivatives $(577) $—
 $(577)

(a)Designated as cash flow hedging instruments.
As of December 31, 20172021 and 2016,2020, we did not have any cash collateral balances for these derivatives.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Effect of Derivative Instruments – Consolidated Statements of Operations
The components of oil and natural gas and NGL revenues for the years ended December 31, 2017, 2016 and 2015derivatives are presented below:
  Years Ended December 31,
  2017 2016 2015
  ($ in millions)
Oil, natural gas and NGL revenues 4,574
 3,866
 4,767
Gains (losses) on undesignated oil, natural gas
and NGL derivatives
 445
 (545) 661
Losses on terminated cash flow hedges (34) (33) (37)
Total oil, natural gas and NGL revenues $4,985
 $3,288
 $5,391
The components of marketing, gathering and compression revenues for the years ended December 31, 2017, 2016 and 2015 are presented below:    
  Years Ended December 31,
  2017 2016 2015
  ($ in millions)
Marketing, gathering and compression revenues $4,511
 $4,881
 $7,077
Losses on undesignated supply contract derivatives —
 (297) 296
Total marketing, gathering and compression revenues $4,511
 $4,584
 $7,373

 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
Gains (losses) on undesignated oil and natural gas derivatives$(1,127)$(379)$629 $40 
Losses on terminated cash flow hedges— (3)(33)(35)
Total oil and natural gas derivatives$(1,127)$(382)$596 $5 
Effect of Derivative Instruments – Accumulated Other Comprehensive Income (Loss)
A reconciliation of the changes in accumulated other comprehensive income (loss) in our consolidated statements of stockholders’ equity related to our cash flow hedges is presented below:
SuccessorPredecessor
Period from February 10, 2021 through December 31, 2021Period from
 January 1, 2021 through
 February 9, 2021		Year Ended December 31, 2020Year Ended December 31, 2019
Before 
Tax  		After 
Tax  		Before 
Tax		After 
Tax		Before 
Tax  		After 
Tax  		Before 
Tax		After 
Tax
Balance, beginning of period$— $— $(12)$45 $(45)$12 $(80)$(23)
Losses reclassified to income— — 3 3 33 33 35 35 
Fresh start adjustments— — 9 9 — — — — 
Elimination of tax effects— — — (57)— — — — 
Balance, end of period$— $— $— $— $(12)$45 $(45)$12 
  Years Ended December 31,
  2017 2016 2015
  Before 
Tax  		 After 
Tax  		 Before 
Tax  		 After 
Tax  		 Before 
Tax  		 After 
Tax  
  ($ in millions)
Balance, beginning of period $(153) $(96) $(160) $(99) $(231) $(143)
Net change in fair value 5
 5
 (27) (13) 32
 20
Losses reclassified to income 34
 34
 34
 16
 39
 24
Balance, end of period $(114) $(57) $(153) $(96) $(160) $(99)
TheOur accumulated other comprehensive loss as of December 31, 2017 representsrepresented the net deferred loss associated with commodity derivative contracts that were previously designated as cash flow hedges for which the original contract months are yet to occur. RemainingThe remaining deferred gain or loss amounts willwere to be recognized in earnings in the month for which the original contract months arewere to occur. AsIn connection with our adoption of December 31, 2017,fresh start accounting, we expectrecorded a fair value adjustment to transfer approximately $17 million of net loss included ineliminate the accumulated other comprehensive income related to net income (loss) duringhedging settlements including the next 12 months. The remaining amounts will be transferred by December 31, 2022.elimination of tax effects. See Note 3 for a discussion of fresh start accounting adjustments.
Credit Risk Considerations
Our derivative instruments expose us to our counterparties’ credit risk. To mitigate this risk, we enter into derivative contracts only with counterparties that are highly rated or deemed by us to have acceptable credit strength and deemed by management to be competent and competitive market-makers, and we attempt to limit our exposure to non-performance by any single counterparty. As of December 31, 2017,2021, our oil and natural gas and NGL derivative instruments were spread among 1110 counterparties.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Hedging Arrangements
Certain of our hedging arrangements are with counterparties that arewere also lenders (or affiliates of lenders) under our revolving credit facility.DIP Credit Facility. The contracts entered into with these counterparties are secured by the same collateral that secures ourthe pre-petition revolving credit facility, which allows us to reduce any letters of credit posted as security with those counterparties. In addition, we enter into bilateral hedging agreements with other counterparties.facility. The counterparties’ and our obligations under the bilateral hedging agreements must be secured by
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cash or letters of credit to the extent that any mark-to-market amounts owed to us or by us exceed defined thresholds. As of December 31, 2021, we did not have any cash or letters of credit posted as collateral for our commodity derivatives.
Fair Value
The fair value of our derivatives is based on third-party pricing models which utilize inputs that are either readily available in the public market, such as oil, natural gas and NGL forward curves and discount rates, or can be corroborated from active markets or broker quotes. These values are compared to the values given by our counterparties for reasonableness. SinceAs our oil, natural gas and NGL and cross currency swapsderivatives do not include optionality and therefore generally have no unobservable inputs, they are classified as Level 2. All other derivatives have some level of unobservable input, such as volatility curves, and are therefore classified as Level 3. Derivatives are also subject to the risk that either party to a contract will be unable to meet its obligations. We factor non-performance risk into the valuation of our derivatives using current published credit default swap rates. To date, this has not had a material impact on the values of our derivatives.
The following table provides information for financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 20172021 and 2016:2020:
SuccessorPredecessor
Significant Other Observable Inputs (Level 2)December 31,
2021		December 31,
2020
Derivative Assets (Liabilities):
Commodity assets$56 $88 
Commodity liabilities(1,199)(206)
Total derivatives$(1,143)$(118)

16.Capitalized Exploratory Well Costs
A summary of the changes in our capitalized exploratory well costs for the periods presented is detailed below. Additions pending the determination of proved reserves excludes amounts capitalized and subsequently charged to expense within the same year.
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
Balance, beginning of period$— $— $7 $36 
Additions pending the determination of proved reserves24 — — 7 
Divestitures and other— — — (3)
Reclassifications to proved properties(10)— — (17)
Charges to exploration expense— — (7)(16)
Balance, end of period$14 $— $— $7 
We had no projects with suspended exploratory well costs capitalized for a period greater than one year as of December 31, 2021, 2020 and 2019, respectively.
132
  
Quoted
Prices in
Active
Markets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2) 
 
Significant
Unobservable
Inputs
(Level 3)
 
Total
Fair Value
    ($ in millions)  
As of December 31, 2017        
Derivative Assets (Liabilities):        
Commodity assets $—
 $—
 $8
 $8
Commodity liabilities —
 (20) (23) (43)
Total derivatives $—
 $(20) $(15) $(35)
         
As of December 31, 2016        
Derivative Assets (Liabilities):        
Commodity assets $—
 $1
 $—
 $1
Commodity liabilities —
 (495) (10) (505)
Foreign currency liabilities —
 (73) —
 (73)
Total derivatives $—
 $(567) $(10) $(577)

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A summary of the changes in the fair values of our financial assets (liabilities) classified as Level 3 during 2017 and 2016 is presented below:
  
Commodity
Derivatives
 
Supply
Contracts
  ($ in millions)
Balance, as of January 1, 2017 $(10) $—
Total gains (losses) (realized/unrealized):    
Included in earnings(a)
 2
 —
Total purchases, issuances, sales and settlements:    
Settlements (7) —
Balance, as of December 31, 2017 $(15) $—
     
Balance, as of January 1, 2016 $(91) $297
Total gains (losses) (realized/unrealized):    
Included in earnings(a)
 6
 (118)
Total purchases, issuances, sales and settlements:    
Settlements 75
 (33)
Sales —
 (146)
Balance, as of December 31, 2016 $(10) $—

(a)  Commodity Derivatives 
Marketing, Gathering
and Compression
Revenue
  
   2017 2016 2017 2016
   ($ in millions)
 Total gains (losses) included in earnings for the period $2
 $6
 $—
 $(118)
 
Change in unrealized gains (losses) related to assets
still held at reporting date
 $(14) $(7) $—
 $—
Qualitative and Quantitative Disclosures about Unobservable Inputs for Level 3 Fair Value Measurements
The significant unobservable inputs for Level 3 derivative contracts include unpublished forward prices of natural gas, market volatility and credit risk of counterparties. Changes in these inputs impact the fair value measurement of our derivative contracts, which is based on an estimate derived from option models. For example, an increase or decrease in the forward prices and volatility of oil and natural gas prices decreases or increases the fair value of oil and natural gas derivatives, and adverse changes to our counterparties’ creditworthiness decreases the fair value of our derivatives. The following table presents quantitative information about Level 3 inputs used in the fair value measurement of our commodity derivative contracts at fair value as of December 31, 2017:
Instrument
Type
 
Unobservable
Input
 Range 
Weighted
Average
 Fair Value
December 31, 2017
        ($ in millions)
Oil trades Oil price volatility curves 13.14% – 24.93% 22.43% $(23)
Natural gas trades 
Natural gas price volatility
curves
 18.82% – 82.61% 38.06% $8

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12.17.Oil and Natural Gas Property Transactions
Under full cost accounting rules, we accounted for the sales of oil and natural gas properties discussed below as adjustments to capitalized costs, with no recognition of gain or loss as the sales did not involve a significant change in proved reserves or significantly alter the relationship between costs and proved reserves.
2017 Transactions
We sold portions of our acreage and producing properties in our Haynesville Shale operating area in northern Louisiana for approximately $915 million, subject to certain customary closing adjustments. Included in the sales were approximately 119,500 net acres and interests in 576 wells that were producing approximately 80 mmcf of gas per day at the time of closing.
We received proceeds of approximately $350 million, net of post-closing adjustments, for the sale of other oil and natural gas properties covering various operating areas.
2016 Transactions
We conveyed our interests in the Barnett Shale operating area located in north central Texas and received from the buyer aggregate net proceeds of approximately $218 million. We sold approximately 212,000 net developed and undeveloped acres along with other property and equipment. We simultaneously terminated most of our future commitments associated with this asset. In connection with this disposition, we paid $361 million to terminate certain natural gas gathering and transportation agreements and paid $58 million to restructure a long-term sales agreement. We recognized $361 million of expense for the termination of contracts and deferred charges of $58 million for the restructured contract. The deferred charges will be amortized to marketing, gathering and compression revenue over the life of the agreement. We may be required to pay additional amounts in respect of certain title and environmental contingencies. Additionally, we recognized a charge of $284 million in 2016 related to the impairment of other fixed assets sold in the divestiture.
We sold the majority of our upstream and midstream assets in the Devonian Shale located in West Virginia, Kentucky and Virginia for proceeds of $140 million. We sold an interest in approximately 1.3 million net acres, retaining all rights below the base of the Kope formation, and approximately 5,300 wells along with related gathering assets, and other property and equipment. Additionally, we recognized an impairment charge of $142 million in 2016 related to other fixed assets sold in the divestiture. In connection with this divestiture, we purchased the underlying interests in one of our remaining VPP transactions for $127 million. All of the acquired interests were conveyed in our divestiture and we no longer have any future obligations related to this VPP.
We acquired oil and natural gas properties in the Haynesville Shale for approximately $85 million.
We sold certain of our other noncore oil and natural gas properties for net proceeds of approximately $1.048 billion, after post-closing adjustments. In conjunction with certain of these sales, we purchased oil and natural gas interests previously sold to third parties in connection with four of our VPP transactions for approximately $259 million. Substantially all of the acquired interests were part of the asset divestitures discussed above and we no longer have any further commitments or obligations related to these VPPs. The asset divestitures cover various operating areas.
2015 Transactions
CHK Cleveland Tonkawa, L.L.C. (CHK C-T) sold all of its oil and natural gas properties to FourPoint Energy, LLC and immediately used the consideration, plus other cash it had on hand, to repurchase and cancel all of CHK C-T’s outstanding preferred shares. In a related transaction, we sold noncore properties adjacent to the CHK C-T properties to FourPoint Energy, LLC for approximately $90 million.
Excluding proceeds received from selling additional interests in our joint venture leasehold described under Joint Ventures below, we received proceeds related to divestitures of other noncore oil and natural gas properties of approximately $66 million.
Joint Ventures
In 2017, 2016 and 2015, we sold interests in additional leasehold we acquired in the Marcellus, Barnett, Utica, Eagle Ford shales and Mid-Continent plays to our joint venture partners for approximately $10 million, $7 million and $33 million, respectively.
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Volumetric Production Payments
A VPP is 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 non-recourse 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 all production beyond the specified volumes, if any, after the scheduled production volumes have been delivered. If contractually scheduled volumes exceed the actual volumes produced from the VPP wellbores that are attributable to the ORRI conveyed, either the shortfall will be made up from future production from these wellbores (or, at our option, from our retained interest in the wellbores) through an adjustment mechanism, or the initial term of the VPP will be extended until all scheduled volumes, to the extent produced, are delivered from the VPP wellbores to the VPP buyer. We retain drilling rights on the properties below currently producing intervals and outside of producing wellbores.
As the operator of the properties from which the VPP volumes have been sold, we bear the cost of producing the reserves attributable to these interests, which we include as a component of production expenses and production taxes in our consolidated statements of operations in the periods these costs are incurred. As with all non-expense-bearing royalty interests, volumes conveyed in a VPP transaction are excluded from our estimated proved reserves; however, the estimated production expenses and taxes associated with VPP volumes expected to be delivered in future periods are included as a reduction of the future net cash flows attributable to our proved reserves for purposes of determining our full cost ceiling test for impairment purposes and in determining our standardized measure. Our commitment to bear the costs on any future production of VPP volumes is not reflected as a liability on our balance sheet. Future costs will depend on the actual production volumes as well as the production costs and taxes in effect during the periods in which the production actually occurs, which could differ materially from our current and historical costs, and production may not occur at the times or in the quantities projected, or at all.
We have committed to purchase natural gas and liquids associated with our VPP transactions. Production purchased under these arrangements is based on market prices at the time of production, and the purchased natural gas and liquids are resold at market prices.
In connection with certain asset divestitures in 2016, we purchased the remaining oil and natural gas interests previously sold in connection with VPP #10, VPP #4, VPP #3, VPP #2 and VPP #1. A majority of the oil and natural gas interests purchased were subsequently sold to the buyers of the assets. VPP#8 expired in August 2015.
As of December 31, 2017, we had the following VPP outstanding:
        Volume Sold
VPP # Date of VPP         Location Proceeds Oil Natural Gas NGL Total
      ($ in millions) (mmbbl)  (bcf) (mmbbl) (bcfe)
9 May 2011 Mid-Continent $853
 1.7
 138
 4.8
 177
The volumes remaining to be delivered on behalf of our VPP buyers as of December 31, 2017 were as follows:
    Volume Remaining as of December 31, 2017
VPP # Term Remaining Oil Natural Gas NGL Total
  (in months)  (mmbbl)  (bcf)  (mmbbl)  (bcfe)
9 38 0.4
 34.1
 0.9
 41.7
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13.Other Property and Equipment
Other Property and Equipment
A summary of other property and equipment held for use and the estimated useful lives thereof is as follows:
SuccessorPredecessor
Estimated
Useful
Life
December 31,
2021		December 31,
2020
(in years)
Buildings and improvements$330 $1,038 10 – 39
Computer equipment87 356 5
Land37 113 
Sand mine2 81 10 – 30
Natural gas compressors(a)
— 36 3 – 20
Other39 130 5 – 20
Total other property and equipment, at cost495 1,754 
Less: accumulated depreciation(26)(799)
Total other property and equipment, net$469 $955 

  December 31, 
Estimated
Useful
Life
  2017 2016 
  ($ in millions) (in years)
Buildings and improvements $1,093
 $1,119
 10 – 39
Computer equipment 345
 337 5
Natural gas compressors 235
 251 3 – 20
Land 126
 139
  
Gathering systems and treating plants 2
 2
 20
Other 185
 205
 5 – 10
Total other property and equipment, at cost 1,986
 2,053
  
Less: accumulated depreciation (672) (632)  
Total other property and equipment, net $1,314
 $1,421
  
Net (Gains) Losses on Sales(a)    Includes assets under finance lease of Fixed Assets
A summary by asset class$27 million, less accumulated depreciation of (gains) or losses on sales of fixed assets for the years ended December 31, 2017, 2016 and 2015 is as follows:
  Years Ended December 31,
  2017 2016 2015
  ($ in millions)
Buildings and land $(4) $(1) $3
Natural gas compressors 1
 (10) —
Gathering systems and treating plants —
 —
 1
Other —
 (1) —
Total net (gains) losses on sales of fixed assets $(3) $(12) $4
Assets Held for Sale
We are continuing to pursue the sale of buildings and land located primarily in Oklahoma and West Virginia. These assets are being actively marketed, and we believe it is probable they will be sold over the next 12 months. As a result, these assets are reflected as held for sale$18 million as of December 31, 2017. Oil2020. The related amortization expense for assets under finance lease is included in depreciation, depletion and natural gas properties that we intend to sell are not presentedamortization expense on our consolidated statement of operations. The lease contract was renegotiated as held for sale pursuantpart of our bankruptcy process and the changes to the rules governing full cost accountingcontract resulted in the reclassification of the finance lease as an operating lease in March 2021.
18.Investments
FTS International, Inc. (NYSE: FTSI). In the 2019 Predecessor Period, the hydraulic fracturing industry experienced challenging operating conditions resulting in the fair value of our investment in FTSI falling below book value of $65 million and remaining below that amount as of the end of the year. Based on FTSI’s 2019 operating results and FTSI’s share price of $1.04 per share as of December 31, 2019, we determined that the reduction in fair value was other-than-temporary, and recognized an impairment of our investment in FTSI of approximately $43 million.
In the 2020 Predecessor Period, FTSI filed for oilChapter 11 bankruptcy and gas properties.we recognized an impairment of our entire investment of $23 million. FTSI emerged from bankruptcy on November 19, 2020, and this restructuring resulted in a reduction of the common stock we owned in FTSI from 20% to less than 2%. The decreased ownership percentage and the loss of significant influence required us to measure the investment at fair value as of December 31, 2020.
In the 2021 Successor Period, FTSI announced it would be acquired in an all cash deal that is expected to close in 2022. As of December 31, 20172021, the investment continues to be measured at fair value.
JWH Midstream LLC. In the 2019 Predecessor Period, in connection with the acquisition of WildHorse, we obtained a 50% membership interest in JWH Midstream LLC (“JWH”). The carrying value of our investment in JWH, which was being accounted for as an equity method investment, was approximately $17 million. In the 2019 Predecessor Period, we paid approximately $7 million to terminate our involvement in the partnership. This removed us from any future obligations related to this joint venture and, 2016,therefore, we had $16impaired the full value of the investment and recognized approximately $24 million and $29 million, respectively, of buildings, land and compressors net of accumulated depreciation, classified as assets held for sale on our consolidated balance sheets.impairment expense in the 2019 Predecessor Period.
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14.19.Impairments
Impairments of Oil and Natural Gas Properties
A summary of our impairments of oil and natural gas properties for the periods presented is as follows:
SuccessorPredecessor
Period from February 10, 2021 through December 31, 2021Period from January 1, 2021 through February 9, 2021Year Ended December 31, 2020Year Ended December 31, 2019
Total impairments of oil and natural gas properties$— $— $8,446 $8 
During the 2020 Predecessor Period, the decrease in demand for crude oil primarily due to the combined impacts of COVID-19 and the OPEC+ production increases resulted in decreases in then current and then expected long-term crude oil and NGL sale prices. These conditions resulted in reductions to the market capitalization of peer companies in the energy industry. We determined these adverse market conditions represented a triggering event to perform an impairment assessment of our long-lived assets used in, and in support of, our operations, including proved oil and gas properties, and our sand mine assets.
Proved Oil and Gas Properties
Our impairment test involved a Step 1 assessment to determine if the net book value of our proved oil and natural gas properties is expected to be recovered from the estimated undiscounted future cash flows.
•We calculated the expected undiscounted future net cash flows of our long-lived assets using management’s assumptions and expectations of (i) commodity prices, which are subject to quarterly full cost ceiling tests. Underbased on the ceiling test, capitalizedNYMEX strip pricing escalated by an inflationary rate (ii) pricing adjustments for differentials, (iii) operating costs, less accumulated amortization(iv) capital investment plans, (v) future production volumes, and related deferred income taxes, may not exceed an amount equal(vi) estimated proved reserves.

•Unprecedented volatility in the price of oil due to the sum ofdecrease in demand led us to rely on NYMEX strip pricing, which represents a Level 1 input.
Certain oil and gas properties in our Eagle Ford, Powder River Basin, and Mid-Continent and other non-core operating areas failed the present value of estimatedStep 1 assessment. For these assets, we used a discounted cash flow analysis to estimate fair value. The expected future net revenues (adjusted for cash flow hedges) lessflows were discounted using a rate of 11%, which we believe represents the estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. Estimated future net revenues for the quarterly ceiling limit are calculated using theweighted average cost of commodity pricescapital of a theoretical market participant. Based on the first dayStep 2 of the month over the trailing 12-month period. In 2017,our long-lived assets impairment test, we did not haverecognized an $8.446 billion impairment for our oil and natural gas properties. In 2016 and 2015, capitalized costs of oil and natural gas properties exceeded the ceiling, resulting in an impairment inbecause the carrying value exceeded estimated fair market value as of our oilMarch 31, 2020.
•Significant inputs associated with the calculation of discounted future net cash flows include estimates of (i) recoverable reserves, (ii) production rates, (iii) future operating and natural gas propertiesdevelopment costs, (iv) future commodity prices escalated by an inflationary rate, adjusted for differentials, and (v) a market-based weighted average cost of $2.564 billioncapital. We utilized NYMEX strip pricing, adjusted for differentials, to value the reserves. The NYMEX strip pricing inputs used are classified as Level 1 fair value assumptions and $18.238 billion, respectively.all other inputs are classified as Level 3 fair value assumptions.
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Impairments of Fixed Assets and Other
We review our long-lived assets, other than oil and natural gas properties, for recoverability whenever events or changes in circumstances indicate that carrying amounts may not be recoverable. We recognize an impairment if the carrying amount of a long-lived asset is not recoverable and exceeds its fair value. A summary of our impairments of fixed assets by asset class and other charges for the years ended December 31, 2017, 2016Successor and 2015Predecessor Periods is as follows:
SuccessorPredecessor
Period from February 10, 2021 through December 31, 2021Period from January 1, 2021 through February 9, 2021Year Ended December 31, 2020Year Ended December 31, 2019
Sand mine$— $— $76 $— 
Natural gas compressors— — 13 — 
Buildings and land— — — 1 
Other1 — — 2 
Total impairments of fixed assets and other$1 $— $89 $3 
  Years Ended December 31,
  2017 2016 2015
  ($ in millions)
Barnett Shale exit costs $—
 $645
 $—
Devonian Shale exit costs —
 142
 —
Gathering systems —
 3
 —
Natural gas compressors —
 21
 21
Buildings and land 5
 11
 —
Other charges 416
 16
 173
Total impairments of fixed assets and other $421
 $838
 $194
Barnett Shale Exit Costs. In 2016, we conveyed our interests in the Barnett Shale operating area located in north central Texas and simultaneously terminated most of our future commitments associated with this asset. As a result of this transaction, we recognized $361 million of charges related to the termination of natural gas gathering and transportation agreements. We also recognized an impairment charge of $284 million in 2016 related to other fixed assets sold in the divestiture.
Devonian Shale Exit Costs. In 2016, we sold the majority of our upstream and midstream assets in the Devonian Shale located in West Virginia and Kentucky. We recognized an impairment charge of $142 million in 2016 related to other fixed assets sold in the divestiture.
Natural Gas Compressors. In 2016,2020 Predecessor Period, we recorded a $13$76 million impairment related to obsolescence of 205 compressors. Additionally, we recorded an $8 million impairment related to 155 compressorsour sand mine assets that support our Eagle Ford operating area for the difference between the aggregate sales pricefair value and carrying value.value of the assets as well as a $13 million impairment of compressor inventory due to a lack of a current market for compressors.
Other. In 2017, we terminated future
20.Exploration Expense
A summary of our exploration expense for the Successor and Predecessor Periods is as follows:
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
Impairments of unproved properties$1 $2 $411 $32 
Dry hole expense1 — 7 25 
Geological and geophysical expense and other5 — 9 27 
Exploration expense$7 $2 $427 $84 
Unproved oil and natural gas transportation commitmentsproperties are periodically assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the projects. The exploration expense charges during the 2020 Predecessor Period are primarily the result of non-cash impairment charges in unproved properties, primarily in our Eagle Ford, Haynesville, Powder River Basin and Mid-Continent operating areas. The decrease in geological and geophysical expense in the 2021 Successor Period, 2021 Predecessor Period and 2020 Predecessor Period was due to fewer exploratory geological and geophysical projects.
21.Other Operating Expense (Income), Net
In the 2021 Successor Period, we recognized approximately $59 million of costs related to divested assetsour acquisition of Vine, which included consulting fees, financial advisory fees, and legal fees. Additionally, we recognized approximately $36 million of severance expense as a result of the Vine Acquisition, which included $15 million of cash severance and $21 million of non-cash severance, primarily related to the issuance of New Common Stock for cash paymentsthe acceleration of $126 million. In 2017, we also paid $290 millioncertain Vine restricted stock unit awards. A majority of Vine executives and employees were terminated on the date of the acquisition. These executives and employees were entitled to assign an oil transportation agreement to a third party.severance benefits in accordance with existing employment agreements.
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In the 2020 Predecessor Period, we terminated certain gathering, processing and transportation contracts and recognized a non-recurring $80 million expense related to the contract terminations. The contract terminations removed approximately $169 million of future commitments related to gathering, processing and transportation agreements. Additionally, we recognized $9 million of expense related to the impairment of sand mine inventory and $42 million of other operating expense primarily related to royalty settlements and other legal matters offset by $51 million of income from the amortization of VPP deferred revenue. In the 2020 Predecessor Period, we sold the assets related to our remaining volumetric production payment and extinguished the liability related to the production volume delivery obligation.
In 2015,the 2019 Predecessor Period, we recorded a $47approximately $37 million loss contingencyof costs related to contract disputes.our acquisition of WildHorse which consisted of consulting fees, financial advisory fees, legal fees and travel and lodging expenses. In 2015,addition, we recorded a $22approximately $38 million impairment of a note receivableseverance expense as a result of the increased credit risk associatedacquisition of WildHorse. A majority of the WildHorse executives and employees were terminated on the date of acquisition. These executives and employees were entitled to severance benefits in accordance with declining commodity prices. existing employment agreements.
22.Separation and Other Termination Costs
In addition, under the terms2021 Successor Period and 2021 Predecessor Period, we incurred charges in of our joint venture agreements,approximately $11 million and $22 million, respectively, related to one-time termination benefits for certain employees. In the 2020 Predecessor Period and 2019 Predecessor Period, we are required to extend, renew or replace certain expiring joint leasehold, at our cost, to ensure that the net acreage is maintained in certain designated areas. In 2015, we entered into a settlement with Total regarding our acreage maintenance commitment in our Barnett Shale joint venture and accrued a $70 million charge. In 2015, as a result of reductions in our planned drilling activity in response to declines in oil and natural gas prices, we terminated contracts with drilling contractors and incurred charges of $18 million.
Nonrecurring Fair Value Measurements. Fair value measurementsapproximately $44 million and $12 million, respectively, related to one-time termination benefits for certain of the impairments were based on recent sales information for comparable assets. As the fair value was estimated using the market approach based on recent prices from orderly sales transactions for comparable assets between market participants, these values were classified as Level 2 in the fair value hierarchy. Other inputs used were not observable in the market; these values were classified as Level 3 in the fair value hierarchy.employees.
15.23.Restructuring and Other Termination CostsAsset Retirement Obligations
Workforce Reductions
In 2016, we recognized $6The components of the change in our asset retirement obligations are shown below:
SuccessorPredecessor
Period from February 10, 2021 through December 31, 2021Period from January 1, 2021 through February 9, 2021Year Ended December 31,
2020
Asset retirement obligations, beginning of period$241 $144 $211 
Additions(a)
48 — 1 
Revisions (b)
63 — (14)
Settlements and disposals(c)
(3)(1)(66)
Accretion expense11 1 12 
Impact of fresh start accounting— 97 — 
Asset retirement obligations, end of period360 241 144 
Less current portion11 5 5 
Asset retirement obligations, long-term$349 $236 $139 

(a)    During the 2021 Successor Period, approximately $44 million of charges relatedadditions relate to a reductionthe acquisition of workforce in connection with the restructuring of our compressor manufacturing subsidiary and the reductions of workforce resulting from the conveyance of our interests in the Barnett Shale and Devonian Shale operating areas.
On September 29, 2015, we reduced our workforce by approximately 15% as part of an overall plan to reduce costs and better align our workforce with the needs of our business and current oil and natural gas commodity prices. In connection with the reduction, we incurred a total charge of approximately $55 million in 2015Vine. See Note 4 for one-time termination benefits. This charge consisted of $47 million in salary expense and $8 million in other termination benefits.
Other
We recognized credits of $19 million in 2015 related to negative fair value adjustments to PSUs granted to former executives of the Company which corresponded to a decrease in the trading price of our common stock. For further discussion of these transactions.
(b)    Revisionsprimarily represent changes in the present value of liabilities resulting from changes in estimated costs and economic lives of producing properties.
(c)    During the 2020 Predecessor Period, approximately $49 million and $14 million of disposals related to our PSUs, see Mid-Continent and Haynesville assets, respectively. See Note 9.4 for further discussion of these transactions.
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16.24.Fair Value MeasurementsMajor Customers
Recurring Fair Value Measurements
Other Current Assets. Assets relatedFor the 2021 Successor Period, sales to our deferred compensation plan are included inValero 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 current assets. The fair value of these assets is determined using quoted market prices as they consist of exchange-traded securities.
Other Current Liabilities. Liabilities related to our deferred compensation plan are included in other current liabilities. The fair values of these liabilities are determined using quoted market prices as the plan consists of exchange-traded mutual funds.
Financial Assets (Liabilities). The following table provides fair value measurement informationpurchasers accounted for the above-noted financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2017 and 2016:
  
Quoted
Prices in
Active
Markets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2) 
 
Significant
Unobservable
Inputs
(Level 3)
 
Total
Fair Value
  ($ in millions)
As of December 31, 2017        
Financial Assets (Liabilities):        
Other current assets $57
 $—
 $—
 $57
Other current liabilities (60) —
 —
 (60)
Total $(3) $—
 $—
 $(3)
         
As of December 31, 2016        
Financial Assets (Liabilities):        
Other current assets $49
 $—
 $—
 $49
Other current liabilities (51) —
 —
 (51)
Total $(2) $—
 $—
 $(2)
See Note 3 for information regarding fair value measurementmore than 10% of our debt instruments. See Note 11 for information regarding fair value measurement of our derivatives.total revenues during the 2021 Successor Period or 2021, 2020 or 2019 Predecessor Periods.
Nonrecurring Fair Value Measurements
See Note 14 regarding nonrecurring fair value measurements.
17.25.Asset Retirement ObligationsSubsequent Events

On January 24, 2022, Chesapeake entered into definitive agreements 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 componentscash portion of the changetransaction will be financed with cash on hand and the use of our Exit Credit Facility. The transaction, which is subject to customary closing conditions, including certain regulatory approvals, is expected to close by the end of the first quarter of 2022. In January 2022, we announced our intent to increase the base quarterly dividend to $0.50 per share beginning in our asset retirement obligations are shown below:the second quarter of 2022, reflecting the cash flow accretion of the transaction.

Additionally, on January 24, 2022, Chesapeake signed an agreement to sell its Powder River Basin assets in Wyoming to Continental Resources, Inc. (NYSE: CLR) 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. At closing, net proceeds from the sale will go toward the purchase price of the Chief Acquisition. The Powder River Basin assets were not classified as held for sale as of December 31, 2021, as the agreement had not been finalized and formal authorization from Chesapeake’s Board of Directors had not yet been obtained.

137
  Years Ended December 31,
  2017 2016
  ($ in millions)
Asset retirement obligations, beginning of period $261
 $473
Additions 5
 4
Revisions (34) (58)
Settlements and disposals (70) (182)
Accretion expense 15
 24
Asset retirement obligations, end of period 177
 261
Less current portion 15
 14
Asset retirement obligation, long-term $162
 $247
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18.Major CustomersSupplemental Disclosures About Oil, Natural Gas and NGL Producing Activities (unaudited)
Sales to Royal Dutch Shell PLC constituted approximately 10% of our total revenues (before the effects of hedging) for the year ended December 31, 2017. Sales to BP PLC constituted approximately 10% and 14% of our total revenues (before the effects of hedging) for the years ended December 31, 2016 and 2015, respectively.
19.Condensed Consolidating Financial Information
Chesapeake Energy Corporation is a holding company, owns no operating assets and has no significant operations independent of its subsidiaries. Our obligations under our outstanding senior notes and contingent convertible senior notes listed in Note 3 are fully and unconditionally guaranteed, jointly and severally, by certain of our 100% owned subsidiaries on a senior unsecured basis. Subsidiaries with noncontrolling interests, consolidated variable interest entities and certain de minimis subsidiaries are non-guarantors.
The tables below are condensed consolidating financial statements for Chesapeake Energy Corporation (parent) on a stand-alone, unconsolidated basis, and its combined guarantor and combined non-guarantor subsidiaries as of December 31, 2017 and for the year ended December 31, 2017. This financial information may not necessarily be indicative of our results of operations, cash flows or financial position had these subsidiaries operated as independent entities.
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CONDENSED CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 2017
($ in millions)
  Parent   
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 Eliminations Consolidated
CURRENT ASSETS:          
Cash and cash equivalents $5
 $1
 $2
 $(3) $5
Other current assets 154
 1,364
 3
 (1) 1,520
Intercompany receivable, net 8,697
 436
 —
 (9,133) —
Total Current Assets 8,856
 1,801
 5
 (9,137) 1,525
PROPERTY AND EQUIPMENT:          
Oil and natural gas properties at cost,
based on full cost accounting, net
 435
 8,888
 27
 —
 9,350
Other property and equipment, net —
 1,314
 —
 —
 1,314
Property and equipment
held for sale, net
 —
 16
 —
 —
 16
Total Property and Equipment,
Net
 435
 10,218
 27
 —
 10,680
LONG-TERM ASSETS:          
Other long-term assets 52
 168
 —
 —
 220
Investments in subsidiaries and
intercompany advances
 806
 (146) —
 (660) —
TOTAL ASSETS $10,149
 $12,041
 $32
 $(9,797) $12,425
           
CURRENT LIABILITIES:          
Current liabilities $190
 $2,168
 $2
 $(4) $2,356
Intercompany payable, net 433
 8,648
 52
 (9,133) —
Total Current Liabilities 623
 10,816
 54
 (9,137) 2,356
LONG-TERM LIABILITIES:          
Long-term debt, net 9,921
 —
 —
 —
 9,921
Other long-term liabilities 101
 419
 —
 —
 520
Total Long-Term Liabilities 10,022
 419
 —
 —
 10,441
EQUITY:          
Chesapeake stockholders’ equity (deficit) (496) 806
 (146) (660) (496)
Noncontrolling interests —
 —
 124
 —
 124
Total Equity (Deficit) (496) 806
 (22) (660) (372)
TOTAL LIABILITIES AND EQUITY $10,149
 $12,041
 $32
 $(9,797) $12,425

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
YEAR ENDED DECEMBER 31, 2017
($ in millions)
  Parent   
Guarantor
Subsidiaries
 
Non-
Guarantor
Subsidiaries
 Eliminations Consolidated
REVENUES:          
Oil, natural gas and NGL $—
 $4,962
 $23
 $—
 $4,985
Marketing, gathering and compression —
 4,511
 —
 —
 4,511
Total Revenues —
 9,473
 23
 —
 9,496
OPERATING EXPENSES:          
Oil, natural gas and NGL production —
 562
 —
 —
 562
Oil, natural gas and NGL gathering, processing and transportation —
 1,463
 8
 —
 1,471
Production taxes —
 88
 1
 —
 89
Marketing, gathering and compression —
 4,598
 —
 —
 4,598
General and administrative 1
 259
 2
 —
 262
Restructuring and other termination costs —
 —
 —
 —
 —
Provision for legal contingencies, net (79) 41
 —
 —
 (38)
Oil, natural gas and NGL depreciation,
depletion and amortization
 —
 909
 4
 —
 913
Depreciation and amortization of other
assets
 —
 82
 —
 —
 82
Impairments of fixed assets and other —
 421
 —
 —
 421
Net gains on sales of fixed assets —
 (3) —
 —
 (3)
Total Operating Expenses (78) 8,420
 15
 —
 8,357
INCOME FROM OPERATIONS 78
 1,053
 8
 —
 1,139
OTHER INCOME (EXPENSE):          
Interest expense (424) (2) —
 —
 (426)
Gains on purchases or exchanges of debt 233
 —
 —
 —
 233
Other income 1
 8
 —
 —
 9
Equity in net earnings (losses) of subsidiary 1,063
 4
 —
 (1,067) —
Total Other Income (Expense) 873
 10
 —
 (1,067) (184)
INCOME BEFORE INCOME TAXES 951
 1,063
 8
 (1,067) 955
INCOME TAX EXPENSE (BENEFIT) 2
 —
 —
 —
 2
NET INCOME 949
 1,063
 8
 (1,067) 953
Net income attributable to
noncontrolling interests
 —
 —
 (4) —
 (4)
NET INCOME ATTRIBUTABLE
TO CHESAPEAKE
 949
 1,063
 4
 (1,067) 949
Other comprehensive income —
 39
 —
 —
 39
COMPREHENSIVE INCOME
ATTRIBUTABLE TO CHESAPEAKE
 $949
 $1,102
 $4
 $(1,067) $988



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31, 2017
($ in millions)
  Parent   
Guarantor
Subsidiaries
 
Non-
Guarantor
Subsidiaries
 Eliminations Consolidated
CASH FLOWS FROM
OPERATING ACTIVITIES:
          
Net Cash Provided By
Operating Activities
 $5
 $736
 $14
 $(10) $745
           
CASH FLOWS FROM
INVESTING ACTIVITIES:
          
Drilling and completion costs —
 (2,186) —
 —
 (2,186)
Acquisitions of proved and unproved properties —
 (285) —
 —
 (285)
Proceeds from divestitures of proved and unproved properties —
 1,249
 —
 —
 1,249
Additions to other property and equipment —
 (21) —
 —
 (21)
Other investing activities —
 55
 —
 —
 55
Net Cash Used In
Investing Activities
 —
 (1,188) —
 —
 (1,188)
           
CASH FLOWS FROM
FINANCING ACTIVITIES:
          
Proceeds from revolving credit facility borrowings 7,771
 —
 —
 —
 7,771
Payments on revolving credit facility borrowings (6,990) —
 —
 —
 (6,990)
Proceeds from issuance of senior notes, net 1,585
 —
 —
 —
 1,585
Cash paid to purchase debt (2,592) —
 —
 —
 (2,592)
Cash paid for preferred stock dividends (183) —
 —
 —
 (183)
Other financing activities (39) (5) (13) 32
 (25)
Intercompany advances, net (456) 456
 —
 —
 —
Net Cash Provided by (Used In)
Financing Activities
 (904) 451
 (13) 32
 (434)
Net increase (decrease) in cash and cash equivalents (899) (1) 1
 22
 (877)
Cash and cash equivalents,
beginning of period
 904
 2
 1
 (25) 882
Cash and cash equivalents, end of period $5
 $1
 $2
 $(3) $5


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

20.Subsequent Events
Subsequent to December 31, 2017, we underwent a reduction in workforce impacting approximately 13% of employees across all functions, primarily on our Oklahoma City campus.
Subsequent to December 31, 2017, we sold approximately 4.3 million shares of FTSI International for net proceeds of approximately $74 million. We continue to hold approximately 22.0 million shares in the publicly traded company.
Subsequent to December 31, 2017, we entered into agreements for the sale of properties in the Mid-Continent, including our Mississippian Lime assets, for expected aggregate proceeds of approximately $500 million. We expect to close these sales by the end of the 2018 second quarter, subject to customary closing conditions.
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Quarterly Financial Data (unaudited)
Summarized unaudited quarterly financial data for 2017 and 2016 are as follows:
  
2017
First Quarter
 
2017
Second Quarter
 
2017
Third Quarter
 
2017
Fourth Quarter
  ($ in millions except per share data)
Total revenues $2,753
 $2,281
 $1,943
 $2,519
Income from operations $241
 $399
 $94
 $405
Net income (loss) attributable to
Chesapeake
 $140
 $494
 $(18) $333
Net income (loss) available to common stockholders $75
 $470
 $(41) $309
         
Net income (loss) per common share:        
Basic $0.08
 $0.52
 $(0.05) $0.34
Diluted $0.08
 $0.47
 $(0.05) $0.33

  
2016
First Quarter
 
2016
Second Quarter
 
2016
Third Quarter
 
2016
Fourth Quarter
  ($ in millions except per share data)
Total revenues $1,953
 $1,622
 $2,276
 $2,021
Loss from operations $(1,099) $(1,783) $(1,234) $(295)
Net loss attributable to
Chesapeake(a)
 $(1,061) $(1,775) $(1,212) $(342)
Net loss available to common stockholders(a)
 $(1,104) $(1,817) $(1,254) $(740)
         
Net loss per common share:        
Basic(a)
 $(1.65) $(2.51) $(1.61) $(0.83)
Diluted(a)
 $(1.65) $(2.51) $(1.61) $(0.83)

(a) During our review of the carrying amount of the Trust’s noncontrolling interests, we identified errors related to the allocation of impairment expense between Chesapeake and the Trust’s noncontrolling interests during previously reported periods. See Note 8 for additional information.
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Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities (unaudited)
Net Capitalized Costs
Capitalized costs related to our oil, natural gas and NGL producing activities are summarized as follows:
 December 31,
 2017 2016SuccessorPredecessor
 ($ in millions)December 31,
2021		December 31,
2020
Oil and oil and natural gas properties:    Oil and oil and natural gas properties:
Proved $68,858
 $66,451
 Proved$7,682 $25,734 
Unproved 3,484
 4,802
 Unproved1,530 1,550 
Total 72,342
 71,253
 Total9,212 27,284 
Less accumulated depreciation, depletion and amortization (62,992) (62,094) Less accumulated depreciation, depletion and amortization(882)(23,007)
Net capitalized costs $9,350
 $9,159
 Net capitalized costs$8,330 $4,277 
Unproved properties not subject to amortization as of December 31, 20172021 and 2016,2020, consisted mainly of leasehold acquired through direct purchases of significant oil and natural gas property interests. We capitalized approximately $194 million, $242 million and $410 million of interest during 2017, 2016 and 2015, respectively, on significant investments in unproved properties that were not yet included in the amortization base of the full cost pool. We will continue to evaluate our unproved properties, and although the timing of the ultimate evaluation or disposition of the properties cannot be determined, we can expect the majority of our unproved properties not held by production to be transferred into the amortization base over the next five years.
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development
Costs incurred in oil and natural gas property acquisition, exploration and development, activities which have beenincluding capitalized interest and asset retirement costs, are summarized as follows:
SuccessorPredecessor
 Years Ended December 31,Period from February 10, 2021 through December 31, 2021Period from January 1, 2021 through February 9, 2021Year Ended December 31, 2020Year Ended December 31, 2019
 2017 2016 2015
 ($ in millions)
Acquisition of Properties:      
Acquisition of Properties(a):
Acquisition of Properties(a):
Proved properties $23
 $403
 $—
Proved properties$2,183 $— $3 $3,264 
Unproved properties 271
 403
 454
Unproved properties1,121 — 6 792 
Exploratory costs 21
 52
 112
Exploratory costs31 — 8 42 
Development costs 2,146
 1,312
 2,941
Development costs717 58 887 2,177 
Costs incurred(a)(b)
 $2,461
 $2,170
 $3,507
Costs incurredCosts incurred$4,052 $58 $904 $6,275 

(a)
Exploratory and development costs are net of $51 million in drilling and completion carries received from our joint venture partners during 2015.
(b)Includes capitalized interest and asset retirement obligations as follows:
Capitalized interest $194
 $242
 $410
Asset retirement obligations(c)
 $(34) $(57) $(15)
(c)    Includes revisions as a result$2.181 billion and $1.118 billion of lower pluggingproved and abandonment costsunproved property acquisitions, respectively, related to our acquisition of Vine in some of our operating areas.
In 2017, we invested approximately $793 million to convert 125 mmboe of PUDs to proved developed reserves.2021.
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Results of Operations from Oil, Natural Gas and NGL Producing Activities
Our results of operations from oil, natural gas and NGL producing activities are presented below for 2017, 2016 and 2015. The following table includes revenues and expenses associated directly with our oil, natural gas and NGL producing activities.activities for the periods presented. It does not include any interest costs or indirect general and administrative costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of our oil, natural gas and NGL operations.
 Years Ended December 31,
 2017 2016 2015SuccessorPredecessor
 ($ in millions)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, natural gas and NGL sales $4,985
 $3,288
 $5,391
Oil, natural gas and NGL sales$4,401 $398 $2,745 $4,517 
Oil, natural gas and NGL production expenses (562) (710) (1,046)
Oil, natural gas and NGL gathering, processing and
transportation expenses
 (1,471) (1,855) (2,119)
Production taxes (89) (74) (99)
Oil and natural gas derivatives and VPP revenueOil and natural gas derivatives and VPP revenue(1,127)(382)652 68 
Production expensesProduction expenses(297)(32)(373)(520)
Gathering, processing and transportation expensesGathering, processing and transportation expenses(780)(102)(1,082)(1,082)
Severance and ad valorem taxesSeverance and ad valorem taxes(158)(18)(149)(224)
ExplorationExploration(7)(2)(427)(84)
Depletion and depreciationDepletion and depreciation(882)(64)(1,014)(2,177)
Accretion of asset retirement obligationsAccretion of asset retirement obligations(11)(1)(12)(11)
Impairment of oil and natural gas properties —
 (2,564) (18,238)Impairment of oil and natural gas properties— — (8,446)(8)
Depletion and depreciation (913) (1,003) (2,099)
Imputed income tax provision(a)
 (768) 1,027
 6,683
Imputed income tax provision(a)
(269)48 1,840 (125)
Results of operations from oil, natural gas and NGL producing
activities		 $1,182
 $(1,891) $(11,527)Results of operations from oil, natural gas and NGL producing activities$870 $(155)$(6,266)$354 

(a)The imputed income tax provision is hypothetical (at the statutory tax rate) and determined without regard to our deduction for general and administrative expenses, interest costs and other income tax credits and deductions, nor whether the hypothetical tax provision (benefit) will be payable (receivable).
(a)    The imputed income tax provision is hypothetical (at the statutory tax rate) and determined without regard to our deduction for general and administrative expenses, interest costs and other income tax credits and deductions, nor whether the hypothetical tax provision (benefit) will be payable (receivable).
Oil, Natural Gas and NGL Reserve Quantities
Our petroleum engineers and independent petroleum engineering firms estimated all of our proved reserves as of December 31, 2017, 20162021, 2020 and 2015.2019. Independent petroleum engineering firmsfirm LaRoche Petroleum Consultants, Ltd. estimated an aggregate of 83%, 70% and 59%91% of our estimated proved reserves (by volume) as of December 31, 2017, 2016 and 2015, respectively, as set forth below:
  December 31,
  2017 2016 2015
Software Integrated Solutions, Division of Schlumberger Technology Corporation 83%70% 23%
Ryder Scott Company, L.P. —% —% 36%
2021.
Proved oil, natural gas and NGL reserves are those quantities of oil, natural gas and NGL 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. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. Based on reserve reporting rules, the price is calculated using the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within the period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. A project to extract hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a
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highest known oil elevation and the potential exists for an
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associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.
Developed oil, natural gas and NGL reserves are reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods where production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
The information provided below on our oil, natural gas and NGL reserves is presented in accordance with regulations prescribed by the SEC. Our reserve estimates are generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates will change as future information becomes available and as commodity prices change. These changes could be material and could occur in the near term.
Presented below is a summary of changes in estimated reserves for 2017, 2016 and 2015:
  Oil Gas NGL Total
  (mmbbl) (bcf) (mmbbl) (mmboe)
December 31, 2017        
Proved reserves, beginning of period 399.1
 6,496
 226.4
 1,708
Extensions, discoveries and other additions 62.7
 3,694
 44.9
 723
Revisions of previous estimates (168.1) (315) (31.0) (252)
Production (32.7) (878) (20.9) (200)
Sale of reserves-in-place (0.9) (418) (0.8) (71)
Purchase of reserves-in-place 0.1
 21
 —
 4
Proved reserves, end of period(a)
 260.2
 8,600
 218.6
 1,912
Proved developed reserves:        
Beginning of period 200.4
 5,126
 134.1
 1,189
End of period 150.9
 4,980
 134.9
 1,116
Proved undeveloped reserves:        
Beginning of period 198.7
 1,370
 92.2
 519
End of period(b)
 109.3
 3,620
 83.6
 796
         
the periods presented:
OilNatural GasNGLTotal
(mmbbl)(bcf)(mmbbl)(mmboe)
December 31, 2021
Proved reserves, beginning of period (Predecessor)161.3 3,530 52.0 802 
Extensions, discoveries and other additions41.0 1,744 16.9 348 
Revisions of previous estimates33.3 1,522 21.1 308 
Production(25.9)(807)(8.0)(168)
Sale of reserves-in-place— — — — 
Purchase of reserves-in-place— 1,835 — 306 
Proved reserves, end of period (Successor)209.7 7,824 82.0 1,596 
Proved developed reserves:
Beginning of period (Predecessor)158.1 3,196 51.4 742 
End of period (Successor)165.7 4,246 61.7 935 
Proved undeveloped reserves:
Beginning of period (Predecessor)3.2 334 0.6 60 
End of period(a) (Successor)
44.0 3,578 20.3 661 
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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
SUPPLEMENTARY INFORMATION –- (Continued)


OilNatural GasNGLTotal
(mmbbl)(bcf)(mmbbl)(mmboe)
December 31, 2020
Proved reserves, beginning of period (Predecessor)358.0 6,566 120.0 1,572 
Extensions, discoveries and other additions1.1 100 0.4 18 
Revisions of previous estimates(148.2)(2,326)(50.6)(586)
Production(37.3)(684)(11.3)(163)
Sale of reserves-in-place(12.3)(126)(6.5)(39)
Purchase of reserves-in-place— — — — 
Proved reserves, end of period (Predecessor)161.3 3,530 52.0 802 
Proved developed reserves:
Beginning of period (Predecessor)201.4 3,377 82.1 846 
End of period (Predecessor)158.1 3,196 51.4 742 
Proved undeveloped reserves:
Beginning of period (Predecessor)156.6 3,189 37.9 726 
End of period(a) (Predecessor)
3.2 334 0.6 60 
December 31, 2019
Proved reserves, beginning of period (Predecessor)215.5 6,777 103.3 1,448 
Extensions, discoveries and other additions52.2 897 13.9 216 
Revisions of previous estimates(40.9)(516)(15.8)(143)
Production(43.0)(728)(12.3)(177)
Sale of reserves-in-place(1.8)(23)(1.4)(7)
Purchase of reserves-in-place176.0 159 32.3 235 
Proved reserves, end of period (Predecessor)358.0 6,566 120.0 1,572 
Proved developed reserves:
Beginning of period (Predecessor)127.6 3,314 67.9 748 
End of period (Predecessor)201.4 3,377 82.1 846 
Proved undeveloped reserves:
Beginning of period (Predecessor)87.9 3,463 35.4 700 
End of period(a) (Predecessor)
156.6 3,189 37.9 726 
___________________________________________
  Oil Gas NGL Total
  (mmbbl) (bcf) (mmbbl) (mmboe)
December 31, 2016        
Proved reserves, beginning of period 313.7
 6,041
 183.5
 1,504
Extensions, discoveries and other additions 191.2
 1,798
 89.0
 580
Revisions of previous estimates (58.9) 598
 2.8
 43
Production (33.2) (1,050) (24.4) (233)
Sale of reserves-in-place (14.7) (1,190) (28.1) (241)
Purchase of reserves-in-place 1.0
 299
 3.6
 55
Proved reserves, end of period(c)
 399.1
 6,496
 226.4
 1,708
Proved developed reserves:        
Beginning of period 215.6
 5,329
 158.0
 1,262
End of period 200.4
 5,126
 134.1
 1,189
Proved undeveloped reserves:        
Beginning of period 98.1
 712
 25.5
 242
End of period(b)
 198.7
 1,370
 92.2
 519
         
December 31, 2015        
Proved reserves, beginning of period 420.8
 10,692
 266.3
 2,469
Extensions, discoveries and other additions 61.1
 805
 35.3
 231
Revisions of previous estimates (110.0) (4,191) (75.8) (885)
Production (41.6) (1,070) (28.0) (248)
Sale of reserves-in-place (16.6) (195) (14.3) (63)
Purchase of reserves-in-place —
 —
 —
 —
Proved reserves, end of period(d)
 313.7
 6,041
 183.5
 1,504
Proved developed reserves:        
Beginning of period 229.3
 8,615
 198.5
 1,864
End of period 215.6
 5,329
 158.0
 1,262
Proved undeveloped reserves:        
Beginning of period 191.5
 2,077
 67.8
 605
End of period(b)
 98.1
 712
 25.5
 242

(a)Includes 1 mmbbl of oil, 20 bcf of natural gas and 2 mmbbls of NGL reserves owned by the Chesapeake Granite Wash Trust, of which 1 mmbbl of oil, 10 bcf of natural gas and 1 mmbbl of NGL are attributable to noncontrolling interest holders
(b)As of December 31, 2017, 2016 and 2015,(a)    As of December 31, 2021, 2020 and 2019, there were no PUDs that had remained undeveloped for five years or more.
(c)Includes 1 mmbbl of oil, 23 bcf of natural gas and 2 mmbbls of NGL reserves owned by the Chesapeake Granite Wash Trust, 1 mmbbl of oil, 12 bcf of natural gas and 1 mmbbl of NGL of which are attributable to the noncontrolling interest holders.
(d)Includes 1 mmbbl of oil, 32 bcf of natural gas and 3 mmbbls of NGL reserves owned by the Chesapeake Granite Wash Trust, 1 mmbbl of oil, 16 bcf of natural gas and 2 mmbbls of NGL of which are attributable to the noncontrolling interest holders.
.
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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
SUPPLEMENTARY INFORMATION – (Continued)


During 2017,2021, we acquired 306 mmboe primarily related to the acquisition of Vine. We recorded extensions and discoveries of 723348 mmboe primarily infollowing our emergence from bankruptcy on February 9, 2021 and certainty regarding our ability to finance the Gulf Coast, Marcellus and Uticadevelopment of our proved reserves over a five-year period. We recorded 308 mmboe of upward revisions of previous estimates, which consisted of 214 mmboe due to longer lateral successful drillinglength adjustments, performance and additional allocated capital inupdates to our 5-yearfive-year development plan. We recorded a downward revision of 327plan and 94 mmboe from previous estimates due to an updated development plan in the Eagle Ford aligning up-spacing, our activity schedule and well performance. Additionally, PUD’s were removed from properties in the Mid-Continent in the process of being divested. As of December 31, 2017, we did not have sufficient technical data to estimate the impact of enhanced completion techniques in Eagle Ford. The downward revision was partially offset by improvedhigher oil, natural gas and NGL prices in 2017 resulting in a 75 mmboe upward revision.2021. The oil and natural gas prices used in computing our reserves as of December 31, 2017,2021, were $51.34$66.56 per bbl and $2.98$3.60 per mcf, respectively, before price differentials.basis differential adjustments.
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SUPPLEMENTARY INFORMATION - (Continued)
During 2016,2020, we recorded extensions and discoveries of 18 mmboe primarily in the Marcellus and Haynesville primarily related to successfully drilled new well additions. We sold 24139 mmboe of proved reserves for approximately $898 million.$136 million primarily in the Mid-Continent. We recorded extensions and discoveries586 mmboe of 580 mmboe, primarily related to undeveloped well additions located in Utica and Eagle Ford. In addition, we recorded upward revisions of 113 mmboe due to changes in previous estimates resulting from improved drilling and operating efficiencies, which includes the impact from lower operating and capital costs, partially offset by downward revisions of 70previous estimates consisting of 423 mmboe which were primarilyof downward revisions due to updates to our five-year development plan in contemplation of ongoing market conditions and uncertainty regarding our ability to finance the resultdevelopment of our proved reserves over a five-year period, downward revisions of 208 mmboe due to lower oil, natural gas and NGL prices in 2016.2020, and upward revisions of 45 mmboe due to ongoing portfolio evaluation including performance adjustments. The oil and natural gas prices used in computing our reserves as of December 31, 2016,2020, were $42.75$39.57 per bbl and $2.49$1.98 per mcf, respectively, before price differentials.basis differential adjustments.
During 2015,2019, we sold 63acquired 235 mmboe primarily related to the acquisition of proved reserves for approximately $97 million plusWildHorse. We recorded extensions and discoveries of 216 mmboe, primarily related to undeveloped well additions in the cancellation of all of CHK C-T’s outstanding preferred shares. See Note 12 to our consolidated financial statements included in Item 8 of this report for further discussion of oilMarcellus and natural gas property transactions. WeEagle Ford operating areas. In addition, we recorded downward revisions of 885110 mmboe which was comprised of a 1,098 mmboe decrease, resulting primarily fromdue to lower oil, natural gas and NGL prices in 2015, partially offset by 2132019, and downward revisions of 33 mmboe of upward revisions resulting from changes in previous estimates.due to ongoing portfolio evaluation including lateral length adjustments, performance and updates to our five-year development plan. The oil and natural gas prices used in computing our reserves as of December 31, 2015,2019, were $50.28$55.69 per bbl and $2.58 per mcf, respectively, before price differentials.basis differential adjustments.
Standardized Measure of Discounted Future Net Cash Flows
Accounting Standards Codification Topic 932 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. Chesapeake has followed these guidelines which are briefly discussed below.
Future cash inflows and future production and development costs as of December 31, 2017, 20162021, 2020 and 20152019 were determined by applying the average of the first-day-of-the-month prices for the 12 months of the year and year-end costs to the estimated quantities of oil, natural gas and NGL to be produced. Actual future prices and costs may be materially higher or lower than the prices and costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on continuation of the economic conditions applied for that year. Estimated future income taxes are computed using current statutory income tax rates including consideration of the current tax basis of the properties and related carryforwards, giving effect to permanent differences and tax credits. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.
The assumptions used to compute the standardized measure are those prescribed by the Financial Accounting Standards Board and do not necessarily reflect our expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.
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SUPPLEMENTARY INFORMATION –- (Continued)


The following summary sets forth our future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure:
 Years Ended December 31, 
 2017 2016 2015 Years Ended December 31,
 ($ in millions) 202120202019
Future cash inflows $26,412
(a) 
$19,835
(b) 
$20,247
(c) 
Future cash inflows$33,700 (a)$8,247 (b)$29,857 (c)
Future production costs (7,044) (6,800) (7,391) Future production costs(6,735)(2,963)(6,956)
Future development costs (4,977) (3,621) (1,518) Future development costs(3,687)(563)(5,757)
Future income tax provisions —
 (79) (228) Future income tax provisions(2,254)(9)(75)
Future net cash flows 14,391
 9,335
 11,110
 Future net cash flows21,024 4,712 17,069 
Less effect of a 10% discount factor (6,901) (4,956) (6,417) Less effect of a 10% discount factor(8,737)(1,626)(8,069)
Standardized measure of discounted future net cash flows(d)
 $7,490
 $4,379
 $4,693
 
Standardized measure of discounted future net cash flowsStandardized measure of discounted future net cash flows$12,287 $3,086 $9,000 

(a)Calculated using prices of $51.34 per bbl of oil and $2.98 per mcf of natural gas, before field differentials.
(b)Calculated using prices of $42.75 per bbl of oil and $2.49 per mcf of natural gas, before field differentials.
(c)Calculated using prices of $50.28 per bbl of oil and $2.58 per mcf of natural gas, before field differentials.
(d)Excludes discounted future net cash inflows attributable to production volumes sold to VPP buyers. See Note 12.
(a)    Calculated using prices of $66.56 per bbl of oil and $3.60 per mcf of natural gas, before basis differential adjustments.
(b)    Calculated using prices of $39.57 per bbl of oil and $1.98 per mcf of natural gas, before basis differential adjustments.
(c)    Calculated using prices of $55.69 per bbl of oil and $2.58 per mcf of natural gas, before basis differential adjustments.
The principal sources of change in the standardized measure of discounted future net cash flows are as follows:
Years Ended December 31,
202120202019
Standardized measure, beginning of period(a)
$3,086 $9,000 $9,495 
Sales of oil and natural gas produced, net of production costs and gathering, processing and transportation(b)
(3,414)(1,140)(2,691)
Net changes in prices and production costs6,674 (5,576)(3,457)
Extensions and discoveries, net of production and
development costs
2,834 71 991 
Changes in estimated future development costs(459)1,933 366 
Previously estimated development costs incurred during the period130 665 775 
Revisions of previous quantity estimates2,034 (1,839)(793)
Purchase of reserves-in-place2,807 — 3,435 
Sales of reserves-in-place— (112)(57)
Accretion of discount309 902 953 
Net change in income taxes(1,423)14 17 
Changes in production rates and other(291)(832)(34)
Standardized measure, end of period(a)
$12,287 $3,086 $9,000 

(a)    The impact of cash flow hedges has not been included in any of the periods presented.
(b)    Excludes gains and losses on derivatives.
143
  Years Ended December 31,
  2017 2016 2015
  ($ in millions)
Standardized measure, beginning of period(a)
 $4,379
 $4,693
 $17,133
Sales of oil and natural gas produced, net of production costs and gathering, processing and transportation(b)
 (2,452) (1,227) (1,503)
Net changes in prices and production costs 3,977
 (1,210) (18,070)
Extensions and discoveries, net of production and
development costs
 1,951
 1,042
 1,005
Changes in estimated future development costs 614
 323
 3,198
Previously estimated development costs incurred during the period 775
 664
 873
Revisions of previous quantity estimates (1,255) 145
 (3,472)
Purchase of reserves-in-place 3
 394
 1
Sales of reserves-in-place (116) 13
 (938)
Accretion of discount 441
 473
 2,201
Net change in income taxes 26
 (8) 4,845
Changes in production rates and other (853) (923) (580)
Standardized measure, end of period(a)(c)
 $7,490
 $4,379
 $4,693

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
SUPPLEMENTARY INFORMATION - (Continued)
(a)Item 9.The impact of cash flow hedges has not been included in any of the periods presented.
(b)Excludes gains and losses on derivatives.
(c)Effect of noncontrolling interest of the Chesapeake Granite Wash Trust is immaterial.

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ITEM 9.Changes In and Disagreements with Accountants on Accounting and Financial Disclosure
Not applicable.
ITEMItem 9A.Controls and Procedures
Evaluation of Disclosure Controls and Procedures
We maintain disclosure controls and procedures designed to ensure that information required to be disclosed in reports we file or submit under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that such information is accumulated and communicated to management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure.
As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(b). Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded as of December 31, 20172021 that our disclosure controls and procedures were effective.
Remediation of Previously Identified Material Weakness
As disclosed in our Annual Report on Form 10-K for the year ended December 31, 2016, our management determined that a material weakness existed in our internal control over financial reporting over the review of the valuation of proved oil and natural gas properties and the accuracy of impairment of oil and natural gas properties. Specifically, the review of the initial configuration of a newly implemented tool used to calculate basis price differentials did not detect an error in the calculation formula and the manual interface control that compared the data used in the tool to the general ledger was not designed at an appropriately disaggregated level.
We have taken the necessary steps to enhance the underlying control activities, which now include restricted access within the tool to maintain and control changes to the formulaic calculations, a manual interface control to validate that the automated interface configuration and calculation formulas are accurate, and a manual recalculation of the basis price differentials.
Based on the results of management’s evaluation, we have concluded that the controls are designed and operating effectively as of December 31, 2017 and, therefore, the previously disclosed material weakness has been remediated.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting that occurred during the quarter ended December 31, 20172021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
It is the responsibility of the management of Chesapeake Energy Corporation to establish and maintain adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). Management utilized the Committee of Sponsoring Organizations of the Treadway Commission's Internal Control-Integrated Framework (2013) in conducting the required assessment of effectiveness of the Company's internal control over financial reporting.
Management has performed an assessment of the effectiveness of the Company's internal control over financial reporting and has determined the Company’s internal control over financial reporting was effective as of December 31, 2021.
Management’s Reportassessment and conclusion on Internal Control Over Financial Reporting is set forththe effectiveness of the Company’s internal control over financial reporting as of December 31, 2021 excludes an assessment of the internal control over financial reporting of Vine Energy, which was acquired in Item 8a business combination on November 1, 2021. Vine Energy represents approximately 20% of this Annual Report on Form 10-K.our consolidated total assets as of December 31, 2021 and approximately 7% of our consolidated revenues for the period from February 10, 2021 through December 31, 2021.
The effectiveness of our internal control over financial reporting as of December 31, 2021 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report which appears herein.
ITEM 9B./s/ DOMENIC J. DELL'OSSO, JR.Other Information
Domenic J. Dell'Osso, Jr.
President and Chief Executive Officer
/s/ MOHIT SINGH
Mohit Singh
Executive Vice President and Chief Financial Officer
February 24, 2022
Not applicable.
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SUPPLEMENTARY INFORMATION - (Continued)

Item 9B.Other Information
Not applicable.
Item 9C.Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
PART III
ITEMItem 10.Directors, Executive Officers and Corporate Governance
The names of executive officers and certain other senior officers of the Company and their ages, titles and biographies as of the date hereof are incorporated by reference from Item 1 of Part I of this report. The other information called for by this Item 10 is incorporated herein by reference to the definitive proxy statement to be filed by Chesapeake pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 2018May 2, 2022 (the 2018“2022 Proxy Statement)Statement”).
ITEMItem 11.Executive Compensation
The information called for by this Item 11 is incorporated herein by reference to the 20182022 Proxy Statement.
ITEMItem 12.Security Ownership of Certain Beneficial Owners and Management and Related StockholderStockholders Matters
The information called for by this Item 12 is incorporated herein by reference to the 20182022 Proxy Statement.
ITEMItem 13.Certain Relationships and Related Transactions, and Director Independence
The information called for by this Item 13 is incorporated herein by reference to the 20182022 Proxy Statement.
ITEMItem 14.Principal Accountant Fees and Services
The information called for by this Item 14 is incorporated herein by reference to the 20182022 Proxy Statement.

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PART IV
ITEMItem 15.ExhibitsExhibit and Financial Statement Schedules

(a)The following financial statements, financial statement schedules and exhibits are filed as a part of this report:
1.
Financial Statements. Chesapeake's consolidated financial statements are included in Item 8 of Part II of this report. Reference is made to the accompanying Index to Financial Statements.
(a)    The following financial statements, financial statement schedules and exhibits are filed as a part of this report:
1.Financial Statements. Chesapeake's consolidated financial statements are included in Item 8 of Part II of this report. Reference is made to the accompanying Index to Financial Statements.
2.Financial Statement Schedules. No financial statement schedules are applicable or required.
3.Exhibits. The exhibits listed below in the Index of Exhibits are filed, furnished or incorporated by reference pursuant to the requirements of Item 601 of Regulation S-K.
2.
Financial Statement Schedules. No financial statement schedules are applicable or required.
3.
Exhibits. The exhibits listed below in the Index of Exhibits are filed, furnished or incorporated by reference pursuant to the requirements of Item 601 of Regulation S-K.
INDEX OF EXHIBITS
    Incorporated by Reference  
Exhibit
Number
 Exhibit Description Form 
SEC File
Number
 Exhibit Filing Date 
Filed or
Furnished
Herewith
3.1.1 
Chesapeake’s Restated Certificate of Incorporation.
 10-Q 001-13726 3.1.1 8/3/2017  
             
3.1.2 
Certificate of Designation of 5% Cumulative Convertible Preferred Stock (Series 2005B), as amended.
 10-Q 001-13726 3.1.4 11/10/2008  
             
3.1.3 
Certificate of Designation of 4.5% Cumulative Convertible Preferred Stock, as amended.
 10-Q 001-13726 3.1.6 8/11/2008  
             
3.1.4 
Certificate of Designation of 5.75% Cumulative Non-Voting Convertible Preferred Stock (Series A).
 8-K 001-13726 3.2 5/20/2010  
             
3.1.5 
Certificate of Designation of 5.75% Cumulative Non-Voting Convertible Preferred Stock, as amended.
 10-Q 001-13726 3.1.5 8/9/2010  
             
3.2 
Chesapeake’s Amended and Restated Bylaws.
 8-K 001-13726 3.2 6/19/2014  
             
4.1* 
Indenture dated as of November 8, 2005 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York Mellon Trust Company, N.A., as Trustee, with respect to 6.875% Senior Notes due 2020.
 8-K 001-13726 4.1.1 11/15/2005  
             
4.2* 
Indenture dated as of May 27, 2008 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York Mellon Trust Company, N.A., as Trustee, with respect to 7.25% Senior Notes due 2018.
 8-K 001-13726 4.1 5/29/2008  
             
4.3* 
Indenture dated as of May 27, 2008 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York Mellon Trust Company, N.A., as Trustee, with respect to 2.25% Contingent Convertible Senior Notes due 2038.
 8-K 001-13726 4.2 5/29/2008  
             
4.4.1* 
Indenture dated as of August 2, 2010 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors, and the Bank of New York Mellon Trust Company, N.A., as Trustee.
 S-3 333-168509 4.1 8/3/2010  
  Incorporated by Reference 
Exhibit
Number
Exhibit DescriptionForm
SEC File
Number
ExhibitFiling Date
Filed or
Furnished
Herewith
2.1
Fifth Amended Joint Plan of Reorganization of Chesapeake Energy Corporation and its Debtor Affiliates Pursuant to Chapter 11 of the Bankruptcy Code (Exhibit A of the Confirmation Order).
8-K001-137262.11/19/2021
2.2
Agreement and Plan of Merger, dated as of August 10, 2021, by and among Chesapeake Energy Corporation, Hannibal Merger Sub, Inc., Hannibal merger Sub, LLC, Vine Energy Inc. and Vine Energy holdings LLC.
8-K001-137262.18/11/21
3.1
Second Amended and Restated Certificate of Incorporation of Chesapeake Energy Corporation.
8-K001-137263.12/9/2021
3.2
Second Amended and Restated Bylaws of Chesapeake Energy Corporation.
8-K001-137263.22/9/2021
3.3
Certificate of Elimination of Series B Preferred Stock of Chesapeake Energy Corporation.
10-K001-137263.33/1/2021
4.1
Description of Securities.
8-A001-13726N/A2/9/2021
10.1
Restructuring Support Agreement, dated June 28, 2020.
8-K001-1372610.16/29/2020
10.2
Backstop Commitment Agreement, dated June 28, 2020 (Exhibit 4 to the Restructuring Support Agreement).
8-K001-1372610.16/29/2020
10.3
Credit Agreement, dated as of February 9, 2021, among Chesapeake Energy Corporation, as borrower, MUFG Union Bank, N.A., as administrative agent, and the lenders and other parties thereto.
8-K001-1372610.12/9/2021
10.4

Registration Rights Agreement, dated as of February 9, 2021, by and among Chesapeake Energy Corporation and the other parties signatory thereto.
8-K001-1372610.22/9/2021
10.5
Class A Warrant Agreement, dated as of February 9, 2021, between Chesapeake Energy Corporation and Equiniti Trust Company.
8-K001-1372610.32/9/2021
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10.6
Class B Warrant Agreement, dated as of February 9, 2021, between Chesapeake Energy Corporation and Equiniti Trust Company.
8-K001-1372610.42/9/2021
10.7
Class C Warrant Agreement, dated as of February 9, 2021, between Chesapeake Energy Corporation and Equiniti Trust Company.
8-K001-1372610.52/9/2021
10.8
Form of Indemnity Agreement.
8-K001-1372610.62/9/2021
10.9†
Chesapeake Energy Corporation 2021 Long Term Incentive Plan.
8-K001-1372610.72/9/2021
10.10
Purchase Agreement, dated as of February 2, 2021, by and among Chesapeake Escrow Issuer LLC, and Goldman Sachs & Co. LLC, RBC Capital Markets, LLC, as representatives of the purchasers signatory thereto, with respect to 5.5% Senior Notes due 2026 and 5.875% Senior Notes due 2029.
10-K001-1372610.103/1/2021
10.11
Indenture dated as of February 5, 2021, among Chesapeake Escrow Issuer LLC, as issuer, the guarantors signatory thereto, and Deutsche Bank Trust Company Americas, as Trustee, with respect to 5.5% Senior Notes due 2026 and 5.875% Senior Notes due 2029.
10-K001-1372610.113/1/2021
10.12
Joinder Agreement, dated as of February 9, 2021, by and among Chesapeake Energy Corporation and the Guarantors party thereto, with respect to 5.5% Senior Notes due 2026 and 5.875% Senior Notes due 2029.
10-K001-1372610.123/1/2021
10.13
First Supplemental Indenture, dated as of February 9, 2021, by and among Chesapeake Energy Corporation, the Guarantors signatory thereto, and Deutsche Bank Trust Company Americas, as Trustee, with respect to 5.5% Senior Notes due 2026 and 5.875% Senior Notes due 2029.
10-K001-1372610.133/1/2021
10.14†
Amendment to the Chesapeake Energy Corporation 2021 Long Term Incentive Plan.
8-K001-1372610.34/27/2021
10.15†
Agreement by and between Robert D. Lawler and Chesapeake Energy Corporation, dated April 27, 2021.
8-K001-1372610.14/27/2021
10.16†
Interim CEO Agreement by and between Michael Wichterich and Chesapeake Energy Corporation, dated April 27, 2021.
8-K001-1372610.24/27/2021
10.17†
Form of Incentive Agreement between Executive Vice President / Senior Vice President and Chesapeake Energy Corporation.
10-K/A001-1372610.144/27/2021
10.18†
Form of Executive/Employee Restricted Stock Unit Award Agreement for 2021 Long Term Incentive Plan.
X
10.19†
Form of Non-Employee Director Restricted Stock Unit Award Agreement for 2021 Long Term Incentive Plan.
10-Q001-1372610.95/13/21
147
             
4.4.2 
Second Supplemental Indenture, dated as of August 17, 2010 to Indenture dated as of August 2, 2010 with respect to 6.625% Senior Notes due 2020.
 8-A 001-13726 4.3 9/24/2010  
             
4.4.3 
Fifth Supplemental Indenture dated February 11, 2011 to Indenture dated as of August 2, 2010 with respect to 6.125% Senior Notes due 2021.
 8-A 001-13726 4.2 2/22/2011  
             
4.4.4 
Fourteenth Supplemental Indenture dated March 18, 2013 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors, and Deutsche Bank Trust Company Americas, as Trustee, to Indenture dated as of August 2, 2010.
 S-3 333-168509 4.17 3/18/2013  
             
4.4.5 
Sixteenth Supplemental Indenture dated April 1, 2013 to Indenture dated as of August 2, 2010 with respect to 5.375% Senior Notes due 2021.
 8-A 001-13726 4.3 4/8/2013  
             
4.4.6 
Seventeenth Supplemental Indenture dated April 1, 2013 to Indenture dated as of August 2, 2010 with respect to 5.75% Senior Notes due 2023.
 8-A 001-13726 4.4 4/8/2013  
             
4.5.1** 
Indenture dated as of April 24, 2014 by and among Chesapeake, as Issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors, and Deutsche Bank Trust Company Americas, as Trustee.
 8-K 001-13726 4.1 4/29/2014  
             
4.5.2 
First Supplemental Indenture dated as of April 24, 2014 to Indenture dated as of April 24, 2014 with respect to Floating Rate Senior Notes due 2019.
 8-K 001-13726 4.2 4/29/2014  
             
4.5.3 
Second Supplemental Indenture dated as of April 24, 2014 to Indenture dated as of April 24 2014 with respect to 4.875% Senior Notes due 2022.
 8-K 001-13726 4.3 4/29/2014  
             
4.6 
Indenture dated as of December 23, 2015 among Chesapeake, as Issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors, and Deutsche Bank Trust Company Americas, as Trustee and Collateral Trustee with respect to 8.00% Senior Secured Second Lien Notes due 2022. 
 8-K 001-13726 4.1 12/23/2015  
             
4.7.1 
Credit Agreement dated December 15, 2014 by and among: Chesapeake Energy Corporation, as borrower; MUFG Union Bank N.A., as administrative agent, co-syndication agent, a swingline lender and a letter of credit issuer; Wells Fargo Bank and National Association, as co-syndication agent, a swingline lender and a letter of credit issuer; Bank of America, N.A., Crédit Agricole Corporate and Investment Bank and JPMorgan Chase Bank, N.A., as co-documentation agents and letter of credit issuers; and certain other lenders named therein.
 10-Q 001-13726 4.1 8/14/2016  
             
TABLE OF CONTENTS

10.20
Agreement by and between Frank J. Patterson and the Company, dated June 11, 2021.
8-K001-1372610.16/11/21
10.21†
Agreement by and between James R. Webb and the Company, dated June 11, 2021.
8-K001-1372610.26/11/21
10.22†
Agreement by and between William M. Buergler and the Company, dated June 11, 2021.
8-K001-1372610.36/11/21
10.23
First Amendment dated June 11, 2021 to the Credit Agreement, dated as of February 9, 2021, among Chesapeake Energy Corporation, as borrower, MUFG Union Bank, N.A., as administrative agent, and the lenders and other parties thereto.
8-K001-1372610.16/14/21
10.24†
Form of Performance Share Unit Award (Absolute TSR) for 2021 Long Term Incentive Plan
10-Q001-1372610.108/10/21
10.25†
Form of Performance Share Unit Award (Relative TSR) for 2021 Long Term Incentive Plan
10-Q001-1372610.118/10/21
10.26†
Performance Share Unit Award Agreement with Michael A. Wichterich, Interim Chief Executive Officer, dated April 30, 2021.
10-Q001-1372610.58/10/21
10.27
Registration Rights Agreement, dated as of August 10, 2021, by and among Chesapeake Energy Corporation, Brix Investment LLC, Brix Investment II LLC, Harvest Investment LLC, Harvest Investment II LLC, Vine Investment LLC and Vine Investment II LLC
8-K001-1372610.18/11/21
10.28
Merger Support Agreement, dater as of August 10, 2021, by and among Chesapeake Energy Corporation, Hannibal merger Sub, Inc., Hannibal Merger Sub, LLC, Vine Energy, Inc. and the stockholders of Vine Energy Inc. listed thereto.
8-K001-1372610.28/11/21
10.29†
Chesapeake Energy Corporation Executive Severance Plan
8-K001-1372610.110/12/21
10.30†
Form of Participation Agreement pursuant to Chesapeake Energy Corporation Executive Severance Plan
8-K001-1372610.210/12/21
10.31†
Executive Chairman Agreement by and between Michael Wichterich and Chesapeake Energy Corporation, dated October 11, 2021
8-K001-1372610.410/12/21
10.32†
Second Amendment to the Chesapeake Energy Corporation 2021 Long Term Incentive Plan.
8-K001-1372610.310/12/21
10.33
Second Amendment to Credit Agreement, dated as of October 29, 2021, among Chesapeake Energy Corporation, as borrower, MUFG Bank, Ltd, as administrative agent, MUFG Union Bank, N.A., as collateral agent, and the lenders and other parties party thereto.
10-Q001-1372610.1811/02/21
148
4.7.2 
First Amendment to Credit Agreement dated September 30, 2015 among Chesapeake, as borrower, MUFG Union Bank N.A., as administrative agent, co-syndication agent, a swingline lender and a letter of credit issuer; Wells Fargo Bank, National Association, as co-syndication agent, a swingline lender and a letter of credit issuer; and certain other lenders named therein.
 10-Q 001-13726 4.1 11/4/2015  
             
4.7.3 
Second Amendment to Credit Agreement dated December 15, 2015 among Chesapeake, as borrower, MUFG Union Bank N.A., as administrative agent, co-syndication agent, a swingline lender and a letter of credit issuer; Wells Fargo Bank, National Association, as co-syndication agent, a swingline lender and a letter of credit issuer; and certain other lenders named therein.
 8-K 001-13726 10.1 12/16/2015  
             
4.7.4†† 
Third Amendment to Credit Agreement dated April 8, 2016 among Chesapeake Energy Corporation, as borrower; MUFG Union Bank N.A., as administrative agent, a swingline lender and a letter of credit issuer; and certain other lenders named therein.
 10-Q 001-13726 4.2 8/4/2016  
             
4.7.5 
Fourth Amendment to Credit Agreement dated May 19, 2017 among Chesapeake Energy Corporation, as borrower; MUFG Union Bank N.A., as administrative agent, a swingline lender and a letter of credit issuer; and certain other lenders named therein.
 8-K 001-13726 10.1 5/22/2017  
             
4.8 
Intercreditor Agreement dated as of December 23, 2015 between MUFG Bank, N.A., as Priority Lien Agent, and Deutsche Bank Trust Company Americas, as Second Lien Collateral Trustee, and acknowledged by Chesapeake and certain of its subsidiaries.
 8-K 001-13726 10.1 12/23/2015  
             
4.9 
Collateral Trust Agreement, dated as of December 23, 2015, by and among Chesapeake, the guarantors named therein, and Deutsche Bank Trust Company Americas as the representative of the holders of the Second Lien Notes and as collateral trustee.
 8-K 001-13726 10.2 12/23/2015  
             
4.10 
Term Loan Agreement dated August 23, 2016 among Chesapeake Energy Corporation, the lenders party thereto and Deutsche Bank Trust Company Americas, as term agent.
 8-K 001-13726 4.1 8/24/2016  
             
4.11 
Class A Term Loan Supplement dated August 23, 2016 among Chesapeake Energy Corporation, the lenders party thereto and Deutsche Bank Trust Company Americas, as term agent.
 8-K 001-13726 4.2 8/24/2016  
             
4.12 
Collateral Trust Agreement, dated as of August 23, 2016 by and among MUFG Union Bank, N.A., as collateral trustee and revolver agent, and Deutsche Bank Trust Company Americas, as term loan agent, and acknowledged and agreed by Chesapeake Energy Corporation and certain of its subsidiaries.
 8-K 001-13726 10.1 8/24/2016  
             
TABLE OF CONTENTS

10.34
Supplemental Indenture, dated as of November 2, 2021, by and among Chesapeake Energy Corporation, the guarantors party thereto and Wilmington Trust, National Association, as Trustee.
8-K001-137264.111/02/21
10.35
Supplemental Indenture, dated as of November 2, 2021, by and among Chesapeake Energy Corporation, the guarantors party thereto and Deutsche Bank Trust Company Americas, as Trustee.
8-K001-137264.211/02/21
10.36
Partnership Interest Purchase Agreement by and among The Jan & Trevor Rees-Jones Revocable Trust, Rees-Jones Family Holdings, LP, Chief E&D Participants, LP, and Chief E&D (GP) LLC (collectively, as Sellers) and Chesapeake Energy Corporation and its affiliates, dated as of January 24, 2022.
X
10.37
Membership Interest Purchase Agreement by and among Radler 2000 Limited Partnership and Tug Hill, Inc., together as Sellers, and Chesapeake Energy Corporation and its affiliates, dated as of January 24, 2022.
X
10.38
Membership Interest Purchase Agreement by and among Radler 2000 Limited Partnership and Tug Hill, Inc., together as Sellers, and Chesapeake Energy Corporation and its affiliates, dated as of January 24, 2022.
X
21
Subsidiaries of Chesapeake Energy Corporation.
X
23.1
Consent of PricewaterhouseCoopers LLP.
X
23.2
Consent of PricewaterhouseCoopers LLP.
X
23.3
Consent of LaRoche Petroleum Consultants, Ltd.
X
31.1
Domenic J. Dell’Osso, Jr., President and Chief Executive Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
X
31.2
Mohit Singh, Executive Vice President and Chief Financial Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
X
32.1
Domenic J. Dell’Osso, Jr., President and Chief Executive Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
X
32.2
Mohit Singh, Executive Vice President and Chief Financial Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
X
95.1
Mine Safety Disclosures
X
99.1
Report of LaRoche Petroleum Consultants, Ltd.
X
101 INSInline XBRL Instance Document.X
149
4.13 
Indenture dated as of October 5, 2016, among Chesapeake Energy Corporation, the subsidiary guarantors named therein and Deutsche Bank Trust Company Americas, as trustee, with respect to the 5.5% Convertible Senior Notes due 2026.
 8-K 001-13726 4.1 10/5/2016  
             
4.14 
Sixth Supplemental indenture dated as of December 20, 2016 to indenture dated as of April 24, 2014 with respect to 8.00% Senior Notes due 2025.
 8-K 001-13726 4.2 12/20/2016  
             
4.15 
Registration Rights Agreement dated as of December 20, 2016, among Chesapeake Energy Corporation, the subsidiary guarantors named therein and Deutsche Bank Securities, Inc.
 8-K 001-13726 4.4 12/20/2016  
             
4.16 
Purchase Agreement, dated May 22, 2017, by and among Chesapeake Energy Corporation, the subsidiary guarantors named therein and Citigroup Global Markets Inc., as representative of the initial purchasers named therein, relating to the private placement of the 8.00% Senior Notes due 2027.
 8-K 001-13726 10.1 5/23/2017  
             
4.17 
Seventh Supplemental Indenture dated as of June 6, 2017 to Indenture dated as of April 24, 2014 with respect to 8.00% Senior Notes due 2027.
 8-K 001-13726 4.2 6/7/2017  
             
4.18 
Registration Rights Agreement dated as of June 6, 2017, among Chesapeake Energy Corporation, the subsidiary guarantors named therein and Citigroup Global Markets Inc.
 8-K 001-13726 4.4 6/7/2017  
             
4.19 
Purchase Agreement, dated September 27, 2017, by and among Chesapeake Energy Corporation, the subsidiary guarantors named therein and Morgan Stanley & Co. LLC, as representative of the initial purchasers named therein, relating to the private placement of the 8.00% Senior Notes due 2025 and 8.00% Senior Notes due 2027.
 8-K 001-13726 10.1 9/28/2017  
             
4.20 
Registration Rights Agreement, dated as of October 12, 2017, among Chesapeake Energy Corporation, the subsidiary guarantors named therein and Morgan Stanley & Co. LLC with respect to 8.00% Senior Notes due 2025.
 8-K 001-13726 4.4 10/12/2017  
             
4.21 
Registration Rights Agreement, dated as of October 12, 2017, among Chesapeake Energy Corporation, the subsidiary guarantors named therein and Morgan Stanley & Co. LLC with respect to 8.00% Senior Notes due 2027.
 8-K 001-13726 4.5 10/12/2017  
             
10.1.1† 
Chesapeake’s 2003 Stock Incentive Plan, as amended.
 10-Q 001-13726 10.1.1 11/9/2009  
             
10.1.2† 
Form of 2013 Restricted Stock Award Agreement for Chesapeake’s 2003 Stock Incentive Plan.
 10-K 001-13726 10.1.3 3/1/2013  
             
10.2.1† 
Chesapeake’s 2005 Amended and Restated Long Term Incentive Plan.
 8-K 001-13726 10.1 6/20/2013  
             
10.2.2† 
Form of 2013 Restricted Stock Award Agreement for 2005 Amended and Restated Long Term Incentive Plan.
 8-K 001-13726 10.3 2/4/2013  
             
TABLE OF CONTENTS

101 SCHInline XBRL Taxonomy Extension Schema Document.X
101 CALInline XBRL Taxonomy Extension Calculation Linkbase Document.X
101 DEFInline XBRL Taxonomy Extension Definition Linkbase Document.X
101 LABInline XBRL Taxonomy Extension Labels Linkbase Document.X
101 PREInline XBRL Taxonomy Extension Presentation Linkbase Document.X
104Cover Page Interactive Data file - the Cover Page Interactive Data File does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
10.2.3†
Form of Nonqualified Stock Option Agreement for 2005 Amended and Restated Long Term Incentive Plan.
8-K001-1372610.12/4/2013
*Schedules have been omitted pursuant to Item 601(a)(5) of Regulation S-K. The registrant hereby undertakes to furnish supplemental copies of any of the omitted schedules upon request by the SEC.
10.2.4††
Form of Retention Nonqualified Stock Option Agreement for 2005 Amended and Restated Long Term Incentive Plan.
8-K001-1372610.22/4/2013
10.2.5†

Form of 2013 Non-Employee Director Restricted Stock Award Agreement for 2005 Amended and Restated Long Term Incentive Plan.
10-K001-1372610.13.73/1/2013
10.2.6†

Form of 2013 Performance Share Unit Award Agreement for 2005 Amended and Restated Long Term Incentive Plan.
10-K001-1372610.13.93/1/2013
10.2.7†

Form of 2014 Performance Share Unit Award Agreement for 2005 Amended and Restated Long Term Incentive Plan.
10-K001-1372610.4.72/27/2014
10.2.8†

Form of Restricted Stock Unit Award Agreement for 2005 Amended and Restated Long Term Incentive Plan.
10-Q001-1372610.88/6/2013
10.2.9†

Form of Non-Employee Director Restricted Stock Unit Award Agreement for 2005 Amended and Restated Long Term Incentive Plan.
10-Q001-1372610.98/6/2013
10.2.10†

Form of Pension and Equity Makeup Restricted Stock Award Agreement for 2005 Amended and Restated Long Term Incentive Plan for Robert D. Lawler.
10-Q001-1372610.108/6/2013
10.3.1†
Chesapeake Energy Corporation Deferred Amended and Restated Deferred Compensation Plan, effective January 1, 2016.
10-K001-1372610.32/25/2016
10.3.2†

Amendment to the Chesapeake Energy Corporation Deferred Compensation Plan for Non-Employee Directors, effective January 1, 2017.
10-K001-1372610.3.23/3/2017
10.4†

Chesapeake Energy Corporation Deferred Compensation Plan for Non-Employee Directors.
10-K001-1372610.163/1/2013
10.5.1†

Employment Agreement dated as of May 20, 2013 between Robert D. Lawler and Chesapeake Energy Corporation.
8-K001-1372610.15/23/2013
10.5.2†
Amendment to Employment Agreement between Robert D. Lawler and Chesapeake Energy Corporation dated as of June 16, 2016.
8-K001-1372610.16/17/2016
10.6†

Employment Agreement dated as of January 1, 2016 between Domenic J. Dell’Osso, Jr. and Chesapeake Energy Corporation.
8-K001-1372610.11/6/2016
10.7†

Employment Agreement dated as of January 1, 2016 between James R. Webb and Chesapeake Energy Corporation.
8-K001-1372610.21/6/2016
10.8†

Employment Agreement dated as of January 1, 2016 between M. Jason Pigott and Chesapeake Energy Corporation.
8-K001-1372610.41/6/2016
10.9†
Employment Agreement dated as of January 1, 2016 between Frank J. Patterson and Chesapeake Energy Corporation.
X
TABLE OF CONTENTS

             
10.10†

 
Form of Employment Agreement dated as of January 1, 2016 between Executive Vice President/Senior Vice President and Chesapeake Energy Corporation.
 8-K 001-13726 10.5 1/6/2016  
             
10.11†

 
Form of Indemnity Agreement for officers and directors of Chesapeake Energy Corporation and its subsidiaries.
 8-K 001-13726 10.3 6/27/2012  
             
10.12†

 
Chesapeake Energy Corporation 2013 Annual Incentive Plan.
 DEF 14A 001-13726 Exhibit G 5/3/2013  
             
10.12.1†

 
Chesapeake Energy Corporation Restated 2014 Long Term Incentive Plan.
 10-Q 001-13726 10.1 8/3/2017  
             
10.12.2†

 
Form of Restricted Stock Unit Award Agreement for 2014 Long Term Incentive Plan.
 10-Q 001-13726 10.2 8/6/2014  
             
10.12.3† 
Form of Restricted Stock Award Agreement for 2014 Long Term Incentive Plan.
 10-Q 001-13726 10.3 8/6/2014  
             
10.12.4†

 
Form of Nonqualified Stock Option Agreement for 2014 Long Term Incentive Plan.
 10-Q 001-13726 10.4 8/6/2014  
             
10.12.5†

 
Form of Performance Share Unit Award Agreement for 2014 Long Term Incentive Plan.
 10-Q 001-13726 10.5 8/6/2014  
             
10.12.6†

 
Form of Director Restricted Stock Unit Award Agreement for 2014 Long Term Incentive Plan.
 10-Q 001-13726 10.6 8/6/2014  
             
10.13 
Employment Agreement dated as of August 29, 2017 between Chesapeake Energy Corporation and William M. Buergler.
 8-K 001-13726 10.1 9/1/2017  
             
12 
Ratios of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Dividends.
         X
             
21 
Subsidiaries of Chesapeake Energy Corporation.
         X
             
23.1 
Consent of PricewaterhouseCoopers LLP.
         X
             
23.2 
Consent of Software Integrated Solutions, Division of Schlumberger Technology Corporation.
         X
             
31.1 
Robert D. Lawler, President and Chief Executive Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
         X
             
31.2 
Domenic J. Dell’Osso, Jr., Executive Vice President and Chief Financial Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
         X
             
32.1 
Robert D. Lawler, President and Chief Executive Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
         X
             
32.2 
Domenic J. Dell’Osso, Jr., Executive Vice President and Chief Financial Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
         X
             
TABLE OF CONTENTS

Management contract or compensatory plan or arrangement.
99
Report of Software Integrated Solutions, Division of Schlumberger Technology Corporation.
X
101 INSXBRL Instance Document.X
101 SCHXBRL Taxonomy Extension Schema Document.X
101 CALXBRL Taxonomy Extension Calculation Linkbase Document.X
101 DEFXBRL Taxonomy Extension Definition Linkbase Document.X
101 LABXBRL Taxonomy Extension Labels Linkbase Document.X
101 PREXBRL Taxonomy Extension Presentation Linkbase Document.X
*The Company agrees to furnish a copy of any of its unfiled long-term debt instruments to the Securities and Exchange Commission upon request.
†Management contract or compensatory plan or arrangement.
††

Confidential treatment has been requested for portions of this exhibit. These portions have been omitted and submitted separately to the Securities and Exchange Commission.
PLEASE NOTE: Pursuant to the rules and regulations of the Securities and Exchange Commission, we have filed or incorporated by reference the agreements referenced above as exhibits to this Annual Report on Form 10-K. The agreements have been filed to provide investors with information regarding their respective terms. The agreements are not intended to provide any other factual information about Chesapeake Energy Corporation or its business or operations. In particular, the assertions embodied in any representations, warranties and covenants contained in the agreements may be subject to qualifications with respect to knowledge and materiality different from those applicable to investors and may be qualified by information in confidential disclosure schedules not included with the exhibits. These disclosure schedules may contain information that modifies, qualifies and creates exceptions to the representations, warranties and covenants set forth in the agreements. Moreover, certain representations, warranties and covenants in the agreements may have been used for the purpose of allocating risk between the parties, rather than establishing matters as facts. In addition, information concerning the subject matter of the representations, warranties and covenants may have changed after the date of the respective agreement, which subsequent information may or may not be fully reflected in our public disclosures. Accordingly, investors should not rely on the representations, warranties and covenants in the agreements as characterizations of the actual state of facts about Chesapeake Energy Corporation or its business or operations on the date hereof.



Item 16.Form 10-K Summary
Not applicable.
150
TABLE OF CONTENTS

ITEM 16.Form 10-K Summary
Not applicable.
TABLE OF CONTENTS

Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
CHESAPEAKE ENERGY CORPORATION
Date: February 24, 2022CHESAPEAKE ENERGY CORPORATIONBy:/s/ DOMENIC J. DELL’OSSO, JR. 
Domenic J. Dell’Osso, Jr.
Date: February 22, 2018By:/s/ ROBERT D. LAWLER      
Robert D. Lawler
President and Chief Executive Officer
POWER OF ATTORNEY
Each person whose signature appears below constitutes and appoints Robert D. Lawler and Domenic J. Dell'Osso, Jr., and each of them, either one of whom may act without joinder of the other, his true and lawful attorneys-in-factattorney-in-fact and agents,agent, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any or all amendments to this Annual Report on Form 10-K, and to file the same, with all, exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-factattorney-in-fact and agents, and each of them,agent full power and authority to do and perform each, and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, and each of them, or the substitute or substitutes of any or all of them, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
SignatureCapacityDate
/s/ ROBERT D. LAWLERDOMENIC J. DELL’OSSO, JR.
President and Chief Executive Officer
(Principal Executive Officer)
February 22, 201824, 2022
Robert D. LawlerDomenic J. Dell’Osso, Jr.
/s/ DOMENIC J. DELL'OSSO, JR.MOHIT SINGH
Executive Vice President
and Chief Financial Officer
(Principal Financial Officer)
February 22, 201824, 2022
Domenic J. Dell'Osso, Jr.Mohit Singh
 /s/ WILLIAM/s/ GREGORY M. BUERGLERLARSON
Senior Vice President
and Chief - Accounting Officer& Controller
(Principal Accounting Officer)
February 22, 201824, 2022
WilliamGregory M. BuerglerLarson
/s/ R. BRAD MARTINMICHAEL WICHTERICHExecutive Chairman and Chairman of the BoardFebruary 22, 201824, 2022
R. Brad MartinMichael Wichterich
/s/ ARCHIE W. DUNHAMTIMOTHY S. DUNCANDirector and Chairman EmeritusFebruary 22, 201824, 2022
Archie W. DunhamTimothy S. Duncan
/s/ GLORIA R. BOYLANDBENJAMIN C. DUSTER, IVDirectorFebruary 22, 201824, 2022
Gloria R. BoylandBenjamin C. Duster, IV
/s/ LUKE R. CORBETTSARAH A. EMERSONDirectorFebruary 22, 201824, 2022
Luke R. CorbettSarah A. Emerson
/s/ LESLIE S. KEATINGMATTHEW M. GALLAGHERDirectorFebruary 22, 201824, 2022
Leslie S. KeatingMatthew M. Gallagher
/s/ MERRILL A. MILLER, JR.BRIAN STECKDirectorFebruary 22, 201824, 2022
Merrill A. Miller, Jr.
/s/ THOMAS L. RYANDirectorFebruary 22, 2018
Thomas L. RyanBrian Steck




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151