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, 20182020
[ ] ☐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
CHESAPEAKE ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
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| Oklahoma | | 73-1395733 |
| (State or other jurisdiction of incorporation or organization) | | (I.R.S. Employer Identification No.) |
| 6100 North Western Avenue, | Oklahoma City, Oklahoma | Oklahoma | 73118 |
| (Address of principal executive offices) | | (Zip Code) |
| | (405) | 848-8000 | |
| (Registrant’s telephone number, including area code) |
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| Securities Registered Pursuant to Section 12(b) of the Act: |
| Title of Each Class | | Trading Symbol | | Name of Each Exchange on Which Registered |
Common Stock, $0.01 par value $0.01per share | | New YorkCHK | | The Nasdaq Stock ExchangeMarket LLC |
Floating Rate Senior Notes due 2019Class A Warrants to purchase Common Stock | | New YorkCHKEW | | The Nasdaq Stock ExchangeMarket LLC |
6.625% Senior Notes due 2020Class B Warrants to purchase Common Stock | | New YorkCHKEZ | | The Nasdaq Stock ExchangeMarket LLC |
6.875% Senior Notes due 2020Class C Warrants to purchase Common Stock | | New YorkCHKEL | | The Nasdaq Stock Exchange |
6.125% Senior Notes due 2021 | | New York Stock Exchange |
5.375% Senior Notes due 2021 | | New York Stock Exchange |
4.875% Senior Notes due 2022 | | New York Stock Exchange |
5.75% Senior Notes due 2023 | | New York Stock Exchange |
4.5% Cumulative Convertible Preferred Stock | | New 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 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. ☐
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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 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 [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 [ ]
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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 is a shell company (as defined in Rule 12b-2 of the Exchange 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 29, 2018,30, 2020, was approximately $4.7 billion.$48 million. As of February 12, 2019,25, 2021, there were 1,631,724,76597,907,081 shares of our $0.01 par value common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement for the 20182021 Annual Meeting of Shareholders are incorporated by reference in Part III.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
2018 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
Glossary of Oil and Gas Terms
The terms defined in this section are used throughout this report.
Bankruptcy Code. Means title 11 of the United States Code, 11 U.S.C. §§ 101–1532, as amended.
Bankruptcy Court. The United States Bankruptcy Court for the Southern District of Texas.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.
Bboe. One billion barrels of oil equivalent.
Bcf. One billion cubic feet of natural gas.
Bcfe. One billion cubic feet of natural gas equivalent.
Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Boe. Barrel of oil equivalent. Natural gas proved reserves and production are converted to boe at 14.73 psia and 60 degrees. Boe is based on six mcf of natural gas to one bbl of oil or one bbl 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.
Chapter 11 Cases. 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.
Completion. 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. 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. The Company, together with all of its direct and indirect subsidiaries that have filed the Chapter 11 Cases.
Developed Acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.
Dry Well. 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. The first date, February 9, 2021, upon which all conditions precedent to the effectiveness of the Plan have been satisfied or waived in accordance with the Plan and no stay of the Confirmation Order is in effect.
Exit Credit Facility. The reserve-based revolving credit facility available upon emergence from bankruptcy.
Exploratory Well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.
Formation. A succession of sedimentary beds that were deposited under the same general geologic conditions.
Full Cost. The full cost method of accounting, as governed by SEC Regulation S-X 4-10(c), consists of capitalizing all costs associated with property acquisition, exploration and development activities into 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 overhead or similar activities are not included.
GAAP. Generally Accepted Accounting Principles in the United States.
Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which a working interest is owned.
Mboe. One thousand barrels of oil equivalent.
Mcf. One 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 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. The sum of the fractional working interests owned in gross acres or gross wells.
NYMEX. New York Mercantile Exchange.
Petition Date. June 28, 2020, the date on which the Debtors commenced the Chapter 11 Cases.
Plan. The Fifth Amended Joint Chapter 11 Plan of Reorganization of Chesapeake Energy Corporation and its Debtor Affiliates, attached as Exhibit A to the Confirmation Order.
Play. A term applied to 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. The difference in the price of oil, natural gas or NGL received at the sales point and the NYMEX price.
Productive Well. A well that is not a dry well. Productive wells include producing wells and wells that are mechanically capable of production.
Proved Developed Reserves. Proved 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. Properties with proved reserves.
Proved Reserves. As used in this report, proved reserves has the meaning given to such term in Rule 4-10(a)(22) of Regulation S-X, which states in part proved oil and natural gas reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
Proved Undeveloped Reserves (PUDs). 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 include the following items:(i) settlements and accruals for settlements 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 of the hedged item. Unrealized gains and losses include changes in the fair value of open interest rate derivatives offset by amounts reclassified to realized gains and losses during the period.
Reservoir. 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.
Restructuring. The financial restructuring of our debt and equity interests as of the date of the Plan, and certain other obligations pursuant to the Plan.
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 United States Securities and Exchange Commission.
Standardized Measure. 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.
Undeveloped Acreage. 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. Properties with no proved reserves.
Volumetric Production Payment (VPP)(“VPP”). As we use the term, a volumetric production payment represents 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.
WildHorse. WildHorse Resource Development Corporation.Immediately following the completion of our acquisition of WildHorse (the “First Merger”), WildHorse merged with and into Brazos Valley Longhorn, L.L.C., a newly formed Delaware limited liability company and wholly owned subsidiary of Chesapeake, which, together with the First Merger, we refer to as the “WildHorse Merger.” For ease of reference, we use the term “WildHorse” to refer to WildHorse Resource Development Corporation prior to the acquisition and Brazos Valley Longhorn, L.L.C. or, “Brazos Valley Longhorn” or “BVL” after the acquisition, as applicable.
Working Interest. The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.
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 Restructuring on our operations, management, and employees, actions by, or disputes among or between, members of the Organization of Petroleum Exporting Countries (OPEC+) and other foreign, oil-exporting countries, market factors, market prices, our ability to meet debt service requirements, our ongoing evaluation and implementation of strategic alternatives, cost-cutting measures, reductions in capital expenditures, refinancing transactions, capital exchange transactions, asset divestitures, reductions in capital expenditures, operational efficiencies and future impairments 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;
•our ability to comply with the covenants under our Exit Credit Facility and other indebtedness;
•our ability to realize our anticipated annualized 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;
•adverse developments or losses from pending or future litigation and regulatory proceedings, including royalty claims;
effects•legislative and regulatory 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 acquisitions and dispositions, including our acquisition of WildHorse and our ability to realize related synergies;
•effects of purchase price adjustments and indemnity obligations; and
•other factors that are described under Risk Factors in Item 1A 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.
PART I
Item 1. Business
Unless the context otherwise requires, references to “Chesapeake”, the “Company”, “us”, “we” and “our” in this report are to Chesapeake Energy Corporation together with its subsidiaries. Our principal executive offices are located at 6100 North Western Avenue, Oklahoma City, Oklahoma 73118, and our main telephone number at that location is (405) 848-8000.
Our Business
We are an independent exploration and production company engaged in the acquisition, exploration and development of properties to produce oil, natural gas and NGLNGLs from underground reservoirs. We own a large and geographically diverse portfolio of onshore U.S. unconventional liquidsnatural gas and natural gasliquids assets, including interests in approximately 13,2007,400 oil and natural gas wells. We have leading positions in the liquids-rich resource plays of the Eagle Ford Shale in South Texas, the stacked pay in the Powder River Basin in Wyoming and the Anadarko Basin in northwestern Oklahoma. Our natural gas resource plays are the Marcellus Shale in the northern Appalachian Basin in Pennsylvania and the Haynesville/Bossier Shales in northwestern Louisiana.
In October 2018, we sold our interests in the Utica Shale operating area located in Ohio for approximately $1.9 billion to Encino Acquisition Partners (“Encino”), a private oil and gas company headquartered in Houston, Texas. We used the net proceeds to reduce debt.
In February 2019, we acquired WildHorse Resource Development Corporation, an oil and gas company with operations in Our liquids-rich resource plays are the Eagle Ford Shale in South Texas and Austin Chalk formationsthe stacked pay in southeast Texas, for approximately 717.3 million sharesthe Powder River Basin in Wyoming.
On June 28, 2020, we and certain of our subsidiaries filed voluntary petitions for relief under chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Bankruptcy Court confirmed the Plan in a bench ruling on January 13, 2021 and entered the Confirmation Order on January 16, 2021. The Debtors emerged from bankruptcy on February 9, 2021. Upon emergence, all existing equity was canceled and new common stock was issued to the previous holders of our FLLO Term Loan Facility, Second Lien Notes, senior unsecured notes and $381certain 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. To facilitate our discussion in cash,this report, we refer to the post-emergence reorganized company as the “Successor” and the assumption of WildHorse’s debt of $1.4 billionpre-emergence company as the “Predecessor.” See Note2 of the acquisition date of February 1, 2019. The acquisition of WildHorse expandsnotes to our oil growth platform and accelerates our progress toward our strategic and financial goals of enhancing our margins, achieving sustainable free cash flow generation, and reducing our net debt to EBITDA ratio. In conjunction with the acquisition under terms of the merger agreement, David W. Hayes, partner for NGP Energy Capital Management, L.L.C. (“NGP”), has joined our board and another designee of NGP is expected to be appointed to fill the next vacancy on our board. Because the acquisition of WildHorse occurred after December 31, 2018, Chesapeake’s consolidated financial statements included in Item 8 of this report for further discussion of our bankruptcy and the notes thereto do not include or take into account the closing of the acquisition and its effects.resulting reorganization.
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.
The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers, including Chesapeake, that file electronically with the SEC.
Business Strategy
Consistent Returns, Sustainable Future
Our strategy is to create shareholder value through theby generating 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.production activities. 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.
We continue to focus on reducing debt, increasing cash provided by operating activities, improving margins through operating efficiencies and financial discipline and operating efficienciesfurther improving our Environmental, Social and improving environmental and safetyCorporate 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
regardless of the commodity price environment, on capital invested, to deploy leading drilling and completion technology throughout our portfolio, and to take advantage of acquisition and divestiture opportunities to strengthen our 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 absolute level of cash flow from operations, but also increasing our cash flow from operations generated per barrel of oil equivalent production.natural gas producing activities. We continue to seek opportunities to reduce cash costs (production, gathering, processing and transportation and general and administrative and interest expenses)administrative) per barrel of oil equivalent production through operational efficiencies, including but not limited to improving our production volumes from existing wells.
We believe that we have emerged from Chapter 11 bankruptcy as a fundamentally stronger company, built to generate sustainable free cash flow with a strengthened balance sheet, geographically diverse asset base and continuously improving ESG performance.
Maintain low leverage and strong liquidity. Now that we have emerged from Chapter 11 bankruptcy, we expect to target a net leverage ratio, which is measured as our dedicationnet debt as a ratio of trailing 12-month EBITDAX, of less
than 1x. 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. As a result, we will target a long-term disciplined capital reinvestment rate, which we define as annual capital expenditures as a percentage of trailing 12-month EBITDAX, of 60% to 70%. We believe this level of reinvestment will be adequate to support our target long-term annual maintenance capital expenditure level, excluding capitalized interest, of $700 million to $750 million. We expect our maintenance capital program to yield in excess of annual production of 400 thousand barrels of oil equivalent 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 reduction initiatives, targeting a long-term annual free cash flow yield of 30% to 40% of annual EBITDAX. Since filing the Chapter 11 Cases in June 2020, we have successfully renegotiated or terminated certain of our midstream contracts and commitments, which resulted in significant reduction to our anticipated gathering, processing and transportation expenses, cumulatively achieving approximately $4 billion in expected lifetime contract savings (or $2 billion discounted to present value, assuming a 10% annual discount rate). For 2019, our total cash costs, inclusive of gathering, processing and transportation, operating, general and administrative and interest expenses were $2.8 billion. Now that we have emerged from Chapter 11 bankruptcy, based on the termination or successful renegotiation of many of our gathering, processing and transportation contracts, as well as reductions in expected interest, operating and general and administrative expenses, we expect our annualized cash costs for 2021 to be reduced by approximately $1 billion relative to 2019.
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 plan to eliminate routine flaring on all new wells completed in 2021 and beyond, and accomplish the same on all wells, enterprise-wide by 2025. We intend to reduce our methane loss rate to 0.09% and our GHG intensity to 5.5 by 2025, reductions of 47% and 33%, respectively, as compared to 2019.
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 25, 2021, and environmental stewardship will provide opportunities to create value for usconsistent with requirements of our DIP Credit Facility we have 19 mmbbls and our shareholders.548 bcf of expected 2021, representing 77% and 74% of 2021 forecasted oil and natural gas production hedged at prices of $42.69/bbl and $2.67/mcf, respectively. Additionally, as of February 25, 2021, we have hedged 11 mmbbl and 273 bcf of expected 2022 oil and natural gas production at prices of $44.30/bbl and $2.53/mcf, respectively.
Operating Areas
We focus our acquisition, exploration, development acquisition and production efforts in the sixfive geographic operating areas described below.
Marcellus - Northern Appalachian Basin in Pennsylvania.
Haynesville - Northwestern Louisiana (Gulf Coast).
Eagle Ford - South Texas.
Brazos Valley - Southeast Texas assets acquired in our WildHorse acquisition on February 1, 2019.Texas.
Powder River Basin - Stacked pay in Wyoming.
Mid-Continent - Anadarko Basin in northwestern Oklahoma.
Well Data
As of December 31, 2018,2020, we held an interest in approximately 13,2007,400 gross (5,600 net) productive wells, including 10,2005,900 properties in which we held a working interest and 3,0001,500 properties in which we held an overriding or royalty interest. Of the 10,2005,900 (3,700 net) properties in which we hadheld a working interest, we operated 7,200 wells, 6,800 gross (3,8002,500 (1,400 net), of which properties were classified as productive natural gas wells and 3,400 gross (1,800(2,300 net) properties were classified as productive oil wells. During 2018,2020 excluding sold properties, we operated 5,200 gross wells and held a non-operating working interest in 700 gross wells. We also drilled or participated in 351188 gross (238(128 net) wells as operator and participated in another 2617 gross (1(nominal net) wells completed by other operators. We operate approximately 97% of our current daily production volumes.
Drilling Activity
The following table sets forth the wells we drilled 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:
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2018 | | 2017 | | 2016 |
| | | Gross | | % | | Net | | % | | Gross | | % | | Net | | % | | Gross | | % | | Net | | % |
| Development: | | | | | | | | | | | | | | | | | | | | | | | | |
| Productive | | 363 |
| | 99 |
| | 227 |
| | 99 |
| | 462 |
| | 99 |
| | 292 |
| | 99 |
| | 431 |
| | 99 |
| | 236 |
| | 99 |
|
| Dry | | 2 |
| | 1 |
| | 1 |
| | 1 |
| | 4 |
| | 1 |
| | 2 |
| | 1 |
| | 1 |
| | 1 |
| | 1 |
| | 1 |
|
| Total | | 365 |
| | 100 |
| | 228 |
| | 100 |
| | 466 |
| | 100 |
| | 294 |
| | 100 |
| | 432 |
| | 100 |
| | 237 |
| | 100 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Exploratory: | | �� | | | | | | | | | | | | | | | | | | | | | | |
| Productive | | 10 |
| | 83 |
| | 9 |
| | 82 |
| | 2 |
| | 100 |
| | 2 |
| | 100 |
| | 3 |
| | 100 |
| | 2 |
| | 100 |
|
| Dry | | 2 |
| | 17 |
| | 2 |
| | 18 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total | | 12 |
| | 100 |
| | 11 |
| | 100 |
| | 2 |
| | 100 |
| | 2 |
| | 100 |
| | 3 |
| | 100 |
| | 2 |
| | 100 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 | | 2018 |
| | Gross | | % | | Net | | % | | Gross | | % | | Net | | % | | Gross | | % | | Net | | % |
| Development: | | | | | | | | | | | | | | | | | | | | | | | | |
| Productive | | 203 | | | 100 | | | 126 | | | 100 | | | 414 | | | 100 | | | 271 | | | 100 | | | 363 | | | 99 | | | 227 | | | 99 | |
| Dry | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | 2 | | | 1 | | | 1 | | | 1 | |
| Total | | 203 | | | 100 | | | 126 | | | 100 | | | 414 | | | 100 | | | 271 | | | 100 | | | 365 | | | 100 | | | 228 | | | 100 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| Exploratory: | | | | | | | | | | | | | | | | | | | | | | | | |
| Productive | | — | | | — | | | — | | | — | | | 1 | | | 20 | | | 1 | | | 20 | | | 10 | | | 83 | | | 9 | | | 82 | |
| Dry | | 2 | | | 100 | | | 2 | | | 100 | | | 4 | | | 80 | | | 4 | | | 80 | | | 2 | | | 17 | | | 2 | | | 18 | |
| Total | | 2 | | | 100 | | | 2 | | | 100 | | | 5 | | | 100 | | | 5 | | | 100 | | | 12 | | | 100 | | | 11 | | | 100 | |
The following table shows the wells we drilled or participated in by operating area:
| | | | | 2018 | | 2017 | | 2016 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Gross Wells | | Net Wells | | Gross Wells | | Net Wells | | Gross Wells | | Net Wells | | 2020 | | 2019 | | 2018 |
| | | | | | | | | | | | | | | Gross Wells | | Net Wells | | Gross Wells | | Net Wells | | Gross Wells | | Net Wells |
| Marcellus | | 52 |
| | 23 |
| | 43 |
| | 21 |
| | 19 |
| | 9 |
| Marcellus | | 79 | | | 33 | | | 44 | | | 22 | | | 52 | | | 23 | |
| Haynesville | | 30 |
| | 21 |
| | 37 |
| | 34 |
| | 41 |
| | 34 |
| Haynesville | | 21 | | | 19 | | | 22 | | | 16 | | | 30 | | | 21 | |
| Eagle Ford | | 162 |
| | 98 |
| | 180 |
| | 106 |
| | 199 |
| | 116 |
| Eagle Ford | | 55 | | | 36 | | | 150 | | | 85 | | | 162 | | | 98 | |
| Brazos Valley | | Brazos Valley | | 31 | | | 29 | | | 83 | | | 79 | | | — | | | — | |
| Powder River Basin | | 41 |
| | 34 |
| | 25 |
| | 21 |
| | 1 |
| | 1 |
| Powder River Basin | | 12 | | | 9 | | | 75 | | | 57 | | | 41 | | | 34 | |
| Mid-Continent | | 52 |
| | 32 |
| | 114 |
| | 58 |
| | 135 |
| | 62 |
| Mid-Continent | | 5 | | | — | | | 40 | | | 12 | | | 52 | | | 32 | |
| Utica | | 40 |
| | 31 |
| | 69 |
| | 56 |
| | 34 |
| | 17 |
| Utica | | — | | | — | | | — | | | — | | | 40 | | | 31 | |
| Other | | — |
| | — |
| | — |
| | — |
| | 6 |
| | — |
| Other | | 2 | | | 2 | | | 5 | | | 5 | | | — | | | — | |
| Total | | 377 |
| | 239 |
| | 468 |
| | 296 |
| | 435 |
| | 239 |
| Total | | 205 | | | 128 | | | 419 | | | 276 | | | 377 | | | 239 | |
As of December 31, 2018,2020, we had 14955 gross (82(32 net) wells in the process of being drilled or completed.
Production Volumes, Sales Prices, Production Expenses and Gathering, Processing and Transportation Expenses
The following table sets forth information regarding our net production volumes, average sales price received for our production, average sales price of our production combined with our realized gains or losses on derivatives and production and gathering, processing and transportation expenses per boe for the periods indicated:
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | | 2020 | | 2019 | | 2018 |
| Net Production: | | | | | | |
| Oil (mmbbl) | | 37 | | | 43 | | | 33 | |
| Natural gas (bcf) | | 685 | | | 728 | | | 832 | |
| NGL (mmbbl) | | 11 | | | 12 | | | 19 | |
| Oil equivalent (mmboe) | | 163 | | | 177 | | | 190 | |
| | | | | | |
| Average Sales Price of Production: | | | | | | |
| Oil ($ per bbl) | | $ | 38.16 | | | $ | 59.16 | | | $ | 67.25 | |
| Natural gas ($ per mcf) | | $ | 1.73 | | | $ | 2.45 | | | $ | 2.99 | |
| NGL ($ per bbl) | | $ | 11.55 | | | $ | 15.62 | | | $ | 26.50 | |
| Oil equivalent ($ per boe) | | $ | 16.84 | | | $ | 25.57 | | | $ | 27.27 | |
| | | | | | |
| Average Sales Price (including realized gains (losses) on derivatives): | | | | |
| Oil ($ per bbl) | | $ | 56.74 | | | $ | 60.00 | | | $ | 57.42 | |
| Natural gas ($ per mcf) | | $ | 1.97 | | | $ | 2.60 | | | $ | 3.00 | |
| NGL ($ per bbl) | | $ | 11.55 | | | $ | 15.62 | | | $ | 25.84 | |
| Oil equivalent ($ per boe) | | $ | 22.09 | | | $ | 26.42 | | | $ | 25.56 | |
| | | | | | |
| Expenses ($ per boe): | | | | | | |
| Oil, natural gas and NGL production | | $ | 2.29 | | | $ | 2.94 | | | $ | 2.50 | |
| Oil, natural gas and NGL gathering, processing and transportation | | $ | 6.64 | | | $ | 6.13 | | | $ | 7.35 | |
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| Net Production: | | | | | | |
| Oil (mmbbl) | | 33 |
| | 33 |
| | 33 |
|
| Natural gas (bcf) | | 832 |
| | 878 |
| | 1,049 |
|
| NGL (mmbbl) | | 19 |
| | 21 |
| | 24 |
|
| Oil equivalent (mmboe) | | 190 |
| | 200 |
| | 233 |
|
| | | | | | | |
| Average Sales Price of Production: | | | | | | |
| Oil ($ per bbl) | | $ | 67.25 |
| | $ | 51.03 |
| | $ | 40.65 |
|
| Natural gas ($ per mcf) | | $ | 2.99 |
| | $ | 2.76 |
| | $ | 2.05 |
|
| NGL ($ per bbl) | | $ | 26.50 |
| | $ | 23.18 |
| | $ | 14.76 |
|
| Oil equivalent ($ per boe) | | $ | 27.27 |
| | $ | 22.88 |
| | $ | 16.63 |
|
| | | | | | | |
| Average Sales Price (including realized gains (losses) on derivatives): | | | | |
| Oil ($ per bbl) | | $ | 57.42 |
| | $ | 53.19 |
| | $ | 43.58 |
|
| Natural gas ($ per mcf) | | $ | 3.00 |
| | $ | 2.75 |
| | $ | 2.20 |
|
| NGL ($ per bbl) | | $ | 25.84 |
| | $ | 22.98 |
| | $ | 14.43 |
|
| Oil equivalent ($ per boe) | | $ | 25.56 |
| | $ | 23.17 |
| | $ | 17.66 |
|
| | | | | | | |
| Expenses ($ per boe): | | | | | | |
| Oil, natural gas and NGL production | | $ | 2.84 |
| | $ | 2.81 |
| | $ | 3.05 |
|
| Oil, natural gas and NGL gathering, processing and transportation | | $ | 7.35 |
| | $ | 7.36 |
| | $ | 7.98 |
|
Oil, Natural Gas and NGL Reserves
The tables below set forth information as of December 31, 2018,2020, with respect to our estimated proved reserves, the associated estimated future net revenue, the present value of estimated future net revenue (“PV-10”) and the standardized measure of discounted future net cash flows (“standardized measure”). None of the estimated future net revenue, PV-10 nor the standardized measure are intended to represent the current market value of the estimated oil, natural gas and NGL reserves we own. All of our estimated reserves are located within the United States.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2020 |
| | Oil | | Natural Gas | | NGL | | Total |
| | (mmbbl) | | (bcf) | | (mmbbl) | | (mmboe) |
| Proved developed | | 158 | | | 3,196 | | | 51 | | | 742 | |
| Proved undeveloped | | 3 | | | 334 | | | 1 | | | 60 | |
Total proved(a) | | 161 | | | 3,530 | | | 52 | | | 802 | |
|
| | | | | | | | | | | | |
| | | December 31, 2018 |
| | | Oil | | Natural Gas | | NGL | | Total |
| | | (mmbbl) | | (bcf) | | (mmbbl) | | (mmboe) |
| Proved developed | | 127.6 |
| | 3,314 |
| | 67.9 |
| | 748 |
|
| Proved undeveloped | | 87.9 |
| | 3,463 |
| | 35.4 |
| | 700 |
|
Total proved(a) | | 215.5 |
| | 6,777 |
| | 103.3 |
| | 1,448 |
|
| | | | | Proved Developed | | Proved Undeveloped | | Total Proved | | Proved Developed | | Proved Undeveloped | | Total Proved |
| | | ($ in millions) | | ($ in millions) |
Estimated future net revenue(b) | | $ | 10,214 |
| | $ | 7,120 |
| | $ | 17,334 |
| Estimated future net revenue(b) | | $ | 4,519 | | | $ | 202 | | | $ | 4,721 | |
Present value of estimated future net revenue (PV-10)(b) | | $ | 6,177 |
| | $ | 3,350 |
| | $ | 9,527 |
| Present value of estimated future net revenue (PV-10)(b) | | $ | 2,976 | | | $ | 111 | | | $ | 3,087 | |
Standardized measure(b) | Standardized measure(b) | | $ | 9,495 |
| Standardized measure(b) | | $ | 3,086 | |
| |
(a) | Marcellus, Haynesville and Eagle Ford accounted for approximately 40%, 27%, and 22%, respectively, of our estimated proved reserves by volume as of December 31, 2018. |
| |
(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, 2018, 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, 2018. The prices used in our PV-10 measure were $65.56 of oil and $3.10 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, 2018. 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 $32 million as of December 31, 2018. |
(a) Marcellus, Eagle Ford, and Haynesville accounted for approximately 47%, 22%, and 18% respectively, of our estimated proved reserves by volume as of December 31, 2020.
(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, 2020, 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, 2020. The prices used in our PV-10 measure were $39.57 of oil and $1.98 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, 2020. 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 million as of December 31, 2020.
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.
As of December 31, 2018,2020, our proved reserve estimates included 70060 mmboe of reserves classified as proved undeveloped, compared to 796726 mmboe as of December 31, 2017.2019. Presented below is a summary of changes in our proved undeveloped reserves (PUDs) for 2018:
|
| | | | | | | |
| | Total |
| | (mmboe) |
| Proved undeveloped reserves, beginning of period | | 796726 |
|
| Extensions and discoveries | | 2361 |
|
| Revisions of previous estimates | | (27(539) | ) |
| Developed | | (115(128) | ) |
SalePurchase of reserves-in-place | | (190— | ) |
| Proved undeveloped reserves, end of period | | 70060 |
|
As of December 31, 2018,2020, all PUDs were planned to be developed within five years.years of original recording. In 2018,2020, we invested approximately $807$509 million to convert 115128 mmboe of PUDs to proved developed reserves. In 2019,During the first quarter of 2021, we estimate that we will invest approximately $1.2 billion$126 million for PUD conversion. We added 236 mmboe of proved undeveloped reserves through extensions and discoveries primarily asAs a result of longer planned lateral lengthsour entry into Chapter 11 bankruptcy and additional allocated capital inthe limited duration of our five-year development plan. We sold 190 mmboeDIP Credit Facility at December 31, 2020, we could not carry any PUD reserves past the maturity date of proved undeveloped reserves primarily in the divestiture of Utica Shale assets. Weour DIP financing and we therefore recorded a downward revision of 27539 mmboe from previous estimates dueof our previously reported PUD reserves. Given our liquidity and financial position post-emergence we expect to ongoing portfolio evaluation including longer lateral and spacing adjustments.record more PUD reserves as of March 31, 2021.
The future net revenue attributable to our estimated PUDs was $7.1 billion$202 million and the present value was $3.3 billion$111 million as of December 31, 2018.2020. These values were calculated assuming that we will expend approximately $3.6 billion$126 million to develop these reserves ($1.2 billion in 2019, $984 million in 2020, $901 million in 2021, $337 million in 2022 and $166 million in 2023). The amount and timingduring the first quarter 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.2021.
Of our 748742 mmboe of proved developed reserves as of December 31, 2018,2020, approximately 206 mmboe, or 3%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, 2018, 20172020, 2019 and 2016,2018, 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.
Reserves Estimation
Our Corporate Reserves Department prepared approximately 20%13% by volume, and approximately 18%11% by value, of our estimated proved reserves 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 1518 years of practical experience in the oil and gas industry, with 12over 15 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 reserves estimates. Each of our Corporate Reserves Engineers has significant engineering experience in reserve estimation. Our engineering technicians have a minimum of a four-year degree in mathematics, economics, finance or other technical/business/science field. We maintain a continuous education program for our engineers and technicians on new technologies and industry advancements as well as refresher training on basic skills and analytical techniques.
We maintain internal controls such as the following to ensure the reliability of reserves estimations:
•We follow comprehensive SEC-compliant internal policies to estimate and report proved reserves. Reserve estimates are made by experienced reservoir engineers or under their direct supervision. All material changes are reviewed and approved by Corporate Reserves Engineers.
•The Corporate Reserves Department reviews our proved reserves at the close of each quarter.
•Each quarter, Reservoir Managers, the Director – Corporate Reserves, the Vice Presidents of our business units, 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 – 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 80%87% by volume, and approximately 82%89% by value, of our estimated proved reserves as of December 31, 2018.2020. 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.
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, |
| | | 2018 | | 2017 | | 2016 |
| | | ($ in millions) |
| Acquisition of Properties: | | | | | | |
| Proved properties | | $ | 80 |
| | $ | 23 |
| | $ | 403 |
|
| Unproved properties | | 216 |
| | 271 |
| | 403 |
|
| Exploratory costs | | 132 |
| | 21 |
| | 52 |
|
| Development costs | | 2,009 |
| | 2,146 |
| | 1,312 |
|
Costs incurred(a) | | $ | 2,437 |
| | $ | 2,461 |
| | $ | 2,170 |
|
| |
(a) | Includes capitalized interest and asset retirement obligations as follows: |
|
| | | | | | | | | | | | |
| Capitalized interest | | $ | 162 |
| | $ | 194 |
| | $ | 242 |
|
Asset retirement obligations(b) | | $ | 8 |
| | $ | (34 | ) | | $ | (57 | ) |
| |
(b) | Activity in 2017 and 2016 primarily reflects revisions as the result of decreased plugging and abandonment costs in certain of our operating areas. |
A summary of our exploration and development, acquisition and divestiture activities in 2018 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 | | 52 |
| | 23 |
| | $ | 170 |
| | $ | 5 |
| | $ | 1 |
| | $ | (2 | ) | | $ | — |
| | $ | 174 |
|
| Haynesville | | 30 |
| | 21 |
| | 346 |
| | 6 |
| | — |
| | (5 | ) | | (8 | ) | | 339 |
|
| Eagle Ford | | 162 |
| | 98 |
| | 696 |
| | 14 |
| | — |
| | (2 | ) | | — |
| | 708 |
|
| Powder River Basin | | 41 |
| | 34 |
| | 395 |
| | 73 |
| | — |
| | (28 | ) | | — |
| | 440 |
|
| Mid-Continent | | 52 |
| | 32 |
| | 201 |
| | 19 |
| | 1 |
| | (123 | ) | | (262 | ) | | (164 | ) |
| Utica | | 40 |
| | 31 |
| | 301 |
| | 90 |
| | 77 |
| | (325 | ) | | (2,039 | ) | | (1,896 | ) |
| Other | | — |
| | — |
| | 32 |
| | 9 |
| | 1 |
| | — |
| | (6 | ) | | 36 |
|
| Total | | 377 |
| | 239 |
| | $ | 2,141 |
| | $ | 216 |
| | $ | 80 |
| | $ | (485 | ) | | $ | (2,315 | ) | | $ | (363 | ) |
| |
(a) | Includes asset retirement disposal of $28 million related to divestitures. |
| |
(b) | Includes capitalized internal costs of $121 million and capitalized interest of $162 million. |
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, 2018.2020. Gross acres are the total number of acres in which we own a working interest. Net acres refer to gross acres multiplied by our fractional working interest. Acreage numbers do not include our unexercised options to acquire additional acreage.
| | | | | Developed Leasehold | | Undeveloped Leasehold | | Fee Minerals | | Total | | Developed Leasehold | | Undeveloped Leasehold | | Fee Minerals | | Total |
| | | 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 | | Gross Acres | | Net Acres |
| | | (in thousands) | | (in thousands) |
| Marcellus | | 541 |
| | 347 |
| | 265 |
| | 177 |
| | 16 |
| | 16 |
| | 822 |
| | 540 |
| Marcellus | | 555 | | | 353 | | | 245 | | | 168 | | | 16 | | | 16 | | | 816 | | | 537 | |
| Haynesville | | 302 |
| | 270 |
| | 99 |
| | 67 |
| | — |
| | — |
| | 401 |
| | 337 |
| Haynesville | | 230 | | | 203 | | | 30 | | | 22 | | | 1 | | | 1 | | | 261 | | | 226 | |
| Eagle Ford | | 308 |
| | 183 |
| | 77 |
| | 52 |
| | — |
| | — |
| | 385 |
| | 235 |
| Eagle Ford | | 316 | | | 188 | | | 45 | | | 31 | | | — | | | — | | | 361 | | | 219 | |
| Brazos Valley | | Brazos Valley | | 360 | | | 298 | | | 222 | | | 126 | | | — | | | — | | | 582 | | | 424 | |
| Powder River Basin | | 73 |
| | 58 |
| | 244 |
| | 189 |
| | 1 |
| | 1 |
| | 318 |
| | 248 |
| Powder River Basin | | 105 | | | 85 | | | 137 | | | 104 | | | 1 | | | 1 | | | 243 | | | 190 | |
| Mid-Continent | | 926 |
| | 602 |
| | 200 |
| | 132 |
| | 38 |
| | 34 |
| | 1,164 |
| | 768 |
| |
Other(a) | | 184 |
| | 146 |
| | 1,066 |
| | 983 |
| | 435 |
| | 431 |
| | 1,685 |
| | 1,560 |
| Other(a) | | 157 | | | 126 | | | 918 | | | 868 | | | 431 | | | 427 | | | 1,506 | | | 1,421 | |
| Total | | 2,334 |
| | 1,606 |
| | 1,951 |
| | 1,600 |
| | 490 |
| | 482 |
| | 4,775 |
| | 3,688 |
| Total | | 1,723 | | | 1,253 | | | 1,597 | | | 1,319 | | | 449 | | | 445 | | | 3,769 | | | 3,017 | |
| |
(a) | Includes 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 noncore divestitures to high-grade our lease inventory and letting some leases expire that are no longer part of our development plans. The following table sets forth the expiration periods of gross and net undeveloped leasehold acres as of December 31, 2018:2020:
| | | | | | | | | | | | | | |
| | Acres Expiring |
| | Gross Acres | | Net Acres |
| | (in thousands) |
| Years Ending December 31: | | | | |
| 2021 | | 60 | | | 52 | |
| 2022 | | 30 | | | 30 | |
| 2023 | | 12 | | | 11 | |
| After 2023 | | 83 | | | 82 | |
Held-by-production(a) | | 1,412 | | | 1,144 | |
| Total | | 1,597 | | | 1,319 | |
(a) Held-by-production acres will remain in force as production continues on the subject leases.
|
| | | | | | |
| | | Acres Expiring |
| | | Gross Acres | | Net Acres |
| | | (in thousands) |
| Years Ending December 31: | | | | |
| 2019 | | 108 |
| | 87 |
|
| 2020 | | 49 |
| | 44 |
|
| 2021 | | 37 |
| | 27 |
|
| After 2021 | | 53 |
| | 51 |
|
Held-by-production(a) | | 1,704 |
| | 1,391 |
|
| Total | | 1,951 |
| | 1,600 |
|
| |
(a) | Held-by-production acres will remain in force as production continues on the subject leases. |
Marketing
The principal function of our marketing operations is to provide oil, natural gas and NGL marketing services, including commodity price structuring, securing and negotiating of gathering, hauling, processing and transportation services, contract administration and nomination services for us and other interest owners in Chesapeake-operated wells. The marketing operations also provide other services for our exploration and production activities, including services to enhance the value of oil and natural gas production by aggregating volumes sold to various intermediary markets, end markets and pipelines. This aggregation allows us to attract larger, more creditworthy customers that in turn assist in maximizing the prices received. 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.
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 46 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of commitments. Major Customers
Sales to Valero Energy Corporation constituted approximately 17%, 12% and 10% of our total revenues (before the effects of hedging) for the yearyears ended December 31, 2018.2020, 2019 and 2018, respectively. No other purchasers accounted for more than 10% of our total revenues forin 2020, 2019 or 2018. 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% of our total revenues (before the effects of hedging) for the year ended December 31, 2016.
Competition
We compete with both major integrated and other independent oil and natural gas companies in all aspects of our business to explore, develop and operate our properties and market our production. Some of our competitors may have larger financial and other resources than us. Competitive conditions may be affected by future legislation and regulations as the United States develops new energy and climate-related policies. In addition, some of our competitors may have a competitive advantage when responding to factors that affect demand for oil and natural gas production, such as changing prices, domestic and foreign political conditions, weather conditions, the price and availability of alternative fuels, the proximity and capacity of natural gas pipelines and other transportation facilities and overall economic conditions. We also face indirect competition from alternative energy sources, including wind, solar and electric power. We believe that our technological expertise, combined with our exploration, land, drilling and production capabilities and the experience of our management team, enables us to compete effectively.
Public Policy and Government Regulation
All of our operations are conducted onshore in the United States. Our industry is subject to a wide range of regulations, laws, rules, taxes, fees and other policy implementation actions that have been pervasive and are under constant review for amendment or expansion. Numerous government agencies have issued extensive regulations whichthat are binding on our industry, some of which carry substantial penalties for failure to comply. These laws and regulations increase the cost of doing business and consequently affect profitability. Additionally, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. We actively monitor regulatory developments applicable to our industry in order to anticipate, design and implement required compliance activities and systems. The following are significant areas of government control and regulation affecting our operations.
Regulation – Environment, Health and Safety
Exploration and Production, Environmental, Health and Safety and Occupational Laws and Regulations
Our operations are subject to federal, tribal, state, and local laws and regulations. These laws and regulations relate to matters that include, but are not limited to, the following:
•reporting of workplace injuries and illnesses;
•industrial hygiene monitoring;
•worker protection and workplace safety;
•approval or permits to drill and to conduct operations;
•provision of financial assurances (such as bonds) covering drilling and well operations;
•calculation and disbursement of royalty payments and production taxes;
•seismic operations and operations/data;
•location, drilling, cementing and casing of wells;
•well design and construction of pad and equipment;
•construction and operations activities in sensitive areas, such as wetlands, coastal regions or areas that contain endangered or threatened species, their habitats, or sites of cultural significance;
•method of completing wells;
well completion and hydraulic fracturing;
•water withdrawal;
•well production and operations, including processing and gathering systems;
•emergency response, contingency plans and spill prevention plans;
air •emissions and fluid discharges;discharges permitting;
•climate change;
•use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations;
•surface usage, maintenance, monitoring and the restoration of properties associated with well pads, pipelines, impoundments and access roads;
•plugging and abandoning of wells; and
•transportation of production.
Shortly after taking office in January 2021, President Biden issued a series of executive orders designed to address climate change and requiring agencies to review environmental actions taken by the Trump administration, as well as a memorandum to departments and agencies to refrain from proposing or issuing rules until a departmental or agency head appointed or designated by the Biden administration has reviewed and approved the rule. These executive orders may result in the development of additional regulations or changes to existing regulations. Failure to comply with these laws and regulations can lead to the imposition of remedial liabilities, administrative, civil or criminal fines or criminal penalties or to 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 costs of environmental protection and of safety and health compliance to be necessary,fundamental, manageable parts of our business. 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, our capital expenditures and operating expenses related to compliance with 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. See the Risk Factors described in Item 1A of this report for further discussion of governmental regulation and ongoing regulatory changes, including with respect to environmental matters,
Our operations also are also 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 forced pooling or integration of tracts to facilitate exploration. Otherexploration, while other states rely on voluntary pooling of lands and leases, which may make it more difficult to develop oil and gas properties. In addition, federal and state conservation laws generally limit the venting or flaring of natural gas, and state conservation laws impose certain requirements regarding the ratable purchase of production. These regulations limit the amounts of oil and gas we can produce from our wells and the number of wells or the locations at which we can drill.
For further discussion, see Item 1A. Risk Factors - We are subject to extensive governmental regulation, which can change and could adversely impact our business.
Regulatory proposals in some states and local communities have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. Federal and state agencies
have continued to assess the potential impacts of hydraulic fracturing, which could spur further action toward federal, state and/or local legislation and regulation. Further restrictions of hydraulic fracturing could make it difficult or impossible to conduct our drilling and completion operations, and thereby reduce the amount of oil, natural gas and NGL that we are ultimately able to produce in commercial quantities from our properties.
Certain of our U.S. natural gas and oil leases, primarily in our Powder River Basin operating area, are granted or approved by the federal government and administered by the Bureau of Land Management (BLM) or Bureau of Indian Affairs (BIA) of the Department of the Interior. Such leases require compliance with detailed federal regulations and orders that regulate, among other matters, drilling and operations on lands covered by these leases and calculation and disbursement of royalty payments to the federal government, tribes or tribal members. The federal government has been particularly active in recent years in evaluating and, in some cases, promulgating new rules and regulations regarding competitive lease bidding, venting and flaring, oil and gas measurement and royalty payment obligations for production from federal lands. In addition, 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. To the extent that the review results in the development of additional restrictions on drilling, limitations on the availability of leases, or restrictions on the ability to obtain required permits, it could have a material adverse impact on our operations.
Permitting activities on federal lands are also subject to frequent delays.
Delays in obtaining permits or an inability to obtain new permits or permit renewals could inhibit our ability to execute our drilling and production plans. Failure to comply with applicable regulations or permit requirements could result in revocation of our permits, inability to obtain new permits and the imposition of fines and penalties.
For further discussion, see Item 1A. Risk Factors - Oil and natural gas drilling and producing operations can be hazardous and may expose us to liabilities. 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.
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 $75$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
Robert D. Lawler, President, Chief Executive Officer and Director
Robert D. (“Doug”) Lawler, 52,54, has served as President and Chief Executive Officer since June 2013. Prior to joining Chesapeake, Mr. Lawler 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., 42,44, has served as Executive Vice President and Chief Financial Officer since November 2010. Mr. Dell'Osso served as our Vice President – Finance and Chief Financial Officer of our wholly owned midstream subsidiary, Chesapeake Midstream Development, L.P., from August 2008 to November 2010. Before joining Chesapeake, Mr. Dell’Osso was an energy investment banker with Jefferies & Co. from 2006 to 2008 and Banc of America Securities from 2004 to 2006.
Frank J. Patterson, ExecutiveVice President – Exploration and Production
Frank J. Patterson, 60,62, 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 Anadarko from 2006 to 2015, most recently as Senior Vice President – International Exploration. Prior to that he was Vice President – Deepwater Exploration at Kerr-McGee and Manager – Geology at Sun E&P/Oryx Energy.
M. Jason Pigott, Executive Vice President – Operations and Technical Services
M. Jason Pigott, 45,has served as Executive Vice President – Operations and Technical Services since August 2016. Previously, he served as 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, 51,53, has served as Executive Vice President – General Counsel and Corporate Secretary since January 2014. Previously, he served as Senior Vice President – Legal 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. Prior to joining Chesapeake, Mr. Webb was an attorney with the law firm of McAfee & Taft from 1995 to October 2012.
William M. Buergler, – Senior Vice President and Chief Accounting Officer
William Buergler, 46,48, 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.
Employees
Human Capital
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. It is a culture that engages the power of our people, working cooperatively to put Chesapeake first and perform our best for the company. We had approximately 2,3501,300 employees as of December 31, 2018.February 25, 2021.
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. Through the Chief Executive Officer Action for Diversity & Inclusion™, Chief Executive Officer Doug Lawler committed himself and Chesapeake to cultivate a workplace in which diverse perspectives and experiences are welcomed and respected and where employees feel encouraged to discuss diversity and inclusion. As the first E&P Chief Executive Officer to sign the pledge, Mr. Lawler joins more than 550 signatories who are sharing best practices and learning opportunities to initiate real change within their organizations. On February 9, 2021, we formed a board committee dedicated to ESG oversight, including our inclusion and diversity efforts. Two of our seven directors are considered diverse, including one female and one “underrepresented minority” (as defined in Nasdaq’s newly proposed listing rule).
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
•Reducing our GHG intensity to 5.5 by 2025
Safety First Every Day
Safety is more than a company metric, it is a value that drives our commitment to responsible operations. We set and deliver on strict safety standards, prioritizing safety for everyone every day. Our safety culture is modeled first by Mr. Lawler, with guidance and leadership from 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.
One program that reinforces this philosophy of personal responsibility is Stop Work Authority. Through Stop Work Authority, every employee and contractor has the right and responsibility 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 equip these 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.
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.
ITEM 1A. Risk Factors
There are numerous factors that affect our business and operating results, 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, 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.
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.
Upon emergence from bankruptcy, the composition of our board of directors changed significantly.
The composition of our board of directors changed significantly upon emergence from bankruptcy. Our new board is comprised of the following members appointed by our new stockholders. Robert D. Lawler, Michael Wichterich, Timothy S. Duncan, Benjamin C. Duster, IV, Sarah Emerson, Matthew M. Gallagher and Brian Steck. While we expect to engage in an orderly transition process as we integrate newly appointed board members, our new board of directors may change views on strategic initiatives and a range of issues that will determine the future of the Company. As a result, the future strategy and plans of the Company may differ materially from those of the past.
Risks Related to Operating Our Business
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, profitability, liquidity, leverage ratio and ability to grow and invest in capital expenditures depend primarily upon the prices we receive for the oil, natural gas and NGL we sell. We incur substantial expenditures to replace reserves, sustain production and fund our business plans. Low oil, natural gas and NGL prices can negatively affect the amount of cash available for capital expenditures, debt service and debt repayment and our ability to borrow money or raise additional capital and, as a result, could have a material adverse effect on our financial condition, results of operations, cash flows and reserves. In addition, periods of low oil and natural gas prices may result in ceiling test write-downsa reduction of the carrying value of our oil and natural gas properties.
Historically, the markets for oil, natural gasproperties due to recognizing impairments in proved and NGL have been volatile, and they are likely to continue to be volatile. For example, during the period from January 1, 2014 to December 31, 2018, NYMEX WTI oil prices ranged from a high of $107.26 per bbl to a low of $26.21 per bbl and NYMEX Henry Hub natural gas prices ranged from a high of $6.15 per MMBtu to a low of $1.64 per MMBtu. As of February 22, 2019, the NYMEX WTI oil price was $57.08 per bbl and the NYMEX Henry Hub natural gas price was $2.72 per MMBtu.unproved properties.
Wide fluctuations 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 recent coronavirus;
•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 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, 2019, including January and February derivative contracts that have settled, approximately 63% of our forecasted oil, natural gas and NGL production revenue was hedged, including 56% and 81% of our forecasted 2019 oil and natural gas production (including WildHorse production from February 1, 2019) at average prices of $57.12 per barrel and $2.85 per mcf, respectively. Even with oil, natural gas and NGL derivatives currently in place to mitigate price risks associated with a portion of our 2019 cash flows, we have substantial exposure to oil, natural gas and NGL prices in 2020 and beyond.movements. In addition, a prolonged extension of lower prices could reduce the quantities of reserves that we may economically produce.
WeThe ongoing coronavirus (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, 2018, we had approximately $8.2 billion in principal amount of debt outstanding (including $381 million of current maturities and $419 million drawn under our senior secured revolving credit facility). As of December 31, 2018, we had approximately $107 million of letters of credit issued and borrowing capacity of approximately $2.5 billion under our $3.0 billion senior secured revolving credit facility (the “Chesapeake revolving credit facility”). In addition, on February 1, 2019, we acquired $1.4 billion principal amount of debt upon the closing of the WildHorse Merger (including $675 million drawn under the WildHorse senior secured revolving credit facility (the “WildHorse revolving credit facility”)). We had approximately $47 million of letters of credit issued and borrowing capacity of approximately $578 million under the $1.3 billion WildHorse revolving credit facility. See Note 3 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our debt obligations, including debt maturities for the next five years and thereafter.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 the Chesapeake revolving credit facility and the WildHorse revolving 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 facilities for liquidity, and the borrowing bases under our $3.0 billion Chesapeake credit facility and our $1.3 billion WildHorse revolving credit facility are subject to redeterminations in the second quarter of 2019. If our borrowing bases under our revolving credit facilities decrease as a result of lower prices of oil, natural gas or NGL, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations and growth at current levels. To the extent that the value of the collateral pledged under either or both of our credit facilities 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 the interest rates under our credit 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. 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. The ongoing COVID-19 pandemic has reached more than 200 countries and has continued to be a rapidly evolving economic and public health situation. 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 and business and government shutdowns. 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 such reopening measures in some cases and reinstitute restrictions in others. We have taken
certain precautionary measures intended to help minimize the risk to our ability to repay or refinanceemployees, our debt. Additionally, challengesbusiness and the communities in which we operate, and we are actively assessing and planning for various operational contingencies in the economyevent one or more of our operational employees experiences any symptoms consistent with COVID-19.However, we cannot guarantee that any actions taken by us will be effective in preventing future disruptions to our business. Moreover, future operations could be negatively affected if a significant number of our employees are quarantined as a result of exposure to the virus.
In addition, actions by our customers and derivative contract counterparties in response to COVID-19 and its economic impacts may also have led and could further lead to reductions in the demand for oil and gas, or further reductions in the prices of oil and gas, or both, which could have a negativean adverse impact on our business. We continue to regularly monitor the credit worthiness of such customers and derivative contract counterparties. Although we have not received notices from our customers or counterparties regarding non-performance issues or delays resulting from the pandemic, we may have to temporarily shut down or further reduce production, which could result in significant downtime and have significant adverse consequences for our business, financial position,condition, results of operations, and cash flows.
If we are unableFurthermore, the impact of the pandemic, including a 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 generate enough cash flow from operationssignificant global economic contraction generally and in our industry in particular. While an agreement to service our indebtedness or are unablecut 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 use future borrowingsresult in a significant downturn in the oil and gas industry. Although OPEC+ agreed in April 2020 to refinance our indebtedness or fund other capital needs, we maycut oil production and has extended such production cuts through March 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 volatility of hydrocarbon commodity prices. 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, the consequences of governmental and liquidityother measures designed to mitigate the spread of the virus, the development and our abilityavailability of treatments and vaccines and the extent to repay or refinance our debt.which these treatments and vaccines may remain effective as potential 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 remain depressed 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 facilities 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 facilities could compel us to apply our available cash to repay our borrowings. If the amounts outstanding under the credit facilities 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 facilities and floating rate senior notes due 2019 bear interest at variable rates and expose us to interest rate risk. As of December 31, 2018, we had $799 million of variable rate indebtedness outstanding. If interest rates increase and we are unable to hedge our interest rate risk on acceptable terms, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same.
Restrictive covenants in certain of our debt agreements could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.
Our debt agreements impose operating and financial restrictions on us. These restrictions limit our ability and that of our restricted subsidiaries to, among other things:
incur additional indebtedness;
make investments or loans;
create liens;
consummate mergers and similar fundamental changes;
make restricted payments;
make investments in unrestricted subsidiaries;
enter into transactions with affiliates; and
use the proceeds of asset sales.
We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under certain of our debt agreements. The restrictions contained in the covenants could:
limit our ability to plan for, or react to, market conditions, to meet capital needs or otherwise to restrict our activities or business plan; and
adversely affect our ability to finance our operations, enter into acquisitions or divestitures to engage in other business activities that would be in our interest.
Also, our credit facilities require 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 facilities, 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.
The WildHorse revolving credit facility and the WildHorse Indenture constrain the ability of WildHorse and its subsidiaries to make distributions or otherwise provide funds to, or guarantee the obligations of, Chesapeake and its other subsidiaries. The provisions of the WildHorse revolving credit facility and the WildHorse Indenture require that all transactions between WildHorse and its subsidiaries, on the one hand, and Chesapeake and its other subsidiaries, on the other hand, be on an arm's-length basis.
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 facilities 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 one of the credit facilities, the affected lenders could foreclose on the collateral securing such credit facility and require repayment of all borrowings outstanding thereunder. If the amounts outstanding under the credit facilities 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 22, 2019, we have received requests and posted approximately $162 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 $355 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 facilities, 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 over the trailing 12-month period. Such write-downs couldnot recoverable. We may be material. As of December 31, 2018, the present value of estimated future net revenue of our proved reserves, discounted at an annual rate of 10%, was $9.5 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 facilities.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 20192021 capital expenditures, inclusive of Brazos Valley and capitalized interest, are $2.3$670 - $2.5 billion$740 million compared to our 20182020 capital spending level of $2.4 billion.$920 million. Management continues to review operational plans for 20192021 and beyond, which could result in changes to projected capital expenditures and projected revenues from sales of oil, natural gas and NGL. If we are unable to fund our capital expenditures as planned, we could experience a curtailment of our exploration and development activity, a loss of properties and a decline in our oil, natural gas and NGL reserves.
If we are not able to replace reserves, we may not be able to sustain production.
Our future success depends largely upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition activities, our proved reserves and production will decline over time. Thus, our future oil and natural gas reserves and production, and therefore our cash flow and income, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves.
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, 2018,2020, approximately 48%7% of our estimated proved reserves (by volume) were undeveloped. TheseAs a result of our entry into Chapter 11 bankruptcy and the limited duration of our DIP Credit Facility at December 31, 2020, these reserve estimates reflect our plans to make significantfor capital expenditures to convert our PUDs into proved developed reserves, including approximately $3.6 billion during$126 million, that can be funded within the next five years ending in 2023.maturity of our then-current financing. 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, 20182020 present value is based on a $65.56$39.57 per bbl of oil price and a $3.10$1.98 per mcf of natural gas price, before considering basis differential adjustments. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of an estimate.
The timing of both the production and the expenses from the development and production of oil and natural gas properties will affect both the timing of future net cash flows from our proved reserves and their present value. Any changes in demand for oil and natural gas, governmental regulations or taxation will also affect the future net cash flows from our production. In addition, the 10% discount factor that is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes is not necessarily the most appropriate discount factor. Interest rates in effect from time to time and the risks associated with our business or the oil and gas industry in general will affect the appropriateness of the 10% discount factor.
Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.
We have a substantial inventory of undeveloped properties. Development and exploratory drilling and production activities are subject to many risks, including the risk that commercially productive reservoirs will not be discovered. We have acquired undeveloped properties that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our initial investments. Additionally, there can be no assurance that undeveloped properties acquired by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive, or that we will recover all or any portion of our investment in such undeveloped properties or wells.
Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient commercial quantities to cover the drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling and completion operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, title problems, equipment failures or accidents, shortages of midstream transportation, equipment or personnel, environmental issues, state or local bans or moratoriums on hydraulic fracturing and produced water disposal, federal restrictions on oil and gas leasing and permitting, and a decline in commodity prices, among others. The profitability of wells, particularly in certain of the areas in which we operate, will be reduced or eliminated if commodity prices decline. In addition, wells that are profitable may not meet our internal return targets, which are dependent upon the current and future market prices for oil, natural gas and NGL, costs associated with producing oil, natural gas and NGL and our ability to add reserves at an acceptable cost. 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 technologies in evaluating undeveloped properties and in conducting our exploration activities. The seismic data and other technologies we use do not allow us to know conclusively, prior to acquisition of undeveloped properties, or drilling a well, whether oil or natural gas is present or may be produced economically. If we incur significant expense in acquiring or developing properties that do not produce as expected or at profitable levels, it could have a material adverse effect on our results of operations and financial condition.
Certain of our undeveloped properties are subject to leases that will expire over the next several years unless production is established on units containing the acreage or the leases are renewed.
Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established. If our leases on our undeveloped properties expire and we are unable to renew the leases, we will lose our right to develop the related properties. Although we seek to actively manage our undeveloped properties, our drilling plans for these areas are subject to change based upon various factors, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. Low commodity prices may cause us to delay our drilling plans and, as a result, lose our right to develop the related properties.
Our commodity price risk management activities may limit the benefit we would receive from increases in commodity prices, may require us to provide collateral for derivative liabilities and involve risk that our counterparties may be unable to satisfy their obligations to us.
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 the Chesapeakeour senior secured revolving credit facility or the WildHorse revolving credit facility, as the case may be. 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.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 its 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 various matters such as our royalty practices. 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 2019 and in future years. If incurred, these charges could materially adversely impact our future results of operations and liquidity.
Oil and natural gas operations are uncertain and involve substantial costs and risks.
Our oil and natural gas operating activities are subject to numerous costs and risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. Drilling for oil, natural gas and NGLs can be unprofitable, not only from dry holes, but from productive wells that do not return a profit because of insufficient revenue from production or high costs. Substantial costs are required to locate, acquire and develop oil and gas properties, and we are often uncertain as to the amount and timing of those costs. Our cost of drilling, completing, equipping and operating wells is often uncertain before drilling commences. Declines in commodity prices and overruns in budgeted expenditures are common risks that can make a particular project uneconomic or less economic than forecasted. While both exploratory and developmental drilling activities involve these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. For the 3% of our daily production volumes from properties which we did not serve as operator as of December 31, 2018, we are dependent on the operator for operational and regulatory compliance. In addition, our oil and gas properties can become damaged, our operations may be curtailed, delayed or canceled and the costs of such operations may increase as a result of a variety of factors, including, but not limited to:
•unexpected drilling conditions, pressure conditions or irregularities in reservoir formations;
•equipment failures or accidents;
•fires, explosions, blowouts, cratering or loss of well control, as well as control;
•the mishandling or underground migration of fluids and chemicals;
•adverse weather conditions and natural disasters, such as tornadoes, earthquakes, hurricanes and extreme temperatures;
•issues with title or in receiving governmental permits or approvals;
•restricted takeaway capacity for our production, including due to inadequate midstream infrastructure or constrained downstream markets;
•environmental hazards or liabilities;
•restrictions in access to, or disposal of, water used or produced in drilling and completion operations;
•shortages or delays in the availability of services or delivery of equipment; and
•unexpected or unforeseen changes in regulatory policy, and political or public opinions.opinion.
The occurrence of one or more of these factors could result in a partial or total loss of our investment in a particular property, as well as significant liabilities. While 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 subjectMoreover, certain of these events could result in environmental pollution and impact to extensive governmental regulationthird parties, including persons living in proximity to our operations, our employees and ongoing regulatory changes, whichemployees of our contractors, leading to possible injuries, death or significant damage to property and natural resources.
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 business.
Our operations are subject to extensive federal, state, tribal, 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 NGLs, conservation policies, reporting obligations, royalty payments, unclaimed property and the imposition of taxes. 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. 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 changes could, among other things, restrict production levels, impose price controls, alter environmental protection requirements 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 or 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, sizeearnings, cash flows 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. As is discussed below this is particularly true of changes related to pipeline safety, seismic activity, hydraulic fracturing, climate change and endangered species designations.
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 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.” Additional action by PHMSA with respect to pipeline integrity management requirements may occur in the future. For example, in 2016 PHMSA proposed new rules for gas pipelines that extend pipeline safety programs beyond high consequence areas to newly proposed “moderate consequence areas or rural areas” and would also impose more rigorous testing and reporting requirements on such pipelines. Elements of a final rulemaking, commonly referred to as the “Gas Mega Rule,” continues to be deliberated by PHMSA’s Gas Pipeline Advisory Committee (GPAC). To date, no final regulatory action has been taken. More recently, in January 2017, PHMSA finalized regulations for hazardous liquid pipelines that significantly extend and expand the reach of certain PHMSA integrity management requirements (i.e., periodic assessments, leak detection and repairs), regardless of the pipeline’s proximity to a high consequence area. The final rule also imposes new reporting requirements for certain unregulated pipelines, including all hazardous liquid gathering lines. Per direction provided via a “Regulatory Freeze” Memo published on January 20, 2017 by the Trump Administration, this final regulatory action was withdrawn and continues to be evaluated by executive leadership. In July 2018, PHMSA issued an advance notice of proposed rulemaking seeking comment on the class location requirements for natural gas transmission pipelines, and particularly the actions operators must take when class locations change due to population growth or building construction near the pipeline. 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.
Seismic Activity. Earthquakes in some of our operating areas and elsewhere have prompted concerns about seismic activity and possible relationships with the energy industry. For example, the Oklahoma Corporation Commission (OCC) issued guidance to operators in the SCOOP and STACK areas for management of certain seismic activity that may be related to hydraulic fracturing activities. Legislative and regulatory initiatives intended to address these concerns may result in additional levels of regulation or other requirements that could lead to operational delays, increase our operating and compliance costs or otherwise adversely affect our operations. In addition, we are currently defending against certain third- party lawsuits and could be subject to additional claims, seeking damages or other remedies as a result of alleged induced seismic activity in our areas of operation.
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. Three states (New York, Maryland and Vermont) have banned the use of high-volume hydraulic fracturing. In addition 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 drilling in general and/or hydraulic fracturing in particular. There have also been certain governmental reviews that focus on deep shale and other formation completion and production practices, including hydraulic fracturing. Governments may continue to study hydraulic fracturing. We cannot predict the outcome of future studies, but based on the results of these studies to date, federal and state legislatures and agencies may seek to further regulate or even ban hydraulic fracturing activities. In addition, if existing laws and regulations with regard to hydraulic fracturing are revised or reinterpreted or if new laws and regulations become applicable to our operations through judicial or administrative actions, our business, financial condition, results of operations and cash flows could be adversely affected. For example, a decision by a Pennsylvania state court in 2018, if upheld, could change the established common law rule of capture and apply liability to oil and gas companies for trespass when hydraulic fracturing results in the production of oil and gas from adjoining property, which may impose burdens on hydraulic fracturing in Pennsylvania that may be material.
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. EPA and BLM have issued regulations for the control of methane emissions, which also include leak detection and repair requirements, for the oil and gas industry; however, following the change in presidential administrations, both agencies took actions to rescind or revise the rules. In September 2018, BLM issued a final rule that rescinded certain requirements of its venting and flaring rule. Similarly, in October 2018, EPA published a proposed rule that amends certain requirements of its methane rule. The EPA rule remains in effect. Nevertheless, several states where we operate have imposed venting and flaring 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 cap and trade and/or carbon tax programs. Cap and trade programs offer greenhouse gas emission allowances that are gradually reduced over time. A cap and trade program 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. A carbon tax 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 certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities.
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. Furthermore, increasing attention to climate change risks has resulted in increased likelihood of governmental investigations and private litigation, which could increase our costs or otherwise adversely affect our business.
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.position.
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.
For water sourcing, Chesapeake first seeks to
Development activities, particularly hydraulic fracturing, require the use non-potable water supplies for our operational needs.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 then be obtained from other sources and transported to the drilling site. AnOur 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 could further restrict our ability to conduct certain operations such as hydraulic fracturing by restricting theor disposal of things such aswaste, including, but not limited to, produced water, and drilling fluids
Environmental matters and related costs can be significant.
As an owner, lesseeother materials associated with the exploration, development or operatorproduction 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 the failure to comply with environmental laws and regulations can result in the imposition of administrative, civil and/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.
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, 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.gas.
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.do. 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 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.
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 would be successfully integrated into our operations and internal controls;
•the due diligence conducted prior to an acquisition would uncover situations that could result in financial or legal exposure, such as title defects and potential environmental and other liabilities;
•post-closing purchase price adjustments will be realized in our favor;
•our assumptions about, among other things, reserves, estimated production, revenues, capital expenditures, operating, operating expenses and costs would be accurate;
•any investment, acquisition, disposition or integration would not divert management resources from the operation of our business; and
•any investment, acquisition, or disposition or integration would 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, seismic activity, climate change, explosions of natural gas transmission lines and the development and operation of pipelines and other midstream facilities 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. 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, intervene in regulatory or administrative proceedings involving our assets or those of our midstream transportation providers, or file lawsuits or other actions 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. The change in presidential administrations and change in control of Congress may also result in 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 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 not economically viable in order to improve our sustainability performance and to meet the specific requirements to perform services for certain customers.
Our operations may be adversely affected by pipeline, trucking and gathering system capacity constraints and may be subject to interruptions that could adversely affect our cash flow.
In certain resource plays, the capacity of gathering and transportation systems is insufficient to accommodate potential production from existing and new wells. We rely heavily on third parties to meet our oil, natural gas and NGL gathering needs. Capital constraints could limit the construction of new pipelines and gathering systems and the providing 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 awaiting a pipeline connection or 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.
Cyber-attacks targeting systems and infrastructure used by the oil and gas industry and related regulations may adversely impact our operations and, if we 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. We have been the subject of cyber-attacks on
our internal systems and through those of third parties but these incidents did not have a material adverse impact on our results of operations. Nevertheless, unauthorizedin the past. 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 our information technology systems cease to function properly or our cybersecurity is breached, we could suffer disruptions to our normal operations, which may include drilling, completion, production and corporate functions. A cyber-attack involving our information systems and related infrastructure, or that of our business associates, 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.
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 expend 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 anystore personal data related to royalty owners. 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 for data security breaches or other CCPA violations. Meanwhile, over fifteen other states have considered privacy laws like the CCPA.
An interruption in operations at our headquarters could adversely affect our business.
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. Low commodity prices have caused and may continue to cause lenders to increase the interest rates under upstream operators’ credit 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. For example, on December 1, 2020, the Bank of Montreal announced its intention to wind down its investments in non-Canadian energy businesses and to cease all investment banking and corporate lending in the sector. 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. We do not intend to resume payingfinancial 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, our Board of Directors may determine to suspend dividend payments on our preferred stockThe restrictions contained in the future. If we failcovenants could:
•limit our ability to pay dividends onplan for, or react to, market conditions, to meet capital needs or otherwise to restrict our preferred stock with respectactivities or business plan; and
•adversely affect our ability to sixfinance our operations, enter into acquisitions or more quarterly periods (whether or not consecutive), the holders of our preferred stock, voting as a single class, will be entitled at the next regular or special meeting of shareholdersdivestitures to elect two additional directors of the Company. We had previously failed to pay dividends on our outstanding preferred stock with respect to four quarterly periods during the fiscal year ended December 31, 2016, before resuming payment,engage in arrears, in the first quarter of 2017.
Certain anti-takeover and other provisions may affect your rights as a shareholder.
Our certificate of incorporation authorizes our Board of Directors to set the terms of and issue preferred stock without shareholder approval. Our Board of Directors could use the preferred stock as a means to delay, defer or prevent a takeover attemptbusiness activities that a shareholder might consider towould be in our best interest. In addition, our revolving credit facilities, preferred stock and
Changes in the method of determining the London Interbank Offered Rate (LIBOR), or the replacement of LIBOR with an alternative reference rate, may adversely affect interest expense related to outstanding debt.
Amounts drawn under certain of our notes contain termsdebt instruments may bear interest at rates based on LIBOR. On July 27, 2017, the Financial Conduct Authority in the United Kingdom announced that may restrict our abilityit would phase out LIBOR as a benchmark by the end of 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to enter into changeexist after 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 control transactions, including requirementsLIBOR cessation or upon an election to repay borrowings under our revolving credit facilitiesearly opt-in, if SOFR becomes available. As SOFR is not currently available, the Credit Agreement also provides that in the event that SOFR is not available at the time of LIBOR cessation, the borrower and to offer to repurchase such notesagent must agree on a change in control. These provisions, along with specified provisionssuccessor rate subject to negative consent rights of the Oklahoma General Corporation Actlenders. While the Credit Agreement provides a framework for a transition to an alternative rate, some uncertainty remains due to the current unavailability of SOFR and our certificatethe inherent open-endedness of incorporation and bylaws, may discourage or impede transactions involving actual orthe amendment mechanism in the absence of SOFR. We are currently evaluating the impact of the potential changes in our control, including transactions that otherwise could involve paymentreplacement of a premium over prevailing market prices to holders of our common stock.
Risks Associated with Acquisition of WildHorse
The WildHorse Merger may not be accretive, andthe LIBOR interest rate. In addition, the overall financial markets may be dilutive, to our earnings per share, which may negatively affect the market price of shares on our common stock.
In connection with the completion of the WildHorse Merger, we issued approximately 717.3 million shares of our common stock. The issuance of these new shares of our common stock could have the effect of depressing the market
price of shares of our common stock, through dilution of earnings per share or otherwise. Any dilution of, or delay of any accretion to, our earnings per share could cause the price of shares of our common stock to decline or increase at a reduced rate.
The market price of shares of our common stock may decline in the futuredisrupted as a result of the salephase-out or replacement of sharesLIBOR. Uncertainty as to the nature of such potential phase-out and alternative reference rates or disruption in the financial market could have a material adverse effect on our financial condition, results of operations and cash flows.
Legal and Regulatory Risks
We are subject to extensive governmental regulation, which can change and could adversely impact our business.
Our operations are subject to extensive federal, state, local and other laws, rules and regulations, including with respect to environmental matters, worker health and safety, wildlife conservation, the gathering and transportation of oil, gas and NGLs, conservation policies, reporting obligations, royalty payments, unclaimed
property and the imposition of taxes, and tribal laws for a minor portion of our common stock held by former WildHorse stockholdersacreage. 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 current stockholders.
Former WildHorse stockholdersif unfavorable restrictions or conditions are imposed on our drilling or completion activities, we may following 60- and 180-day lock-up periodsnot be able to conduct our operations as planned. For example, on January 20, 2021, the Acting Secretary for certain primary former WildHorse stockholders following the closing dateDepartment of the WildHorse Merger, seek to sell the shares of our common stock delivered to them following the consummation of the WildHorse Merger. Other shareholders may also seek to sell shares of our common stock held by them following,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 anticipation of,offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. To the WildHorse Merger.extent that the review results in the development of additional restrictions on drilling, limitations on the availability of leases, or restrictions on the ability to obtain required permits, it 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 granted certain stockholders of WildHorse registration rights with respectaffected, 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 and increase taxes, royalties and other amounts payable to the sharesgovernment. 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 common stockoperations materially differently than they receivewould 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 WildHorse Merger. These sales (orevent 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. Further, legislation funding PHMSA through 2023 requires the perception thatagency 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 sales may occur), coupled with the increase in the outstanding numberrequirements or other potential new or amended regulations, but they could be significant. Moreover, violations of shares of our common stock, may affect the market for, and the market price of, our common stock in an adverse manner.
We may fail to realize all of the anticipated benefits of the WildHorse Merger.
The success of the WildHorse Merger will depend, in part, on our ability to realize the anticipated benefits and cost savings from combining our and WildHorse’s businesses, including operational and other synergies that we believe the combined company will achieve. We expect that the WildHorse Merger will provide substantial cost savings with $200 million to $280 million in projected average annual savings, totaling $1 billion to $1.5 billion by 2023, due to operational and capital efficiencies as a result of Chesapeake’s significant expertise with unconventional assets and technical and operational excellence. The anticipated benefits and cost savings of the WildHorse Merger 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 operational cost savings, may not be realized. The integration process may, for us and WildHorse,pipeline safety regulations can result in the lossimposition of key employees,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 disruptionfuture and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of ongoing businessesregulation or inconsistencies in standards, controls, procedurespermitting requirements were imposed on hydraulic fracturing operations, our business and policies. Thereoperations could be subject to delays, increased operating and compliance costs and potential unknown liabilitiesbans. Additional regulation could also lead to greater opposition to hydraulic fracturing, including litigation.
Climate Change. Continuing political and unforeseen expensessocial 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. 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; however, inSeptember 2018, BLM published a final rule to repeal certain requirements of these regulations. Similarly, in September 2019, EPA published a rule proposing to reconsider certain aspects of its regulations for the control of methane emissions. Nevertheless, 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 WildHorse Mergervalue 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 were not discoveredresults 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 courseimposition of performing due diligence. The integration will require significant timeadministrative, civil or criminal fines and focus from management following the acquisition.
We will incur substantial transaction fees and costspenalties, as well as injunctions limiting operations in connection with the WildHorse Merger.
We expect to incur a number of non-recurring transaction-relatedaffected areas. Any future costs associated with completingthese 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 WildHorse Merger.protection of the environment could have a significant impact on our operations and profitability.
Increasing attention to environmental, social and governance matters 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, universities and other members of the investing community. These feesactivities include increasing attention and demands for action related to climate change and promoting the use of energy saving building materials. 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, regardless of whether there is a legal requirement to do so, could also cause reputational harm to our business and could have a material adverse effect on us.
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 mayof 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 substantial. Non-recurring transactionenacted by any of these governmental authorities making it more costly for us to produce oil and natural gas by increasing our tax burden. The new presidential administration has called for changes to fiscal and tax policies which could lead to comprehensive tax reform. New federal legislation could be proposed that, if enacted, would impact federal income tax law applicable to the deduction of intangible drilling and development costs, percentage depletion and bonus depreciation. Other proposals changing federal income tax law could include but are not limiteda new corporate minimum tax based on book income, an increase to fees paid to legal, financialthe corporate tax rate and accounting advisors, filing feesthe elimination of certain tax credits. If enacted, certain of these proposals could have a correlative impact on state income taxes. In addition, state and printing costs.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.
The issuance ofTrading in our new common stock, to shareholdersadditional issuances of WildHorse as well asnew common stock and certain other stock transactions could lead to a second, potentially more restrictive annual limitation on the utilization of our loss carryforwards to reduce future taxable income.
Our ability to utilize U.S.tax attributes such as net operating loss carryforwards, (NOL)disallowed business interest carryforwards, tax credits and possibly other tax basis items. Increased restriction of these items reduces their ability to reduceoffset future taxable income, and federalwhich may result in an increase to income tax is subject to various limitationsliabilities.
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”). The utilization of such carryforwards may be limited under Section 382, as all of the Code uponcommon stock and preferred stock of the occurrence of ownership changes resulting from issuances of our stockPredecessor, or the sale or exchange of ourold loss corporation, was canceled and replaced with new common stock by certain shareholders if, as a result, there is a cumulative change of more than 50% in the beneficial ownership of our stock during any three-year period. For this purpose, “stock” includes certain preferred stock. In the event of such an ownership change, Section 382 of the Code imposesSuccessor, or the new loss corporation (the “First Ownership Change”).As such, an annual limitation on the amount of our loss carryforwards that canwill be used to offset taxable income. The limitation is generally equal to the product of (a)computed based on the fair market value of ourthe new equity immediately after emergence multiplied by (b) the long-term tax-exempt rate in effect for the month in which an ownership change occurs. Ifof 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.
Based on current estimates, we arebelieve the Company was in a net unrealized built-in gain position at the time of an ownership change, then the First Ownership Change. This is due in large part to currently existing rules allowing a taxpayer to compare its tax basis to the face value of pre-emergence debt.Should the Company’s final calculations confirm that it was, in fact, in a net unrealized built-in gain position at such time, the annual limitation iswill be increased if there areby each year’s recognized built-in gains, duringif any, post-change year,occurring within a five-year period following the First Ownership Change, but only to the extent of anythe net unrealized built-in gains inherent ingain which existed at the assets sold. If we aretime of the First Ownership Change.
In the event a second ownership change occurs and the Company is in a net unrealized built-in loss position at the time of anthe second ownership change, then a new and potentially more restrictive annual limitation would apply. Upon a second ownership change, the Company would likely have significantly less debt and as such a determination of its net unrealized built-in gain or loss position will likely not utilize its debt level and will be based solely upon the comparison of its tax basis to the fair market value of its assets. 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 may applyin such a case would also be applied to certain of the Company’s tax attributes 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 carryforwards, such as depreciable basisexisting at the time of tangible equipment. 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.
Some states impose similar limitations on tax attribute utilization upon experiencing an ownership change. We do not believe we
General Risk Factors
A deterioration in general economic, business or industry conditions would have a limitationmaterial 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 utilizecontinue operations and materially adversely impact our U.S. loss carryforwardsresults 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 tax attributes under Section 382actions 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 Code asUnited States or other countries could adversely affect the global economy in unpredictable ways, including the disruption of December 31, 2018. We further believeenergy supplies and markets, increased volatility in commodity prices, or the possibility that the WildHorse Merger did not resultinfrastructure on which we rely could be a direct target or an indirect casualty of an act of terrorism, and, in an ownership change based on information currently available. However, issuances, sales and/or exchangesturn, could materially and adversely affect our business and results of our stock (including, potentially, relatively small transactions and transactions beyond our control) occurring after December 31, 2018, taken together with prior transactions with respect to our stock and the WildHorse Merger, could trigger an ownership changeoperations.
ITEM 1B.Unresolved Staff Comments
under Section 382 of the Code and therefore a limitation on our ability to utilize our U.S. loss carryforwards and other tax attributes. Any such limitation could cause some loss carryforwards to expire before we would be able to utilize them to reduce taxable income in future periods, possibly resulting in a substantial income tax expense or write down of our tax assets or both.
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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.
ITEM 3. Legal Proceedings
Litigation and RegulatoryChapter 11 Proceedings
WeCommencement of the Chapter 11 Cases automatically stayed the proceedings and actions against us that are involveddescribed 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 IIthis 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 6 of the notes to our consolidated financial statements included in Item 8 of this report for information regarding our estimation and provision for potential losses related to litigation and regulatory proceedings. Business Operations. We are involved in various lawsuits and disputes incidental to our business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions. The majority of these prepetition legal proceedings, including the matters below, have been settled during the Chapter 11 Cases or will be resolved in connection with the claims reconciliation process before the Bankruptcy Court. Any allowed claim related to such prepetition litigation will be treated in accordance with the Plan.
Regarding royalty claims, we
We and other natural gas producers have been named in various lawsuits alleging royalty underpayments.underpayment of royalties and other shares of the proceeds of production. 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 underpayment of royaltiesamounts owed 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. PlaintiffsRoyalty 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 of the legal effect of lease provisions governing royalty calculations. We have resolved a number of these claims through negotiated settlements of past and future royalty obligations and have prevailed in various other lawsuits. We are currently defending numerous lawsuits seeking damages with respect to underpayment of royalties or other shares of the proceeds of production in multiple states where we have operated, including the matters set forththose 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 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 ourthe 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 and August 9, 2018, we reached tentative settlements to resolve substantially all Pennsylvania civil royalty cases for a total at that time of approximately $35$36 million. Subsequent to our Bankruptcy Filing the parties reopened settlement discussions.
We also previously disclosed defending lawsuits alleging various violationsbelieve losses are reasonably possible in certain 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. On April 12, 2018, we reached a tentative settlement to resolve substantially all Oklahoma civil class action antitrustpending royalty cases for which we have not accrued a loss contingency, but we are currently unable to estimate an insignificant amount. The final fairness hearing is set for April 25, 2019.
On July 28, 2017, OOGC America LLC (OOGC) filed a demand for arbitration withamount or range of loss or the American Arbitration Association against Chesapeake Exploration, L.L.C.,impact the actions could have on our wholly owned subsidiary,future results of operations or cash flows. Uncertainties in connection with OOGC’s purchasepending royalty cases generally include the complex nature of certain oilthe claims and gas leasesdefenses, the potential size of the class in class actions, the scope and other assets pursuant to a Purchasetypes of the properties and Sale Agreement entered into on October 10, 2010. In connection withagreements involved, and the sale, we also entered into a Development Agreement with OOGC, dated November 15, 2010 (the “Development Agreement”), which governs each of our rights and obligations with respect to the sale, including the transportation and marketing of oil and gas. OOGC’s breach of contract, breach of agency and fiduciary duties and other claims generally alleged, among other things, that we subjected OOGC to excessive rates for gathering and other services provided for under the Development Agreement and interfered with OOGC’s right to audit the documents that supported those rates. On November 13, 2018, a unanimous panel denied every claim asserted by OOGC other than OOGC being entitled to a declaration clarifying its audit rights.applicable production years.
On July 24, 2018, Healthcare of Ontario Pension Plan (HOOPP) filed a demand for arbitration with the American Arbitration Association regarding HOOPP’s purchase of our interest in Chaparral Energy, Inc. stock for $215 million on January 5, 2014. HOOPP claims that we engaged in material misrepresentations and fraud, and that we violated the Exchange Act and Oklahoma Uniform Securities Act. HOOPP seeks either rescission or $215 million in monetary damages, and in either case, interest, attorney’s fees, disgorgement and punitive damages. We intend to vigorously defend these claims.
On January 29, 2020, a well control incident occurred at one of our wellsites in Burleson County, Texas, causing the deaths of three of our contractors’ employees and injuring a fourth. In February 2019, a putative class action lawsuitconnection with this incident, eleven lawsuits have been brought against us and our contractors alleging negligence, gross negligence, and breach of contract, and seeking wrongful death damages, survival statute damages, exemplary damages, and interest. Ten of the suits have been filed in the District Court of Dallas County, Texas. A joint motion to consolidate filed by all the parties in nine of the ten Dallas County lawsuits is currently pending before the Texas was filed against FTS International, Inc. (“FTSI”), certain investment banks, FTSI’s directors including certain ofMultidistrict Litigation Panel. The
eleventh suit is pending in Burleson County, Texas. The proceedings are in their early stages and are all stayed due to the pending bankruptcy. Our general and excess liability insurance policies provide coverage for third party bodily injury and wrongful death claims, and the contracts between us and our officers and certain shareholders of FTSI including us. The lawsuit alleges various violations of Sections 11 (withcontractors with respect to certain of our officers in their capacities as directors of FTSI) and 15 (with respect to such officers and us)the well contain customary cross-indemnification provisions.
Environmental Contingencies
The nature of the Securities Actoil 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 1933an 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 connection with public disclosure made duringan acquisition or agree to assume liability for the initial public offering of FTSI. The suit seeks damages in excess of $1,000,000 and attorneys’ fees and other expenses. We intend to vigorously defend these claims.
Environmental Proceedings
Our subsidiary Chesapeake Appalachia, LLC (CALLC) is engaged in discussions with the EPA, the U.S. Army Corps of Engineers and the Pennsylvania Department of Environmental Protection (PADEP) regarding potential violationsremediation of the permitting requirements of the federal Clean Water Act (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.
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 received another Finding of Violation from EPA on December 20, 2018 alleging violations of the CAA and violations of the Ohio State Implementation Plan at a number of our Ohio facilities. We have begun discussions with EPA aimed at resolving the allegations. Resolution of this matter may result in monetary sanctions of more than $100,000.property.
We are named as a defendant in numerous lawsuits in Oklahoma alleging that we and other companies have engaged in activities that have caused earthquakes. These lawsuits seek 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 seek the reimbursement of insurance premiums and the award of punitive damages, attorneys’ fees, costs, expenses and interest. We are vigorously defending these claims. Any allowed claim related to such prepetition litigation will be treated in accordance with the Plan.
We are in discussions with the Pennsylvania Department of Environmental Protection (PADEP) regarding gas migration in the vicinity of certain of our wells in Wyoming 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, resolution of the matter may result in monetary sanctions of more than $300,000. | |
ITEM 4. | Mine Safety Disclosures |
Not applicable.Other Matters
Based on management’s current assessment, we are of the opinion that no pending or threatened lawsuit or dispute relating to our business operations is likely to have a material adverse effect on our future consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.
ITEM 4. Mine Safety Disclosures
The information concerning mine safety violations and other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17CFR 229.104) is included in Exhibit 95.1 to this Form 10-K.
PART II
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ITEM 5.ITEM 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Common Stock
Our common stock tradeswas previously listed on the New York Stock Exchange (the “NYSE”) under the symbol "CHK".
Shareholders
“CHK.” As a result of February 12, 2019, there were approximately 2,000 holdersour failure to satisfy the continued listing requirements of record ofthe NYSE, on June 29, 2020, our common stock ceased to trade on the NYSE. Since June 30, 2020, our common stock has been quoted on the OTC Pink Marketplace maintained by the OTC Markets Group, Inc. under the symbol “CHKAQ.” On July 20, 2020, the NYSE filed a Form 25 with the SEC to delist our common stock, senior notes and approximately 307,000 beneficial owners.cumulative convertible preferred stock from the NYSE. The delisting was effective 10 days after the Form 25 was filed and our common stock, senior notes and cumulative convertible preferred stock were deregistered under Section 12(b) of the Exchange Act on October 18, 2020. Our common stock was canceled on February 9, 2021 as a result of our Chapter 11 proceedings.
On February 9, 2021, subsequent to our emergence from Bankruptcy, there were 97,906,968 outstanding shares of common stock of the Successor listed on the Nasdaq Stock Market LLC under the symbol CHK. In addition, on February 9, 2021, we had 11,111,111 Class A Warrants, 12,345,679 Class B Warrants and 9,768,527 Class C Warrants outstanding that are exercisable for one share of common stock per warrant at the initial exercise prices of $27.63, $32.13 and $36.18 per share, respectively. The warrants are immediately exercisable and will expire on February 9, 2026.
Dividends
We ceased paying dividends on our common stock in the 2015 third quarter and do not intend to resume paying cash dividends on our common stock in the foreseeable future. Our revolving credit facility and the certificates of designation for our preferred stock contain restrictions on our ability to declare and pay cash dividends on our common or preferred stock if an event of default has occurred. The certificates of designation for our preferred stock prohibit payment of cash dividends on our common stock unless we have declared and paid (or set apart for payment) full accumulated dividends on the preferred stock. After suspending the payment of dividends on our outstanding convertible preferred stock during fiscal year 2016, we reinstated the payment of dividends on each series of our outstanding convertible preferred stock beginning with the dividends payable in the 2017 first quarter and paid all dividends in arrears.2015.
Unregistered Sales of Equity Securities and Use of Proceeds
The following table presents information aboutThere were no repurchases or unregistered sales of our common stock during the quarter ended December 31, 2018:2020.
Shareholders
As of February 25, 2021, there were approximately 122 holders of record of our common stock.
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| | | | | | | | | | | | | | |
| Period | | Total Number of Shares Purchased(a) | | Average Price Paid Per
Share(a) | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | | Maximum Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs(b) |
| | | | | | | | | ($ in millions) |
| October 1, 2018 through October 31, 2018 | | 10,989 |
| | $ | 4.60 |
| | — |
| | $ | 1,000 |
|
| November 1, 2018 through November 30, 2018 | | — |
| | $ | — |
| | — |
| | $ | 1,000 |
|
| December 1, 2018 through December 31, 2018 | | — |
| | $ | — |
| | — |
| | $ | 1,000 |
|
| Total | | 10,989 |
| | $ | — |
| | — |
| | |
| |
(a) | Includes shares of common stock purchased on behalf of our deferred compensation plan. |
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(b) | In December 2014, our Board of Directors authorized the repurchase of up to $1 billion of our common stock from time to time. The repurchase program does not have an expiration date. As of December 31, 2018, there have been no repurchases under the program. |
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ITEM 6.
| Selected Financial Data |
ITEM 6. Selected Financial Data
The following table sets forth selected consolidated financial data of Chesapeake as of and for the years ended December 31, 2020, 2019, 2018, 2017 2016, 2015 and 2014. The data are derived from our audited consolidated financial statements.2016. The table below should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations and our consolidated financial statements, including the notes thereto, appearing in Items 7 and 8, respectively, of this report.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | | 2020 | | 2019 | | 2018 | | 2017 | | 2016 |
| | | ($ in millions, except per share data) |
| STATEMENT OF OPERATIONS DATA: | | | | | | | | | | |
| Total revenues | | $ | 5,296 | | | $ | 8,595 | | | $ | 10,030 | | | $ | 10,039 | | | $ | 8,705 | |
Net income (loss) available to common stockholders(a) | | $ | (9,756) | | | $ | (416) | | | $ | 133 | | | $ | (631) | | | $ | (4,018) | |
| | | | | | | | | | |
EARNINGS (LOSS) PER COMMON SHARE:(b) | | | | | | | | | | |
| Basic | | $ | (998.26) | | | $ | (49.97) | | | $ | 29.26 | | | $ | (139.32) | | | $ | (1,051.83) | |
| Diluted | | $ | (998.26) | | | $ | (49.97) | | | $ | 29.26 | | | $ | (139.32) | | | $ | (1,051.83) | |
| | | | | | | | | | |
| CASH DIVIDEND DECLARED PER COMMON SHARE | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | |
| BALANCE SHEET DATA (AT END OF PERIOD): | | | | | | | | | | |
| Total assets | | $ | 6,584 | | | $ | 16,193 | | | $ | 12,735 | | | $ | 14,925 | | | $ | 17,048 | |
| Long-term debt, net of current maturities | | $ | — | | | $ | 9,073 | | | $ | 7,341 | | | $ | 9,921 | | | $ | 9,938 | |
| Total equity (deficit) | | $ | (5,341) | | | $ | 4,401 | | | $ | 2,133 | | | $ | 1,943 | | | $ | 2,565 | |
(a) Includes $8.535 billion, $11 million, $131 million, $814 million and $563 million of impairments of oil and gas properties and other fixed assets for the years ended December 31, 2020, 2019, 2018, 2017 and 2016, respectively.
(b) Amounts have been retroactively adjusted to reflect a 1-for-200 (1:200) reverse stock split effective April 14, 2020. See Note 11 of the notes to our consolidated financial statements included in Item 8 of this report for additional information. |
| | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
| | | ($ in millions, except per share data) |
| STATEMENT OF OPERATIONS DATA: | | | | | | | | | | |
| Total revenues | | $ | 10,231 |
| | $ | 9,496 |
| | $ | 7,872 |
| | $ | 12,764 |
| | $ | 23,125 |
|
Net income (loss) available to common stockholders(a) | | $ | 775 |
| | $ | 813 |
| | $ | (4,915 | ) | | $ | (14,738 | ) | | $ | 1,273 |
|
| | | | | | | | | | | |
| EARNINGS (LOSS) PER COMMON SHARE: | | | | | | | | | | |
| Basic | | $ | 0.85 |
| | $ | 0.90 |
| | $ | (6.43 | ) | | $ | (22.26 | ) | | $ | 1.93 |
|
| Diluted | | $ | 0.85 |
| | $ | 0.90 |
| | $ | (6.43 | ) | | $ | (22.26 | ) | | $ | 1.87 |
|
| | | | | | | | | | | |
| CASH DIVIDEND DECLARED PER COMMON SHARE | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 0.0875 |
| | $ | 0.35 |
|
| | | | | | | | | | | |
| BALANCE SHEET DATA (AT END OF PERIOD): | | | | | | | | | | |
| Total assets | | $ | 10,947 |
| | $ | 12,425 |
| | $ | 13,028 |
| | $ | 17,314 |
| | $ | 40,655 |
|
| Long-term debt, net of current maturities | | $ | 7,341 |
| | $ | 9,921 |
| | $ | 9,938 |
| | $ | 10,311 |
| | $ | 11,058 |
|
| Total equity (deficit) | | $ | 467 |
| | $ | (372 | ) | | $ | (1,203 | ) | | $ | 2,397 |
| | $ | 18,205 |
|
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(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 2018, 2017 and 2014, 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 |
ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations Overview
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 this report.
The transformationIntroduction
We are an independent exploration and production company engaged in the acquisition, exploration and development of Chesapeake over the past five years has been significantproperties to produce oil, natural gas and our progress acceleratedNGLs from underground reservoirs. We own a large and geographically diverse portfolio of onshore U.S. unconventional natural gas and liquids assets, including interests in 2018 and early 2019. We believe our recent accomplishments and achievements have made our company stronger. Highlights include the following:
acquired WildHorse, anapproximately 7,400 oil and natural gas company with operationswells. Our natural gas resource plays are the Marcellus Shale in the northern Appalachian Basin in Pennsylvania and the Haynesville/Bossier Shales in northwestern Louisiana. Our liquids-rich resource plays are the Eagle Ford Shale in South Texas and Austin Chalk formationsthe stacked pay in southeast Texas,the Powder River Basin in Wyoming.
Recent Developments
Voluntary Reorganization Under Chapter 11
On June 28, 2020, the Debtors filed voluntary petitions for approximately 717.3 millionrelief under 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 (DRJ). Subsidiaries with noncontrolling interests, consolidated variable interest entities and certain de minimis subsidiaries (collectively, the “Non-Filing Entities”) were not part of the Chapter 11 Cases. The Debtors and the Non-Filing Entities continued to operate in the ordinary course of business during the Chapter 11 Cases.
During the Chapter 11 Cases, the Debtors operated as debtors-in-possession in accordance with the applicable provisions of the Bankruptcy Code. The Bankruptcy Court granted first day motions filed by us that were designed primarily to mitigate the impact of the Chapter 11 Cases on our operations, customers and employees. As a result, we were able to conduct normal business activities and pay all associated obligations for the period following the Bankruptcy filing and were authorized to pay owner royalties, employee wages and benefits, and certain vendors and suppliers in the ordinary course for goods and services provided. During the pendency of the Chapter 11 Cases, all transactions outside the ordinary course of business required the prior approval of the Bankruptcy Court.
For the duration of the Chapter 11 Cases, our operations and ability to develop and execute our business plan were subject to the risks and uncertainties associated with the Chapter 11 process as described in Item 1A. “Risk Factors.” As a result of these risks and uncertainties, the number of our shares of our common stock and $381stockholders, assets, liabilities, officers and/or directors could be significantly different following the outcome of the Chapter 11 Cases, and the description of our operations, properties and capital plans included in this Form 10-Q may not accurately reflect our operations, properties and capital plans following the Chapter 11 Cases.
During the Chapter 11 Cases, we expected our financial results to continue to be volatile as Restructuring activities and expenses, contract terminations and rejections, and claims assessments significantly impact our consolidated financial statements. As a result, our historical financial performance is likely not indicative of our financial performance after the date of the Petition Date. In addition, we incurred significant professional fees and other costs in connection with preparation for the Chapter 11 Cases.
On October 13, 2020, we filed a notice with the Bankruptcy Court that we reached an agreement with Tapstone Energy, LLC (“Tapstone Energy”) as the “Stalking Horse” bidder to sell our Mid-Continent asset for $85 million in cash,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 assumptionsale 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 WildHorse’s debta gain of $1.4 billion as of February 1, 2019. We anticipateapproximately $27 million.
On November 22, 2020, we filed notice with the acquisition to materially increase our oil production and enhance our oil production mix as well as significantly reduce costs due to operational synergiesBankruptcy Court that we believehad reached an agreement with The Williams Companies, Inc. (“Williams”) 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 combined companyCourt approved the transaction with Williams 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.
See Item 1. Business, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 2 of the notes to our consolidated financial statements included in Item 8 of this report for a 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 significant volatility, uncertainty, and economic disruption during 2020. 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. There remains considerable uncertainty regarding how long the pandemic and related market conditions will achieve. We expectpersist. In certain cases, states that the WildHorse Merger will provide substantial cost savings with $200 millionhad begun taking steps to $280 millionreopen their economies experienced a subsequent surge in projected average annual savings, totaling $1 billioncases of COVID-19, causing these states to $1.5 billion by 2023, due tocease such reopening measures in some cases and reinstitute restrictions in others. To date, we have experienced limited operational and capital efficienciesimpacts as a result of Chesapeake’s significant expertise with unconventional assetsCOVID-19 or the related governmental restrictions.
As an essential business under the guidelines issued by each of the states in which we operate, we have been allowed to continue operations. As a result, in mid-March of 2020, we restricted access to all of our offices and technicalfor a period of time directed employees to work remotely to the extent possible. We began to re-open our offices in phases beginning in mid-May of 2020, and operational excellence;
soldwe have implemented special precautions to minimize the risk to our interests inemployees of exposure. These actions have allowed us to maintain the Utica Shale operating area located in Ohio for approximately $1.9 billion,engagement and used the proceedsconnectivity of our personnel. However, due to reduce outstanding debt by approximately $1.8 billion, including our senior secured second lien notes;
retired our secured term loan due 2021 and significantly extended our debt maturity profile by issuing at par $850 million of 7.00% Senior Notes due 2024 and $400 million of 7.50% Senior Notes due 2026 for net proceeds of $1.2 billion, reducing our annual cash interest by approximately $30 million based on interest rates at the time of retirement;
continued to simplify our balance sheet, by repurchasing the CHK Utica, L.L.C. investors’ overriding royalty interests (ORRI) for $199 million;
improved liquidity by amending and restating our Chesapeake revolving credit facility, extending its maturity date by approximately four years;
improved cash flow from operations by $1.3 billion;
improved our cost structure by reducing our production, general and administrative, and gathering, processing and transportation expenses by $78 million, or 3%; and
generated approximately $528 million in proceedssevere impacts from the disposition of certain non-core assets and other property sales in addition toCOVID-19 pandemic on the sale of our Utica Shale properties.
Looking forward into 2019, we are confident in our ability to drive further competitive performance through the quality of our investments and our capital and operating discipline. We have secured a strong hedge positionglobal demand for oil and natural gas, that provides stability and certaintyfinancial results may not necessarily be indicative of operating results for the 2020 fiscal year or for any other future period. Moreover, future operations could be negatively affected if a significant number of our employees are quarantined as a result of exposure to the virus.
Our first priority in our cash generating capability should commodity prices experience volatility.
In 2019, our focus remains concentrated on four strategic priorities:
reduce total leverageresponse to achieve long term net debt/EBITDA of 2x;
increase net cash provided by operating activities to fund capital expenditures;
improve margins through financial discipline and operating efficiencies; and
maintain industry leading environmentalthis crisis has been the health and safety performance.of our employees and those of our other business counterparties. We have implemented preventative measures and developed corporate and regional response plans to minimize unnecessary risk of exposure and prevent infection, while supporting our employees, contractors and vendors to the best of our ability. We have a business continuity team tasked with responding to health, safety and environmental matters and personnel issues, and we have activated this business continuity team to address the impacts of the pandemic on our business as they develop. We also have modified certain business practices (including those related to employee travel, employee work locations, and cancellation of physical participation in meetings, events and conferences) to protect the health and safety of our employees and contractors and the communities in which we operate by conforming to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention, the World Health Organization and other governmental and regulatory authorities.
BusinessThere is considerable uncertainty regarding how long the pandemic and Industry Outlook
Overrelated market conditions will persist and the past decade,extent and duration of governmental and other measures implemented to try to slow the landscapespread of energy productionthe virus, such as large-scale travel bans and restrictions, border closures, quarantines, shelter-in-place orders and business and government shutdowns. One of the largest impacts of the pandemic has changed dramaticallybeen a significant reduction in global demand for oil and, to a lesser extent, natural gas. In addition, in the United States. Domestic energyfirst half of 2020, oil prices declined significantly due to an increase in supply emanating from a disagreement on production capabilitiescuts among members of OPEC+ and certain non-OPEC oil-producing countries. The resulting oversupply and the reduced demand in response to COVID-19 have increasedtogether caused prices in the nation’s supplyoil and gas market to remain depressed. Oil and natural gas prices are expected to continue to be volatile as a result of both crudethe near-term production instability and the ongoing COVID-19 pandemic and as changes in oil and natural gas primarily driven by advances in technology, horizontal drillinginventories, industry demand and hydraulic fracture stimulation techniques. As a result of this increase
in domesticglobal and national economic performance are reported. The supply of crudeand demand imbalance has disrupted the oil and natural gas commodityexploration and production industry and other industries that serve exploration and production companies. We
expect to see continued volatility in oil and natural gas prices for these products are meaningfully lower than they were a decade ago, and may remain volatile for the foreseeable future.future, and such volatility has adversely impacted and is expected to continue to adversely impact our business, cash flows, liquidity, financial condition and results of operations.
As of the date of this Form 10-K, our efforts to respond to the challenges presented by the conditions described above and minimize the impacts to our business have yielded positive results. We have moved quickly to implement strategies to reduce costs, increase operational efficiencies and lower our capital spending. In 2020, we reduced our workforce by 25%. In connection with this reduction, we recorded non-recurring charges of approximately $44 million for the year ended December 31, 2020, and we anticipate an estimated annualized savings of approximately $70 million. In February 2021, we reduced our workforce by an additional 15%. In addition, due to the significant drop in oil prices and midstream constraints in 2020, we shut in wells and delayed 38 turn-in-lines, which reduced our oil production by approximately 50%, 25% and 10% in May, June and July, respectively. In response to recent improvements in market conditions, we have returned most wells to production and intend to complete most of our drilled but uncompleted wells by the second quarter of 2021. We anticipate our capital expenditures for the remainder of the year will be focused primarily on our natural gas assets. We have not received any funding under the CARES Act or other federal programs to support our operations and do not anticipate that we will. We are continuing to address concerns to protect the health and safety of our employees and those of our customers and other business counterparties, and this includes changes to comply with health-related guidelines as they are modified and supplemented.
We cannot predict the full impact that COVID-19 or the current significant disruption and volatility in the oil and natural gas markets will have undergoneon our business, cash flows, liquidity, financial condition and results of operations. The ultimate impact of the pandemic will depend on future developments that cannot be anticipated, including, among others, the ultimate severity of the virus, the consequences of governmental and other measures designed to mitigate the spread of the virus, the development and availability of treatments and vaccines and the extent to which these treatments and vaccines may remain effective as potential new strains of the virus emerge, the duration of the pandemic, any actions taken by members of Organization of Petroleum Exporting Countries (OPEC+) and other foreign, oil-exporting countries, actions taken by governmental authorities, customers and other thirds parties, workforce availability, and the timing and extent of any return to normal economic and operating conditions. For additional discussion regarding risks associated with the COVID-19 pandemic, see Item 1A “Risk Factors” in this report.
Cancellation of Rights Plan
On April 23, 2020, our Board of Directors declared a mutli-year effort to reduce our cost structure significantly and improve the profitabilitydividend of one Right payable on May 4, 2020 for each share of our upstream portfolio. We have sold our non-upstream businesses, assets in under-performing basins and reduced our operating and general and administrative costs suchcommon stock outstanding on May 4, 2020 to the shareholders of record on that date (the “Rights”). In connection with the distribution of the Rights, we are currently experiencing higher profitability than comparedentered into a Rights Agreement with Computershare Trust Company, N.A., as rights agent (the “Rights Agreement”). Each Right entitles the registered holder to periods when commodity prices were much higher. purchase from us Preferred Shares.
The improvements in our cost structure give us a strategic advantage as a low cost developer of unconventional oil and gas assets in the U.S. We recently used this strategic advantageRights Agreement was intended to successfully acquire Wildhorse, a single asset, oil-focused company with an attractive acreage position of high-margin, undrilled locations. Our strategy going forward will be to leverage our advantages to drive shareholderprotect value by growing cash flow throughpreserving our ability to use our tax attributes to offset potential future income taxes for federal income tax purposes. Our ability to use our tax attributes would have been substantially limited if we had experienced an ownership change under Section 382 of the developmentCode prior to emergence from bankruptcy on February 9, 2021. The Rights Agreement reduced the likelihood of an ownership change by deterring any person or group of affiliated or associated persons from acquiring beneficial ownership of 4.9% or more of the outstanding shares of our extensive portfoliocommon stock.
In connection with the adoption of drilling opportunities. We intendthe Rights Agreement the Company filed a Certificate of Designations of Series B Preferred Stock with the Secretary of State of the State of Oklahoma setting forth the rights, powers, and preferences of the Series B Preferred Stock issuable upon exercise of the Rights (the “Preferred Shares”). On the Plan Effective Date, the Company filed a Certificate of Elimination with the Secretary of State of the State of Oklahoma eliminating the Preferred Shares and returning them to maintain capital discipline as we target cash flow growth rates that canauthorized but undesignated shares of the Company’s preferred stock. The foregoing is a summary of the terms of the Certificate of Elimination. The summary does not purport to be sustainable with internally generated resources.complete and is qualified in its entirety by reference to the Certificate of Elimination.
Liquidity and Capital Resources
Liquidity Overview
Our primary sources of capital resources and liquidity have historically consisted of internally generated cash flows from operations, borrowings under certain credit agreements, dispositions of non-core assets and the capital markets when conditions are favorable. Our ability to grow, makeissue additional indebtedness, dispose of assets or access the capital expendituresmarkets was substantially limited during the Chapter 11 Cases and service our debt depends primarily upon the prices we receive for the oil, natural gas and NGL we sell. Substantial expenditures are required to replace reserves, sustain production and fund our business plans. Historically, oil and natural gas prices have been volatile, and may be subject to wide fluctuationscourt approval in the future. A decline in oil, natural gas and NGL prices could negatively affect the amount of cash we generate and have available for capital expenditures and debt service and could have a material impact on our financial position, results of operations, cash flows and on the quantities of reserves that we can economically produce or provide as collateral to our credit facility lenders. Other risks and uncertainties that could affectmost instances. Accordingly, our liquidity include, but are not limited to, counterparty credit risk for our receivables, access to capital markets, regulatory risks and our ability to meet financial covenants in our financing agreements.
Baseddepended mainly on our cash balance, forecasted cash flowsgenerated from operating activities and availabilityavailable funds under the DIP Credit Facility discussed below.
The Bankruptcy Filing constituted an event of default under certain of our secured and unsecured debt obligations. As a result of the Bankruptcy Filing, the principal and interest due under these debt instruments became immediately due and payable. However, pursuant to Section 362 of the Bankruptcy Code, the creditors were stayed from taking any action as a result of such defaults.
Recent Events Affecting Liquidity
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 our pre-petition revolving credit facilities, we expectfacility and/or their affiliates (collectively, the “Commitment Parties”), pursuant to be ablewhich, 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 our outstanding borrowings under the pre-petition revolving credit facility. Pursuant to the Commitment Letter, the Commitment Parties 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 DIP Credit Facility provided us the capital necessary to fund our plannedoperations during the Chapter 11 reorganization proceedings. The proceeds of the DIP Credit Facility were used for, among other things, post-petition working capital, expenditures, meet our debt service requirementspermitted capital investments, general corporate purposes, letters of credit, administrative costs, premiums, expenses and fund our other commitments and obligationsfees for the next 12 months.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 July 1, 2020, the Company, as borrower, entered into the DIP Credit Agreement along with the Debtor guarantors party thereto, MUFG Union Bank, N.A., as agent, and the other lender, issuer, and agent parties thereto. On September 15, 2020, we entered into the first amendment to the DIP Credit Agreement. The amendment, among other things, amended the maximum hedging covenant to allow the Debtors to enter into additional non-speculative hedge agreements based on forecasted production. See Note 2 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our DIP Credit Facility. As of December 31, 2018,2020, we had a cash balance of $4$279 million, as compared to $5$6 million as of December 31, 2017,2019, and a net working capital deficit of $1.230$1.986 billion as of December 31, 2018,2020, as compared to a net working capital deficit of $831 million as of December 31, 2017. As of December 31, 2018, our working capital deficit includes $381 million of debt due in the next 12 months. Our total principal debt as of December 31, 2018 was $8.168 billion compared to $9.981$1.141 billion as of December 31, 2017.2019. Additionally, our DIP Credit Facility was approved by the Bankruptcy Court on July 31, 2020 which allowed us up to $925 million of borrowing capacity. As of December 31, 2018,2020, we had $2.474 billion of borrowing capacity available under the Chesapeake revolving credit facility, withno outstanding borrowings of $419 million and $107 million utilized for various letters of credit. As of the WildHorse acquisition date of February 1, 2019, we had $578 million of borrowing capacity available under the WildHorse revolving credit facility, with outstanding borrowings of $675 million and $47 million utilized as a letter of credit.our DIP Credit Facility. See Note 35 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our debt obligations, including principal and carrying amounts of our notes. Although we have taken measuresPost-Emergence Debt
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 mitigate liquidity concerns over the next 12 months, as outlined above in Overview, 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 portionprevious holders of our outstanding indebtedness to improve our liquidity. We closely monitor the amountsterm loan, second lien notes, senior notes 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 facilities. 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.certain general unsecured creditors.
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 (the “Exit 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 and the next scheduled redetermination will be on or about October 1, 2021. The aggregate initial elected commitments of the lenders under the Exit Credit Facility will be $1.75 billion of revolving Tranche A Loans (the “Tranche A Loans”) and $220 million of fully funded Tranche B Loans (the “Tranche B Loans”).
The Exit Credit Facility provides for a $200.0 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
On February 2, 2021, the Company, issued $500 million aggregate principal amount of its 5.5% 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 being 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.
Based upon the business plan approved by the Court and our hedging activities we expect to generate adequate cash flows from operating activities to fully fund all investing activities without incremental borrowings under our Exit Credit Facility.
Derivative and Hedging Activities
Our results of operations and cash flows are impacted by changes in market prices for oil, natural gas and NGL. To mitigate a portion of theour exposure to adverse market 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 NGL, allow us to better predict with greater certainty the total revenue we willexpect to receive.
We utilize various oil, natural gas and NGL derivative instruments to protect a portion of our cash flow against downside risk. As of February 22, 2019, including25, 2021, we had downside oil price protection on approximately 19 mmbbls through swaps at $42.69 per bbl. We had downside natural gas price protection on 548 bcf through swaps and collars at an average price of $2.67 per mcf.
| | | | | | | | | | | | | | | | | | | | |
Oil Derivatives(a) |
| Year | | Type of Derivative Instrument | | Notional Volume | | Average NYMEX/Basis Price |
| | | | (mmbbls) | | |
| 2021 | | Fixed-price swaps | | 19 | | | $42.69 |
| 2021 | | Basis protection swaps(b) | | 5 | | | $0.61 |
| 2022 | | Fixed-price swaps | | 11 | | | $44.30 |
| 2022 | | Basis protection swaps(b) | | 2 | | | $0.09 |
| 2023 | | Fixed-price swaps | | 2 | | | $47.17 |
| | | | | | |
Natural Gas Derivatives(a) |
| Year | | Type of Derivative Instrument | | Notional Volume | | Average NYMEX/Basis Price |
| | | | (bcf) | | |
| 2021 | | Fixed-price swaps(c) | | 518 | | | $2.67 |
| 2021 | | Two-way collars | | 30 | | | $2.80/$3.29 |
| 2021 | | Basis protection swaps | | 119 | | | ($0.57) |
| 2022 | | Fixed-price swaps | | 249 | | | $2.55 |
| 2022 | | Two-way collars | | 23 | | | $2.30/$2.94 |
| 2022 | | Basis protection swaps | | 30 | | | $0.18 |
| 2023 | | Fixed-price swaps | | 45 | | | $2.75 |
| 2023 | | Basis protection swaps | | 4 | | | $0.75 |
(a) Includes amounts settled in January and February derivative contracts that have settled, approximately 63% of our forecasted oil, natural gas and NGL production revenue was hedged, including 56% and 81% of our forecasted 2019 oil and natural gas production (including WildHorse production from February 1, 2019) at average prices of $57.12 per barrel and $2.85 per mcf, respectively.2021.
(b) Includes CMA WTI Roll swaps. |
| | | | | | | |
Oil Derivatives(a) |
| Year | | Type of Derivative Instrument | | Notional Volume | | Average NYMEX Price |
| | | | | (mmbbls) | | |
| 2019 | | Swaps | | 17 |
| | $57.16 |
| 2019 | | Two-way collars | | 6 |
| | $58.00/$67.75 |
| 2019 | | Basis protection swaps | | 7 |
| | $6.01 |
| 2019 | | Puts | | 2 |
| | $53.83 |
| 2020 | | Swaps | | 7 |
| | $58.28 |
| 2020 | | Two-way collars | | 2 |
| | $65.00/$83.25 |
| | | | | | | |
Natural Gas Derivatives(a) |
| Year | | Type of Derivative Instrument | | Notional Volume | | Average NYMEX Price |
| | | | | (bcf) | | |
| 2019 | | Swaps | | 453 |
| | $2.87 |
| 2019 | | Two-way collars | | 55 |
| | $2.75/$3.02 |
| 2019 | | Three-way collars | | 88 |
| | $2.50/$2.80/$3.10 |
| 2019 | | Calls | | 22 |
| | $12.00 |
| 2019 | | Basis protection swaps | | 50 |
| | ($0.56) |
| 2020 | | Swaps | | 217 |
| | $2.75 |
| 2020 | | Call swaptions | | 106 |
| | $2.77 |
| 2020 | | Calls | | 22 |
| | $12.00 |
| |
(a) | Includes amounts settled in January and February 2019. |
See Note 1314 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of derivatives and hedging activities. Debt
We decreased our total principal amount of debt outstanding by approximately $1.8 billion in 2018. We accomplished this primarily by using the net proceeds from the sale of our Utica interests and other assets. We currently plan to use cash flow from operations and availability under our credit facilities to fund our capital expenditures for 2019. We are seeking to reduce cash costs (production, gathering, processing and transportation, general and administrative and interest expenses), improve our production volumes from existing wells, and achieve additional operating and capital efficiencies with a focus on growing our oil volumes.
In 2018, we issued at par $850 million of 7.00% Senior Notes due 2024 (the “2024 notes”) and $400 million of 7.50% Senior Notes due 2026 (the “2026 notes” and, together with the 2024 notes, the “senior notes”) pursuant to a public offering for net proceeds of approximately $1.236 billion. We may redeem some or all of the 2024 notes at any time prior to April 1, 2021 and some or all of the 2026 notes at any time prior to October 1, 2021, in each case at a price equal to 100% of the principal amount of the notes to be redeemed plus a “make-whole” premium.
We used the net proceeds from the senior notes, together with cash on hand and borrowings under the Chesapeake revolving credit facility, to repay in full $1.233 billion of borrowings under our secured term loan due 2021 for $1.285 billion, which included a $52 million make-whole premium. We recorded a loss of approximately $65 million associated with the repayment of the term loan, including the make-whole premium and the write-off of $13 million of associated deferred charges. Also in 2018, we used the proceeds from the sale of our Utica assets in Ohio to redeem all of the $1.416 billion aggregate principal amount outstanding of our 8.00% Senior Secured Second Lien Notes due 2022 which included a $60 million make-whole premium. We recorded a gain of approximately $331 million associated with the redemption, including the realization of the remaining $391 million difference in principal and book value due to troubled debt restructuring accounting in 2015, offset by the make-whole premium of $60 million.
We may continue to use a combination of cash, borrowings and issuances of our common stock or other securities to retire our outstanding debt, including any debt assumed in connection with the completion with the WildHorse acquisition, through privately negotiated transactions, open market repurchases, redemptions, tender offers or otherwise, but we are under no obligation to do so. We expect to generate additional liquidity with proceeds from future sales of assets that do not fit our strategic priorities.
Chesapeake Revolving Credit Facility
The Chesapeake revolving credit facility is currently subject to a $3.0 billion borrowing base that matures in September 2023. As of December 31, 2018, we had $2.474 billion of borrowing capacity available under the Chesapeake revolving credit facility. Our next borrowing base redetermination is scheduled for the second quarter of 2019. As of December 31, 2018, we had outstanding borrowings of $419 million under the Chesapeake revolving credit facility and had used $107 million of the Chesapeake revolving credit facility for various letters of credit. Borrowings under the facility bear interest at a variable rate. Under the Chesapeake revolving credit facility, we borrowed $11.697 billion and repaid $12.059 billion in 2018, we borrowed $7.771 billion and repaid $6.990 billion in 2017 and we borrowed and repaid $5.146 billion in 2016. See Note 3 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of the terms of the Chesapeake revolving credit facility. As of December 31, 2018, we were in compliance with all applicable financial covenants under the credit agreement. Our leverage ratio was approximately 3.31 to 1.00. Our secured leverage ratio and fixed charge coverage ratio were not in effect for the quarter ended December 31, 2018, due to the Utica Shale divestiture taking place during the quarter. Both ratios, in addition to the leverage ratio, will be in effect for the quarter ending March 31, 2019.WildHorse Revolving Credit Facility
In connection with the acquisition of WildHorse, our subsidiary Brazos Valley Longhorn became the borrower under the WildHorse revolving credit facility. The WildHorse revolving credit facility has a maximum credit amount of $2.0 billion, with current aggregate elected commitments of $1.3 billion and a current borrowing base of $1.3 billion. The WildHorse revolving credit facility matures in December 2021. The borrowing base under the WildHorse revolving credit facility is subject to redetermination, on at least a semi-annual basis, primarily on estimated proved reserves. The next scheduled redetermination is in the second quarter of 2019. As of the WildHorse acquisition date of February 1, 2019, we had $578 million of borrowing capacity available under the WildHorse revolving credit facility, with outstanding borrowings of $675 million and $47 million utilized as a letter of credit. The WildHorse revolving credit facility is guaranteed by certain of Brazos Valley Longhorn’s subsidiaries (the “BVL Guarantors”) and is required to be secured by substantially all of the assets of Brazos Valley Longhorn and BVL Guarantors, including mortgages on not less than 85% of the proved reserves of their oil and gas properties.
The obligations under the WildHorse revolving credit facility are the senior secured obligations of Brazos Valley Longhorn and the BVL Guarantors. The obligations under the WildHorse revolving credit facility will not be obligations of Chesapeake or any of its subsidiaries other than Brazos Valley Longhorn and the BVL Guarantors. The obligations under the WildHorse revolving credit facility will rank equally in right of payment with all other senior secured indebtedness of Brazos Valley Longhorn and the other BVL Guarantors, and will be effectively senior to Brazos Valley Longhorn’s and the BVL Guarantors’ senior unsecured indebtedness, including their obligations under the WildHorse senior notes, to the extent of the value of the collateral securing the WildHorse revolving credit facility.
The Wildhorse revolving credit facility is used for the liquidity and expenses of Brazos Valley Longhorn and its subsidiaries and not Chesapeake or any of its subsidiaries other than Brazos Valley Longhorn, Brazos Valley Longhorn Finance Corp. (“BVL Finance Corp.”) and the other BVL Guarantors. Revolving loans under the WildHorse revolving credit facility bear interest at the alternate base rate, Eurodollar rate or LIBOR market index rate at Brazos Valley Longhorn’s election, plus an applicable margin (ranging from 0.50%-1.50% per annum for alternate base rate loans, 1.50%-2.50% per annum for Eurodollar loans and 1.50%-2.50% per annum for LIBOR market index rate loans), depending on Brazos Valley Longhorn’s total commitment usage. The unused portion of the total commitments are subject to a commitment fee that varies from 0.375% to 0.500%, depending on Brazos Valley Longhorn’s total commitment usage. The terms of the WildHorse revolving credit facility include covenants limiting, among other things, the ability of Brazos Valley Longhorn and its Restricted Subsidiaries (as defined under the WildHorse revolving credit facility) to incur additional indebtedness, make investments or loans, incur liens, consummate mergers or similar fundamental changes, make restricted payments, including dividends to Chesapeake, and enter into transactions with affiliates, including Chesapeake and its other subsidiaries. The WildHorse revolving credit facility also contains financial covenants that require Brazos Valley Longhorn to maintain (i)(x) if there are no loans outstanding thereunder, a ratio of net debt to EBITDAX (as defined under the WildHorse revolving credit facility) of not more than 4.00 to 1.00 as of the last day of each fiscal quarter or (y) if there are such loans outstanding, a ratio of total debt to EBITDAX of not more than 4.00 to 1.00 as of the last day of each fiscal quarter and (ii) a ratio of current assets (including availability under the WildHorse revolving credit facility) to current liabilities of not less than 1.00 to 1.00 as of the last day of each fiscal quarter. As of December 31, 2018, WildHorse was in compliance with all applicable financial covenants under the credit agreement. WildHorse’s ratio of net debt to EBITDAX was 1.81 to 1.00 and our ratio of current assets was 4.30 to 1.00 as of December 31, 2018.
The WildHorse revolving credit facility includes events of default relating to customary matters, including, among other things, nonpayment of principal, interest or other amounts; violation of covenants; incorrectness of representations and warranties in any material respect; defaults with respect to indebtedness in an aggregate principal amount of $25.0 million or more; bankruptcy; judgments involving liability of $15.0 million or more that are not paid; change of control; and ERISA events. Many events of default are subject to customary notice and cure periods.
WildHorse Senior Notes
As a result of the completion of the acquisition of WildHorse, Brazos Valley Longhorn assumed the obligations under WildHorse’s $700 million aggregate principal amount of 6.875% Senior Notes due 2025 (the “WildHorse senior notes”) and BVL Finance Corp., a wholly owned subsidiary of Brazos Valley Longhorn, became a co-issuer of the WildHorse senior notes.
The WildHorse senior notes are the senior unsecured obligations of Brazos Valley Longhorn, BVL Finance Corp. and the other BVL Guarantors. The WildHorse senior notes will not be obligations of Chesapeake or any of its subsidiaries other than Brazos Valley Longhorn, BVL Finance Corp. and the other BVL Guarantors. The WildHorse senior notes will rank equally in right of payment with all other senior unsecured indebtedness of Brazos Valley Longhorn, BVL Finance Corp. and the other BVL Guarantors, and will be effectively subordinated to Brazos Valley Longhorn’s, BVL Finance Corp.’s and the other BVL Guarantors’ senior secured indebtedness, including their obligations under the WildHorse revolving credit facility, to the extent of the value of the collateral securing such indebtedness.
The indenture (the “WildHorse indenture”) governing the WildHorse senior notes contains customary reporting covenants (including furnishing quarterly and annual reports to the holders of the WildHorse senior notes) and restrictive covenants that, among other things, restrict the ability of Brazos Valley Longhorn and its subsidiaries to: (i) pay dividends on, purchase or redeem Brazos Valley Longhorn’s equity interests or purchase or redeem subordinated debt; (ii) make certain investments; (iii) incur or guarantee additional indebtedness or issue certain types of equity securities; (iv) create or incur certain secured debt; (v) sell assets; (vi) consolidate, merge or transfer all or substantially all of Brazos Valley Longhorn’s assets; (vii) enter into agreements that restrict distributions or other payments from Brazos Valley Longhorn’s restricted subsidiaries to Brazos Valley Longhorn; (viii) engage in transactions with affiliates, including Chesapeake and its other subsidiaries; and (ix) create unrestricted subsidiaries. These covenants are subject to a number of important qualifications and limitations. In addition, most of the covenants will be terminated before the WildHorse senior notes mature if at any time no default or event of default exists under the WildHorse indenture and the WildHorse senior notes receive an investment grade rating from both of two specified ratings agencies. The WildHorse indenture also contains customary events of default.
If the WildHorse senior notes are downgraded within 90 days after the consummation of the acquisition of WildHorse (which constitutes a “Change of Control” under the WildHorse indenture), the WildHorse indenture requires Brazos Valley Longhorn (or a third party, in certain circumstances) to make an offer to repurchase the WildHorse senior notes at 101% of their principal amount, plus accrued and unpaid interest, within 30 days of such downgrade. If any holder of WildHorse senior notes accepts such offer, Brazos Valley Longhorn may (subject to the terms and conditions thereof) fund the purchase price with loans under the WildHorse revolving credit facility or Chesapeake may elect to draw under the Chesapeake revolving credit facility, use cash on hand, issue debt securities or use other sources of liquidity to fund such repurchase. If Brazos Valley Longhorn and Chesapeake are not required to make such offer or not all holders of WildHorse senior notes accept such an offer, Chesapeake may seek to amend, engage in liability management transactions with respect to, or redeem or refinance, the WildHorse senior notes at any time.
The WildHorse revolving credit facility and the WildHorse Indenture constrain the ability of WildHorse and its subsidiaries to make distributions or otherwise provide funds to, or guarantee the obligations of, Chesapeake and its other subsidiaries. The provisions of the WildHorse revolving credit facility and the WildHorse Indenture require that all transactions between WildHorse and its subsidiaries, on the one hand, and Chesapeake and its other subsidiaries, on the other hand, be on an arm's-length basis
Contractual Obligations and Off-Balance Sheet Arrangements
From time 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 commitments as of December 31, 2018:2020:
|
| | | | | | | | | | | | | | | | | | | | |
| | | Payments Due By Period |
| | | Total | | 2019 | | 2020-2021 | | 2022-2023 | | 2024 and Beyond |
| | | ($ in millions) |
Long-term debt:(a) | | | | | | | | | | |
Principal(b) | | $ | 8,168 |
| | $ | 381 |
| | $ | 1,479 |
| | $ | 1,208 |
| | $ | 5,100 |
|
| Interest | | 3,058 |
| | 523 |
| | 942 |
| | 793 |
| | 800 |
|
Capital lease obligation(c) | | 30 |
| | 10 |
| | 20 |
| | — |
| | — |
|
Operating lease obligations(d) | | 4 |
| | 3 |
| | 1 |
| | — |
| | — |
|
Operating commitments(e) | | 5,786 |
| | 837 |
| | 1,467 |
| | 1,051 |
| | 2,431 |
|
Unrecognized tax benefits(f) | | 53 |
| | — |
| | — |
| | 53 |
| | — |
|
| Standby letters of credit | | 107 |
| | 107 |
| | — |
| | — |
| | — |
|
| Other | | 18 |
| | 4 |
| | 8 |
| | 6 |
| | — |
|
Total contractual cash obligations(g) | | $ | 17,224 |
| | $ | 1,865 |
| | $ | 3,917 |
| | $ | 3,111 |
| | $ | 8,331 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Payments Due By Period |
| | Total | | 2021 | | 2022-2023 | | 2024-2025 | | 2026 and Beyond |
| | ($ in millions) |
| Long-term debt: | | | | | | | | | | |
Principal(a) | | $ | 9,096 | | | $ | 2,472 | | | $ | 440 | | | $ | 4,702 | | | $ | 1,482 | |
Interest(a) | | 2,375 | | | 607 | | | 1,130 | | | 560 | | | 78 | |
Finance lease obligation(b) | | 10 | | | 10 | | | — | | | — | | | — | |
Operating lease obligations(c) | | 30 | | | 28 | | | 2 | | | — | | | — | |
Operating commitments(d) | | 5,102 | | | 872 | | | 1,326 | | | 992 | | | 1,912 | |
| Standby letters of credit | | 54 | | | 54 | | | — | | | — | | | — | |
| Other | | 12 | | | 6 | | | 6 | | | — | | | — | |
Total contractual cash obligations(e) | | $ | 16,679 | | | $ | 4,049 | | | $ | 2,904 | | | $ | 6,254 | | | $ | 3,472 | |
| |
(a) | We assumed $1.4 billion of debt with the completion of the WildHorse acquisition on February 1, 2019 that is not included in the table above. |
| |
(b) | See Note 3 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our long-term debt. |
| |
(c) | See Note 6 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our capital lease obligation. |
| |
(d) | 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. |
| |
(a) The maturities of our debt obligations and associated interest reflect their original expiration dates and do not reflect any acceleration due to any events of default pertaining to these obligations. See Note 5 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our long-term debt. (b) See Note 8 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our finance lease obligation. (c) See Note 8 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our operating lease obligations. (d) See Note 6 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our gathering, processing and transportation agreements and service contract commitments. (e) | See Note 4 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our gathering, processing and transportation agreements and service contract commitments. |
| |
(f) | See Note 8 of the notes to our consolidated financial statements included in Item 8 of this report for a discussion of unrecognized tax benefits. |
(g) 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 1314 and 2122, respectively, of the
notes to our consolidated financial statements included 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 14 of the notes to our consolidated financial statements included in Item 8 of this report. Capital Expenditures
Our 2019For the year ending December 31, 2021, we currently expect to bring or have online approximately 110 to 125 gross wells across five to six rigs and plan to invest between approximately $670 – $740 million in capital expenditures. We expect that approximately 80% of our 2021 capital expenditures will be directed toward our natural gas assets. We currently plan to fund our 2021 capital program isthrough cash on hand, expected to generate greater capital efficiency than the 2018 program as we focus on expandingcash flow from our margins through disciplined investing in the highest-return projects.operations and borrowings under our Exit Revolver. We have significant control and flexibility over the timing and execution ofmay alter or change our development plan, enabling usplans with respect to reduce our capital spending as needed. Our forecasted 2019program and expected capital expenditures inclusivebased on developments in our business, our financial position, our industry or any of Brazos Valley and capitalized interest, are $2.3 – $2.5 billion compared to our 2018 capital spending level of $2.4 billion. Management continues to review operational plans for 2019 and beyond,the markets in which could result in changes to projected capital expenditures and projected revenues from sales of oil, natural gas and NGL.we operate.
Credit Risk
Derivative instruments that enableOur customers and counterparties are experiencing uncertain economic conditions which may impact their ability to make payments to us, to managewhich could adversely affect our exposure to oil, natural gasbusiness, cash flows, liquidity, financial condition 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. Asresults of December 31, 2018, our oil, natural gas and NGL derivative instruments were spread among 11 counterparties. Additionally,operations. We monitor the counterparties under these arrangements are required to secure their obligations in excesscreditworthiness of defined thresholds.
Our accounts receivable are primarily from purchasers of oil, natural gas and NGL ($976 million as of December 31, 2018) and exploration and production companies that own interests in properties we operate ($211 million as of December 31, 2018). This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in thatall our customers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. Wecounterparties 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. During 2018, 2017 and 2016, we recognized $6 million, $9 million and $10 million, respectively, of bad debt expense related to potentially uncollectible receivables.
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 22, 2019, we have received requests and posted approximately $162 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 $355 million, which may be in the form of additional letters of credit, cash or other acceptable collateral. However, we have substantial long-term business relationships with each of these counterparties, and we may be able to mitigate any collateral requests through ongoing business arrangements and by offsetting amounts that the counterparty owes us. Any posting of collateral consisting of cash or letters of credit reduces availability under our revolving credit facility and negatively impacts our liquidity.
Sources of Funds
The following table presents the sources of our cash and cash equivalents for the years ended December 31, 2018, 20172020, 2019 and 2016.2018. See Note 143 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of divestitures of oil and natural gas assets. | | | | | | | | | | | | | | | Years Ended December 31, |
| | | Years Ended December 31, | | | 2020 | | 2019 | | 2018 |
| | | 2018 | | 2017 | | 2016 | | | ($ in millions) |
| | | ($ in millions) | |
| Cash provided by (used in) operating activities | | $ | 2,000 |
| | $ | 745 |
| | $ | (204 | ) | |
| Cash provided by operating activities | | Cash provided by operating activities | | $ | 1,164 | | | $ | 1,623 | | | $ | 1,730 | |
| Proceeds from issuances of debt, net | | 1,236 |
| | 1,585 |
| | 3,686 |
| Proceeds from issuances of debt, net | | — | | | 1,563 | | | 1,236 | |
| Proceeds from revolving credit facility borrowings, net | | — |
| | 781 |
| | — |
| Proceeds from revolving credit facility borrowings, net | | 339 | | | 496 | | | — | |
| Proceeds from divestitures of proved and unproved properties, net | | 2,231 |
| | 1,249 |
| | 1,406 |
| Proceeds from divestitures of proved and unproved properties, net | | 136 | | | 130 | | | 2,231 | |
| Proceeds from sales of other property and equipment, net | | 147 |
| | 55 |
| | 131 |
| Proceeds from sales of other property and equipment, net | | 14 | | | 6 | | | 147 | |
| Proceeds from sales of investments | | 74 |
| | — |
| | — |
| Proceeds from sales of investments | | — | | | — | | | 74 | |
| Total sources of cash and cash equivalents | | $ | 5,688 |
| | $ | 4,415 |
| | $ | 5,019 |
| Total sources of cash and cash equivalents | | $ | 1,653 | | | $ | 3,818 | | | $ | 5,418 | |
Cash Flow from Operating Activities
Cash provided by operating activities was $2.000$1.164 billion, $1.623 billion and $1.730 billion in 2020, 2019 and 2018, compared to cash provided by operating activities of $745 millionrespectively. The decrease in 2017 and cash used in operating activities of $204 million in 2016. The increase in 20182020 is primarily the result of higherlower prices for the oil, natural gas and NGL we sold. The increasedecrease in 20172019 is primarily the result of higherlower prices for the oil, natural gas and NGL we sold and decreases inas well as certain of our operating expenses, partially offset by lower volumes of oil, natural gas and NGL sold, the paymentcash expenditures related to the litigation involving the early redemption of our 6.775% Senior Notes due 2019 and payments for terminations of transportation contracts.WildHorse acquisition. Changes in cash flow from operations are largely due to the same factors that affect our net income, excluding various non-cash items, such as depreciation, depletion and amortization, certain impairments, gains or losses on sales of fixed assets, deferred income taxes and mark-to-market changes in our derivative instruments. See further discussion below under Results of Operations.
Debt issuances
The following table reflects the proceeds received from issuances of debt in 2018, 20172020, 2019 and 2016.2018. See Note 35 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion. | | | | | | | | | | | | | | | | Years Ended December 31, |
| | | Years Ended December 31, | | 2020 | | 2019 | | 2018 |
| | | 2018 | | 2017 | | 2016 | | Principal Amount of Debt Issued | | Net Proceeds | | Principal Amount of Debt Issued | | Net Proceeds | | Principal Amount of Debt Issued | | Net
Proceeds |
| | | Principal Amount of Debt Issued | | Net Proceeds | | Principal Amount of Debt Issued | | Net Proceeds | | Principal Amount of Debt Issued | | Net
Proceeds | | ($ in millions) |
| | | ($ in millions) | |
| Term loan | | Term loan | | $ | — | | | $ | — | | | $ | 1,500 | | | $ | 1,455 | | | $ | — | | | $ | — | |
| Senior secured second lien notes | | Senior secured second lien notes | | — | | | — | | | 120 | | | 108 | | | — | | | — | |
| Senior notes | | $ | 1,250 |
| | $ | 1,236 |
| | $ | 1,600 |
| | $ | 1,585 |
| | $ | 1,000 |
| | $ | 975 |
| Senior notes | | — | | | — | | | — | | | — | | | 1,250 | | | 1,236 | |
| Convertible senior notes | | — |
| | — |
| | — |
| | — |
| | 1,250 |
| | 1,235 |
| |
| Term loans | | — |
| | — |
| | — |
| | — |
| | 1,500 |
| | 1,476 |
| |
| Total | | $ | 1,250 |
| | $ | 1,236 |
| | $ | 1,600 |
| | $ | 1,585 |
| | $ | 3,750 |
| | $ | 3,686 |
| Total | | $ | — | | | $ | — | | | $ | 1,620 | | | $ | 1,563 | | | $ | 1,250 | | | $ | 1,236 | |
Divestitures of Proved and Unproved Properties
DuringIn 2020, we divested our Mid-Continent asset for $130 million and certain non-core assets for approximately $6 million. In 2019, we divested certain non-core assets for approximately $130 million. In 2018, we divested $2.231 billion of proved and unproved properties including $1.868 billion for all of our Utica Shale properties in Ohio. During 2017 and 2016, we divested certain non-core assets for approximately $1.249 billion and $1.406 billion, respectively. Proceeds from these transactions were used to repay debt and fund our development program. See Note 143 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion.
Uses of Funds
The following table presents the uses of our cash and cash equivalents for the years ended December 31, 2018, 20172020, 2019 and 2016:2018:
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | | 2020 | | 2019 | | 2018 |
| | ($ in millions) |
| Oil and Natural Gas Expenditures: | | | | | | |
| Drilling and completion costs | | $ | 1,111 | | | $ | 2,180 | | | $ | 1,848 | |
| Acquisitions of proved and unproved properties | | 9 | | | 35 | | | 128 | |
| Total oil and natural gas expenditures | | 1,120 | | | 2,215 | | | 1,976 | |
| Other Uses of Cash and Cash Equivalents: | | | | | | |
| Cash paid to purchase debt | | 94 | | | 1,073 | | | 2,813 | |
| DIP credit facility and exit facilities financing costs | | 109 | | | — | | | — | |
| Business combination, net | | — | | | 353 | | | — | |
| Payments on revolving credit facility borrowings, net | | — | | | — | | | 362 | |
| Extinguishment of other financing | | — | | | — | | | 122 | |
| Additions to other property and equipment | | 22 | | | 48 | | | 21 | |
| Cash paid for preferred stock dividends | | 22 | | | 91 | | | 92 | |
| Other | | 13 | | | 36 | | | 27 | |
| Total other uses of cash and cash equivalents | | 260 | | | 1,601 | | | 3,437 | |
| Total uses of cash and cash equivalents | | $ | 1,380 | | | $ | 3,816 | | | $ | 5,413 | |
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| | | ($ in millions) |
| Oil and Natural Gas Expenditures: | | | | | | |
| Drilling and completion costs | | $ | 1,958 |
| | $ | 2,186 |
| | $ | 1,295 |
|
| Acquisitions of proved and unproved properties | | 135 |
| | 101 |
| | 552 |
|
| Interest capitalized on unproved leasehold | | 153 |
| | 184 |
| | 236 |
|
| Total oil and natural gas expenditures | | 2,246 |
| | 2,471 |
| | 2,083 |
|
| Other Uses of Cash and Cash Equivalents: | | | | | | |
| Cash paid to purchase debt | | 2,813 |
| | 2,592 |
| | 2,734 |
|
| Payments on revolving credit facility borrowings, net | | 362 |
| | — |
| | — |
|
| Extinguishment of other financing | | 122 |
| | — |
| | — |
|
| Additions to other property and equipment | | 21 |
| | 21 |
| | 37 |
|
| Cash paid for preferred stock dividends | | 92 |
| | 183 |
| | — |
|
| Distributions to noncontrolling interest owners | | 6 |
| | 8 |
| | 10 |
|
| Other | | 27 |
| | 17 |
| | 98 |
|
| Total other uses of cash and cash equivalents | | 3,443 |
| | 2,821 |
| | 2,879 |
|
| Total uses of cash and cash equivalents | | $ | 5,689 |
| | $ | 5,292 |
| | $ | 4,962 |
|
Drilling and Completion Costs
Our drilling and completion costs decreased in 20182020 compared to 20172019 primarily as a result of decreased drilling and completion activity.activity mainly in our liquids-rich plays. We spud, completed, and connected wells at a higher average working interest in 2019 compared to 2018 due to the divestiture of the Utica asset and the acquisition of the Brazos Valley asset. Our average operated rig count was 8 rigs and spud wells were 167 in 2020 compared to an average operated rig count of 18 rigs and 333 spud wells in 2019 and 17 rigs and 322 spud wells in 2018. We completed 351188 operated wells in 20182020 compared to 401370 in 2017.2019 and 351 in 2018.
Business Combination - Acquisition of WildHorse
In 2019, we acquired WildHorse for approximately 3.6 million reverse stock split adjusted shares of our common stock and $381 million less $28 million of cash held by WildHorse as of the acquisition date. See Note 3 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of the acquisition. Cash Paid to Purchase Debt
In 2020, we repurchased approximately $160 million aggregate principal amount of our senior notes for $94 million. In 2019, we repurchased $698 million principal amount of our BVL Senior Notes for $693 million and retired 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. In 2018, we used $2.813 billion of cash to repurchase $2.701 billion principal amount of debt.
DIP Credit Facility Financing Costs
In 2017,2020, we used $2.592 billionpaid $109 million of cashone-time fees to repurchase $2.389 billion principal amount of debt. In 2016, we used $2.734 billion of cashlenders to repurchase $2.884 billion principal amount of debt.establish our DIP Credit Facility and Exit Credit Facility.
Extinguishment of Other Financing
In 2018, we repurchased previously conveyed overriding royalty interests (ORRIs) from the CHK Utica, L.L.C. investors and extinguished our obligation to convey future ORRIs to the investors for combined consideration of $199 million. The cash paid was bifurcated between extinguishment of the obligation and acquisition of the ORRI.
Dividends
We paid dividends of $22 million, $91 million and $92 million on our preferred stock during 2020, 2019 and 2018, respectively. On April 17, 2020, we announced that we were suspending payment of dividends on each series of our outstanding convertible preferred stock. Pursuant to the restructuring support agreement associated with our Chapter 11 Cases (the “Restructuring Support Agreement”), each holder of an equity interest in Chesapeake had such interest canceled, released, and extinguished without any distribution. See Note 52 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion ofadditional information about the transaction.Chapter 11 Cases. We paid dividends of $92 million on our preferred stock during 2018 and paid dividends of $183 million on our preferred stock in 2017, including $92 million of dividends in arrears that had been suspended throughout 2016. We did not pay dividends on our preferred stock in 2016. We eliminated common stock dividends in the 2015 third quarter and do not intend to resume paying cash dividends on our common stock in the foreseeable future.
Results of Operations
Year ended December 31, 2020 compared to the year ended December 31, 2019
Below is a discussion of changes in our results of operations for 2020 compared to 2019. A discussion of changes in our results of operations for 2019 compared to 2018 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 Form 10-K for the year ended December 31, 2019 as filed with the SEC on February 27, 2020.
Oil, Natural Gas and NGL Production and Average Sales Prices |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2018 |
| | | Oil | | Natural Gas | | NGL | | Total |
| | | mbbl per day | | $/bbl | | mmcf per day | | $/mcf | | mbbl per day | | $/bbl | | mboe per day | | % | | $/boe |
| Marcellus | | — |
| | — |
| | 828 |
| | 3.06 |
| | — |
| | — |
| | 138 |
| | 26 |
| | 18.38 |
|
| Haynesville | | — |
| | — |
| | 789 |
| | 2.90 |
| | — |
| | — |
| | 131 |
| | 25 |
| | 17.43 |
|
| Eagle Ford | | 60 |
| | 69.01 |
| | 137 |
| | 3.46 |
| | 20 |
| | 25.57 |
| | 103 |
| | 20 |
| | 49.93 |
|
| Powder River Basin | | 11 |
| | 63.38 |
| | 64 |
| | 2.91 |
| | 4 |
| | 26.83 |
| | 25 |
| | 5 |
| | 38.20 |
|
| Mid-Continent | | 9 |
| | 63.93 |
| | 64 |
| | 2.76 |
| | 5 |
| | 26.43 |
| | 25 |
| | 5 |
| | 36.23 |
|
Retained assets(a) | | 80 |
| | 67.67 |
| | 1,882 |
| | 3.01 |
| | 29 |
| | 25.88 |
| | 422 |
| | 81 |
| | 27.98 |
|
Divested assets(b) | | 10 |
| | 63.72 |
| | 396 |
| | 2.90 |
| | 23 |
| | 27.26 |
| | 99 |
| | 19 |
| | 24.26 |
|
| Total | | 90 |
| | 67.25 |
| | 2,278 |
| | 2.99 |
| | 52 |
| | 26.50 |
| | 521 |
| | 100 | % | | 27.27 |
|
| | | | | | | | | | | | | | | | | | | |
| | | 2017 |
| | | Oil | | Natural Gas | | NGL | | Total |
| | | mbbl per day | | $/bbl | | mmcf per day | | $/mcf | | mbbl per day | | $/bbl | | mboe per day | | % | | $/boe |
| Marcellus | | — |
| | — |
| | 804 |
| | 2.45 |
| | — |
| | — |
| | 134 |
| | 24 |
| | 14.67 |
|
| Haynesville | | — |
| | — |
| | 784 |
| | 2.85 |
| | — |
| | — |
| | 131 |
| | 24 |
| | 17.10 |
|
| Eagle Ford | | 59 |
| | 52.34 |
| | 142 |
| | 3.30 |
| | 18 |
| | 22.95 |
| | 100 |
| | 18 |
| | 39.24 |
|
| Powder River Basin | | 6 |
| | 49.97 |
| | 37 |
| | 3.01 |
| | 3 |
| | 27.33 |
| | 15 |
| | 3 |
| | 32.57 |
|
| Mid-Continent | | 8 |
| | 49.24 |
| | 69 |
| | 2.79 |
| | 5 |
| | 22.99 |
| | 25 |
| | 5 |
| | 28.77 |
|
Retained assets(a) | | 73 |
| | 51.78 |
| | 1,836 |
| | 2.71 |
| | 26 |
| | 23.37 |
| | 405 |
| | 74 |
| | 23.07 |
|
Divested assets(b) | | 17 |
| | 47.87 |
| | 570 |
| | 2.92 |
| | 31 |
| | 23.02 |
| | 143 |
| | 26 |
| | 22.34 |
|
| 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 | | — |
| | — |
| | 730 |
| | 1.56 |
| | — |
| | — |
| | 121 |
| | 19 |
| | 9.31 |
|
| Haynesville | | — |
| | — |
| | 681 |
| | 2.31 |
| | — |
| | — |
| | 114 |
| | 18 |
| | 13.87 |
|
| Eagle Ford | | 56 |
| | 42.19 |
| | 140 |
| | 2.61 |
| | 17 |
| | 14.85 |
| | 97 |
| | 15 |
| | 30.97 |
|
| Powder River Basin | | 6 |
| | 39.58 |
| | 37 |
| | 2.36 |
| | 3 |
| | 17.27 |
| | 15 |
| | 3 |
| | 24.78 |
|
| Mid-Continent | | 5 |
| | 42.47 |
| | 39 |
| | 2.27 |
| | 3 |
| | 16.71 |
| | 14 |
| | 2 |
| | 23.55 |
|
Retained assets(a) | | 67 |
| | 41.98 |
| | 1,627 |
| | 2.00 |
| | 23 |
| | 15.26 |
| | 361 |
| | 57 |
| | 17.76 |
|
Divested assets(b) | | 24 |
| | 36.89 |
| | 1,240 |
| | 2.13 |
| | 44 |
| | 14.50 |
| | 274 |
| | 43 |
| | 15.13 |
|
| Total | | 91 |
| | 40.65 |
| | 2,867 |
| | 2.05 |
| | 67 |
| | 14.76 |
| | 635 |
| | 100 | % | | 16.63 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2020 |
| | | Oil | | Natural Gas | | NGL | | Total |
| | | mbbl per day | | $/bbl | | mmcf
per day | | $/mcf | | mbbl per day | | $/bbl | | mboe per day | | % | | $/boe |
| Marcellus | | — | | | — | | | 1,052 | | | 1.64 | | | — | | | — | | | 175 | | | 39 | | | 9.82 | |
| Haynesville | | — | | | — | | | 521 | | | 1.83 | | | — | | | — | | | 87 | | | 20 | | | 10.99 | |
| Eagle Ford | | 50 | | | 39.12 | | | 135 | | | 2.28 | | | 18 | | | 12.56 | | | 91 | | | 20 | | | 27.47 | |
| Brazos Valley | | 36 | | | 37.30 | | | 50 | | | 0.86 | | | 6 | | | 6.02 | | | 50 | | | 11 | | | 28.13 | |
| Powder River Basin | | 13 | | | 36.64 | | | 58 | | | 1.92 | | | 4 | | | 14.94 | | | 26 | | | 6 | | | 24.22 | |
Retained assets(a) | | 99 | | | 38.14 | | | 1,816 | | | 1.73 | | | 28 | | | 11.46 | | | 429 | | | 96 | | | 16.80 | |
Divested assets(b) | | 4 | | | 37.92 | | | 56 | | | 1.87 | | | 3 | | | 12.36 | | | 16 | | | 4 | | | 17.85 | |
| Total | | 103 | | | 38.16 | | | 1,872 | | | 1.73 | | | 31 | | | 11.55 | | | 445 | | | 100 | % | | 16.84 | |
| | | | | | | | | | | | | | | | | | |
| | 2019 |
| | | Oil | | Natural Gas | | NGL | | Total |
| | | mbbl per day | | $/bbl | | mmcf
per day | | $/mcf | | mbbl per day | | $/bbl | | mboe per day | | % | | $/boe |
| Marcellus | | — | | | — | | | 946 | | | 2.48 | | | — | | | — | | | 158 | | | 32 | | | 14.88 | |
| Haynesville | | — | | | — | | | 672 | | | 2.42 | | | — | | | — | | | 112 | | | 23 | | | 14.53 | |
| Eagle Ford | | 58 | | | 61.22 | | | 153 | | | 2.73 | | | 19 | | | 17.04 | | | 102 | | | 21 | | | 41.72 | |
| Brazos Valley | | 33 | | | 59.29 | | | 49 | | | 1.79 | | | 5 | | | 8.04 | | | 47 | | | 10 | | | 44.96 | |
| Powder River Basin | | 19 | | | 54.28 | | | 86 | | | 2.47 | | | 5 | | | 16.63 | | | 38 | | | 8 | | | 34.31 | |
Retained assets(a) | | 110 | | | 59.47 | | | 1,906 | | | 2.46 | | | 29 | | | 15.37 | | | 457 | | | 94 | | | 25.51 | |
Divested assets(b) | | 8 | | | 55.30 | | | 89 | | | 2.09 | | | 5 | | | 17.66 | | | 27 | | | 6 | | | 26.65 | |
| Total | | 118 | | | 59.20 | | | 1,995 | | | 2.45 | | | 34 | | | 15.62 | | | 484 | | | 100 | % | | 25.58 | |
(a) Includes assets retained as of December 31, 2018.2020.
| |
(b) | Divested assets include Barnett, Devonian and certain Mid-Continent assets in 2016, certain Haynesville assets in 2017 and Utica assets in Ohio in 2018. |
(b) Divested assets include Mid-Continent assets in 2020.
Oil, Natural Gas and NGL Sales | | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | change | | 2019 |
| | | ($ in millions) |
| Oil | | $ | 1,427 | | | (44) | % | | $ | 2,543 | |
| Natural gas | | 1,188 | | | (33) | % | | 1,782 | |
| NGL | | 130 | | | (32) | % | | 192 | |
| Oil, natural gas and NGL sales | | $ | 2,745 | | | (39) | % | | $ | 4,517 | |
|
| | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | change | | 2017 | | change | | 2016 |
| | | ($ in millions) |
| Oil | | $ | 2,201 |
| | 32 | % | | $ | 1,668 |
| | 23 | % | | $ | 1,351 |
|
| Natural gas | | 2,486 |
| | 3 | % | | 2,422 |
| | 12 | % | | 2,155 |
|
| NGL | | 502 |
| | 4 | % | | 484 |
| | 34 | % | | 360 |
|
| Oil, natural gas and NGL sales | | $ | 5,189 |
| | 13 | % | | $ | 4,574 |
| | 18 | % | | $ | 3,866 |
|
2018 vs. 2017. The increasedecrease in the price received per boe in 20182020 resulted in an $836 million increasea $1.423 billion decrease in revenues, and decreased sales volumes resulted in a $221$349 million decrease in revenues, for a total net increasedecrease in revenues of $615 million.
2017 vs. 2016. The increase in the price received per boe in 2017 resulted in a $1.250 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.
$1.772 billion. See Note 79 of the notes to our consolidated financial statements included in Item 8 of this report for a complete discussion of oil, natural gas and NGL sales. Oil, Natural Gas and NGL Derivatives | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | 2019 |
| | | ($ in millions) |
| Oil derivatives – realized gains (losses) | | $ | 694 | | | $ | 36 | |
| Oil derivatives – unrealized gains (losses) | | (140) | | | (248) | |
| Total gains (losses) on oil derivatives | | 554 | | | (212) | |
| | | | |
| Natural gas derivatives – realized gains (losses) | | 161 | | | 114 | |
| Natural gas derivatives – unrealized gains (losses) | | (119) | | | 103 | |
| Total gains (losses) on natural gas derivatives | | 42 | | | 217 | |
| Total gains (losses) on oil, natural gas and NGL derivatives | | $ | 596 | | | $ | 5 | |
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| | | ($ in millions) |
| Oil derivatives – realized gains (losses) | | $ | (321 | ) | | $ | 70 |
| | $ | 97 |
|
| Oil derivatives – unrealized gains (losses) | | 445 |
| | (134 | ) | | (318 | ) |
| Total gains (losses) on oil derivatives | | 124 |
| | (64 | ) | | (221 | ) |
| | | | | | | |
| Natural gas derivatives – realized gains (losses) | | 7 |
| | (9 | ) | | 151 |
|
| Natural gas derivatives – unrealized gains (losses) | | (154 | ) | | 489 |
| | (500 | ) |
| Total gains (losses) on natural gas derivatives | | (147 | ) | | 480 |
| | (349 | ) |
| | | | | | | |
| NGL derivatives – realized gains (losses) | | (13 | ) | | (4 | ) | | (8 | ) |
| NGL derivatives – unrealized gains (losses) | | 2 |
| | (1 | ) | | — |
|
| Total gains (losses) on NGL derivatives | | (11 | ) | | (5 | ) | | (8 | ) |
| Total gains (losses) on oil, natural gas and NGL derivatives | | $ | (34 | ) | | $ | 411 |
| | $ | (578 | ) |
See Note 1314 of the notes to our consolidated financial statements included in Item 8 of this report for a complete discussion of our derivative activity.
Marketing Revenues and Expenses
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | change | | 2019 |
| | | ($ in millions) |
| Marketing revenues | | $ | 1,869 | | | (53) | % | | $ | 3,967 | |
| Marketing expenses | | 1,889 | | | (53) | % | | 4,003 | |
| Marketing margin | | $ | (20) | | | 44 | % | | $ | (36) | |
|
| | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | change | | 2017 | | change | | 2016 |
| | | ($ in millions) |
| Marketing revenues | | $ | 5,076 |
| | 13 | % | | $ | 4,511 |
| | (2 | )% | | $ | 4,584 |
|
| Marketing expenses | | 5,158 |
| | 12 | % | | 4,598 |
| | (4 | )% | | 4,778 |
|
| Marketing gross margin | | $ | (82 | ) | | 6 | % | | $ | (87 | ) | | 55 | % | | $ | (194 | ) |
2018 vs. 2017. Marketing revenues and expenses increased in 2018 primarily as a result of increased oil, natural gas and NGL prices received in our marketing operations. Gross margin was negatively impacted by downstream pipeline delivery commitments.
2017 vs. 2016. Marketing revenues and expenses decreased in 20172020 primarily as a result of decreased oil, natural gas and NGL prices received in our marketing operations. Grossoperations and less volumes being marketed. Marketing margin increased primarily as a resultdue to improved margins related to non-equity transactions.
Other Revenue
| | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | 2019 |
| | | ($ in millions) |
| Other revenue | | $ | 56 | | | $ | 63 | |
Other revenue primarily relates to the amortization of deferred VPP revenue. In 2020, we sold the reversal of cumulative unrealized gains associated with the termination of a supply contract derivative in 2016 as well as the sale of a significant portion of our gathering and compression assets in 2016.
Oil, Natural Gas and NGL Production Expenses |
| | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | change | | 2017 | | change | | 2016 |
| | | ($ in millions) |
| Oil, natural gas and NGL production expenses | | | | | | | | | | |
| Marcellus | | $ | 34 |
| | 21 | % | | $ | 28 |
| | — | % | | $ | 28 |
|
| Haynesville | | 57 |
| | 8 | % | | 53 |
| | 33 | % | | 40 |
|
| Eagle Ford | | 183 |
| | (3 | )% | | 188 |
| | 27 | % | | 148 |
|
| Powder River Basin | | 49 |
| | 63 | % | | 30 |
| | 36 | % | | 22 |
|
| Mid-Continent | | 102 |
| | (8 | )% | | 111 |
| | 21 | % | | 92 |
|
Retained Assets(a) | | 425 |
| | 4 | % | | 410 |
| | 24 | % | | 330 |
|
| Divested Assets | | 49 |
| | (54 | )% | | 107 |
| | (67 | )% | | 325 |
|
| Total | | 474 |
| | (8 | )% | | 517 |
| | (21 | )% | | 655 |
|
| Ad valorem tax | | 65 |
| | 44 | % | | 45 |
| | (18 | )% | | 55 |
|
| Total oil, natural gas and NGL production expenses | | $ | 539 |
| | (4 | )% | | $ | 562 |
| | (21 | )% | | $ | 710 |
|
| | | ($ per boe) |
| Oil, natural gas and NGL production expenses | | | | | | | | | | |
| Marcellus | | $ | 0.68 |
| | 17 | % | | $ | 0.58 |
| | (8 | )% | | $ | 0.63 |
|
| Haynesville | | $ | 1.20 |
| | 9 | % | | $ | 1.10 |
| | 13 | % | | $ | 0.97 |
|
| Eagle Ford | | $ | 4.88 |
| | (5 | )% | | $ | 5.15 |
| | 23 | % | | $ | 4.18 |
|
| Powder River Basin | | $ | 5.36 |
| | (3 | )% | | $ | 5.53 |
| | 34 | % | | $ | 4.14 |
|
| Mid-Continent | | $ | 11.26 |
| | (7 | )% | | $ | 12.12 |
| | (30 | )% | | $ | 17.31 |
|
Retained Assets(a) | | $ | 2.76 |
| | (1 | )% | | $ | 2.78 |
| | 11 | % | | $ | 2.50 |
|
| Divested Assets | | $ | 1.34 |
| | (34 | )% | | $ | 2.04 |
| | (37 | )% | | $ | 3.23 |
|
| Total | | $ | 2.50 |
| | (3 | )% | | $ | 2.59 |
| | (8 | )% | | $ | 2.81 |
|
| Ad valorem tax | | $ | 0.34 |
| | 55 | % | | $ | 0.22 |
| | (8 | )% | | $ | 0.24 |
|
| Total oil, natural gas and NGL production expenses per boe | | $ | 2.84 |
| | 1 | % | | $ | 2.81 |
| | (8 | )% | | $ | 3.05 |
|
(a) Includes assets retained as of December 31, 2018.
2018 vs. 2017. The absolute increase for retained properties was the result of increased production volumes related to our retained assets primarily in the Powder River Basin. The total per unit increase was the result of increased ad valorem tax primarily due to higher prices received for our oil, natural gas and NGL production. Production expenses in 2018 included approximately $15 million associated with VPP production volumes.
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 $44 million, respectively, associated with VPP production volumes.
We anticipate a continued decrease in production expenses associated with VPP production volumes as the contractually scheduled volumes under our remaining VPP agreement decrease and operating efficiencies generally improve.
Oil, Natural Gas, and NGL Gathering, Processing and Transportation Expenses
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| | | ($ in millions, except per unit) |
| Oil, natural gas and NGL gathering, processing and transportation expenses | | $ | 1,398 |
| | $ | 1,471 |
| | $ | 1,855 |
|
| Oil ($ per bbl) | | $ | 4.30 |
| | $ | 3.94 |
| | $ | 3.61 |
|
| Natural gas ($ per mcf) | | $ | 1.32 |
| | $ | 1.34 |
| | $ | 1.47 |
|
| NGL ($ per bbl) | | $ | 8.37 |
| | $ | 7.88 |
| | $ | 7.83 |
|
| Total ($ per boe) | | $ | 7.35 |
| | $ | 7.36 |
| | $ | 7.98 |
|
2018 vs. 2017. The absolute and per unit decrease for oil and natural gas gathering, processing and transportation expenses was primarily due to lower gathering fees associated with restructured midstream contracts, lower volume commitments on downstream pipelines and certain 2017 and 2018 divestitures.
2017 vs. 2016. The absolute decrease was primarily due to lower volumes. The per unit decrease was due to contract improvements and asset sales.
|
| | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | change | | 2017 | | change | | 2016 |
| | | ($ in millions, except per unit) |
| Production taxes | | $ | 124 |
| | 39 | % | | $ | 89 |
| | 20 | % | | $ | 74 |
|
| Production taxes per boe | | $ | 0.65 |
| | 48 | % | | $ | 0.44 |
| | 38 | % | | $ | 0.32 |
|
The absolute and per unit increase in production taxes for each year was primarily due to higher prices received for our oil, natural gas and NGL production, offset by lower production volumes.
General and Administrative Expenses |
| | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | change | | 2017 | | change | | 2016 |
| | | ($ in millions, except per unit) |
| Gross overhead | | $ | 714 |
| | (10 | )% | | $ | 791 |
| | (12 | )% | | $ | 900 |
|
| Allocated to production expenses | | (141 | ) | | (20 | )% | | (177 | ) | | (15 | )% | | (209 | ) |
| Allocated to marketing | | (20 | ) | | (31 | )% | | (29 | ) | | (47 | )% | | (55 | ) |
| Capitalized general and administrative expenses | | (119 | ) | | (13 | )% | | (137 | ) | | (8 | )% | | (149 | ) |
| Reimbursed from third parties | | (154 | ) | | (17 | )% | | (186 | ) | | (25 | )% | | (247 | ) |
| General and administrative expenses, net | | $ | 280 |
| | 7 | % | | $ | 262 |
| | 9 | % | | $ | 240 |
|
| | | | | | | | | | | |
| General and administrative expenses, net per boe | | $ | 1.47 |
| | 12 | % | | $ | 1.31 |
| | 27 | % | | $ | 1.03 |
|
2018 vs. 2017. Gross overhead decreased primarily due to our reduction in workforce. The absolute and per unit net expense increase was primarily due to less overhead allocated to production expenses, marketing expenses and capitalized general and administrative costs, as well as lower producing overhead reimbursements from third party working interest owners, due to certain divestitures in 2017 and 2018.
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 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.
Restructuring and Other Termination Costs. On January 30, 2018, we underwent a reduction in workforce impacting approximately 13% of employees across all functions, primarily on our Oklahoma City campus. In connection withextinguished the reduction, we incurred a total charge of approximately $38 million in 2018 for one-time termination benefits. The charge consisted of $33 million in salary and severance expense and $5 million in other termination benefits. In 2016, we recognized $6 million of chargesliability related to a reduction of workforce in connection with the restructuring of our compressor manufacturing subsidiary and the reductions of workforce resulting from the conveyance of our interests in the Barnett Shale and Devonian Shale operating areas.production volume delivery obligation. See Note 197 of the notes to our consolidated financial statements included in Item 8 of this report for a discussion of our restructuring and termination costs.Provision for Legal Contingencies, Net |
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| | | ($ in millions) |
| Provision for legal contingencies, net | | $ | 26 |
| | $ | (38 | ) | | $ | 123 |
|
The 2018 and 2016 amounts consist of accruals for loss contingencies primarily related to royalty claims. The 2017 amount consists of the recovery of a legal settlement, partially offset by accruals for loss contingencies primarily related to royalty claims. See Note 4 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of royalty claims.Oil, Natural Gas and NGL Depreciation, Depletion and Amortization |
| | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | change | | 2017 | | change | | 2016 |
| | | ($ in millions, except per unit) |
| Oil, natural gas and NGL depreciation, depletion and amortization | | $ | 1,145 |
| | 15 | % | | $ | 995 |
| | (10 | )% | | $ | 1,107 |
|
| Oil, natural gas and NGL depreciation, depletion and amortization per boe | | $ | 6.02 |
| | 21 | % | | $ | 4.98 |
| | 5 | % | | $ | 4.76 |
|
2018 vs. 2017. The absolute and per unit increase in 2018 is primarily the result of a higher depletion rate per boe. The depletion rate per boe is a function of capitalized costs, future development costs, and the related underlying reserves in the periods presented. The increase in depletion rate per boe primarily reflects a downward revision in proved reserve estimates in the fourth quarter of 2017 due to an updated development plan in the Eagle Ford aligning up-spacing, our activity schedule and well performance.
2017 vs. 2016. The absolute decrease was primarily the result of the sale of Barnett and certain Mid-Continent assets in 2016 and the sale of certain Haynesville assets in 2017.
Loss on Sale of Oil and Natural Gas Properties
In 2018, we sold all of our net acres in the Utica Shale operating area located in Ohio along with related property and equipment (collectively, the “Designated Properties”) for net proceeds of $1.868 billion to Encino. The sale of our Designated Properties to Encino involved a significant change in proved reserves under SEC rules for full cost companies and significantly altered the relationship between costs and proved reserves and therefore resulted in the recognition of loss of approximately $578 million. See Note 14 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of the transaction. |
| | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | change | | 2017 | | change | | 2016 |
| | | ($ in millions) |
| Impairments | | $ | 53 |
| | 960 | % | | $ | 5 |
| | (100 | )% | | $ | 3,025 |
|
In 2018, we recorded a $45 million impairment related to 890 compressors and $8 million for other property and equipment for the difference between the fair value and carrying value. In 2016, we recognized an impairment in the
carrying value of our oil and natural gas properties of $2.564 billion and impairments totaling $426 million related to other fixed assets sold in our Barnett Shale and Devonian Shale divestitures. See Note 17 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our impairments.VPPs.Other Operating ExpenseGains on Sales of Assets |
| | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | change | | 2017 | | change | | 2016 |
| | | ($ in millions) |
| Other operating expense | | $ | 10 |
| | (98 | )% | | $ | 413 |
| | 13 | % | | $ | 365 |
|
| | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | 2019 |
| | | ($ in millions) |
| Gains on sales of assets | | $ | 30 | | | $ | 43 | |
The 2017In 2020, we filed a notice with the Bankruptcy Court that we reached an agreement with Tapstone Energy to sell our Mid-Continent asset in a transaction under Section 363 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 2016 amounts consistthe 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 discrete costs incurred to terminate various gatheringa gain of approximately $27 million.
In 2019, we received proceeds of approximately $136 million, net of post-closing adjustments, and transportation agreements, including those associated withrecognized a net gain of approximately $43 million, primarily for the sale of non-core oil and natural gas asset divestitures. properties.
See Note 3 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of these transactions.
Oil, Natural Gas and NGL Production Expenses | | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | change | | 2019 |
| | ($ in millions) |
| Oil, natural gas and NGL production expenses | | | | | | |
| Marcellus | | $ | 32 | | | — | % | | $ | 32 | |
| Haynesville | | 36 | | | (12) | % | | 41 | |
| Eagle Ford | | 112 | | | (38) | % | | 180 | |
| Brazos Valley | | 89 | | | (8) | % | | 97 | |
| Powder River Basin | | 42 | | | (42) | % | | 72 | |
Retained Assets(a) | | 311 | | | (26) | % | | 422 | |
Divested Assets(b) | | 62 | | | (37) | % | | 98 | |
| Total oil, natural gas and NGL production expenses | | $ | 373 | | | (28) | % | | $ | 520 | |
| | | | | | |
| | ($ per boe) |
| Oil, natural gas and NGL production expenses | | | | | | |
| Marcellus | | $ | 0.50 | | | (11) | % | | $ | 0.56 | |
| Haynesville | | $ | 1.14 | | | 14 | % | | $ | 1.00 | |
| Eagle Ford | | $ | 3.37 | | | (30) | % | | $ | 4.83 | |
| Brazos Valley | | $ | 4.86 | | | (14) | % | | $ | 5.66 | |
| Powder River Basin | | $ | 4.41 | | | (15) | % | | $ | 5.17 | |
Retained Assets(a) | | $ | 1.98 | | | (22) | % | | $ | 2.53 | |
Divested Assets(b) | | $ | 10.52 | | | 5 | % | | $ | 9.99 | |
| Total oil, natural gas and NGL production expenses per boe | | $ | 2.29 | | | (22) | % | | $ | 2.94 | |
(a) Includes assets retained as of December 31, 2020.
(b) Divested assets include our Mid-Continent assets in 2020.
The absolute and per unit decrease was primarily the result of production curtailments and reduced workover activity in our liquids-rich operating areas due to lower commodity prices.
Oil, Natural Gas, and NGL Gathering, Processing and Transportation Expenses
| | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | 2019 |
| | ($ in millions, except per unit) |
| Oil, natural gas and NGL gathering, processing and transportation expenses | | $ | 1,082 | | | $ | 1,082 | |
| Oil ($ per bbl) | | $ | 4.00 | | | $ | 3.20 | |
| Natural gas ($ per mcf) | | $ | 1.28 | | | $ | 1.21 | |
| NGL ($ per bbl) | | $ | 4.90 | | | $ | 5.32 | |
| Total ($ per boe) | | $ | 6.64 | | | $ | 6.13 | |
The per unit increase for oil and natural gas gathering, processing and transportation expenses was primarily due to the increase in transportation expense related to oil deficiency fees for our Eagle Ford operating area and production curtailments.
Severance and Ad Valorem Taxes | | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | change | | 2019 |
| | | ($ in millions, except per unit) |
| Severance taxes | | $ | 87 | | | (40) | % | | $ | 144 | |
| Ad valorem taxes | | 62 | | | (23) | % | | 80 | |
| Severance and ad valorem taxes | | $ | 149 | | | (33) | % | | $ | 224 | |
| | | | | | |
| Severance taxes per boe | | $ | 0.53 | | | (35) | % | | $ | 0.81 | |
| Ad valorem taxes per boe | | 0.38 | | | (17) | % | | 0.46 | |
| Severance and ad valorem taxes per boe | | $ | 0.91 | | | (28) | % | | $ | 1.27 | |
The decrease in severance taxes was primarily due to the reduction in value as a result of decreased prices in areas where tax is calculated on net revenue instead of production. The decrease in ad valorem taxes is primarily due to lower assessed property values for 2020 compared to 2019.
Exploration Expense
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | change | | 2019 |
| | | ($ in millions) |
| Impairments of unproved properties | | $ | 411 | | | 1,184 | % | | $ | 32 | |
| Dry hole expense | | 7 | | | (72) | % | | 25 | |
| Geological and geophysical expense and other | | 9 | | | (67) | % | | 27 | |
| Exploration expense | | $ | 427 | | | 408 | % | | $ | 84 | |
The increase in exploration expense was the result of non-cash impairment charges of $411 million in unproved properties, primarily in our liquids-rich operating areas of $266 million. Our development plans contained significant reductions in future capital assigned to the liquids-rich plays resulting in a lack of intent and ability to develop unproved properties in the next five years. Additionally, a non-cash impairment charge of $144 million with respect to our Haynesville assets was recorded due to unfavorable economic conditions and capital constraints.
General and Administrative Expenses | | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | change | | 2019 |
| | | ($ in millions, except per unit) |
| Gross overhead | | $ | 578 | | | (15) | % | | $ | 682 | |
| Allocated to production expenses | | (186) | | | (12) | % | | (212) | |
| Allocated to marketing expenses | | (11) | | | (21) | % | | (14) | |
| Allocated to exploration expenses | | — | | | (100) | % | | (11) | |
| Allocated to sand mine expense | | (3) | | | (57) | % | | (7) | |
| Capitalized general and administrative expenses | | (71) | | | (3) | % | | (73) | |
| Reimbursed from third parties | | (40) | | | (20) | % | | (50) | |
| General and administrative expenses, net | | $ | 267 | | | (15) | % | | $ | 315 | |
| | | | | | |
| General and administrative expenses, net per boe | | $ | 1.63 | | | (8) | % | | $ | 1.78 | |
Gross overhead decreased primarily due to our reduction in workforce in 2020.
Separation and Other Termination Costs
In 2020 and 2019, we incurred charges of approximately $44 million and $12 million, respectively, related to one-time termination benefits for certain employees.
Provision for Legal Contingencies | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | 2019 |
| | | ($ in millions) |
| Provision for legal contingencies | | $ | 27 | | | $ | 19 | |
The 2020 and 2019 amounts consist of accruals for loss contingencies related to royalty claims.
Depreciation, Depletion and Amortization | | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | change | | 2019 |
| | | ($ in millions, except per unit) |
| Depreciation, depletion and amortization | | $ | 1,097 | | | (52) | % | | $ | 2,264 | |
| Depreciation, depletion and amortization per boe | | $ | 6.72 | | | (48) | % | | $ | 12.82 | |
The absolute and per unit decreases in 2020 are primarily the result of an $8.446 billion impairment recognized in 2020 on our proved oil and natural gas properties due to lower forecasted commodity prices, which reduced the depletable carrying value.
Impairments | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | 2019 |
| | | ($ in millions) |
| Impairments of oil and gas properties | | $ | 8,446 | | | $ | 8 | |
| Impairments of other fixed assets | | 89 | | | 3 | |
| Total impairments | | $ | 8,535 | | | $ | 11 | |
Oil and natural gas properties. In 2020, we recorded impairments of proved oil and natural gas properties related to Eagle Ford, Brazos Valley, Powder River Basin, Mid-Continent and other non-core assets, all of which were due to lower forecasted commodity prices.
Other fixed assets. In 2020, we recorded a $76 million impairment of our sand mine assets that support our Brazos Valley operating area for the difference between the fair value and carrying value of the assets as well as a $13 million impairment of compressor inventory due to a lack of a current market for compressors.
See Note 18 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our other operating expense.impairments. Other Operating Expense | | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | change | | 2019 |
| | | ($ in millions) |
| Other operating expense | | $ | 109 | | | 18 | % | | $ | 92 | |
In 2020, 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.
In 2019, we recorded approximately $37 million of costs related to our acquisition of WildHorse which consisted of consulting fees, financial advisory fees, legal fees and travel and lodging expenses. In addition, we recorded approximately $38 million of severance expense as a result of the acquisition of WildHorse. A majority of the WildHorse executives and employees were terminated at the time of acquisition. These executives and employees were entitled to severance benefits in accordance with existing employment agreements.
Interest Expense
| | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | | 2020 | | 2019 |
| | | ($ in millions, except per unit) |
| Interest expense on DIP credit facility | | $ | 3 | | | $ | — | |
| Interest expense on senior notes | | 239 | | | 578 | |
| Interest expense on term loan | | 71 | | | 4 | |
| Interest expense on pre-petition revolving credit facility | | 89 | | | 96 | |
| Amortization of discount, issuance costs and other | | 31 | | | 3 | |
| Amortization of premium | | (87) | | | (5) | |
| Realized gains on interest rate derivatives | | — | | | (5) | |
| Unrealized losses on interest rate derivatives | | — | | | 4 | |
| Capitalized interest | | (15) | | | (24) | |
| Total interest expense | | $ | 331 | | | $ | 651 | |
| | | | |
| Interest expense per boe | | $ | 2.03 | | | $ | 3.68 | |
| | | | |
| Average pre-petition revolving credit facility | | $ | 1,887 | | | $ | 1,934 | |
| Average DIP credit facility | | $ | 1 | | | $ | — | |
| Average senior notes borrowings | | n/a | | $ | 7,857 | |
| Average term loan borrowings | | n/a | | $ | 37 | |
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| | | ($ in millions) |
| Interest expense on senior notes | | $ | 591 |
| | $ | 551 |
| | $ | 588 |
|
| Interest expense on term loan | | 86 |
| | 127 |
| | 46 |
|
| Amortization of loan discount, issuance costs and other | | 24 |
| | 40 |
| | 33 |
|
| Amortization of premium | | (88 | ) | | (138 | ) | | (165 | ) |
| Interest expense on revolving credit facility | | 37 |
| | 39 |
| | 35 |
|
| Realized gains on interest rate derivatives | | (3 | ) | | (3 | ) | | (11 | ) |
| Unrealized losses on interest rate derivatives | | 2 |
| | 4 |
| | 21 |
|
| Capitalized interest | | (162 | ) | | (194 | ) | | (251 | ) |
| Total interest expense | | $ | 487 |
| | $ | 426 |
| | $ | 296 |
|
| | | | | | | |
Interest expense per boe(a) | | $ | 2.55 |
| | $ | 2.11 |
| | $ | 1.18 |
|
| | | | | | | |
| Average senior notes borrowings | | $ | 8,160 |
| | $ | 7,714 |
| | $ | 8,749 |
|
| Average credit facilities borrowings | | $ | 505 |
| | $ | 443 |
| | $ | 195 |
|
| Average term loan borrowings | | $ | 911 |
| | $ | 1,446 |
| | $ | 537 |
|
| |
(a) | Includes the effects of realized (gains) losses from interest rate derivatives, excludes the effects of unrealized (gains) losses from interest rate derivatives and is shown net of amounts capitalized. |
The decrease in capitalized interest expense on senior notes is a result of lower average balances of unproved oil and natural gas properties, the primary assetdue to our Chapter 11 proceedings. We have not paid or recognized interest expense on which interest is capitalized. any outstanding debt that was reclassified to liabilities subject to compromise.
See Note 35 of the notes to our consolidated financial statements included in Item 8 of this report for a discussion of our debt refinancing.instruments. Gains (Losses) on Investments
FTS International Inc. (NYSE: FTSI). In 2018, FTS International, Inc. (NYSE: FTSI)(FTSI) completed an initial public offering. Due to the offering, the ownership percentage of our equity method investment in FTSI decreased from approximately 29% to 24% and resulted in a gain of $78 million. In addition, we sold approximately 4.3 million shares of FTSI in the offering for net proceeds of approximately $74 million and recognized a gain of $61 million decreasing our ownership percentage to approximately 20%. We continue to hold approximately 22.0 million shares
In 2019, the hydraulic fracturing industry experienced challenging operating conditions resulting in the publicly traded company. current fair value of our investment in FTSI falling below book value of $65 million and remaining below that value 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 2016,2020, the hydraulic fracturing industry experienced challenging operating conditions resulting in FTSI filing for Chapter 11 bankruptcy, and we recognized an other-than-temporary impairment of our Sundrop Fuels Inc. (Sundrop)entire investment of $119$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.
JWH Midstream LLC (JWH). In 2019, 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 2019, 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, therefore, we impaired the full value of the investment and recognized approximately $24 million of impairment expense in 2019.
See Note 1617 of the notes to our consolidated financial statements included in Item 8 of this report for a discussion of our investments.
Gains (Losses) on Purchases or Exchanges of Debt. In 2018,2020, we used the net proceeds from the issuance of our 2024 and 2026 senior notes, together with cash on hand and borrowings under the Chesapeake revolving credit facility, to repay in full $1.233 billion of borrowings under our secured term loan due 2021 for $1.285 billion, which included a $52repurchased approximately $160 million make-whole premium. We recorded a loss of approximately $65 million associated with the repayment of the term loan, including the make-whole premium and the write-off of $13 million of associated deferred charges. Also in 2018, we used the proceeds from the sale of our Utica assets in Ohio to redeem all of the $1.416 billion aggregate principal amount outstanding of our 8.00% Senior Secured Second Lien Notes due 2022 which included a $60 million call premium. We recorded a gain of approximately $331 million associated with the redemption, including the realization of the remaining $391 million difference in principal and book value due to troubled debt restructuring accounting in 2015, offset by the make-whole premium of $60 million. Additionally, we recorded a loss of $3 million associated with certain deferred charges related to the Chesapeake revolving credit facility prior to its amendment and restatement.
In 2017, we retired $2.389 billion principal amount of our outstanding senior notes senior secured second lien notesfor $95 million and contingent convertible notes through purchases in the open market, tender offers, redemptions or repayment upon maturity for $2.592 billion, which included the maturity of our 6.25% Euro-denominated Senior Notes due 2017 and the corresponding cross currency swap. We recorded an aggregate gain of approximately $233 million associated with the repurchases and tender offers.
$65 million. 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. Additionally,2019, we privately negotiated an exchangeexchanges of approximately $577$507 million principal amount of our outstanding senior notes for 235,563,519 shares of common stock and contingent$186 million principal amount of our outstanding convertible senior notes for 109,351,70773,389,094 shares of common shares.stock. We recorded an aggregate net gain of approximately $236$64 million associated with the repurchases and exchanges. Additionally, in various transactions throughout 2019, we repurchased approximately $698 million principal amount of the BVL Senior Notes, recognizing a net $10 million gain on the transactions.
Other Income. In 2018,2019, we extinguishedrecognized $9 million of other income from the sale of seismic data licenses to third parties. The remaining amount in 2019 was from other non-operating miscellaneous income.
Reorganization Items, Net
| | | | | | | | |
| | Years Ended December 31, 2020 |
| | ($ in millions) |
| Provision for allowed claims | | $ | (879) | |
| Write off of unamortized debt premiums (discounts) | | 518 | |
| Write off of unamortized debt issuance costs | | (61) | |
| Debt and equity financing fees | | (145) | |
| Loss on divested assets | | (128) | |
| Legal and professional fees | | (113) | |
| Gain on settlement of pre-petition accounts payable | | 15 | |
| Loss on settlement of pre-petition revenues payable | | (3) | |
| Reorganization items, net | | $ | (796) | |
We have incurred and will continue to incur significant expenses, gains and losses associated with our
obligation to convey future ORRIsreorganization, primarily the 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
CHK Utica L.L.C. investors and recognized a $61 million gain included in other income on our consolidated statement of operations. See Note 5 ofChapter 11 Filings for the notes to our consolidated financial statements included in Item 8 of this report for a discussion of this transaction.reorganization process. Income Tax Expense (Benefit). We recorded an income tax benefit of $19 million and $331 million in 2020 and 2019, respectively. The income tax benefit for 2020 consists of a reversal of the income tax expense recorded in 2019 of $10 million relating to Texas no longer being in 2018,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. The income tax benefit for 2019 consists mainly of a $314 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 $314 million resulting from the business combination accounting for WildHorse. Other material items included in the 2019 income tax benefit include a benefit for the reversal of a liability for unrecognized tax benefits of $32 million partially offset by an expense of $10 million associated with the aforementioned deferred tax position in Texas and a current state income tax expense of $2 million in 2017 and an income tax benefit of $190 million in 2016. Our effective tax rate can fluctuate as a result of various items, including the impact of state income taxes, permanent differences, tax law changes and adjustments to the valuation allowance.$6 million. See Note 810 of the notes to our consolidated financial statements included in Item 8 of this report for a discussion of income tax expense (benefit).
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 consider to be most significant to our financial statements are discussed below. Our management has discussed each critical accounting estimate with the Audit Committee of our Board of Directors.
OilBankruptcy Proceedings. We have applied Accounting Standards Codification (ASC) 852, Reorganizations (“ASC 852”) in preparing our consolidated financial statements. ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 Cases, distinguish transactions and Natural Gas Properties. We follow the full cost method of accounting under which all costsevents that are directly associated with property acquisition, explorationthe reorganization from the ongoing operations of the business. Accordingly, certain revenues, expenses, realized gains and development activitieslosses and provisions for losses that are capitalized.
Underrealized or incurred in the full cost method, capitalizedbankruptcy proceedings, including losses related to executory contracts that were approved for rejection by the Bankruptcy Court, and unamortized deferred financing costs, premiums and discount associated with debt classified as liabilities subject to compromise, are amortizedrecorded in reorganization items, net on a composite unit-of-production method based on proved oil and natural gas reserves. If we maintain the same levelour accompanying consolidated statements of production year over year, the depreciation, depletion and amortization expenseoperations. In addition, pre-petition obligations that 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 prescribedimpacted by the SECbankruptcy reorganization process have been classified on a quarterly basis. This quarterly review is referred toour consolidated balance sheets as a ceiling test.
Two primary factors impacting this test are reserve estimates and the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended December 31, 2018. Downward revisions2020 as liabilities subject to estimates of oil and natural gas reserves and/or unfavorable prices can have a material impact oncompromise. These liabilities are reported at the present value of estimated future net revenues. Any excess ofamounts we anticipate will be allowed by the net book value, less deferred income taxes, is generally written off as an expense.Bankruptcy Court, even if they may be settled for lesser amounts. See Oil and Natural Gas Properties in Note 12 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.more information.
Oil and Natural Gas Reserves. 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 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 this report for further information.
Derivatives. We use commodity priceImpairments. Long-lived assets used in operations, including proved oil 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 contractsproperties, are reflected in oil, natural gas and NGL revenues and results of interest rate derivative contracts are reflected in interest expense.
Due to the volatility of oil, natural gas and NGL prices and, to a lesser extent, interest rates and foreign exchange rates, our financial condition and results of operations may be significantly impacted byassessed 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 the marketlowest 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 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 our derivative instruments. Asthe asset group, the carrying value is written down to estimated fair value by discounting using a weighted average cost of December 31, 2018 and 2017, the fair valuescapital. Because there usually is a lack of our derivatives were netquoted market prices for long-lived assets, of $282 million and net liabilities of $35 million, respectively.
One of the primary factors that can have an impact on our results of operations is the method used to value our derivatives. We have established 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 toimpaired assets is assessed by management using the risk that counterparties will be unable to meet their obligations. This non-performance risk is consideredincome approach. Level 3 inputs associated with the calculation of discounted cash flows used in the valuationimpairment analysis include our estimate of our derivative instruments, but to date has not had a material impact on the valuesfuture crude oil and natural gas prices, production costs, development expenditures, anticipated production 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 conditionsproved reserves and other factors.relevant data. Additionally, in accordance with accounting guidancewe utilize NYMEX strip pricing, adjusted for derivatives and hedging,differentials, to value 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.reserves.
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 instruments and the transactions being hedged, both at inception and on an ongoing basis. This correlation is complicated since energy commodity prices, the primary risk we hedge, have quality and location differences that can be difficult to hedge effectively. The factors underlying our estimates of fair value and our assessment of correlation of our derivative instruments are impacted by actual results and changes in conditions that affect these factors, many of which are beyond our control.
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 deferred tax assets and liabilities for temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements. Deferred tax assets for NOL carryforwards and tax creditdisallowed business interest carryforwards have also been recognized. We routinely assess the realizability of our deferred tax assets and reduce such assets by a valuation allowance if it is more likely than not that all or some portion of the deferred tax assets will not be realized. In assessing the need for additional valuation allowances 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:
•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 if deferred tax assets are not more likely than not to be realized. As of December 31, 2018 and 2017, we had deferred tax assets totaling $3.252 billion and $2.826 billion upon which we had a valuation allowance of $2.433 billion and $2.674 billion, respectively.
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 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. Guidance is also provided regarding de-recognition, classification and disclosure of these uncertain tax positions. If a tax position does not meet or exceed the more likely than not threshold then no benefit can be recorded. We accrue 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 810 of the notes to our consolidated financial statements included in Item 8 of this report. Disclosures About EffectsContingencies. We are subject to various legal proceedings, claims, and liabilities that arise in the ordinary course of Transactions with Related Parties
Our equity method investeesbusiness. Except for contingencies acquired in a business combination, which are considered related parties. See Note 9recorded 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 amount within the range is a better estimate than any other, the 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 for further discussionlitigation-related liabilities are based on the facts and circumstances of transactionsthe individual case and on information currently available to us. The extent of information available varies based on the status of the litigation and our evaluation of the claim and legal arguments. In future periods, a number of factors 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 process, we evaluate the available information and may consult with third-party legal counsel to determine whether liability accruals should be established or adjusted.
ITEM 7A.Quantitative and Qualitative Disclosures About Market Risk
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ITEM 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 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, natural gas and NGL 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 1314 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of the fair value measurements associated with our derivatives.
As of For the year ended December 31, 2018, our2020, oil, natural gas, and NGL revenue, excluding any effect of our derivative instruments, consisted of the following types of instruments:
Swaps: We receive a fixed pricewere $1.4 billion, $1.2 billion, and pay a floating market price to the counterparty for the hedged commodity. In exchange for higher fixed prices$130 million, respectively. Based on certain of our swap trades, we may sell call options and call swaptions.
Options: We sell, and occasionally buy, call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, we pay the counterparty the excess on sold call options, and we receive the excess on bought call options. If the market price settles below the fixed price of the call option, no payment is due from either party.
Call Swaptions: We sell call swaptions to counterparties in exchange for a premium that allow the counterparty, on a specific date, to extend an existing fixed-price swap for a certain period of time
Collars: These instruments contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the put and the call strike prices, no payments are due from either party. Three-way collars include the sale by us of an additional put option in exchange for a more favorable strike price on the call option. This eliminates the counterparty’s downside exposure below the second put option strike price.
Basis Protection Swaps: These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point. We receive the fixed price differential and pay the floating market price differential to the counterparty for the hedged commodity.
As of December 31, 2018, we had the following open oil and natural gas derivative instruments:
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| | | | | Weighted Average Price | | Fair Value |
| | | Volume | | Fixed | | Call | | Put | | Differential | | Asset
(Liability) |
| | | (mmbbl) | | ($ per bbl) | | ($ in millions) |
| Oil: | | | | | | | | | | | | |
| Swaps: | | | | | | | | | | | | |
| Short-term | | 10 |
| | $ | 58.97 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 117 |
|
| Long-term | | 2 |
| | $ | 68.14 |
| | $ | — |
| | $ | — |
| | $ | — |
| | 40 |
|
| Collars: | | | | | | | | | | | | |
| Short-term | | 6 |
| | $ | — |
| | $ | 67.75 |
| | $ | 58.00 |
| | $ | — |
| | 68 |
|
| Long-term | | 2 |
| | $ | — |
| | $ | 83.25 |
| | $ | 65.00 |
| | $ | — |
| | 30 |
|
| Basis Protection Swaps: | | | | | | | | | | | | |
| Short-term | | 7 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 6.01 |
| | 5 |
|
| Total Oil | | 260 |
|
| | | (bcf) | | ($ per mcf) | |
|
| Natural Gas: | | | | | | | | | | | | |
| Swaps: | | | | | | | | | | | | |
| Short-term | | 447 |
| | $ | 2.87 |
| | $ | — |
| | $ | — |
| | $ | — |
| | 11 |
|
| Long-term | | 176 |
| | $ | 2.75 |
| | $ | — |
| | $ | — |
| | $ | — |
| | 15 |
|
| Three-Way Collars: | | | | | | | | | | | | |
| Short-term | | 88 |
| | $ | — |
| | $ | 3.10 |
| | $ 2.50/2.80 |
| | $ | — |
| | 1 |
|
| Collars: | | | | | | | | | | | | |
| Short-term | | 55 |
| | $ | — |
| | $ | 3.02 |
| | $ | 2.75 |
| | $ | — |
| | (3 | ) |
| Call Options (sold): | | | | | | | | | | | | |
| Short-term | | 22 |
| | $ | — |
| | $ | 12.00 |
| | $ | — |
| | $ | — |
| | — |
|
| Long-term | | 22 |
| | $ | — |
| | $ | 12.00 |
| | $ | — |
| | $ | — |
| | — |
|
| Call Swaptions: | | | | | | | | | | | | |
| Long-term | | 106 |
| | $ | 2.77 |
| | $ | — |
| | $ | — |
| | $ | — |
| | (9 | ) |
| Basis Protection Swaps: | | | | | | | | | | | | |
| Short-term | | 50 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (0.56 | ) | | — |
|
| Total Natural Gas | | 15 |
|
| Total Commodities | | 275 |
|
| Contingent Consideration: | | | | | | | | | | |
| Utica Divestiture: | | | | | | | | | | | | |
| Short-term | | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | 7 |
|
| Total Derivative Asset | | $ | 282 |
|
In addition to the open derivative positions disclosed above, as of December 31, 2018, we had $56 million of net derivative losses related to settled contracts for future periods that will be recorded within2020 production, oil, natural gas, and NGL revenues as realized gains (losses) on derivatives once they are transferred from either accumulated other comprehensive incomerevenue for the year ended December 31, 2020 would have increased or unrealized gains (losses) on derivativesdecreased by approximately $140 million, $120 million, and $13 million, respectively, for each 10% increase or decrease in prices. As of December 31, 2020, the month of related production, based on the terms specified in the original contract as noted below:
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| | | | |
| | | December 31,
2018 |
| | | ($ in millions) |
| Short-term | | $ | (23 | ) |
| Long-term | | (33 | ) |
| Total | | $ | (56 | ) |
The table below reconciles the changes in fair valuevalues of our oil and natural gas derivatives during 2018. Ofwere net assets of $19 million and net liabilities of $137 million, respectively. A 10% increase in forward oil prices would decrease the $282valuation of oil derivatives by $187 million while a 10% decrease would increase the valuation by $185 million. A 10% increase in forward gas prices would decrease the valuation of gas derivatives by approximately $129 million while a 10% decrease would increase the valuation by $129 million. This fair value asset as of December 31, 2018, a $206 million asset relates to contracts maturing in the next 12 months and a $76 million asset relates to contracts maturing after 12 months. All open derivative instruments as of December 31, 2018 are expected to mature bychange assumes volatility based on prevailing market parameters at December 31, 2020.
|
| | | | |
| | | December 31,
2018 |
| | | ($ in millions) |
| Fair value of contracts outstanding, as of January 1, 2018 | | $ | (35 | ) |
| Change in fair value of contracts | | 644 |
|
| Contracts realized or otherwise settled | | (327 | ) |
| Fair value of contracts outstanding, as of December 31, 2018 | | $ | 282 |
|
Interest Rate Risk
The table below presents principal cash flowsOur exposure to interest rate changes relates primarily to borrowings under our pre-petition revolving credit facility and related weighted average interest rates by expected maturity dates, usingDIP Credit Facility. Interest was payable on borrowings under the earliest demand repurchase datepre-petition revolving credit facility and DIP Credit Facility based on a floating rate. See Note 5 of the notes to our consolidated financial statements included in Item 8 of this report for contingent convertible senior notes. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Years of Maturity | | |
| | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | Thereafter | | Total |
| | ($ in millions) |
| Liabilities: | | | | | | | | | | | | | |
| Debt – fixed rate | $ | 1 |
| | $ | 664 |
| | $ | 815 |
| | $ | 451 |
| | $ | 338 |
| | $ | 5,100 |
| | $ | 7,369 |
|
| Average interest rate | 2.25 | % | | 6.71 | % | | 5.88 | % | | 4.88 | % | | 5.75 | % | | 7.18 | % | | 6.79 | % |
| Debt – variable rate | $ | 380 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 419 |
| | $ | — |
| | $ | 799 |
|
| Average interest rate | 5.68 | % | | — | % | | — | % | | — | % | | 3.89 | % | | — | % | | 4.74 | % |
Changesadditional information. As of December 31, 2020, we had $1.929 billion in borrowings outstanding under our pre-petition revolving credit facility and no outstanding borrowings under our DIP Credit Facility. A 1.0% increase in interest rates affectbased on the amountvariable borrowings as of December 31, 2020 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 facilities 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 $19 million per year. Changes in interest rates do affect the fair value of our fixed-rate debt.
As of December 31, 2018, we had $5 million of net gains related to settled interest rate 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.
ITEM 8. Financial Statements and Supplementary Data |
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| INDEX TO FINANCIAL STATEMENTS
CHESAPEAKE ENERGY CORPORATION
(DEBTOR-IN-POSSESSION) | |
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| for the Years Ended December 31, 2018, 20172020, 2019 and 20162018 | |
| for the Years Ended December 31, 2018, 20172020, 2019 and 20162018 | |
| for the Years Ended December 31, 2018, 20172020, 2019 and 20162018 | |
| for the Years Ended December 31, 2018, 20172020, 2019 and 20162018 | |
| Notes to the Consolidated Financial Statements: | |
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| Supplementary Information: | |
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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, 2018.
The effectiveness of the Company's internal control over financial reporting, as of December 31, 2018, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report, which appears herein.
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| | | | |
/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 27, 2019 |
| | | | |
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Chesapeake Energy Corporation
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Chesapeake Energy Corporation and its subsidiaries (the “Company”) as of December 31, 20182020 and 2017,2019, and the related consolidated statements of operations, of comprehensive income (loss), of stockholders’ equity and of cash flows and stockholders’ equity for each of the three years in the period ended December 31, 2018,2020, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 20182020 and 2017,2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20182020 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, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for OpinionsOpinion
The Company's management is responsible for theseThese consolidated financial statements for maintaining effective internal control over financial reporting, and for its assessmentare the responsibility of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting.Company’s management. Our responsibility is to express opinionsan opinion on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits 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, and whether effectivefraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting was maintained in all material respects.
but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.opinion.
Subsequent Event
DefinitionAs discussed in Note 2 to the consolidated financial statements, Chesapeake Energy Corporation and Limitationscertain of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regardingits subsidiaries (collectively the reliability“Debtors”) filed voluntary petitions on June 28, 2020 with the United States Bankruptcy Court for the Southern District of financial reportingTexas (“Bankruptcy Court”) for relief under the provisions of Chapter 11 of the United States Code Bankruptcy Code. The Bankruptcy Court confirmed the Debtors joint plan of reorganization on January 16, 2021 and the preparationDebtors emerged from Bankruptcy on February 9, 2021.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policiesthat were communicated or required to be communicated to the audit committee and procedures that (i) pertainrelate to accounts or disclosures that are material 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 ofconsolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in accordance with generally accepted accounting principles,any way our opinion on the consolidated financial statements, taken as a whole, and that receipts and expenditures ofwe are not, by communicating the company are being made only in accordance with authorizations of management and directors ofcritical audit matters below, providing separate opinions on the company; and (iii) provide reasonable assurance regardingcritical 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
prevention or timely detectionAs described in Note 1 to the consolidated financial statements, the Company’s property and equipment, net balance was $5.2 billion as of unauthorized acquisition, use, or dispositionDecember 31, 2020, and depreciation, depletion, and amortization (DD&A) expense for the year ended December 31, 2020 was $1.1 billion, 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 producing activities. 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 company’s assetsquality 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 oil and natural gas reserves have been developed by specialists, specifically petroleum engineers.
The principal considerations for our determination that could haveperforming procedures relating to the impact of proved oil and natural gas reserves on proved oil and natural gas properties, net is a material effectcritical audit matter are (i) the significant judgment by management, including the use of specialists, when developing the estimates of proved oil and natural gas reserves, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence 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 reserve 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.
Impairment Assessment of Certain Proved Oil and Natural Gas Properties
BecauseAs described in Notes 1 and 18 to the consolidated financial statements, the property and equipment, net balance was $5.2 billion as of its inherent limitations, internal control over financial reportingDecember 31, 2020, and impairment expense for the year ended December 31, 2020 was $8.5 billion, both of which substantially related to proved oil and natural gas properties. When circumstances indicate that the carrying value of proved oil and natural gas properties may not prevent or detect misstatements. Also, projectionsbe recoverable, management compares unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of anycash flows of other assets. If the expected undiscounted pre-tax future cash flows are lower than the unamortized capitalized costs, the capitalized costs are reduced to fair value. Fair value is generally estimated using an income approach. The expected future cash flows used for impairment assessment and related fair value measurements are typically based on judgmental assessments of future production volumes, commodity prices, operating costs, weighted average cost of capital and capital investment plans, considering all available information at the date of assessment.
The principal considerations for our determination that performing procedures relating to the impairment assessment of certain proved 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 measurement of proved oil and natural gas properties; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to future production volumes, commodity prices, and operating costs, as well as the weighted average cost of capital; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of certain controls relating to management’s proved oil and natural gas properties impairment assessment. These procedures also included, among others (i) testing management’s process for developing the fair value measurement of proved oil and natural gas properties; (ii) evaluating the appropriateness of the income approach model; (iii) testing the completeness and accuracy of underlying data used in the model; and (iv) evaluating the reasonableness of significant assumptions used by management related to future production volumes, commodity prices, and operating costs, as well as the weighted average cost of capital. Evaluating the reasonableness of management’s assumptions related to future commodity prices 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 assumptions as compared to the past performance of the Company. Professionals with specialized skill and knowledge were used to assist in the evaluation of effectivenessthe Company’s income approach model and weighted average cost of capital. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved oil and natural gas reserve volumes as stated in the Critical Audit Matter titled “The Impact of Proved Oil and Natural Gas Reserves on Proved Oil and Natural Gas Properties, Net” and the reasonableness of the future periods are subject toproduction volumes. As a basis for using this work, the risk that controls may become inadequate because of changes in conditions, or thatspecialists’ qualifications were understood and, the degree of complianceCompany’s relationship with the policies orspecialists was assessed. The procedures may deteriorate.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.
/s/ PricewaterhouseCoopers LLP
Oklahoma City, Oklahoma
February 27, 2019March 1, 2021
We have served as the Company’s auditor since 1992.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
CONSOLIDATED BALANCE SHEETS
| | | | | | | | | | | | | | |
| | December 31, |
| | 2020 | | 2019 |
| ASSETS | | ($ in millions) |
| CURRENT ASSETS: | | | | |
| Cash and cash equivalents ($0 and $2 attributable to our VIE) | | $ | 279 | | | $ | 6 | |
| Accounts receivable, net | | 746 | | | 990 | |
| Short-term derivative assets | | 19 | | | 134 | |
| Other current assets | | 64 | | | 121 | |
| Total Current Assets | | 1,108 | | | 1,251 | |
| PROPERTY AND EQUIPMENT: | | | | |
| Oil and natural gas properties, at cost based on successful efforts accounting: | | | | |
Proved oil and natural gas properties ($0 and $755 attributable to our VIE) | | 25,734 | | | 30,765 | |
| Unproved properties | | 1,550 | | | 2,173 | |
| Other property and equipment | | 1,754 | | | 1,810 | |
| Total Property and Equipment, at Cost | | 29,038 | | | 34,748 | |
Less: accumulated depreciation, depletion and amortization ($0 and ($713) attributable to our VIE) | | (23,806) | | | (20,002) | |
| Property and equipment held for sale, net | | 10 | | | 10 | |
| Total Property and Equipment, Net | | 5,242 | | | 14,756 | |
| Other long-term assets | | 234 | | | 186 | |
| TOTAL ASSETS | | $ | 6,584 | | | $ | 16,193 | |
| | | | |
The accompanying notes are an integral part of these consolidated financial statements.
69
|
| | | | | | | | |
| | | December 31, |
| | | 2018 | | 2017 |
| | | ($ in millions) |
| CURRENT ASSETS: | | | | |
| Cash and cash equivalents ($1 and $2 attributable to our VIE) | | $ | 4 |
| | $ | 5 |
|
| Accounts receivable, net | | 1,247 |
| | 1,322 |
|
| Short-term derivative assets | | 209 |
| | 27 |
|
| Other current assets | | 138 |
| | 171 |
|
| Total Current Assets | | 1,598 |
| | 1,525 |
|
| 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) | | 69,642 |
| | 68,858 |
|
| Unproved properties | | 2,337 |
| | 3,484 |
|
| Other property and equipment | | 1,721 |
| | 1,986 |
|
| Total Property and Equipment, at Cost | | 73,700 |
| | 74,328 |
|
Less: accumulated depreciation, depletion and amortization (($465) and ($461) attributable to our VIE) | | (64,685 | ) | | (63,664 | ) |
| Property and equipment held for sale, net | | 15 |
| | 16 |
|
| Total Property and Equipment, Net | | 9,030 |
| | 10,680 |
|
| LONG-TERM ASSETS: | | | | |
| Long-term derivative assets | | 76 |
| | — |
|
| Other long-term assets | | 243 |
| | 220 |
|
| TOTAL ASSETS | | $ | 10,947 |
| | $ | 12,425 |
|
| | | | | |
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
CONSOLIDATED BALANCE SHEETS – (Continued)
| | | | | | | | | | | | | | |
| | December 31, |
| | 2020 | | 2019 |
| LIABILITIES AND EQUITY (DEFICIT) | | ($ in millions) |
| CURRENT LIABILITIES: | | | | |
| Accounts payable | | $ | 346 | | | $ | 498 | |
| Current maturities of long-term debt, net | | 1,929 | | | 385 | |
| Accrued interest | | 3 | | | 75 | |
| Short-term derivative liabilities | | 93 | | | 2 | |
| Other current liabilities ($0 and $1 attributable to our VIE) | | 723 | | | 1,432 | |
| Total Current Liabilities | | 3,094 | | | 2,392 | |
| Long-term debt, net | | 0 | | | 9,073 | |
| Long-term derivative liabilities | | 44 | | | 2 | |
| Asset retirement obligations, net of current portion | | 139 | | | 200 | |
| Other long-term liabilities | | 5 | | | 125 | |
| Liabilities subject to compromise | | 8,643 | | | 0 | |
| Total Liabilities | | 11,925 | | | 11,792 | |
CONTINGENCIES AND COMMITMENTS (Note 6) | | 0 | | 0 |
| EQUITY (DEFICIT): | | | | |
| Stockholders’ Equity (deficit): | | | | |
Preferred stock, $0.01 par value, 20,000,000 shares authorized:
5,563,458 and 5,563,458 shares outstanding | | 1,631 | | | 1,631 | |
Common stock, $0.01 par value, 22,500,000 and 15,000,000 shares authorized: 9,780,547 and 9,772,793 shares issued(a) | | 0 | | | 0 | |
| Additional paid-in capital | | 16,937 | | | 16,973 | |
| Accumulated deficit | | (23,954) | | | (14,220) | |
| Accumulated other comprehensive income | | 45 | | | 12 | |
Less: treasury stock, at cost; 0 and 26,224 common shares(a) | | 0 | | | (32) | |
| Total Stockholders’ Equity (Deficit) | | (5,341) | | | 4,364 | |
| Noncontrolling interests | | 0 | | | 37 | |
| Total Equity (Deficit) | | (5,341) | | | 4,401 | |
| TOTAL LIABILITIES AND EQUITY (DEFICIT) | | $ | 6,584 | | | $ | 16,193 | |
(a) Amounts and shares have been retroactively adjusted to reflect a 1-for-200 (1:200) reverse stock split effective April 14, 2020. See Note 11 for additional information. The accompanying notes are an integral part of these consolidated financial statements.
70
|
| | | | | | | | |
| | | December 31, |
| | | 2018 | | 2017 |
| | | ($ in millions) |
| CURRENT LIABILITIES: | | | | |
| Accounts payable | | $ | 763 |
| | $ | 654 |
|
| Current maturities of long-term debt, net | | 381 |
| | 52 |
|
| Accrued interest | | 141 |
| | 137 |
|
| Short-term derivative liabilities | | 3 |
| | 58 |
|
| Other current liabilities ($2 and $3 attributable to our VIE) | | 1,540 |
| | 1,455 |
|
| Total Current Liabilities | | 2,828 |
| | 2,356 |
|
| LONG-TERM LIABILITIES: | | | | |
| Long-term debt, net | | 7,341 |
| | 9,921 |
|
| Long-term derivative liabilities | | — |
| | 4 |
|
| Asset retirement obligations, net of current portion | | 155 |
| | 162 |
|
| Other long-term liabilities | | 156 |
| | 354 |
|
| Total Long-Term Liabilities | | 7,652 |
| | 10,441 |
|
| CONTINGENCIES AND COMMITMENTS (Note 4) | |
| |
|
| EQUITY: | | | | |
| Chesapeake Stockholders’ Equity: | | | | |
Preferred stock, $0.01 par value, 20,000,000 shares authorized:
5,603,458 shares outstanding | | 1,671 |
| | 1,671 |
|
Common stock, $0.01 par value, 2,000,000,000 shares authorized: 913,715,512 and 908,732,809 shares issued | | 9 |
| | 9 |
|
| Additional paid-in capital | | 14,378 |
| | 14,437 |
|
| Accumulated deficit | | (15,660 | ) | | (16,525 | ) |
| Accumulated other comprehensive loss | | (23 | ) | | (57 | ) |
Less: treasury stock, at cost; 3,246,553 and 2,240,394 common shares | | (31 | ) | | (31 | ) |
| Total Chesapeake Stockholders’ Equity (Deficit) | | 344 |
| | (496 | ) |
| Noncontrolling interests | | 123 |
| | 124 |
|
| Total Equity (Deficit) | | 467 |
| | (372 | ) |
| TOTAL LIABILITIES AND EQUITY | | $ | 10,947 |
| | $ | 12,425 |
|
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES - (DEBTOR-IN-POSSESSION)
CONSOLIDATED STATEMENTS OF OPERATIONS
| | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2020 | | 2019 | | 2018 |
| | | ($ in millions except per share data) |
| REVENUES AND OTHER: | | | | | | |
| Oil, natural gas and NGL | | $ | 3,341 | | | $ | 4,522 | | | $ | 5,155 | |
| Marketing | | 1,869 | | | 3,967 | | | 5,076 | |
| Total Revenues | | 5,210 | | | 8,489 | | | 10,231 | |
| Other | | 56 | | | 63 | | | 63 | |
| Gains (losses) on sales of assets | | 30 | | | 43 | | | (264) | |
| Total Revenues and Other | | 5,296 | | | 8,595 | | | 10,030 | |
| OPERATING EXPENSES: | | | | | | |
| Oil, natural gas and NGL production | | 373 | | | 520 | | | 474 | |
| Oil, natural gas and NGL gathering, processing and transportation | | 1,082 | | | 1,082 | | | 1,398 | |
| Severance and ad valorem taxes | | 149 | | | 224 | | | 189 | |
| Exploration | | 427 | | | 84 | | | 162 | |
| Marketing | | 1,889 | | | 4,003 | | | 5,158 | |
| General and administrative | | 267 | | | 315 | | | 335 | |
| Separation and other termination costs | | 44 | | | 12 | | | 38 | |
| Provision for legal contingencies | | 27 | | | 19 | | | 26 | |
| Depreciation, depletion and amortization | | 1,097 | | | 2,264 | | | 1,737 | |
| Impairments | | 8,535 | | | 11 | | | 131 | |
| Other operating expense | | 109 | | | 92 | | | 0 | |
| Total Operating Expenses | | 13,999 | | | 8,626 | | | 9,648 | |
| INCOME (LOSS) FROM OPERATIONS | | (8,703) | | | (31) | | | 382 | |
| OTHER INCOME (EXPENSE): | | | | | | |
| Interest expense | | (331) | | | (651) | | | (633) | |
| Gains (losses) on investments | | (20) | | | (71) | | | 139 | |
| Gains on purchases or exchanges of debt | | 65 | | | 75 | | | 263 | |
| Other income | | 16 | | | 39 | | | 67 | |
| Reorganization items, net | | (796) | | | 0 | | | 0 | |
| Total Other Expense | | (1,066) | | | (608) | | | (164) | |
| INCOME (LOSS) BEFORE INCOME TAXES | | (9,769) | | | (639) | | | 218 | |
| INCOME TAX EXPENSE (BENEFIT): | | | | | | |
| Current income taxes | | (9) | | | (26) | | | 0 | |
| Deferred income taxes | | (10) | | | (305) | | | (10) | |
| Total Income Tax Expense (Benefit) | | (19) | | | (331) | | | (10) | |
| NET INCOME (LOSS) | | (9,750) | | | (308) | | | 228 | |
| Net (income) loss attributable to noncontrolling interests | | 16 | | | 0 | | | (2) | |
| NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE | | (9,734) | | | (308) | | | 226 | |
| Preferred stock dividends | | (22) | | | (91) | | | (92) | |
| Loss on exchange of preferred stock | | 0 | | | (17) | | | 0 | |
| Earnings allocated to participating securities | | 0 | | | 0 | | | (1) | |
| NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS | | $ | (9,756) | | | $ | (416) | | | $ | 133 | |
EARNINGS (LOSS) PER COMMON SHARE:(a) | | | | | | |
| Basic | | $ | (998.26) | | | $ | (49.97) | | | $ | 29.26 | |
| Diluted | | $ | (998.26) | | | $ | (49.97) | | | $ | 29.26 | |
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in thousands):(a) |
| Basic | | 9,773 | | | 8,325 | | | 4,546 | |
| Diluted | | 9,773 | | | 8,325 | | | 4,546 | |
(a) All share and per share information has been retroactively adjusted to reflect a 1-for-200 (1:200) reverse stock split effective April 14, 2020. SeeNote 11 for additional information. The accompanying notes are an integral part of these consolidated financial statements.
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|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| | | ($ in millions except per share data) |
| REVENUES: | | | | | | |
| Oil, natural gas and NGL | | $ | 5,155 |
| | $ | 4,985 |
| | $ | 3,288 |
|
| Marketing | | 5,076 |
| | 4,511 |
| | 4,584 |
|
| Total Revenues | | 10,231 |
| | 9,496 |
| | 7,872 |
|
| OPERATING EXPENSES: | | | | | | |
| Oil, natural gas and NGL production | | 539 |
| | 562 |
| | 710 |
|
| Oil, natural gas and NGL gathering, processing and transportation | | 1,398 |
| | 1,471 |
| | 1,855 |
|
| Production taxes | | 124 |
| | 89 |
| | 74 |
|
| Marketing | | 5,158 |
| | 4,598 |
| | 4,778 |
|
| General and administrative | | 280 |
| | 262 |
| | 240 |
|
| Restructuring and other termination costs | | 38 |
| | — |
| | 6 |
|
| Provision for legal contingencies, net | | 26 |
| | (38 | ) | | 123 |
|
| Depreciation, depletion and amortization | | 1,145 |
| | 995 |
| | 1,107 |
|
| Loss on sale of oil and natural gas properties | | 578 |
| | — |
| | — |
|
| Impairments | | 53 |
| | 5 |
| | 3,025 |
|
| Other operating expenses | | 10 |
| | 413 |
| | 365 |
|
| Total Operating Expenses | | 9,349 |
| | 8,357 |
| | 12,283 |
|
| INCOME (LOSS) FROM OPERATIONS | | 882 |
| | 1,139 |
| | (4,411 | ) |
| OTHER INCOME (EXPENSE): | | | | | | |
| Interest expense | | (487 | ) | | (426 | ) | | (296 | ) |
| Gains (losses) on investments | | 139 |
| | — |
| | (137 | ) |
| Gains on purchases or exchanges of debt | | 263 |
| | 233 |
| | 236 |
|
| Other income | | 70 |
| | 9 |
| | 19 |
|
| Total Other Expense | | (15 | ) | | (184 | ) | | (178 | ) |
| INCOME (LOSS) BEFORE INCOME TAXES | | 867 |
| | 955 |
| | (4,589 | ) |
| INCOME TAX EXPENSE (BENEFIT): | | | | | | |
| Current income taxes | | — |
| | (9 | ) | | (19 | ) |
| Deferred income taxes | | (10 | ) | | 11 |
| | (171 | ) |
| Total Income Tax Expense (Benefit) | | (10 | ) | | 2 |
| | (190 | ) |
| NET INCOME (LOSS) | | 877 |
| | 953 |
| | (4,399 | ) |
| Net (income) loss attributable to noncontrolling interests | | (4 | ) | | (4 | ) | | 9 |
|
| NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE | | 873 |
| | 949 |
| | (4,390 | ) |
| Preferred stock dividends | | (92 | ) | | (85 | ) | | (97 | ) |
| Loss on exchange of preferred stock | | — |
| | (41 | ) | | (428 | ) |
| Earnings allocated to participating securities | | (6 | ) | | (10 | ) | | — |
|
| NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS | | $ | 775 |
| | $ | 813 |
| | $ | (4,915 | ) |
| EARNINGS (LOSS) PER COMMON SHARE: | | | | | | |
| Basic | | $ | 0.85 |
| | $ | 0.90 |
| | $ | (6.43 | ) |
| Diluted | | $ | 0.85 |
| | $ | 0.90 |
| | $ | (6.43 | ) |
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in millions): | | | | | | |
| Basic | | 909 |
| | 906 |
| | 764 |
|
| Diluted | | 909 |
| | 906 |
| | 764 |
|
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | | 2020 | | 2019 | | 2018 |
| | | ($ in millions) |
| NET INCOME (LOSS) | | $ | (9,750) | | | $ | (308) | | | $ | 228 | |
| OTHER COMPREHENSIVE INCOME, NET OF INCOME TAX: | | | | | | |
Reclassification of losses on settled derivative instruments(a) | | 33 | | | 35 | | | 34 | |
| Other Comprehensive Income | | 33 | | | 35 | | | 34 | |
| COMPREHENSIVE INCOME (LOSS) | | (9,717) | | | (273) | | | 262 | |
COMPREHENSIVE (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS | | 16 | | | 0 | | | (2) | |
| COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE | | $ | (9,701) | | | $ | (273) | | | $ | 260 | |
(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.
72
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| | | ($ in millions) |
| NET INCOME (LOSS) | | $ | 877 |
| | $ | 953 |
| | $ | (4,399 | ) |
| OTHER COMPREHENSIVE INCOME (LOSS), NET OF INCOME TAX: | | | | | | |
| Unrealized gains (losses) on derivative instruments, net of income tax benefit of $0, $0, and ($14) | | — |
| | 5 |
| | (13 | ) |
| Reclassification of losses on settled derivative instruments, net of income tax expense of $0, $0 and $18 | | 34 |
| | 34 |
| | 16 |
|
| Other Comprehensive Income | | 34 |
| | 39 |
| | 3 |
|
| COMPREHENSIVE INCOME (LOSS) | | 911 |
| | 992 |
| | (4,396 | ) |
COMPREHENSIVE (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS | | (4 | ) | | (4 | ) | | 9 |
|
| COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE | | $ | 907 |
| | $ | 988 |
| | $ | (4,387 | ) |
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
CONSOLIDATED STATEMENTS OF CASH FLOWS
| | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2020 | | 2019 | | 2018 |
| | ($ in millions) |
| CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
| NET INCOME (LOSS) | | $ | (9,750) | | | $ | (308) | | | $ | 228 | |
ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO CASH PROVIDED BY OPERATING ACTIVITIES: | | | | | | |
| Depreciation, depletion and amortization | | 1,097 | | | 2,264 | | | 1,737 | |
| Deferred income tax benefit | | (10) | | | (305) | | | (10) | |
| Derivative (gains) losses, net | | (596) | | | (3) | | | 26 | |
| Cash receipts (payments) on derivative settlements, net | | 884 | | | 202 | | | (345) | |
| Stock-based compensation | | 21 | | | 30 | | | 32 | |
| (Gains) losses on sales of assets | | (30) | | | (43) | | | 264 | |
| Impairments | | 8,535 | | | 11 | | | 131 | |
| Non-cash reorganization items, net | | (213) | | | 0 | | | 0 | |
| Exploration | | 417 | | | 49 | | | 96 | |
| (Gains) losses on investments | | 20 | | | 63 | | | (139) | |
| Gains on purchases or exchanges of debt | | (65) | | | (79) | | | (263) | |
| Other | | (61) | | | (4) | | | (118) | |
| Decrease in accounts receivable and other assets | | 303 | | | 376 | | | 16 | |
| (Decrease) increase in accounts payable, accrued liabilities and other | | 612 | | | (630) | | | 75 | |
| Net Cash Provided By Operating Activities | | 1,164 | | | 1,623 | | | 1,730 | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | |
| Drilling and completion costs | | (1,111) | | | (2,180) | | | (1,848) | |
| Business combination, net | | 0 | | | (353) | | | 0 | |
| Acquisitions of proved and unproved properties | | (9) | | | (35) | | | (128) | |
| Proceeds from divestitures of proved and unproved properties | | 136 | | | 130 | | | 2,231 | |
| Additions to other property and equipment | | (22) | | | (48) | | | (21) | |
| Proceeds from sales of other property and equipment | | 14 | | | 6 | | | 147 | |
| Proceeds from sales of investments | | 0 | | | 0 | | | 74 | |
| Net Cash Provided By (Used In) Investing Activities | | (992) | | | (2,480) | | | 455 | |
The accompanying notes are an integral part of these consolidated financial statements.
73
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| | | ($ in millions) |
| CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
| NET INCOME (LOSS) | | $ | 877 |
| | $ | 953 |
| | $ | (4,399 | ) |
ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES: | | | | | | |
| Depreciation, depletion and amortization | | 1,145 |
| | 995 |
| | 1,107 |
|
| Deferred income tax expense (benefit) | | (10 | ) | | 11 |
| | (171 | ) |
| Derivative (gains) losses, net | | 26 |
| | (409 | ) | | 739 |
|
| Cash receipts (payments) on derivative settlements, net | | (345 | ) | | (18 | ) | | 448 |
|
| Stock-based compensation | | 32 |
| | 49 |
| | 52 |
|
| Loss on sale of oil and gas properties | | 578 |
| | — |
| | — |
|
| Impairments | | 53 |
| | 5 |
| | 3,025 |
|
| (Gains) losses on investments | | (139 | ) | | — |
| | 137 |
|
| Gains on purchases or exchanges of debt | | (263 | ) | | (235 | ) | | (236 | ) |
| Other | | (108 | ) | | (135 | ) | | (145 | ) |
| (Increase) decrease in accounts receivable and other assets | | 16 |
| | (163 | ) | | (4 | ) |
| (Decrease) increase in accounts payable, accrued liabilities and other | | 138 |
| | (308 | ) | | (757 | ) |
| Net Cash Provided By (Used In) Operating Activities | | 2,000 |
| | 745 |
| | (204 | ) |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | |
| Drilling and completion costs | | (1,958 | ) | | (2,186 | ) | | (1,295 | ) |
| Acquisitions of proved and unproved properties | | (288 | ) | | (285 | ) | | (788 | ) |
| Proceeds from divestitures of proved and unproved properties | | 2,231 |
| | 1,249 |
| | 1,406 |
|
| Additions to other property and equipment | | (21 | ) | | (21 | ) | | (37 | ) |
| Proceeds from sales of other property and equipment | | 147 |
| | 55 |
| | 131 |
|
| Proceeds from sales of investments | | 74 |
| | — |
| | — |
|
| Other | | — |
| | — |
| | (77 | ) |
| Net Cash Provided By (Used In) Investing Activities | | 185 |
| | (1,188 | ) | | (660 | ) |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | |
| Proceeds from revolving credit facility borrowings | | 11,697 |
| | 7,771 |
| | 5,146 |
|
| Payments on revolving credit facility borrowings | | (12,059 | ) | | (6,990 | ) | | (5,146 | ) |
| Proceeds from issuance of senior notes, net | | 1,236 |
| | 1,585 |
| | 2,210 |
|
| Proceeds from issuance of term loan, net | | — |
| | — |
| | 1,476 |
|
| Cash paid to purchase debt | | (2,813 | ) | | (2,592 | ) | | (2,734 | ) |
| Extinguishment of other financing | | (122 | ) | | — |
| | — |
|
| Cash paid for preferred stock dividends | | (92 | ) | | (183 | ) | | — |
|
| Distributions to noncontrolling interest owners | | (6 | ) | | (8 | ) | | (10 | ) |
| Other | | (27 | ) | | (17 | ) | | (21 | ) |
| Net Cash Provided By (Used In) Financing Activities | | (2,186 | ) | | (434 | ) | | 921 |
|
| Net increase (decrease) in cash and cash equivalents | | (1 | ) | | (877 | ) | | 57 |
|
| Cash and cash equivalents, beginning of period | | 5 |
| | 882 |
| | 825 |
|
| Cash and cash equivalents, end of period | | $ | 4 |
| | $ | 5 |
| | $ | 882 |
|
| | | | | | | |
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
CONSOLIDATED STATEMENTS OF CASH FLOWS – (Continued)
| | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2020 | | 2019 | | 2018 |
| | ($ in millions) |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | |
| Proceeds from pre-petition revolving credit facility borrowings | | 3,656 | | | 10,676 | | | 11,697 | |
| Payments on pre-petition revolving credit facility borrowings | | (3,317) | | | (10,180) | | | (12,059) | |
| Proceeds from DIP credit facility borrowings | | 60 | | | 0 | | | 0 | |
| Payments on DIP credit facility borrowings | | (60) | | | 0 | | | 0 | |
| DIP credit facility and exit facilities financing costs | | (109) | | | 0 | | | 0 | |
| Proceeds from issuance of senior notes, net | | 0 | | | 108 | | | 1,236 | |
| Proceeds from issuance of term loan, net | | 0 | | | 1,455 | | | 0 | |
| Cash paid to purchase debt | | (94) | | | (1,073) | | | (2,813) | |
| Extinguishment of other financing | | 0 | | | 0 | | | (122) | |
| Cash paid for preferred stock dividends | | (22) | | | (91) | | | (92) | |
| Other | | (13) | | | (36) | | | (33) | |
| Net Cash Provided By (Used In) Financing Activities | | 101 | | | 859 | | | (2,186) | |
| Net increase (decrease) in cash and cash equivalents | | 273 | | | 2 | | | (1) | |
| Cash and cash equivalents, beginning of period | | 6 | | | 4 | | | 5 | |
| Cash and cash equivalents, end of period | | $ | 279 | | | $ | 6 | | | $ | 4 | |
| | | | | | |
| Supplemental disclosures to the consolidated statements of cash flows are presented below: | | |
| | | | | | |
| | Years Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| | ($ in millions) |
| SUPPLEMENTAL CASH FLOW INFORMATION: | | | | | | |
| Cash paid for reorganization items, net | | $ | 140 | | | $ | 0 | | | $ | 0 | |
| Interest paid, net of capitalized interest | | $ | 224 | | | $ | 691 | | | $ | 664 | |
| Income taxes paid, net of refunds received | | $ | 0 | | | $ | (6) | | | $ | (3) | |
| | | | | | |
| SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES: | | | | | | |
| Change in accrued drilling and completion costs | | $ | (216) | | | $ | (19) | | | $ | 174 | |
| Put option premium on equity backstop agreement | | $ | 60 | | | $ | 0 | | | $ | 0 | |
| Operating lease obligations recognized | | $ | 32 | | | $ | 0 | | | $ | 0 | |
| Common stock issued for business combination | | $ | 0 | | | $ | 2,037 | | | $ | 0 | |
| Debt exchanged for common stock | | $ | 0 | | | $ | 693 | | | $ | 0 | |
| Preferred stock exchanged for common stock | | $ | 0 | | | $ | 40 | | | $ | 0 | |
| Change in senior notes exchanged | | $ | 0 | | | $ | 971 | | | $ | 0 | |
| Acquisition of other property and equipment including assets under finance lease | | $ | 0 | | | $ | 0 | | | $ | 27 | |
The accompanying notes are an integral part of these consolidated financial statements.
74
|
| | | | | | | | | | | | |
| Supplemental disclosures to the consolidated statements of cash flows are presented below: | | |
| | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| | | ($ in millions) |
| SUPPLEMENTAL CASH FLOW INFORMATION: | | | | | | |
| Interest paid, net of capitalized interest | | $ | 518 |
| | $ | 492 |
| | $ | 344 |
|
| Income taxes paid, net of refunds received | | $ | (3 | ) | | $ | (16 | ) | | $ | (27 | ) |
| | | | | | | |
| SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES: | | | | | | |
| Change in accrued drilling and completion costs | | $ | 174 |
| | $ | 14 |
| | $ | (23 | ) |
| Change in accrued acquisitions of proved and unproved properties | | $ | 7 |
| | $ | 9 |
| | $ | (13 | ) |
| Change in divested proved and unproved properties | | $ | (21 | ) | | $ | (57 | ) | | $ | 52 |
|
| Acquisition of other property and equipment including assets under capital lease | | $ | 27 |
| | $ | — |
| | $ | — |
|
| Debt exchanged for common stock | | $ | — |
| | $ | — |
| | $ | 471 |
|
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| | | ($ in millions) |
| PREFERRED STOCK: | | | | | | |
| Balance, beginning of period | | $ | 1,631 | | | $ | 1,671 | | | $ | 1,671 | |
Exchange/conversions of 100, 40,000 and 0 shares of preferred stock for common stock | | 0 | | | (40) | | | 0 | |
| Balance, end of period | | 1,631 | | | 1,631 | | | 1,671 | |
COMMON STOCK:(a) | | | | | | |
| Balance, beginning of period | | 0 | | | 0 | | | 0 | |
| Common shares issued for WildHorse Merger | | 0 | | | 0 | | | 0 | |
| Exchange of senior notes and convertible notes | | 0 | | | 0 | | | 0 | |
| Balance, end of period | | 0 | | | 0 | | | 0 | |
ADDITIONAL PAID-IN CAPITAL:(a) | | | | | | |
| Balance, beginning of period | | 16,973 | | | 14,387 | | | 14,446 | |
| Common shares issued for WildHorse Merger | | 0 | | | 2,037 | | | 0 | |
| Stock-based compensation | | (14) | | | 27 | | | 33 | |
| Exchange of contingent convertible notes for 0, 366,945 and 0 shares of common stock | | 0 | | | 135 | | | 0 | |
| Exchange of senior notes for 0, 1,177,817 and 0 shares of common stock | | 0 | | | 440 | | | 0 | |
Exchange of preferred stock for 0, 51,839, and 0 shares of common stock | | 0 | | | 40 | | | 0 | |
| Equity component of contingent convertible notes repurchased | | 0 | | | (2) | | | 0 | |
| Dividends on preferred stock | | (22) | | | (91) | | | (92) | |
| Balance, end of period | | 16,937 | | | 16,973 | | | 14,387 | |
| RETAINED EARNINGS (ACCUMULATED DEFICIT): | | | | | | |
| Balance, beginning of period | | (14,220) | | | (13,912) | | | (14,130) | |
| Net income (loss) attributable to Chesapeake | | (9,734) | | | (308) | | | 226 | |
| Cumulative effect of change in accounting principle | | 0 | | | 0 | | | (8) | |
| Balance, end of period | | (23,954) | | | (14,220) | | | (13,912) | |
| ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | |
| Balance, beginning of period | | 12 | | | (23) | | | (57) | |
| Hedging activity | | 33 | | | 35 | | | 34 | |
| Balance, end of period | | 45 | | | 12 | | | (23) | |
The accompanying notes are an integral part of these consolidated financial statements.
75
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| | | ($ in millions) |
| PREFERRED STOCK: | | | | | | |
| Balance, beginning of period | | $ | 1,671 |
| | $ | 1,771 |
| | $ | 3,062 |
|
Exchange/conversions of 0, 236,048 and 1,412,009 shares of preferred stock for common stock | | — |
| | (100 | ) | | (1,291 | ) |
| Balance, end of period | | 1,671 |
| | 1,671 |
| | 1,771 |
|
| COMMON STOCK: | | | | | | |
| Balance, beginning of period | | 9 |
| | 9 |
| | 7 |
|
Exchange of senior notes, contingent convertible notes and preferred stock | | — |
| | — |
| | 1 |
|
| Conversion of preferred stock | | — |
| | — |
| | 1 |
|
| Balance, end of period | | 9 |
| | 9 |
| | 9 |
|
| ADDITIONAL PAID-IN CAPITAL: | | | | | | |
| Balance, beginning of period | | 14,437 |
| | 14,486 |
| | 12,403 |
|
| Stock-based compensation | | 33 |
| | 54 |
| | 64 |
|
| Exchange of contingent convertible notes for 0, 0 and 55,427,782 shares of common stock | | — |
| | — |
| | 241 |
|
| Exchange of senior notes for 0, 0 and 53,923,925 shares of common stock | | — |
| | — |
| | 229 |
|
Exchange/conversion of preferred stock for 0, 9,965,835, and 120,186,195 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 | | (92 | ) | | (183 | ) | | — |
|
| Issuance costs | | — |
| | — |
| | (5 | ) |
| Balance, end of period | | 14,378 |
| | 14,437 |
| | 14,486 |
|
| RETAINED EARNINGS (ACCUMULATED DEFICIT): | | | | | | |
| Balance, beginning of period | | (16,525 | ) | | (17,474 | ) | | (13,084 | ) |
| Net income (loss) attributable to Chesapeake | | 873 |
| | 949 |
| | (4,390 | ) |
| Cumulative effect of change in accounting principle | | (8 | ) | | — |
| | — |
|
| Balance, end of period | | (15,660 | ) | | (16,525 | ) | | (17,474 | ) |
| ACCUMULATED OTHER COMPREHENSIVE LOSS: | | | | | | |
| Balance, beginning of period | | (57 | ) | | (96 | ) | | (99 | ) |
| Hedging activity | | 34 |
| | 39 |
| | 3 |
|
| Balance, end of period | | (23 | ) | | (57 | ) | | (96 | ) |
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY - (Continued)
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| | | ($ in millions) |
TREASURY STOCK – COMMON:(a) | | | | | | |
| Balance, beginning of period | | (32) | | | (31) | | | (31) | |
| Purchase of 17,901, 14,391, and 7,550 shares for company benefit plans | | (2) | | | (7) | | | (4) | |
| Release of 44,126, 4,398 and 2,519 shares from company benefit plans | | 34 | | | 6 | | | 4 | |
| Balance, end of period | | 0 | | | (32) | | | (31) | |
| TOTAL STOCKHOLDERS’ EQUITY (DEFICIT) | | (5,341) | | | 4,364 | | | 2,092 | |
| NONCONTROLLING INTERESTS: | | | | | | |
| Balance, beginning of period | | 37 | | | 41 | | | 44 | |
| Net income attributable to noncontrolling interests | | (16) | | | 0 | | | 2 | |
| Distributions to noncontrolling interest owners | | 0 | | | (4) | | | (5) | |
| Divestiture of underlying assets | | (21) | | | 0 | | | 0 | |
| Balance, end of period | | 0 | | | 37 | | | 41 | |
| TOTAL EQUITY (DEFICIT) | | $ | (5,341) | | | $ | 4,401 | | | $ | 2,133 | |
(a) Amounts and shares have been retroactively adjusted to reflect a 1-for-200 (1:200) reverse stock split effective April 14, 2020. See Note 11 for additional information. The accompanying notes are an integral part of these consolidated financial statements.
76
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| | | ($ in millions) |
| TREASURY STOCK – COMMON: | | | | | | |
| Balance, beginning of period | | (31 | ) | | (27 | ) | | (33 | ) |
| Purchase of 1,510,022, 1,206,419, and 37,871 shares for company benefit plans | | (4 | ) | | (7 | ) | | — |
|
| Release of 503,863, 186,529 and 255,091 shares from company benefit plans | | 4 |
| | 3 |
| | 6 |
|
| Balance, end of period | | (31 | ) | | (31 | ) | | (27 | ) |
| TOTAL CHESAPEAKE STOCKHOLDERS’ EQUITY (DEFICIT) | | 344 |
| | (496 | ) | | (1,331 | ) |
| NONCONTROLLING INTERESTS: | | | | | | |
| Balance, beginning of period | | 124 |
| | 128 |
| | 141 |
|
| Net income (loss) attributable to noncontrolling interests | | 4 |
| | 4 |
| | (9 | ) |
| Distributions to noncontrolling interest owners | | (5 | ) | | (8 | ) | | (4 | ) |
| Balance, end of period | | 123 |
| | 124 |
| | 128 |
|
| TOTAL EQUITY (DEFICIT) | | $ | 467 |
| | $ | (372 | ) | | $ | (1,203 | ) |
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Basis of Presentation and Summary of Significant Accounting Policies | |
1. | Basis of Presentation and Summary of Significant Accounting Policies |
Description of Company
Chesapeake Energy Corporation ("Chesapeake", “we,” “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) from underground reservoirs. Our operations are located onshore in the United States. 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. 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. 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.
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 are realized or incurred during the bankruptcy proceedings, including losses related to executory contracts that were approved for rejection by the Bankruptcy Court, and unamortized deferred financing 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 may be impacted by the Chapter 11 process have been classified on the consolidated balance sheet as of December 31, 2020 as liabilities subject to compromise. These liabilities are reported at the amounts we anticipate will be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts. 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, 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.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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 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 1011 for further discussion of our 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 one1 reportable operating segment, which is exploration and production because 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 1011 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.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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. See Note 79 for further discussion of 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. Capitalizedactivities are also expensed as incurred. All property acquisition costs and development costs are amortized oncapitalized when incurred.
Exploratory drilling costs are initially capitalized, or suspended, pending the determination of proved reserves. If proved reserves are found, drilling costs remain capitalized and are classified as proved properties. Costs of unsuccessful 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 compositeproducing well and sufficient progress is
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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 depleted using the UOP method based on total estimated proved developed and undeveloped reserves.
Proceeds from the sales of individual oil and natural gas properties and the capitalized 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 remaining properties in the amortization base.
When circumstances indicate that the carrying value of proved oil and natural gas reserves. Estimatesproperties may not be recoverable, we compare unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on our proved reserves asestimate of December 31, 2018 were prepared by an independent engineering firm and our internal staff.
Proceeds from the sale offuture crude oil and natural gas properties are accounted for as reductions of capitalizedprices, operating costs, unless these sales involve a significant change inanticipated production from proved reserves and significantly alterother relevant data, are lower than the relationship betweenunamortized 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 expected future cash flows used for impairment reviews and related fair value measurements are typically based on judgmental assessments of commodity prices, pricing adjustments for differentials, operating costs, capital investment plans, future production volumes, and estimated proved reserves, in which caseconsidering 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 gain or loss is recognized.
The costs of unproved properties are excluded from amortization until the properties are evaluated. We review all of our unproved properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties and otherwise if impairment has occurred.
The table below sets forth themarket-based weighted average cost of unproved properties excluded fromcapital. We have classified these fair value measurements as Level 3 in the amortization base as of December 31, 2018 and the year in which the associated costs were incurred:
|
| | | | | | | | | | | | | | | | | | | | |
| | | Year of Acquisition | | |
| | | 2018 | | 2017 | | 2016 | | Prior | | Total |
| | | ($ in millions) |
| Leasehold cost | | $ | 24 |
| | $ | 31 |
| | $ | 40 |
| | $ | 1,577 |
| | $ | 1,672 |
|
| Exploration cost | | 122 |
| | — |
| | 2 |
| | — |
| | 124 |
|
| Capitalized interest | | 125 |
| | 84 |
| | 63 |
| | 269 |
| | 541 |
|
| Total | | $ | 271 |
| | $ | 115 |
| | $ | 105 |
| | $ | 1,846 |
| | $ | 2,337 |
|
We also review, on a quarterly basis, the carryingfair value of our oil and natural gas properties under the full cost accounting rules of the SEC. This quarterly review is referred to as a ceiling test. Under the ceiling test, 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 less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects.hierarchy.
Other Property and Equipment
Other property and equipment consists primarily of buildings and improvements, land, vehicles, computers, a sand mine, natural gas compressors under capitalfinance lease and office equipment. Major renewals and betterments are capitalized while the costs of repairs and maintenance are charged to expense as incurred. Other property and equipment costs, excluding land, are depreciated on a straight-line basis and recorded within depreciation, depletion and amortization of other assets in the consolidated statement of operations. Natural gas compressors under capitalfinance lease are depreciated over the shorter of their estimated useful lives or the term of the related lease.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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 16 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 average borrowing cost on debt by the average amount of 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.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Accounts Payable
Included in accounts payable as of December 31, 2018 and 20172019 are liabilities of approximately $104$57 million and $92 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 0 corresponding liabilities as of December 31, 2020 due to our $279 million cash balance.
Debt Issuance Costs
IncludedCosts associated with the arrangement of our Exit Credit Facility were included in other long-term assets areand will be amortized over the life of the facility using the straight-line method. The Exit Credit Facility unamortized issuance costs as of December 31, 2020 were $33 million and will begin amortization upon emergence from bankruptcy when the facility becomes fully available.
Costs associated with the issuance and amendments of the Chesapeakeour pre-petition revolving credit facility.facility were included in other long-term assets and the remaining unamortized issuance costs were amortized over the life of the facility using the straight-line method. The remaining unamortized issuance costs as of December 31, 2018 and 2017,2019 totaled $30 million and $22 million, respectively, and are being amortized over the life of the Chesapeake revolving credit facility using the straight-line method. Included in debt are costs$27 million. Costs associated with the issuance of our senior notes. Thenotes were included in long-term debt and the remaining unamortized issuance costs as of December 31, 2018 and 2017, totaled $53 million and $63 million, respectively, and arewere being amortized over the life of the senior notes using the effective interest method. The remaining unamortized issuance costs as of December 31, 2019 totaled $44 million. 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 5 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 6 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 6 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 2122 for further discussion of asset retirement obligations. CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Revenue Recognition
Revenue from the sale of oil, natural gas and NGL is recognized upon the transfer of control of the products, which is typically when the products are delivered to customers. Prior to the adoption of Revenue from Contracts with Customers (Topic 606) on January 1, 2018, revenue from the sale of oil, natural gas and NGL was recognized when title passed to customers. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration we expect to receive in exchange for those products.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Revenue from contracts with customers includes the sale of our oil, natural gas and NGL production (recorded as oil, natural gas and NGL revenues in the consolidated statements of operations) as well as the sale of certain of our joint interest holders’ production which we purchase under joint operating arrangements (recorded in marketing revenues in the consolidated statements of operations). In connection with the marketing of these products, we obtain 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.
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 earn 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, (recorded within oil, natural gas and NGL revenues in the consolidated statements of operations) as well as 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 (recorded within marketing revenues in the consolidated statements of operations).
In circumstances where we act as an agent rather than a principal, our results of operations related to oil, natural gas and NGL marketing activities are presented on a net basis. See Note 9 for further discussion of 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 5 and 14 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. As of December 31, 2018,2020, none of our open derivative instruments were designated as cash flow hedges.
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 the derivatives are deemed to contain, for accounting purposes, a significant financing element at contract inception,
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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 1314 for further discussion of our derivative instruments. Share-Based Compensation
Our share-based compensation program consists of restricted stock, stock options, performance share units and cash 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, this value is amortized over the vesting period, which is generally three 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 are settled in cash, they are classified as a liability in our consolidated financial statements 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.
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,expense, oil, natural gas and NGL production expenses,expense, exploration expense, or marketing gathering and compression expenses,expense, based on the employees involved in those activities. See Note 1112 for further discussion of share-based compensation. Recently Issued Accounting StandardsLiability Management
The Financial Accounting Standards Board (FASB) issued Topic 606 superseding virtually all existing revenue recognition guidance. We adopted this new standardLiability 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 extent that they were incremental and directly related to our bankruptcy reorganization, are reflected in reorganization items, net in our consolidated statements of operations.
2. Chapter 11 Proceedings
On June 28, 2020, the Debtors filed voluntary petitions for relief under the Bankruptcy Code in the first quarterBankruptcy Court. On June 29, 2020, the Bankruptcy Court entered an order authorizing the joint administration of 2018 using the modified retrospective approach. See Note 7 for further details regarding our adoptionChapter 11 Cases under the caption In re Chesapeake Energy Corporation, Case No. 20-33233. The Non-Filing Entities were not part of Topic 606.the Chapter 11 Cases. The Debtors and the Non-Filing Entities have continued to operate in the ordinary course of business during the Chapter 11 Cases. In February 2018,The Bankruptcy Court confirmed the FASB issued Accounting Standards Update (ASU) 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. The new standard allows for stranded tax effects resulting from the tax reform legislation commonly known as the Tax Cuts and Jobs Act, which was signed into law on December 22, 2017 (the “Tax Act”), previously recognizedPlan in accumulated other comprehensive income to be reclassified to retained earnings. For public business entities, the amendments are effective for annual periods, including interim periods within the annual periods, beginning after December 15, 2018. This standard is effective for us beginninga bench ruling on January 1, 2019,13, 2021 and we will elect not to reclassifyentered the income tax effectsConfirmation Orderon January 16, 2021.The Debtors emerged from bankruptcy on February 9, 2021 (the “Effective Date”). Although the Company is no longer a debtor-in-possession, the Company was a debtor-in-possession through the year ending December 31, 2020. As such, the Company’s bankruptcy proceedings and related matters have been summarized below.
Debtor-In-Possession
During the pendency of the Tax Act from accumulated other comprehensive incomeChapter 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 retained earnings.
In August 2017,mitigate the FASB issued ASU 2017-12, Derivativesimpact of the Chapter 11 Cases on our operations, customers and Hedging (Topic 815), which makes significant changesemployees. As a result, we were able to conduct normal business activities and pay all associated obligations for the current hedge accounting guidance. The new standard eliminatesperiod following the requirementPetition Date and were also authorized to separately measurepay mineral interest owner royalties, employee wages and report hedge ineffectivenessbenefits, and generally requires the entire changecertain vendors and suppliers 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 documentationordinary course for goods 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 plan to adopt this standard on January 1, 2019 and do not expect it to have an impact on our consolidated financial statements and related disclosures.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
services provided prior to the Petition Date. During the pendency of the Chapter 11 Cases, all transactions outside the ordinary course of business required the prior approval of the Bankruptcy Court.
In February 2016,Automatic Stay
Subject to certain specific exceptions under the FASB issued ASU 2016-02, Leases (Topic 842), which requires lesseesBankruptcy Code, the filing of the Chapter 11 Cases automatically stayed all judicial or administrative actions against us and efforts by creditors to recognize a lease liabilitycollect on or otherwise exercise rights or remedies with respect to pre-petition claims. Absent an order from the Bankruptcy Court, substantially all of the Debtors’ pre-petition liabilities were subject to compromise and a right-of-use (ROU) assetdischarge under the Bankruptcy Code. The automatic stay was lifted on the Effective Date.
Plan of Reorganization
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 approximately 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 Allowed General Unsecured Claims and reserved 37,174,210 shares of New Common Stock for issuance upon exercise of the Warrants, which were the result of the transactions described below. We also entered into a registration rights agreement, a warrants agreement and amended our articles of incorporation and bylaws for the authorization of the New Common Stock and to provide registration rights thereunder, among other corporate governance actions. See Note 11 for further discussion of our post-emergence equity. •Each holder of a Predecessor equity interest in Chesapeake, including our common and preferred stock, had such interest canceled, released, and extinguished without any distribution.
•Each holder of obligations 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 FLLO 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 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 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 issued in connection with the backstop obligation thereunder to purchase unsubscribed shares of the New Common Stock.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
•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 determination of the allowed 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 Company 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, Robert D. Lawler, and six non-employee directors, Michael Wichterich, 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 the Effective Date.
Potential Claims
We filed with the Bankruptcy Court schedules and statements setting forth, among other things, the assets and liabilities of us and each of our Debtor subsidiaries, subject to the assumptions filed in connection therewith. Certain of these schedules and statements were amended after filing. Certain holders of pre-petition claims that are not governmental units were required to file proofs of claim by the deadline for general claims, (the “bar date”), which was set by the Bankruptcy Court as October 30, 2020. Governmental units were required to file proof of claims by December 28, 2020, the deadline that was set by the Bankruptcy Court.
As of February 25, 2021, the Debtors had received approximately 8,100 proofs of claim, approximately 72% of which represent general unsecured claims, for an aggregate amount of approximately $42.7 billion. We will continue
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
to evaluate these claims throughout the Chapter 11 process and recognize or adjust amounts in future financial statements as necessary using the best information available at such time. Differences between amounts scheduled by us and claims by creditors will ultimately be reconciled and resolved in connection with the claims resolution process. In light of the expected number of creditors, the claims resolution process may take considerable time to complete and has continued after our emergence from bankruptcy.
Fresh-Start Reporting
Upon emergence from bankruptcy on February 9, 2021, we expect to qualify for fresh-start reporting. In order to qualify for fresh start-reporting (i) the holders of existing voting shares of the Company prior to its emergence must receive 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 reorganization must be less than the post-petition liabilities and allowed claims. Under the principles of fresh-start reporting, a new reporting entity will be considered to have been created, and, as a result, the Company will allocate the reorganization value of the Company to its individual assets, including property, plant and equipment, based on their estimated fair values. The process of estimating the fair value of the Company’s assets, liabilities and equity upon emergence is currently ongoing and, therefore, such amounts have not yet been finalized. In support of the Plan, the enterprise value of the Successor Company was estimated and approved by the Bankruptcy Court to be in the range of $3.5 billion to $4.7 billion.
Financial Statement Classification of Liabilities Subject to Compromise
The accompanying consolidated balance sheet as of December 31, 2020 includes amounts classified as liabilities subject to compromise, which represent liabilities we anticipate will be allowed as claims in the Chapter 11 Cases. These amounts represent our current estimate of known or potential obligations to be resolved in connection with the Chapter 11 Cases, and may differ from actual future settlement amounts paid. Differences between liabilities estimated and claims filed, or to be filed, will be investigated and resolved in connection with the claims resolution process. We will continue to evaluate these liabilities throughout the Chapter 11 process and adjust amounts as necessary. Such adjustments may be material.
Liabilities subject to compromise includes amounts related to the rejection of various executory contracts and unexpired leases. Additional amounts may be included in liabilities subject to compromise in future periods if additional executory contracts and unexpired leases are rejected. The nature of many of the potential claims arising under our executory contracts and unexpired leases has not been determined at this time, and therefore, such claims are not reasonably estimable at this time and may be material.
The following table summarizes the components of liabilities subject to compromise included on our consolidated balance sheet as of December 31, 2020:
| | | | | | | | |
| | December 31, 2020 |
| | ($ in millions) |
| Debt | | $ | 7,166 | |
| Accounts payable | | 15 | |
| Accrued interest | | 235 | |
| Provision for contract rejection damages | | 729 | |
| Other liabilities | | 498 | |
| Liabilities subject to compromise | | $ | 8,643 | |
Reorganization Items, Net
We have incurred and will continue to incur significant expenses, gains and losses associated with our reorganization, primarily the write-off of unamortized debt issuance costs and related unamortized premiums and discounts, debt and equity financing fees, provision for all leases, including operating leases,allowed claims and legal and professional fees incurred subsequent to the Chapter 11 Filings for the reorganization process. Provision for allowed claims primarily represents damages from contract rejections and settlements attributable to the midstream savings requirement as
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
stipulated by the Plan. The amount of these items, which are being expensed as incurred significantly affect our statements of operations.
The following table summarizes the components in reorganization items, net included in our consolidated statements of operations for the year ended December 31, 2020:
| | | | | | | | |
| | Year Ended December 31, 2020 |
| | ($ in millions) |
| Provision for allowed claims | | (879) | |
| Write off of unamortized debt premiums (discounts) | | 518 | |
| Write off of unamortized debt issuance costs | | (61) | |
| Debt and equity financing fees | | (145) | |
| Loss on divested assets | | (128) | |
| Legal and professional fees | | (113) | |
| Gain on settlement of pre-petition accounts payable | | 15 | |
| Loss on settlement of pre-petition revenues payable | | (3) | |
| Reorganization items, net | | $ | (796) | |
Going Concern
During the Company’s bankruptcy proceedings and prior to the Bankruptcy Court’s entry of an order confirming the Debtors’ Plan of Reorganization, the Company’s ability to continue as a going concern was contingent upon, among other things, its ability to (i) develop and successfully implement a plan of reorganization and obtain creditor acceptance and confirmation under the Bankruptcy Code, (ii) achieve savings on certain midstream contracts through rejection or renegotiation of terms, (iii) achieve certain liquidity metrics, and (iv) obtain exit financing sources sufficient to meet the Company’s future obligations. The Company’s debt obligations and uncertainties related to the bankruptcy process raised substantial doubt about its ability to continue as a going concern.
As a result of the execution of the Plan of Reorganization and emergence from bankruptcy on February 9, 2021, management concluded there is no longer substantial doubt about the Company’s ability to continue as a going concern.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
3. Oil and Natural Gas Property Transactions
Mid-Continent Divestiture
On October 13, 2020, we filed a notice with termsthe Bankruptcy Court that we reached an agreement with Tapstone Energy in excessa 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 12 months. This ASU modifies the definitionauction 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 leasegain 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 to transfer certain Haynesville assets, including interests in 144 producing wells and outlinesapproximately 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 and the exchange resulted in the recognition measurement, presentation,of loss of approximately $128 million based on the difference between the carrying value of the assets and disclosurethe fair value of leasing arrangementsthe assets surrendered. The exchange was executed to obtain sufficient savings on midstream obligations as required by both lesseesthe 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 lessors.gas company with operations in the Eagle Ford Shale and Austin Chalk formations in southeast Texas, for approximately 3.6 million reverse stock split-adjusted shares of our common stock and $381 million in cash. We funded the cash portion of the consideration through borrowings under the pre-petition revolving credit facility. In connection with the closing, we acquired all of WildHorse’s debt. See Note 5 for additional information on the acquired debt. 2019 Purchase Price Allocation
We have accounted for the acquisition of WildHorse and its corresponding merger (the “Merger”) with and into our wholly owned subsidiary, Brazos Valley Longhorn, L.L.C. (“Brazos Valley Longhorn” or “BVL”), as a business combination, using the acquisition method. The standard will not applyfollowing table represents the final allocation of the total purchase price of WildHorse to our leasesthe identifiable assets acquired and the liabilities assumed based on the fair values as of mineral rights to explore for or usethe acquisition date.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| | | | | |
| 2019
Purchase Price Allocation |
| ($ in millions) |
| Consideration: | |
| Cash | $ | 381 | |
Fair value of Chesapeake’s common stock issued in the Merger (a) | 2,037 | |
| Total consideration | $ | 2,418 | |
| |
| Fair Value of Liabilities Assumed: | |
| Current liabilities | $ | 166 | |
| Long-term debt | 1,379 | |
| Deferred tax liabilities | 314 | |
| Other long-term liabilities | 36 | |
| Amounts attributable to liabilities assumed | $ | 1,895 | |
| |
| Fair Value of Assets Acquired: | |
| Cash and cash equivalents | $ | 28 | |
| Other current assets | 128 | |
| Proved oil and natural gas properties | 3,264 | |
| Unproved properties | 756 | |
| Other property and equipment | 77 | |
| Other long-term assets | 60 | |
| Amounts attributable to assets acquired | $ | 4,313 | |
| |
| Total identifiable net assets | $ | 2,418 | |
(a) Based on 3.6 reverse stock split-adjusted Chesapeake common shares issued at closing at $568 per share (closing price as of February 1, 2019).
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The fair values of assets acquired and liabilities assumed were based on the following key inputs:
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 resources, including the intangible rights to explore for those natural resources and rights to use the land in which those natural resources are contained. We plan to make certain elections permitting us to not reassess whether any expired or existing contracts contained leases, permitting us to not reassess the lease classification for any expired or existing leases (all existing leases that were classified as operating leases in accordance with Topic 840 will be classified as operating leases, and all existing leases that were classified as capital leases in accordance with Topic 840 will be classified as finance leases), and permitting us to not reassess initial direct costs for any existing leases. We will also take an election permitting us to continue applying our current policy for land easements that existedproperties as of or expired before, the effectiveacquisition 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 a combination of the NYMEX strip pricing and consensus pricing to not recognizevalue the reserves. Our estimates of commodity prices for purposes of determining discounted cash flows ranged from a ROU asset or lease liability2019 price of $56.33 per barrel of oil increasing to a 2023 price of $61.17 per barrel of oil. Similarly, natural gas prices ranged from a 2019 price of $2.82 per mmbtu then increasing to a 2023 price of $3.00 per mmbtu. Both oil and natural gas commodity prices were held flat after 2023 and adjusted for short-term leases.inflation. We then applied various discount rates depending on the classification of reserves and other risk 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 estimated 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.
Deferred Income Taxes
For federal income tax purposes, the WildHorse acquisition qualified as a tax-free merger, as a result, we acquired carryover tax basis in WildHorse’s assets and liabilities. Deferred tax liabilities and assets were recorded for differences between the purchase price allocated to the assets acquired and liabilities assumed based on the fair value and the carryover tax basis. See Note 10 for further discussion of deferred income taxes. WildHorse Revenues and Expenses Subsequent to Acquisition
We have completedincluded in our assessmentconsolidated statements of contracts potentially affected by the new standardoperations revenues of $752 million, direct operating expenses of $810 million, including depreciation, depletion and have completed our assessment of the accounting treatment for these leases. The adoption will primarily impact other assetsamortization, and other liabilitiesexpense of $83 million related to the WildHorse business for the period from February 1, 2019 to December 31, 2019.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Pro Forma Financial Information
The following unaudited pro forma financial information for the years ended December 31, 2019 and will also impact ongoing disclosures but will not have a material impact2018, respectively, is based on our balance sheet, results of operations or cash flows. We planhistorical consolidated financial statements adjusted to adoptreflect as if the new standardWildHorse acquisition had occurred on January 1, 2018. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including adjustments to conform the classification of expenses in WildHorse’s statements of operations to our classification for similar expenses and the estimated tax impact of pro forma adjustments.
| | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2019 | | 2018 |
| | ($ in millions except per share data) |
| Revenues | | $ | 8,587 | | | $ | 11,211 | |
| Net income (loss) available to common stockholders | | $ | (431) | | | $ | 195 | |
Earnings (loss) per common share:(a) | | | | |
| Basic | | $ | (51.77) | | | $ | 42.89 | |
| Diluted | | $ | (51.77) | | | $ | 42.89 | |
(a)All per share information has been retroactively adjusted to reflect the 1-for-200 (1:200) reverse stock split effective April 14, 2020. See Note 11 for additional information. 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 effective date,sale of non-core oil and natural gas properties.
2018 Transactions
We sold all of our approximately 1,500,000 gross (900,000 net) acres in Ohio, of which approximately 320,000 net acres are prospective for the Utica Shale with approximately 920 producing wells, along with related property and equipment for net proceeds of $1.868 billion to Encino, with additional contingent payments to us of up to $100 million comprised of $50 million in consideration in each case if, on or prior to December 31, 2019, there is a period of twenty (20) trading days out of a period of thirty (30) consecutive trading days where (i) the average of the NYMEX natural gas strip prices for the months comprising the year 2022 equals or exceeds $3.00/mmbtu as permitted by ASU 2018-11calculated pursuant to the purchase agreement, and (ii) the average of the NYMEX natural gas strip prices for the months comprising the year 2023 equals or exceeds $3.25/mmbtu as calculated pursuant to the purchase agreement. The contingent consideration expired on December 31, 2019 with no value attributed to the arrangement. We recognized a loss of approximately $273 million associated with the transaction.
In 2018, we will not adjust comparative-period financial statementssold portions of our acreage, producing properties and will continue to apply the guidance in ASC 840, including its disclosure requirements,other related property and equipment in the comparative periods presented priorMid-Continent, including our Mississippian Lime assets, for approximately $491 million, subject to adoption.
Reclassifications
Certain reclassifications have been madecertain customary closing adjustments. Included in the sales were approximately 238,500 net acres and interests in approximately 3,200 wells. We recognized a gain of approximately $12 million associated with the transactions. Also, in 2018, we received proceeds of approximately $37 million subject to the consolidated financial statements for 2017 and 2016 to conform to the presentation usedcustomary closing adjustments, for the 2018 consolidated financial statements.sale of other oil and natural gas properties covering various operating areas.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
4. 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. See Note 3 for further discussion of our convertible senior notes and contingent convertible senior notes. Shares of common stock for the following dilutive securities were excluded from the calculation of diluted EPS as the effect was antidilutive.
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| | | (thousands) |
Common stock equivalent of our preferred stock outstanding(a) | | 290 | | | 290 | | | 298 | |
Common stock equivalent of our convertible senior notes outstanding(a) | | 621 | | | 621 | | | 729 | |
Common stock equivalent of our preferred stock outstanding prior to exchange(a) | | 0 | | | 5 | | | 0 | |
Participating securities(a) | | 0 | | | 2 | | | 6 | |
(a)Amount has been retroactively adjusted to reflect the 1-for-200 (1:200) reverse stock split effective April 14, 2020. See Note 11 for additional information. As a result of the Company’s reverse stock split effective on April 14, 2020, proportionate adjustments were made to the conversion price of Chesapeake’s outstanding 5.5% Convertible Senior Notes due 2026, 4.5% Cumulative Convertible Preferred Stock, 5.00% Cumulative Convertible Preferred Stock (Series 2005B), 5.75% Cumulative Convertible Non-Voting Preferred Stock (Series A) and 5.75% Cumulative Non-Voting Convertible Preferred Stock and to the outstanding awards and number of shares issued and issuable under the Company's equity compensation plans. See Note 11 for additional information. |
| | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| | | (in millions) |
| Common stock equivalent of our preferred stock outstanding | | 60 |
| | 60 |
| | 63 |
|
| Common stock equivalent of our convertible senior notes outstanding | | 146 |
| | 146 |
| | 146 |
|
| Common stock equivalent of our preferred stock outstanding prior to exchange | | — |
| | 1 |
| | 37 |
|
| Participating securities | | 1 |
| | 1 |
| | 1 |
|
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
5. Debt
Chapter 11 Proceedings and Emergence
The Bankruptcy Filing constituted an event of default under certain of our secured and unsecured debt obligations. As a result of the Bankruptcy Filing, the principal and interest due under these debt instruments became immediately due and payable. However, pursuant to Section 362 of the Bankruptcy Code, the creditors were stayed from taking any action as a result of such defaults. On the Effective Date, our obligations under the FLLO Term Loan and Senior Notes, including interest and accrued interest, were fully extinguished in exchange for equity in the post-emergence Company. In addition, our pre-petition revolving credit facility was restructured into a new exit credit facility.
Reclassification of Debt
The principal amounts outstanding under the FLLO Term Loan, Second Lien Notes and all of our other unsecured senior and convertible senior notes were reclassified as liabilities subject to compromise on the accompanying consolidated balance sheet as of December 31, 2020. Additionally, non-cash adjustments were made to write off all of the related unamortized debt issuance costs and associated discounts and premiums of approximately $457 million, which are included in reorganization items, net in the accompanying consolidated statements of operations for the year ended December 31, 2020, as discussed in Note 2. The agreements for our FLLO Term Loan, Second Lien Notes, and unsecured senior and convertible senior notes contain provisions regarding the calculation of interest upon default. Upon default, the interest rate on the FLLO Term Loan increased from LIBOR plus 8.00% to alternative base rate (ABR) (3.25% during the fourth quarter) plus Applicable Margin (7.00% during the fourth quarter) plus 2.00%. For the Second Lien Notes and all of our other unsecured senior and convertible senior notes, the interest rate remained the same upon default. However, interest accrued on the amount of unpaid interest in addition to the principal balance. We did not pay or recognize interest on the FLLO Term Loan, Second Lien Notes, or unsecured senior and convertible senior notes during the Chapter 11 process.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Pre-emergence debt
Our long-term debt consisted of the following as of December 31, 20182020 and 2017:2019:
| | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 | | December 31, 2019 |
| Principal Amount | | Carrying
Amount | | Principal
Amount | | Carrying Amount |
| ($ in millions) |
| DIP credit facility | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| Pre-petition revolving credit facility | 1,929 | | | 1,929 | | | 1,590 | | | 1,590 | |
| Term loan due 2024 | 1,500 | | | 1,500 | | | 1,500 | | | 1,470 | |
| 11.5% senior secured second lien notes due 2025 | 2,330 | | | 2,330 | | | 2,330 | | | 3,248 | |
| 6.625% senior notes due 2020 | 176 | | | 176 | | | 208 | | | 208 | |
| 6.875% senior notes due 2020 | 73 | | | 73 | | | 93 | | | 93 | |
| 6.125% senior notes due 2021 | 167 | | | 167 | | | 167 | | | 167 | |
| 5.375% senior notes due 2021 | 127 | | | 127 | | | 127 | | | 127 | |
| 4.875% senior notes due 2022 | 272 | | | 272 | | | 338 | | | 338 | |
| 5.75% senior notes due 2023 | 167 | | | 167 | | | 209 | | | 209 | |
| 7.00% senior notes due 2024 | 624 | | | 624 | | | 624 | | | 624 | |
| 6.875% senior notes due 2025 | 2 | | | 2 | | | 2 | | | 2 | |
| 8.00% senior notes due 2025 | 246 | | | 246 | | | 246 | | | 245 | |
| 5.5% convertible senior notes due 2026 | 1,064 | | | 1,064 | | | 1,064 | | | 765 | |
| 7.5% senior notes due 2026 | 119 | | | 119 | | | 119 | | | 119 | |
| 8.00% senior notes due 2026 | 46 | | | 46 | | | 46 | | | 44 | |
| 8.00% senior notes due 2027 | 253 | | | 253 | | | 253 | | | 253 | |
| Debt issuance costs | — | | | 0 | | | — | | | (44) | |
| Total debt, net | 9,095 | | | 9,095 | | | 8,916 | | | 9,458 | |
| Less current maturities of long-term debt, net | (1,929) | | | (1,929) | | | (385) | | | (385) | |
| Less amounts reclassified to liabilities subject to compromise | (7,166) | | | (7,166) | | | 0 | | | 0 | |
| Total long-term debt, net | $ | 0 | | | $ | 0 | | | $ | 8,531 | | | $ | 9,073 | |
|
| | | | | | | | | | | | | | | |
| | December 31, 2018 | | December 31, 2017 |
| | Principal Amount | | Carrying
Amount | | Principal
Amount | | Carrying
Amount |
| | ($ in millions) |
| 7.25% senior notes due 2018 | — |
| | — |
| | 44 |
| | 44 |
|
| Floating rate senior notes due 2019 | 380 |
| | 380 |
| | 380 |
| | 380 |
|
| 6.625% senior notes due 2020 | 437 |
| | 437 |
| | 437 |
| | 437 |
|
| 6.875% senior notes due 2020 | 227 |
| | 227 |
| | 227 |
| | 227 |
|
| 6.125% senior notes due 2021 | 548 |
| | 548 |
| | 548 |
| | 548 |
|
| 5.375% senior notes due 2021 | 267 |
| | 267 |
| | 267 |
| | 267 |
|
| 4.875% senior notes due 2022 | 451 |
| | 451 |
| | 451 |
| | 451 |
|
8.00% senior secured second lien notes due 2022(a) | — |
| | — |
| | 1,416 |
| | 1,895 |
|
| 5.75% senior notes due 2023 | 338 |
| | 338 |
| | 338 |
| | 338 |
|
| 7.00% senior notes due 2024 | 850 |
| | 850 |
| | — |
| | — |
|
| 8.00% senior notes due 2025 | 1,300 |
| | 1,291 |
| | 1,300 |
| | 1,290 |
|
5.5% convertible senior notes due 2026(b)(c)(d) | 1,250 |
| | 866 |
| | 1,250 |
| | 837 |
|
| 7.5% senior notes due 2026 | 400 |
| | 400 |
| | — |
| | — |
|
| 8.00% senior notes due 2027 | 1,300 |
| | 1,299 |
| | 1,300 |
| | 1,298 |
|
2.25% contingent convertible senior notes due 2038(b)(d) | 1 |
| | 1 |
| | 9 |
| | 8 |
|
| Term loan due 2021 | — |
| | — |
| | 1,233 |
| | 1,233 |
|
| Revolving credit facility | 419 |
| | 419 |
| | 781 |
| | 781 |
|
| Debt issuance costs | — |
| | (53 | ) | | — |
| | (63 | ) |
| Interest rate derivatives | — |
| | 1 |
| | — |
| | 2 |
|
| Total debt, net | 8,168 |
| | 7,722 |
| | 9,981 |
| | 9,973 |
|
Less current maturities of long-term debt, net(e) | (381 | ) | | (381 | ) | | (53 | ) | | (52 | ) |
| Total long-term debt, net | $ | 7,787 |
| | $ | 7,341 |
| | $ | 9,928 |
| | $ | 9,921 |
|
In 2020, we repurchased approximately $160 million aggregate principal amount of the following senior notes for $95 million and recorded an aggregate gain of approximately $65 million.
| | | | | | | | |
(a) | The carrying amount as of December 31, 2017 included a premium amount of $479 million associated with a troubled debt restructuring. The premium was being amortized based on the effective yield method. | Notes Repurchased |
| | ($ in millions) |
| 6.625% senior notes due 2020 | | $ | 32 | |
(b)6.875% senior notes due 2020 | 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. |
| 20 | |
(c) | The conversion and redemption provisions of our convertible4.875% senior notes are as follows:due 2022 | | 66 | |
| 5.75% senior notes due 2023 | | 42 | |
| Total | | $ | 160 | |
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 a threshold amount during a specified period in a fiscal quarter. Convertibility based on common stock price is measured quarterly. During the fourth quarter of 2018, the price of our common stock was below the threshold level and, as a result, the holders do not have the option to convert their notes in the first quarter of 2019 under this provision. The notes are also convertible, at the holder’s option, during specified five-day periods if the trading price of the notes is below certain levels determined by reference to the trading price of our common stock. The notes were not convertible under this provision during the year ended December 31, 2018. Upon conversion of
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Debt Issuances and Retirements 2019
Term Loan. In December 2019, we entered into a convertiblesecured 4.5-year term loan facility in an aggregate principal amount of $1.5 billion for net proceeds of approximately $1.455 billion. Our obligations under the new facility are unconditionally guaranteed on a joint and several basis by the same subsidiaries that guarantee our revolving credit facility and second lien notes (including BVL and its subsidiaries) and are secured by first-priority liens on the same collateral securing our revolving credit facility (with a position in the collateral proceeds waterfall junior to the revolving credit facility). The term loan bears interest at a rate of London Interbank Offered Rate (LIBOR) plus 8.00% per annum, subject to a 1.00% LIBOR floor, or the Alternative Base Rate (ABR) plus 7.00% per annum, subject to a 2.00% ABR floor, at our option. The loan was made at 98% of par. We used the net proceeds to finance tender offers for our unsecured BVL senior note,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 holderretirement of our BVL senior notes and the BVL revolving credit facility.
The term loan matures in June 2024 and voluntary prepayments are subject to a make-whole premium prior to the 18-month anniversary of the closing of the term loan, a premium to par of 5.00% from the 18-month anniversary until but excluding the 30-month anniversary, a premium to par of 2.5% from the 30-month anniversary until but excluding the 42-month anniversary and at par beginning on the 42-month anniversary. The term loan may be subject to mandatory prepayments and offers to prepay 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.
Events of default under the term loan include, among other things, nonpayment of principal, interest or other amounts; violation of covenants; incorrectness of representations and warranties in any material respect; cross-payment default and cross acceleration with respect to other indebtedness with an outstanding principal balance of $125 million or more; bankruptcy; judgments involving liability of $125 million or more that are not paid; and ERISA events. Many events of default are subject to customary notice and cure periods.
Senior Secured Second Lien Notes. In December 2019, we completed private offers to exchange newly issued 11.5% Senior Secured Second Lien Notes due 2025 (the “Second Lien Notes”) for the following outstanding senior unsecured notes (the “Existing Notes”):
| | | | | | | | |
| | Notes Exchanged |
| | ($ in millions) |
| 7.00% senior notes due 2024 | | $ | 226 | |
| 8.00% senior notes due 2025 | | 999 | |
| 8.00% senior notes due 2026 | | 873 | |
| 7.5% senior notes due 2026 | | 281 | |
| 8.00% senior notes due 2027 | | 837 | |
| Total | | $ | 3,216 | |
The Second Lien Notes are secured second lien obligations and are contractually junior to our current and future secured first lien indebtedness, including indebtedness incurred under our revolving credit facility and term loan facility, to the extent of the value of the collateral securing such indebtedness, effectively senior to all 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, make certain restricted payments, 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
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
independent of its subsidiaries. Chesapeake’s obligations under the Second Lien Notes are jointly and severally, fully and unconditionally guaranteed by the same subsidiaries that guarantee our revolving credit facility and term loan facility (including BVL and its subsidiaries). See Note 24 for condensed combined debtor financial information regarding our guarantor and non-guarantor subsidiaries. The exchanges of the Existing Notes (with a carrying value of $3.152 billion) for $2.210 billion of Second Lien Notes, were accounted for as a troubled debt restructuring. For the majority of the notes in this exchange, the future undiscounted cash flows were greater than the net carrying value of the original debt, so no gain was recognized and a new effective interest rate was established based on the carrying value of the original debt. The amount of the extinguished debt will receive cash,be amortized over the life of the notes as a reduction to interest expense. As a result, our reported interest expense will be significantly less than the contractual interest payments throughout the term of the Second Lien Notes.
In a subsequent transaction in December 2019, we issued an additional $120 million of 11.5% Senior Secured Second Lien Notes due 2025 pursuant to a private offering, at 89.75% of par. Additionally, in December 2019, we entered into a purchase and sale agreement with the same counterparty to acquire $101 million principal amount of our 6.625% Senior Notes due 2020, 4.875% Senior Notes due 2022 and 5.75% Senior Notes due 2023 at a discount. During the first quarter of 2020, we repurchased the senior notes.
Exchanges of Senior Notes for Common Stock. We privately negotiated exchanges of approximately $507 million principal amount of our outstanding senior notes for 235,563,519 shares of common stock or a combinationand $186 million principal amount of cash and common stock, at our election, according to the conversion rate specified in the indenture.
The common stock price conversion threshold amount for the convertible senior notes is 130% of the conversion price of $8.568.
Optional Redemption by the Company. We may redeem theoutstanding convertible senior notes for cash on73,389,094 shares of common stock. We recorded an aggregate net gain of approximately $64 million associated with the exchanges.
We issued at par approximately $919 million of 8.00% Senior Notes due 2026 (“2026 notes”) pursuant to a private exchange offer for the following outstanding senior unsecured notes:
| | | | | | | | |
| | Notes Exchanged |
| | ($ in millions) |
| 6.625% senior notes due 2020 | | $ | 229 | |
| 6.875% senior notes due 2020 | | 134 | |
| 6.125% senior notes due 2021 | | 381 | |
| 5.375% senior notes due 2021 | | 140 | |
| Total | | $ | 884 | |
We may redeem some or after September 15, 2019, if the price of our common stock exceeds 130%all of the conversion price during a specified period2026 notes at any time prior to March 15, 2022 at a redemption price ofequal to 100% of the principal amount of the notes.
Holders’ Demand Repurchase Rights. The holdersnotes to be redeemed plus a “make-whole” premium. At any time prior to March 15, 2022, we also may redeem up to 35% of our convertible senior notes may require us to repurchase, in cash, all or a portion of their notes at 100% of the aggregate principal amount of each series of notes with an amount of cash not greater than the net cash proceeds of certain equity offerings at a specified redemption price. In addition, we may redeem some or all of the 2026 notes at any time on or after March 15, 2022 at the redemption prices in accordance with the terms of the notes, uponthe indenture and supplemental indenture governing the notes. These senior notes are unsecured 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 are jointly and severally, fully and unconditionally guaranteed by all of our wholly owned subsidiaries that guarantee the Chesapeake revolving credit facility and certain fundamental changes.
| |
(d) | The carrying amounts as of December 31, 2018 and 2017, are reflected net of discounts of $384 million and $414 million, respectively, associated with the equity component of our convertible and contingent convertible senior notes. This amount is being amortized based on the effective yield method through the first demand repurchase date as applicable. |
| |
(e) | As of December 31, 2018, net current maturities of long-term debt includes our Floating Rate Senior Notes due April 2019 and our 2.25% Contingent Convertible Senior Notes due 2038. |
Debt maturitiesother unsecured senior notes. We accounted for the next five yearsexchange as a modification to existing debt and thereafter are as follows:no gain or loss was recognized.
|
| | | | |
| | | Principal Amount of Debt Securities |
| | | ($ in millions) |
| 2019 | | $ | 381 |
|
| 2020 | | 664 |
|
| 2021 | | 815 |
|
| 2022 | | 451 |
|
| 2023 | | 757 |
|
| Thereafter | | 5,100 |
|
| Total | | $ | 8,168 |
|
We repaid upon maturity $380 million principal amount of our Floating Rate Senior Notes due April 2019 with borrowings from our Chesapeake revolving credit facility.
Debt Issuances and Retirements 2018
We issued at par $850 million of 7.00% Senior Notes due 2024 (“2024 notes”) and $400 million of 7.50% Senior Notes due 2026 (“2026 notes”) pursuant to a public offering for net proceeds of approximately $1.236 billion. We may redeem some or all of the 2024 notes at any time prior to April 1, 2021 and some or all of the 2026 notes at
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
any time prior to October 1, 2021, in each case at a price equal to 100% of the principal amount of the notes to be redeemed plus a “make-whole” premium. At any time prior to April 1, 2021, with respect to the 2024 notes, and October 1, 2021, with respect to the 2026 notes, we also may redeem up to 35% of the aggregate principal amount of each series of notes with an amount of cash not greater than the net cash proceeds of certain equity offerings at a specified redemption price. In addition, we may redeem some or all of the 2024 notes at any time on or after April 1, 2021 and some or all of the 2026 notes at any time on or after October 1, 2021, in each case at the redemption prices in accordance with the terms of the notes and the indenture and supplemental indenture governing the notes. These senior notes are unsecured 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 are jointly and severally, fully and unconditionally guaranteed by certain of our direct and indirect wholly owned subsidiaries.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
We used the net proceeds from the 2024 and 2026 notes, together with cash on hand and borrowings under the Chesapeake revolving credit facility, to repay in full $1.233 billion of borrowings under our secured term loan due 2021 for $1.285 billion, which included a $52 million make-whole premium. We recorded a loss of approximately $65 million associated with the repayment of the term loan, including the make-whole premium and the write-off of $13 million of associated deferred charges.
We used a portion of the proceeds from the sale of our Utica Shale assets in Ohio to redeem all of the $1.416 billion aggregate principal amount outstanding of our 8.00% Senior Secured Second Lien Notes due 2022 for $1.477 billion. We recorded a gain of approximately $331 million associated with the redemption, including the realization of the remaining $391 million difference in principal and book value due to troubled debt restructuring accounting in 2015, offset by the make-whole premium of $60 million.
We repaid upon maturity $44 million principal amount of our 7.25% Senior Notes due 2018.
As required by the terms of the indenture for our 2.25% Contingent Convertible Senior Notes due 2038 (“2038 notes”), the holders were provided the option to require us to purchase on December 15, 2018, all or a portion of the holders’ 2038 notes at par plus accrued and unpaid interest up to, but excluding, December 15, 2018. On December 17, 2018, we paid an aggregate of approximately $8 million to purchase all of the 2038 notes that were tendered and not withdrawn. An aggregate of $1 million principal amount of the 2038 notes remained outstanding as of December 31, 2018. Subsequent to December 31, 2018, we redeemed these notes at par and discharged the related indenture.
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.
We retired $2.389 billion principal amount of our outstanding senior notes, senior secured second lien notes, contingent convertible notes and term loan through purchases in the open market, tender offers or repayment upon maturity for $2.592 billion using proceeds from the issuances described above. For the open market repurchases and tender offers, we recorded a net aggregate gain of approximately $233 million, including $374 million of premium associated with our 8.00% Senior Secured Second Lien Notes due 2022.
Senior Notes and Convertible Senior Notes
Our senior notes and our 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 convertible senior notes are jointly and severally, fully and unconditionally guaranteed by certain of our direct and indirect wholly owned subsidiaries. See Note 2324 for consolidating financial information regarding our guarantor and non-guarantor subsidiaries. We may redeem theOur senior notes, other than the convertible senior notes, were redeemable at any time at specified make-whole or redemption prices. Our senior notes arewere governed by indentures containing covenants that maycould limit our ability and our subsidiaries’ ability to incur certain secured indebtedness, enter into sale-leaseback transactions, and consolidate, merge or transfer assets. The indentures governing the senior notes and the convertible senior notes dodid not have any financial or restricted payment covenants. Indentures for the senior notes and convertible senior notes havehad cross
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
default provisions that applyapplied to other indebtedness Chesapeake or any guarantor subsidiary may have from time to time with an outstanding principal amount of at least $50 million or $75 million, depending on the indenture.
ChesapeakePre-Petition Revolving Credit Facility
In 2018, we amended and restated our credit agreement dated December 15, 2014. The amended and restated ChesapeakeOur revolving credit facility matureswas scheduled to mature in September 2023 and the aggregate initial commitment of the lenders and borrowing base under the facility iswas $3.0 billion. The Chesapeake revolving credit facility provides for an accordion feature, pursuant to which the aggregate commitments thereunder may be increased to up to $4.0 billion from time to time, subject to agreement of the participating lenders and certain other customary conditions. Borrowing base redeterminations will continue to occur semiannually and our next borrowing base redetermination is scheduled for the second quarter of 2019. As of
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
December 31, 2018,2020, we had outstanding borrowings of $419 million$1.929 billion under the Chesapeakeour revolving credit facility and had used $107$54 million of the Chesapeake revolving credit facility for various letters of credit. We recorded a loss of $3 million associated with certain deferred charges related to the Chesapeake revolving credit facility prior to its amendment and restatement.
Borrowings under the Chesapeakeour revolving credit facility bear interest at an alternative base rate (ABR) or LIBOR, at our election, plus an applicable margin ranging from 0.50%-2.00%1.50%-2.50% per annum for ABR loans and 1.50%-3.00%2.50%-3.50% per annum for LIBOR loans, depending on the percentage of the borrowing base then being utilized and whether our leverage ratio exceeds 4.00 to 1.utilized.
The ChesapeakeOur revolving credit facility iswas subject to various financial and other covenants. The terms of the revolving credit facility includeincluded covenants limiting, among other things, our ability to incur additional indebtedness, make investments or loans, incur liens, consummate mergers and similar fundamental changes, make restricted payments, make investments in unrestricted subsidiaries and enter into transactions with affiliates. The Chesapeake revolving
On December 3, 2019, we entered into the second amendment to our credit facility contains financial covenants that, afteragreement. Among other things, the suspensionamendment (i) permitted the issuance of mostcertain secured indebtedness with a lien priority or proceeds recovery behind the obligations under the credit agreement without a corresponding 25% reduction in the borrowing base under the credit agreement, if issued by the next scheduled redetermination of the covenants duringborrowing base, (ii) increased the fourthamount of indebtedness that can be secured on a pari passu first-lien basis with (and with recovery proceeds behind) the obligations under the credit agreement from $1 billion to $1.5 billion, (iii) increased the applicable margin as defined in the credit agreement on borrowings under the credit agreement by 100 basis points, (iv) requires liquidity of at least $250 million at all times, (v) for each fiscal quarter of 2018commencing with the fiscal quarter ending December 31, 2019, replaced the secured leverage ratio financial covenant with a requirement that the first lien secured leverage ratio not exceed 2.50 to 1 as a result of the closingend of such fiscal quarter, (vi) increased the maximum permitted leverage ratio as of the saleend of certain of our Utica Shale, beginning in the firsteach fiscal quarter of 2019, require us to maintain (i) a leverage ratio of not more than 5.504.50 to 1 through the fiscal quarter ending September 30, 2019, which threshold decreases over timeDecember 31, 2021, with step-downs to 4.004.25 to 1 for the fiscal quarter ending March 31, 20212022 and to 4.00 to 1 for each fiscal quarter ending thereafter, (ii) a secured leverage ratioand (vii) required that we use the aggregate net cash proceeds of not more than 2.50certain asset sales in excess of $50 million to 1prepay certain indebtedness and/or reduce commitments under our credit agreement, until the laterretirement of (x)all of our senior notes maturing before September 12, 2023. On December 26, 2019, we entered into the fiscal quarter ending March 31, 2021 or (y)third amendment to our credit agreement, which, among other things, permitted the fiscal quarter in whenissuance of certain secured indebtedness with a lien priority behind the Company’s leverage ratio does not exceed 4.00 to 1 and (iii) a fixed charge coverage ratio of not less than 2.00 to 1 through the fiscal quarter ending December 31, 2019; not less than 2.25 to 1 through the fiscal quarter ending June 30, 2020; and not less than 2.50 to 1 for the fiscal quarter ended September 30, 2020 and thereafter.
For the fiscal quarter ended December 31, 2018, our only applicable financial covenant required us to maintain a leverage ratio of not more than 5.50 to 1.
As of December 31, 2018, we were in compliance with all applicable financial covenantsobligations under the credit agreement and we were able to borrow up towithout a corresponding 25% reduction in the full availabilityborrowing base under the Chesapeake revolving credit facility.agreement, if issued by December 31, 2019 and issued in exchange for, or the proceeds used to refinance, our senior notes.
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, 2020 | | December 31, 2019 |
| | Carrying Amount | | Estimated Fair Value | | Carrying Amount | | Estimated Fair Value |
| | | | | ($ in millions) | | |
| Short-term debt (Level 1) | | $ | 0 | | | $ | 0 | | | $ | 385 | | | $ | 360 | |
| Long-term debt (Level 1) | | $ | 0 | | | $ | 0 | | | $ | 753 | | | $ | 622 | |
| Long-term debt (Level 2) | | $ | 0 | | | $ | 0 | | | $ | 8,320 | | | $ | 6,085 | |
| Liabilities subject to compromise (Level 1) | | $ | 982 | | | $ | 43 | | | $ | 0 | | | $ | 0 | |
| Liabilities subject to compromise (Level 2) | | $ | 6,184 | | | $ | 1,694 | | | $ | 0 | | | $ | 0 | |
Post-emergence Debt
Our post-emergence exit financing consists of a senior secured Exit Credit Facility, which includes a reserve-based revolving credit facility and a non-revolving loan facility, and unsecured senior notes, which all were entered into on the Effective Date. The initial outstanding principal amounts under the Exit Credit Facility and unsecured senior notes were:
|
| | | | | | | | | | | | | | | | |
| | | December 31, 2018 | | December 31, 2017 |
| | | Carrying Amount | | Estimated Fair Value | | Carrying Amount | | Estimated Fair Value |
| | | | | ($ in millions) | | |
| Short-term debt (Level 1) | | $ | 381 |
| | $ | 379 |
| | $ | 52 |
| | $ | 53 |
|
| Long-term debt (Level 1) | | $ | 3,495 |
| | $ | 3,173 |
| | $ | 2,633 |
| | $ | 2,629 |
|
| Long-term debt (Level 2) | | $ | 3,846 |
| | $ | 3,644 |
| | $ | 7,286 |
| | $ | 7,301 |
|
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| | | | | | | | |
4. | Contingencies and Commitments | February 9, 2021 |
| | ($ in millions) |
| 5.5% Senior Notes due 2026 | | $ | 500 | |
| 5.875% Senior Notes due 2029 | | 500 | |
| Exit Credit Facility - Exit Revolver | | 50 | |
| Exit Credit Facility - Non-Revolving Loan Facility | | 221 | |
| Total | | $ | 1,271 | |
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 (the “Exit 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 and the next scheduled redetermination will be on or about October 1, 2021. The aggregate initial elected commitments of the lenders under the Exit Credit Facility will be $1.75 billion of revolving Tranche A Loans (the “Tranche A Loans”) and $220 million of fully funded Tranche B Loans (the “Tranche B Loans”).
The Exit Credit Facility provides for a $200.0 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 had no additional secured debt outstanding at emergence.
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 (the “Escrow Issuer”) an indirect wholly-owned subsidiary of the Company, issued $500 million aggregate principal amount of its 5.5% 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 is part of a series of exit financing transactions being 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.
The Notes are guaranteed on a senior unsecured basis by each of the Company’s subsidiaries that guarantee the Exit Credit Facility. The gross proceeds from the offering of the Notes were deposited into a segregated escrow account (the “Escrow Account”) and were released upon satisfaction of certain escrow release conditions (the “Escrow Conditions”), including the occurrence of the Effective Date. Prior to the satisfaction of the Escrow Conditions, the Notes are secured by a lien on amounts deposited into the Escrow Account.
The Notes were issued pursuant to an indenture, dated as of February 5, 2021 (the “Indenture”), among the Issuer, the Guarantors and Deutsche Bank Trust Company Americas, as trustee.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Interest on the Notes will be payable semi-annually, on February 1st and August 1st of each year, commencing on August 1, 2021, to holders of record on the immediately preceding January 15th and July 15th.
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 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.
6. 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. The majority of these prepetition legal proceedings, including the matters below, have been settled during the Chapter 11 Cases or will be resolved in connection with the claims reconciliation process before the Bankruptcy Court. Any allowed claim related to such prepetition litigation will be treated in accordance with the Plan.
Business Operations. We are involved in various lawsuits and disputes incidental to our business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions. The majority of these prepetition legal proceedings have been settled during the Chapter 11 Cases or will be resolved in connection with the claims reconciliation process before the Bankruptcy Court. Any allowed claim related to such prepetition litigation will be treated in accordance with the Plan.
Regarding royalty claims, weWe and other natural gas producers have been named in various lawsuits alleging royalty underpayment.underpayment of royalties and other shares of the proceeds of production. The suitslawsuits 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 royaltiesamounts owed 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. PlaintiffsRoyalty 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 of the legal effect of lease provisions governing royalty calculations. We have resolved a number of these claims through negotiated settlements of past and future royalty obligations and have prevailed in various other lawsuits. We are currently defending numerous lawsuits seeking damages with respect to underpayment of royalties or other shares of the proceeds of production 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 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 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 and August 9, 2018, we reached tentative settlements to resolve substantially all Pennsylvania civil royalty cases for a total at that time of approximately $35$36 million. Subsequent to our Bankruptcy Filing the parties reopened settlement discussions.
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 also previously disclosed 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. On April 12, 2018, we reached a tentative settlement to resolve substantially all Oklahoma civil class action antitrust cases for an insignificant amount. The final fairness hearing is set for April 25, 2019.
On July 28, 2017, OOGC America LLC (OOGC) filed a demand for arbitration with the American Arbitration Association against Chesapeake Exploration, L.L.C., our wholly owned subsidiary, in connection with OOGC’s purchase of certain oil and gas leases and other assets pursuant to a Purchase and Sale Agreement entered into on October 10, 2010. In connection with the sale, we also entered into a Development Agreement with OOGC, dated November 15, 2010 (the “Development Agreement”), which governs each of our rights and obligations with respect to the sale, including the transportation and marketing of oil and gas. OOGC’s breach of contract, breach of agency and fiduciary duties and other claims generally allege, among other things, that we subjected OOGC to excessive rates for gathering and other services provided for under the Development Agreement and interfered with OOGC’s right to audit the documents that supported those rates. On November 13, 2018, a unanimous panel denied every claim asserted by OOGC other than OOGC being entitled to a declaration clarifying its audit rights.
On July 24, 2018, Healthcare of Ontario Pension Plan (HOOPP) filed a demand for arbitration with the American Arbitration Association regarding HOOPP’s purchase of our interest in Chaparral Energy, Inc. stock for $215 million on January 5, 2014. HOOPP claims that we engaged in material misrepresentations and fraud, and that we violated the Securities Exchange Act of 1934 (the “Exchange Act”) and Oklahoma Uniform Securities Act. HOOPP seeks either rescission or $215 million in monetary damages, and in either case, interest, attorney’s fees, disgorgement and punitive damages. We intend to vigorously defend these claims.
On January 29, 2020, a well control incident occurred at one of our wellsites in Burleson County, Texas, causing the deaths of three of our contractors’ employees and injuring a fourth. In February 2019, a putative class action lawsuitconnection with this incident, eleven lawsuits have been brought against us and our contractors alleging negligence, gross negligence, and breach of contract, and seeking wrongful death damages, survival statute damages, exemplary damages, and interest. Ten of the suits have been filed in the District Court of Dallas County, Texas. A joint motion to consolidate filed by all the parties in nine of the ten Dallas County lawsuits is currently pending before the Texas was filed against FTS International, Inc. (“FTSI”), certain investment banks, FTSI’s directors including certain ofMultidistrict Litigation Panel. The eleventh suit is pending in Burleson County, Texas. The proceedings are in their early stages and are all stayed due to the pending bankruptcy. Our general and excess liability insurance policies provide coverage for third party bodily injury and wrongful death claims, and the contracts between us and our officers and certain shareholders of FTSI including us. The lawsuit alleges various violations of Sections 11 (withcontractors with respect to certain of our officers in their capacities as directors of FTSI)the well contain customary cross-indemnification provisions. The well control incident liability was not reduced for the potential insurance recovery and 15 (with respect to such officers and us) ofa receivable for the Securities Act of 1933 in connection with public disclosure made during the initial public offering of FTSI. The suit seeks damages in excess of $1,000,000 and attorneys’ fees and other expenses. We intend to vigorously defend these claims.probable recovery was recorded.
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 named as a defendant in numerous lawsuits in Oklahoma alleging that we and other companies have engaged in activities that have caused earthquakes. These lawsuits seek 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 seek the reimbursement of insurance premiums and the award of punitive damages, attorneys’ fees, costs, expenses and interest. We are vigorously defending these claims. Any allowed claim related to such prepetition litigation will be treated in accordance with the Plan.
We are in discussions with the Pennsylvania Department of Environmental Protection (PADEP) regarding gas migration in the vicinity of certain of our wells in Wyoming 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, resolution of the matter may result in monetary sanctions of more than $300,000.
Other Matters
Based on management’s current assessment, we are of the opinion that no pending or threatened lawsuit or dispute relating to our business operations is likely to have a material adverse effect on our future consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.
Commitments
Operating Leases
Future operating lease commitments related to other property and equipment are not recorded as obligations in the accompanying consolidated balance sheets. The aggregate undiscounted minimum future lease payments are presented below:
|
| | | | |
| | | December 31, 2018 |
| | | ($ in millions) |
| 2019 | | $ | 3 |
|
| 2020 | | 1 |
|
| Total | | $ | 4 |
|
Operating lease expense for the years ended December 31, 2018, 2017 and 2016, was $4 million, $3 million and $5 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. Since filing the Chapter 11 Cases in June 2020, we have successfully renegotiated or terminated certain of our midstream contracts and commitments, including significantly reducing our gathering, processing and transportation expenses. Accordingly, $838 million of damages was accrued in liabilities subject to compromise. As of December 31, 2020, we were still negotiating certain of our midstream contracts pending our emergence from bankruptcy. Commitments related to gathering, processing and transportation agreements are not recorded as obligations in the accompanying consolidated balance sheets; however, they are reflected in our estimates of proved reserves.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The aggregate undiscounted commitments under our gathering, processing and transportation agreements, excluding any reimbursement from working interest and royalty interest owners, credits for third-party volumes or future costs under cost-of-service agreements, are presented below:
| | | | | | | | December 31,
2020 |
| | | December 31,
2018 | | | ($ in millions) |
| | | ($ in millions) | |
| 2019 | | $ | 832 |
| |
| 2020 | | 774 |
| |
| 2021 | | 683 |
| 2021 | | $ | 865 | |
| 2022 | | 581 |
| 2022 | | 729 | |
| 2023 | | 470 |
| 2023 | | 596 | |
| 2024 – 2034 | | 2,431 |
| |
| 2024 | | 2024 | | 521 | |
| 2025 | | 2025 | | 471 | |
| 2026 – 2034 | | 2026 – 2034 | | 1,911 | |
| Total | | $ | 5,771 |
| Total | | $ | 5,093 | |
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.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Service Contract
We have a contractcontracts with a third-party contractorcontractors to provide maintenance and other services to ourgenerators and natural gas compressors under capital lease. This commitment iscompressors. These commitments are not recorded as an obligation in the accompanying consolidated balance sheets. The aggregate undiscounted minimum future payments under thisthese service contract iscontracts are detailed below.
|
| | | | |
| | | December 31, 2018 |
| | | ($ in millions) |
| 2019 | | $ | 5 |
|
| 2020 | | 5 |
|
| 2021 | | 5 |
|
| Total | | $ | 15 |
|
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 14 for further discussion of our VPP transactions. | | | | | | | | |
| | | December 31,
2020 |
| | | ($ in millions) |
| 2021 | | $ | 7 | |
| 2022 | | 2 | |
| Total | | $ | 9 | |
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 14 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.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
7. Other Liabilities
Other current liabilities as of December 31, 20182020 and 20172019 are detailed below:
| | | | | December 31, | | December 31, |
| | | 2018 | | 2017 | | 2020 | | 2019 |
| | | ($ in millions) | | | ($ in millions) |
| Revenues and royalties due others | | $ | 687 |
| | $ | 612 |
| Revenues and royalties due others | | $ | 236 | | | $ | 516 | |
| Accrued drilling and production costs | | 258 |
| | 216 |
| Accrued drilling and production costs | | 104 | | | 326 | |
| Other accrued taxes | | Other accrued taxes | | 82 | | | 150 | |
| Debt and equity financing fees | | Debt and equity financing fees | | 69 | | | 0 | |
| Accrued compensation and benefits | | Accrued compensation and benefits | | 59 | | | 156 | |
| Operating leases | | Operating leases | | 24 | | | 9 | |
| Joint interest prepayments received | | 73 |
| | 74 |
| Joint interest prepayments received | | 8 | | | 52 | |
| Accrued compensation and benefits | | 202 |
| | 214 |
| |
| Other accrued taxes | | 108 |
| | 43 |
| |
VPP deferred revenue(a) | | VPP deferred revenue(a) | | 0 | | | 55 | |
| Other | | 212 |
| | 296 |
| Other | | 141 | | | 168 | |
| Total other current liabilities | | $ | 1,540 |
| | $ | 1,455 |
| Total other current liabilities | | $ | 723 | | | $ | 1,432 | |
Other long-term liabilities as of December 31, 20182020 and 20172019 are detailed below:
| | | | | | | | | | | | | | |
| | December 31, |
| | 2020 | | 2019 |
| | | ($ in millions) |
VPP deferred revenue(a) | | $ | 0 | | | $ | 9 | |
| Other | | 5 | | | 116 | |
| Total other long-term liabilities | | $ | 5 | | | $ | 125 | |
(a)At the inception of our volumetric production payment (VPP) agreements, we (i) removed the proved reserves associated with the VPP, (ii) recognized VPP proceeds as deferred revenue, which were being amortized on a unit-of-production basis to other revenue over the term of the VPP, (iii) retained responsibility for the production costs and capital costs related to VPP interests and (iv) ceased recognizing production associated with the VPP volumes. In 2020, we sold the assets related to our remaining VPP and extinguished the liability related to our production volume delivery obligation.
|
| | | | | | | | |
| | | December 31, |
| | | 2018 | | 2017 |
| | | ($ in millions) |
CHK Utica ORRI conveyance obligation(a) | | $ | — |
| | $ | 156 |
|
| Unrecognized tax benefits | | 53 |
| | 101 |
|
| Other | | 103 |
| | 97 |
|
| Total other long-term liabilities | | $ | 156 |
| | $ | 354 |
|
| |
(a) | In 2018, we repurchased previously conveyed ORRI from the CHK Utica, L.L.C. investors and extinguished our obligation to convey future ORRIs to the CHK Utica, L.L.C. investors for combined consideration of $199 million. The total CHK Utica ORRI conveyance obligation extinguished in 2018 was $183 million, of which, $30 million was recorded in current liabilities and $153 million was recorded in long-term liabilities. The fair value of the consideration allocated to the extinguishment of liability, $122 million, was less than the carrying amount of the conveyance obligation and resulted in a gain of $61 million recognized in other income on our consolidated statement of operations. The fair value of the consideration allocated to the purchase of ORRIs on proved producing properties was $77 million and recorded in proved oil and natural gas properties in our consolidated balance sheet. |
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
8. Leases
| |
6. | Capital Lease Obligation |
We are a lessee under various agreements for compressors, drilling rigs, vehicles and other equipment. As of December 31, 2020, 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 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 $2 million related to 2 office space leases, a long-term hydraulic fracturing agreement and other equipment leases. Regarding our long-term hydraulic fracturing agreements, we made a policy election to treat both lease and non-lease components as a single lease component. All of these acquired leases were approved for rejection during our bankruptcy process and subsequently removed from our balance sheet.
In 2018, we sold our wholly owned subsidiary, Midcon Compression, L.L.C., to a third party and subsequently leased back somecertain natural gas compressors for 38 months. The aggregate undiscounted minimum future lease payments are presented below:is accounted for as a finance lease liability.
|
| | | | |
| | | December 31, 2018 |
| | | ($ in millions) |
| 2019 | | $ | 10 |
|
| 2020 | | 10 |
|
| 2021 | | 10 |
|
| Total minimum lease payments | | 30 |
|
| Less imputed interest | | (3 | ) |
| Present value of minimum lease payments | | 27 |
|
| Less current maturities | | (10 | ) |
| Present value of minimum lease payment, less current maturities | | $ | 17 |
|
The FASB issued Revenue from Contracts with Customers (Topic 606) superseding virtually all existing revenue recognition guidance. We adopted this new standard in the first quarter of 2018 using the modified retrospective approach. We applied the new standard to all contracts that were not completedfollowing table presents our ROU assets and lease liabilities as of January 1, 2018December 31, 2020 and reflected the aggregate effect of all modifications in determining and allocating the transaction price. The cumulative effect of adoption of $8 million did not have a material impact on our consolidated financial statements. However, the adoption did result in certain purchase and sale contracts being recorded on a net basis, as an agent, rather than on a gross basis, as principal, due to management’s evaluation under new considerations within Topic 606 that indicated we do not have control over the specified commodity in purchase and sale contracts with the same counterparty. Such presentation change did not have an impact on income (loss) from operations, earnings per share or cash flows.2019.
In accordance with the new revenue standard requirements, the disclosure of the impact of adoption on our consolidated statements of operations was as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | 2019 |
| | | Finance | | Operating | | Finance | | Operating |
| | | ($ in millions) |
| ROU assets | | $ | 9 | | | $ | 29 | | | $ | 17 | | | $ | 22 | |
| | | | | | | | |
| Lease liabilities: | | | | | | | | |
Current lease liabilities | | $ | 9 | | | $ | 27 | | | $ | 9 | | | $ | 9 | |
Long-term lease liabilities | | 0 | | | 2 | | | 9 | | | 16 | |
Total lease liabilities | | 9 | | | 29 | | | 18 | | | 25 | |
| Less amounts reclassified to liabilities subject to compromise | | (9) | | | (5) | | | 0 | | | 0 | |
| Total lease liabilities, net | | $ | 0 | | | $ | 24 | | | $ | 18 | | | $ | 25 | |
|
| | | | | | | | | | | | |
| | | Before adoption of ASC 606 | | Adjustments | | As Reported |
| | | | | ($ in millions) | | |
| Statement of Operations for the Year Ended December 31, 2018 | | | | |
| Marketing revenues | | $ | 5,871 |
| | $ | (795 | ) | | $ | 5,076 |
|
| Marketing operating expenses | | $ | 5,953 |
| | $ | (795 | ) | | $ | 5,158 |
|
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Additional information for the Company’s operating and finance leases is presented below:
| | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | | 2020 | | 2019 |
| Lease cost: | | ($ in millions) |
| Amortization of ROU assets | | $ | 9 | | | $ | 8 | |
| Interest on lease liability | | 1 | | | 2 | |
| Finance lease cost | | 10 | | | 10 | |
| Operating lease cost | | 17 | | | 26 | |
| Short-term lease cost | | 32 | | | 112 | |
| Total lease cost | | $ | 59 | | | $ | 148 | |
| | | | |
| Other information: | | | | |
| Operating cash outflows from finance lease | | $ | 1 | | | $ | 2 | |
| Operating cash outflows from operating leases | | $ | 9 | | | $ | 11 | |
| Investing cash outflows from operating leases | | $ | 40 | | | $ | 127 | |
| Financing cash outflows from finance lease | | $ | 9 | | | $ | 8 | |
| | | | |
| | December 31, |
| | 2020 | | 2019 |
| Weighted average remaining lease term - finance lease | | 1.00 year | | 2.00 years |
| Weighted average remaining lease term - operating leases | | 1.12 years | | 4.65 years |
| Weighted average discount rate - finance lease | | 7.50 | % | | 7.50 | % |
| Weighted average discount rate - operating leases | | 6.46 | % | | 4.85 | % |
Maturity analysis of finance lease liabilities and operating lease liabilities are presented below:
| | | | | | | | | | | | | | |
| | December 31, 2020 |
| | | Finance Lease | | Operating Leases |
| | | ($ in millions) |
| 2021 | | $ | 10 | | | $ | 28 | |
| 2022 | | 0 | | | 2 | |
| Total lease payments | | 10 | | | 30 | |
| Less imputed interest | | (1) | | | (1) | |
| Present value of lease liabilities | | 9 | | | 29 | |
| Less current maturities | | (9) | | | (27) | |
| Present value of lease liabilities, less current maturities | | $ | 0 | | | $ | 2 | |
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
9. Revenue Recognition
The following table shows revenue disaggregated by operating area and product type, for the yearyears ended December 31, 2020, 2019 and 2018:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2020 |
| | Oil | | Natural Gas | | NGL | | Total |
| | ($ in millions) |
| Marcellus | | $ | 0 | | | $ | 631 | | | $ | 0 | | | $ | 631 | |
| Haynesville | | 0 | | | 362 | | | 0 | | | 362 | |
| Eagle Ford | | 717 | | | 113 | | | 84 | | | 914 | |
| Brazos Valley | | 485 | | | 16 | | | 13 | | | 514 | |
| Powder River Basin | | 170 | | | 41 | | | 20 | | | 231 | |
| Mid-Continent | | 55 | | | 25 | | | 13 | | | 93 | |
| Revenue from contracts with customers | | 1,427 | | | 1,188 | | | 130 | | | 2,745 | |
| Gains on oil, natural gas and NGL derivatives | | 554 | | | 42 | | | 0 | | | 596 | |
| Oil, natural gas and NGL revenue | | $ | 1,981 | | | $ | 1,230 | | | $ | 130 | | | $ | 3,341 | |
| | | | | | | | |
| Marketing revenue from contracts with customers | | $ | 1,195 | | | $ | 494 | | | $ | 110 | | | $ | 1,799 | |
| Other marketing revenue | | 67 | | | 3 | | | 0 | | | 70 | |
| Marketing revenue | | $ | 1,262 | | | $ | 497 | | | $ | 110 | | | $ | 1,869 | |
| | | | | | | | |
| | Year Ended December 31, 2019 |
| | | Oil | | Natural Gas | | NGL | | Total |
| | | ($ in millions) |
| Marcellus | | $ | 0 | | | $ | 856 | | | $ | 0 | | | $ | 856 | |
| Haynesville | | 0 | | | 620 | | | 0 | | | 620 | |
| Eagle Ford | | 1,289 | | | 153 | | | 119 | | | 1,561 | |
| Brazos Valley | | 721 | | | 32 | | | 16 | | | 769 | |
| Powder River Basin | | 369 | | | 77 | | | 32 | | | 478 | |
| Mid-Continent | | 164 | | | 44 | | | 25 | | | 233 | |
| Revenue from contracts with customers | | 2,543 | | | 1,782 | | | 192 | | | 4,517 | |
| Gains (losses) on oil, natural gas and NGL derivatives | | (212) | | | 217 | | | 0 | | | 5 | |
| Oil, natural gas and NGL revenue | | $ | 2,331 | | | $ | 1,999 | | | $ | 192 | | | $ | 4,522 | |
| | | | | | | | |
| Marketing revenue from contracts with customers | | $ | 2,473 | | | $ | 900 | | | $ | 246 | | | $ | 3,619 | |
| Other marketing revenue | | 311 | | | 41 | | | 0 | | | 352 | |
| Losses on marketing derivatives | | 0 | | | (4) | | | 0 | | | (4) | |
| Marketing revenue | | $ | 2,784 | | | $ | 937 | | | $ | 246 | | | $ | 3,967 | |
| | | | | | | | |
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| | | | | Year Ended December 31, 2018 | | Year Ended December 31, 2018 |
| | | Oil | | Natural Gas | | NGL | | Total | | | Oil | | Natural Gas | | NGL | | Total |
| | | ($ in millions) | | | ($ in millions) |
| Marcellus | | $ | — |
| | $ | 924 |
| | $ | — |
| | $ | 924 |
| Marcellus | | $ | 0 | | | $ | 924 | | | $ | 0 | | | $ | 924 | |
| Haynesville | | 2 |
| | 836 |
| | — |
| | 838 |
| Haynesville | | 2 | | | 836 | | | 0 | | | 838 | |
| Eagle Ford | | 1,514 |
| | 173 |
| | 185 |
| | 1,872 |
| Eagle Ford | | 1,514 | | | 173 | | | 185 | | | 1,872 | |
| Powder River Basin | | 244 |
| | 68 |
| | 38 |
| | 350 |
| Powder River Basin | | 244 | | | 68 | | | 38 | | | 350 | |
| Mid-Continent | | 246 |
| | 84 |
| | 55 |
| | 385 |
| Mid-Continent | | 246 | | | 84 | | | 55 | | | 385 | |
| Utica | | 195 |
| | 401 |
| | 224 |
| | 820 |
| Utica | | 195 | | | 401 | | | 224 | | | 820 | |
| Revenue from contracts with customers | | 2,201 |
| | 2,486 |
| | 502 |
| | 5,189 |
| Revenue from contracts with customers | | 2,201 | | | 2,486 | | | 502 | | | 5,189 | |
| Gains (losses) on oil, natural gas and NGL derivatives | | 124 |
| | (147 | ) | | (11 | ) | | (34 | ) | Gains (losses) on oil, natural gas and NGL derivatives | | 124 | | | (147) | | | (11) | | | (34) | |
| Oil, natural gas and NGL revenue | | $ | 2,325 |
| | $ | 2,339 |
| | $ | 491 |
| | $ | 5,155 |
| Oil, natural gas and NGL revenue | | $ | 2,325 | | | $ | 2,339 | | | $ | 491 | | | $ | 5,155 | |
| | | | | | | | | | | | | | | | | |
| Marketing revenue from contracts with customers | | $ | 2,740 |
| | $ | 1,194 |
| | $ | 456 |
| | $ | 4,390 |
| Marketing revenue from contracts with customers | | $ | 2,740 | | | $ | 1,194 | | | $ | 456 | | | $ | 4,390 | |
| Other marketing revenue | | 457 |
| | 229 |
| | — |
| | 686 |
| Other marketing revenue | | 457 | | | 222 | | | 0 | | | 679 | |
| Gains on marketing derivatives | | Gains on marketing derivatives | | 0 | | | 7 | | | 0 | | | 7 | |
| Marketing revenue | | $ | 3,197 |
| | $ | 1,423 |
| | $ | 456 |
| | $ | 5,076 |
| Marketing revenue | | $ | 3,197 | | | $ | 1,423 | | | $ | 456 | | | $ | 5,076 | |
Accounts Receivable
Accounts receivable as of December 31, 20182020 and 20172019 are detailed below:
| | | | | | | | | | | | | | |
| | December 31, |
| | 2020 | | 2019 |
| | ($ in millions) |
| Oil, natural gas and NGL sales | | $ | 589 | | | $ | 737 | |
| Joint interest billings | | 119 | | | 200 | |
| Other | | 68 | | | 74 | |
| Allowance for doubtful accounts | | (30) | | | (21) | |
| Total accounts receivable, net | | $ | 746 | | | $ | 990 | |
|
| | | | | | | | |
| | | December 31, |
| | | 2018 | | 2017 |
| | | ($ in millions) |
| Oil, natural gas and NGL sales | | $ | 976 |
| | $ | 959 |
|
| Joint interest billings | | 211 |
| | 209 |
|
| Other | | 77 |
| | 184 |
|
| Allowance for doubtful accounts | | (17 | ) | | (30 | ) |
| Total accounts receivable, net | | $ | 1,247 |
| | $ | 1,322 |
|
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
10. Income Taxes
The components of the income tax provisionexpense (benefit) for each of the periods presented below are as follows:
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| | | ($ in millions) |
| Current | | | | | | |
| Federal | | $ | — |
| | $ | (14 | ) | | $ | (14 | ) |
| State | | — |
| | 5 |
| | (5 | ) |
| Current Income Taxes | | — |
| | (9 | ) | | (19 | ) |
| Deferred | | | | | | |
| Federal | | 3 |
| | 13 |
| | (147 | ) |
| State | | (13 | ) | | (2 | ) | | (24 | ) |
| Deferred Income Taxes | | (10 | ) | | 11 |
| | (171 | ) |
| Total | | $ | (10 | ) | | $ | 2 |
| | $ | (190 | ) |
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| | ($ in millions) |
| Current | | | | | | |
| Federal | | $ | (3) | | | $ | 0 | | | $ | 0 | |
| State | | (6) | | | (26) | | | 0 | |
| Current Income Taxes | | (9) | | | (26) | | | 0 | |
| Deferred | | | | | | |
| Federal | | 0 | | | (297) | | | 3 | |
| State | | (10) | | | (8) | | | (13) | |
| Deferred Income Taxes | | (10) | | | (305) | | | (10) | |
| Total | | $ | (19) | | | $ | (331) | | | $ | (10) | |
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:
| | | | | | | | | | | | | | | Years Ended December 31, |
| | | Years Ended December 31, | | 2020 | | 2019 | | 2018 |
| | | 2018 | | 2017 | | 2016 | | ($ in millions) |
| | | ($ in millions) | |
| Income tax expense (benefit) at the federal statutory rate (21%, 35%, 35%) | | $ | 182 |
| | $ | 333 |
| | $ | (1,606 | ) | |
| Income tax expense (benefit) at the federal statutory rate of 21% | | Income tax expense (benefit) at the federal statutory rate of 21% | | $ | (2,051) | | | $ | (134) | | | $ | 45 | |
| State income taxes (net of federal income tax benefit) | | 23 |
| | 66 |
| | (30 | ) | State income taxes (net of federal income tax benefit) | | (41) | | | (21) | | | 27 | |
| Remeasurement of deferred tax assets and liabilities | | — |
| | 1,266 |
| | — |
| |
| Change in valuation allowance | | (230 | ) | | (1,676 | ) | | 1,423 |
| |
| Partial release of valuation allowance due to the WildHorse Merger | | Partial release of valuation allowance due to the WildHorse Merger | | 0 | | | (314) | | | 0 | |
| Change in valuation allowance excluding impact of WildHorse Merger | | Change in valuation allowance excluding impact of WildHorse Merger | | 2,010 | | | 114 | | | (97) | |
| Reorganization items | | Reorganization items | | 41 | | | 0 | | | 0 | |
| Equity-based compensation (non-officer) | | Equity-based compensation (non-officer) | | 10 | | | 4 | | | 4 | |
| Officer compensation limited under Section 162(m) | | Officer compensation limited under Section 162(m) | | 9 | | | 3 | | | 5 | |
| Other | | 15 |
| | 13 |
| | 23 |
| Other | | 3 | | | 17 | | | 6 | |
| Total | | $ | (10 | ) | | $ | 2 |
| | $ | (190 | ) | Total | | $ | (19) | | | $ | (331) | | | $ | (10) | |
We applied the guidance in SABStaff Accounting Bulletin 118 when accounting for the enactment-date effect of the tax reform legislation commonly known as the Tax Act.Cuts and Jobs Act, which was signed into law on December 22, 2017 (the “Tax Act”). At December 31, 2017, we had not completed our accounting for all of the enactment-date income tax effects of the Tax Act under ASC 740, Income Taxes, for certain items as we were waiting on additional guidance to be issued. At December 31, 2018, we have nowhad completed our accounting for all of the enactment-date income tax effects of the Tax Act. The adjustments made during 2018 arewere considered immaterial but nevertheless are included as a component of income tax expense (benefit) in our consolidated statement of operations for the year ended December 31, 2018, which is fully offset with an adjustment to the valuation allowance against our net deferred tax asset.asset position.
We reassessed the realizability of our deferred tax assets and continue to maintain a full valuation allowance against all or substantially all of our net deferred tax asset. The $230 millionasset positions for federal and state purposes. Of the net decreaseincrease in our valuation allowance, $2.010 billion is reflected as a component of income tax expense in our consolidated statement of operations for the year ended December 31, 2018. This decrease in the valuation allowance is primarily due to offsetting current year tax expense.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
2020.
Deferred income taxes are provided to reflect temporary differences in the tax basis of assets and liabilities and their reported amounts in the financial statements. The tax-effected temporary differences, tax credits and net operating loss
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(NOL) carryforwards and disallowed business interest carryforwards that comprise our deferred income taxes are as follows:
| | | | | Years Ended December 31, | | December 31, |
| | | 2018 | | 2017 | | 2020 | | 2019 |
| | | ($ in millions) | | ($ in millions) |
| Deferred tax liabilities: | | | | | Deferred tax liabilities: | |
| Property, plant and equipment | | $ | (544 | ) | | $ | — |
| Property, plant and equipment | | $ | 0 | | | $ | (546) | |
| Volumetric production payments | | (117 | ) | | (129 | ) | Volumetric production payments | | 0 | | | (89) | |
| Carrying value of debt | | (95 | ) | | — |
| |
| Derivative instruments | | (56 | ) | | — |
| Derivative instruments | | 0 | | | (14) | |
| Other | | (7 | ) | | (20 | ) | Other | | (3) | | | (5) | |
| Deferred tax liabilities | | (819 | ) | | (149 | ) | Deferred tax liabilities | | (3) | | | (654) | |
| | | | | | | | | |
| Deferred tax assets: | | | | | Deferred tax assets: | |
| Property, plant and equipment | | — |
| | 1 |
| Property, plant and equipment | | 907 | | | 0 | |
| Net operating loss carryforwards | | 2,737 |
| | 2,248 |
| Net operating loss carryforwards | | 2,066 | | | 1,971 | |
| Carrying value of debt | | — |
| | 161 |
| Carrying value of debt | | 48 | | | 169 | |
| Disallowed business interest carryforward | | 194 |
| | — |
| Disallowed business interest carryforward | | 293 | | | 25 | |
| Asset retirement obligations | | 40 |
| | 42 |
| Asset retirement obligations | | 34 | | | 50 | |
| Investments | | 132 |
| | 161 |
| Investments | | 71 | | | 83 | |
| Accrued liabilities | | Accrued liabilities | | 288 | | | 64 | |
| Derivative instruments | | — |
| | 17 |
| Derivative instruments | | 53 | | | 0 | |
| Accrued liabilities | | 89 |
| | 125 |
| |
| Other | | 60 |
| | 71 |
| Other | | 51 | | | 87 | |
| Deferred tax assets | | 3,252 |
| | 2,826 |
| Deferred tax assets | | 3,811 | | | 2,449 | |
| Valuation allowance | | (2,433 | ) | | (2,674 | ) | Valuation allowance | | (3,808) | | | (1,805) | |
| Net deferred tax assets | | 819 |
| | 152 |
| |
| Net deferred tax assets | | $ | — |
| | $ | 3 |
| |
| Deferred tax assets after valuation allowance | | Deferred tax assets after valuation allowance | | 3 | | | 644 | |
| Net deferred tax liability | | Net deferred tax liability | | $ | 0 | | | $ | (10) | |
As of December 31, 2018,2020, we had federal NOL carryforwards of approximately $10.138$7.803 billion and state NOL carryforwards of approximately $10.688 billion, which excludes the NOL carryforwards related to unrecognized tax benefits.$7.784 billion. The associated deferred tax assets related to these federal and state NOL carryforwards were $2.129$1.639 billion and $608$427 million, respectively. The federal NOL carryforwards generated in tax years prior to 2018 expire between 2031in 2036 and 2037. As a result of the Tax Act, the 2018 through 2020 federal NOL carryforward hascarryforwards have no expiration. The value of all of these carryforwards depends on our ability to generate future taxable income.
As of December 31, 20182020, and 2017,2019, we had deferred tax assets of $3.252$3.811 billion and $2.826$2.449 billion upon which we had a valuation allowance of $2.433$3.808 billion and $2.674$1.805 billion, respectively. Of the net change in the valuation allowance of $241 million$2.003 billion for both federal and state deferred tax assets, $230 million$2.010 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.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
A valuation allowance against deferred tax assets, including NOL carryforwards and disallowed business interest carryforwards, is recognized when it is more likely than not that all or some portion of the benefit from the deferred tax assets 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 existing taxable temporary differences, and tax planning strategies, as well as the current and forecasted business economics of our industry. Management assesses all available evidence, both positive and negative, to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. A significant piece of objectively verifiable negative evidence is the cumulative loss incurred over the three-year period ended December 31, 2018.2020. Such objective negative evidence limits our ability to consider various forms of subjective positive evidence, such as ourany projections for future income. Accordingly, management has not changed its judgment for the period ended December 31, 20182020 with respect to the need for a full valuation allowance against all or substantially all of our net deferred tax asset position.positions for federal and state purposes. The amount of the deferred tax assetassets considered realizable could be adjusted if projections of future taxable income are increased and/or if objective negative evidence in the form of cumulative losses is no longer present. Based on our current forecast, we may come out of a three-year cumulative loss position during 2019. Should we return toachieve a level of sustained profitability, as forecasted, consideration will need to be given to future projections of taxable income to determine whether such projections provide an adequate source of taxable income for the realization of our deferred tax assets, namely federal NOL carryforwards and disallowed business interest carryforwards. If so, then all or a portion of the valuation allowance could possibly be releasedreleased.
On February 1, 2019, we completed the acquisition of WildHorse. For federal income tax purposes, the transaction qualified as earlya tax-free merger under Section 368 of the Code and, as a result, we acquired carryover tax basis in WildHorse’s assets and liabilities. We recorded a net deferred tax liability of $314 million as part of the business combination accounting for WildHorse. As a consequence of maintaining a full valuation allowance against our net deferred tax asset positions (federal and state), a partial release of the valuation allowance was recorded as a discrete income tax benefit of $314 million through the consolidated statement of operations in the first quarter of 2019. The net deferred tax liability determined through business combination accounting includes deferred tax liabilities on plant, property and equipment and prepaid compensation totaling $401 million, partially offset by deferred tax assets totaling $87 million relating to federal NOL carryforwards, disallowed business interest carryforwards and certain other deferred tax assets. These carryforwards will be subject to an annual limitation under Section 382 of the Code of approximately $61 million. We determined that no separate valuation allowances were required to be established through business combination accounting against any of the individual deferred tax assets acquired.
Our ability to utilize NOL carryforwards, disallowed business interest carryforwards, tax credits and possibly other tax attributes to reduce future federal taxable income and federal income tax is subject to various limitations under Section 382 of the Code. The utilization of thesesuch attributes may be limited uponsubject to an annual limitation under Section 382 of 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 such shareholders are definedCode should transactions involving our equity result in Treasury regulations), and the offering of stock by us during any three-year period resulting in an aggregate changea cumulative shift of more than 50% in the beneficial ownership of Chesapeake.our stock during any three-year testing period (an “Ownership Change”). For this purpose, “stock” includes certain preferred stock. The annual limitation is generally equal to the product of (a) the fair market value of our equity immediately before the Ownership Change (i.e., the value of the old loss corporation) multiplied by (b) the long-term tax-exempt rate in effect for the month in which an Ownership Change occurs. If we are in a net unrealized built-in gain position at the time of an Ownership Change, then the limitation is increased by each year’s recognized built-in gains occurring within a five-year period following the Ownership Change, but only to the extent of the net unrealized built-in gain which existed at the time of the Ownership Change. However, 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, 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. 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, disallowed business interest carryforwards and tax credits, such as tax depreciation, depletion and amortization. Some states impose similar limitations on tax attribute utilization upon experiencing an Ownership Change.
As of December 31, 2018,2020, we do not believe that an ownership change hasOwnership Change had occurred that would limitsubject us to an annual limitation on the utilization of our NOL carryforwards, disallowed business interest carryforwards, tax credits and possibly other tax attributes. Certain future transactions involvingattributes although our equity (including relatively small transactionscumulative shift continues to be at a level greater than 40%.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Therefore, with the exception of the NOL carryforwards and transactions beyond our control) could cause an ownership change and thereforedisallowed business interest carryforwards acquired upon the WildHorse Merger, we do not believe we had a limitation on the ability to utilize our carryforwards and other tax attributes under Section 382 of the Code as of December 31, 2020. However, upon emergence from bankruptcy on February 9, 2021, the Company did experience an Ownership Change.If the old loss corporation is under the jurisdiction of the court in a case under Title 11 of the United States Code, then the annual limitation generally is based on the post-emergence fair market value of the equity of the new loss corporation as opposed to the fair market value of the equity of the old loss corporation. As such, an annual limitation will be computed based on the fair market value of the new equity immediately after emergence and will pertain to the post-emergence utilization of NOL carryforwards, disallowed business interest carryforwards and possibly other tax attributes.credits existing at the time of emergence.
Accounting guidance for recognizing and measuring uncertain tax positions requires a more 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, classification and disclosure of uncertain tax positions. As of December 31, 20182020, and 2017,2019, the amount of unrecognized tax benefits related to NOL carryforwards and tax liabilities associated with uncertain tax positions was $79$74 million for both years. For both 2020 and $106 million, respectively. Of the 2018 amount, $32 million is related to state tax liabilities,2019, $29 million is related to state tax receivables not expected to be recovered and the remainder is related to NOL carryforwards. Of the 2017 amount, $74 million is related to state tax liabilities, $4 million is related to federal tax liabilities and the remainder is related to NOL carryforwards. If recognized, $61$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, 20182020, and 2017,2019, we had no amounts accrued liabilities of $20 million and $23 million, respectively, for interest related to these uncertain tax positions. We recognize interest related to uncertain tax positions as a component of interest expense. Penalties, if any, related to uncertain tax positions would be recorded in other expenses.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
A reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows:
| | | | | 2018 | | 2017 | | 2016 | | 2020 | | 2019 | | 2018 |
| | | ($ in millions) | | ($ in millions) |
| Unrecognized tax benefits at beginning of period | | $ | 106 |
| | $ | 202 |
| | $ | 280 |
| Unrecognized tax benefits at beginning of period | | $ | 74 | | | $ | 79 | | | $ | 106 | |
| Additions based on tax positions related to the current year | | — |
| | — |
| | — |
| Additions based on tax positions related to the current year | | 0 | | | 0 | | | 0 | |
| Additions to tax positions of prior years | | — |
| | 4 |
| | 33 |
| Additions to tax positions of prior years | | 0 | | | 27 | | | 0 | |
| Settlements | | — |
| | (100 | ) | | (111 | ) | Settlements | | 0 | | | (32) | | | 0 | |
| Expiration of the applicable statute of limitations | | (23 | ) | | — |
| | — |
| Expiration of the applicable statute of limitations | | 0 | | | 0 | | | (23) | |
| Reductions to tax positions of prior years | | (4 | ) | | — |
| | — |
| Reductions to tax positions of prior years | | 0 | | | 0 | | | (4) | |
| Unrecognized tax benefits at end of period | | $ | 79 |
| | $ | 106 |
| | $ | 202 |
| Unrecognized tax benefits at end of period | | $ | 74 | | | $ | 74 | | | $ | 79 | |
Our federal and state income tax returns are subject to examination by federal and state tax authorities. FederalNotification was received from the IRS during February 2021 that the examination cycles 2010 through 2013 and 2014 through 2015 were settledof the WildHorse 2017 federal income tax return has been closed as a no-change audit. Further, the IRS has concluded the fieldwork relating to our 2016 federal income tax return with the Internal Revenue Service (IRS) during the first and third quarters of 2018, respectively. However, certain of theseno changes proposed. Our tax years remain open for purposes of adjusting federal net operating loss carryforwards upon utilization. Tax years 20162017 through 20182019 remain open for all purposes of examination by the IRS. IRS as do the WildHorse 2018 federal income tax return and the 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 20162017 through 20182019 as well as certain earlier years remain open for examination by state tax authorities. Currently, several state examinations are in 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 or financial position.operations.
| |
9. | 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, 2018, 2017 and 2016, our expenditures for hydraulic fracturing services with FTSI were $93 million, $111 million and $3 million, respectively.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
11. Equity
Chapter 11 Proceedings
Upon our emergence from Chapter 11 on February 9, 2021, as discussed in Note 2, our then-authorized common stock and preferred stock were canceled and released under the Plan without receiving any recovery on account thereof. Pre-Emergence Equity
Common Stock
Stock. A summary of the changes in our common shares issued for the years ended December 31, 2018, 20172020, 2019 and 20162018 is detailed below:
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| | | (in thousands) |
Shares issued as of January 1(a) | | 9,773 | | | 4,568 | | | 4,543 | |
Common shares issued for WildHorse Merger(a)(b) | | 0 | | | 3,587 | | | 0 | |
Exchange of senior notes(a)(c) | | 0 | | | 1,178 | | | 0 | |
Exchange of convertible notes(a)(c) | | 0 | | | 367 | | | 0 | |
Exchange of preferred stock(a) | | 0 | | | 52 | | | 0 | |
Restricted stock issuances (net of forfeitures and cancellations)(a)(d) | | 8 | | | 21 | | | 25 | |
Shares issued as of December 31(a) | | 9,781 | | | 9,773 | | | 4,568 | |
(a)All share information has been retroactively adjusted to reflect the 1-for-200 (1:200) reverse stock split effective April 14, 2020. See below for additional information.
(b)See Note 3 for discussion of WildHorse Merger. (c)See Note 5 for discussion of debt exchanges. (d)See Note 12 for discussion of restricted stock. Reverse Stock Split. On April 13, 2020, our board of directors and our shareholders approved a 1-for-200 (1:200) reverse stock split of our common stock and a reduction of the total number of authorized shares of our common stock as determined by a formula based on two-thirds of the reverse stock split ratio. The reverse stock split became effective as of the close of business on April 14, 2020. Our common stock began trading on a split-adjusted basis on the NYSE at the market open on April 15, 2020. The par value of the common stock was not adjusted as a result of the reverse stock split.
The reverse stock split was intended to, among other things, increase the per share trading price of our common stock to satisfy the $1.00 minimum per share closing price requirement for continued listing on the NYSE. As a result of the reverse stock split, each 200 pre-split shares of common stock outstanding were automatically combined into one issued and outstanding share of common stock. The fractional shares that resulted from the reverse stock split were canceled by paying cash in lieu of the fair value. The number of outstanding shares of common stock was reduced from approximately 1.957 billion as of April 10, 2020 to approximately 9.784 million shares (without giving effect to the liquidation of fractional shares). The total number of shares of common stock that we are authorized to issue was reduced from 3,000,000,000 to 22,500,000 shares. All share and per share amounts in the accompanying consolidated financial statements and notes thereto were retroactively adjusted for all periods presented to give effect to this reverse stock split, including reclassifying an amount equal to the reduction in par value of our common stock to additional paid-in capital.
During the year ended December 31, 2019, our shareholders approved a proposal to amend our restated certificate of incorporation to increase the number of authorized shares of our common stock from 15,000,000 shares to 22,500,000 shares, adjusted for our reverse stock split.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
|
| | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| | | (in thousands) |
| Shares issued as of January 1 | | 908,733 |
| | 896,279 |
| | 664,796 |
|
| Restricted stock issuances (net of forfeitures and cancellations) | | 4,983 |
| | 2,488 |
| | 1,945 |
|
| Exchange/conversion of preferred stock | | — |
| | 9,966 |
| | 120,186 |
|
| Exchange of convertible notes | | — |
| | — |
| | 55,428 |
|
| Exchange of senior notes | | — |
| | — |
| | 53,924 |
|
| Shares issued as of December 31 | | 913,716 |
|
| 908,733 |
| | 896,279 |
|
On April 23, 2020, our Board of Directors declared a dividend of one Right payable on May 4, 2020 for each share of our common stock outstanding on May 4, 2020 to the shareholders of record on that date (the “Rights”). In connection with the distribution of the Rights, we entered into a Rights Agreement with Computershare Trust Company, N.A., as rights agent (the “Rights Agreement”). Each Right entitles the registered holder to purchase from us Preferred Shares.
The Rights Agreement was intended to protect value by preserving our ability to use our tax attributes to offset potential future income taxes for federal income tax purposes. Our ability to use our tax attributes would have been substantially limited if we had experienced an ownership change under Section 382 of the Code prior to emergence from bankruptcy on February 9, 2021. The Rights Agreement reduced the likelihood of an ownership change by deterring any person or group of affiliated or associated persons from acquiring beneficial ownership of 4.9% or more of the outstanding shares of our common stock.
In connection with the adoption of the Rights Agreement the Company filed a Certificate of Designations of Series B Preferred Stock with the Secretary of State of the State of Oklahoma setting forth the rights, powers, and preferences of the Series B Preferred Stock issuable upon exercise of the Rights (the “Preferred Shares”). On the Plan Effective Date, the Company filed a Certificate of Elimination with the Secretary of State of the State of Oklahoma eliminating the Preferred Shares and returning them to authorized but undesignated shares of the Company’s preferred stock. The foregoing is a summary of the terms of the Certificate of Elimination. The summary does not purport to be complete and is qualified in its entirety by reference to the Certificate of Elimination.
Preferred Stock. Following is a summary of our preferred stock, including the primary conversion terms as of December 31, 2018:2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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 | | 0.1984 | | | $ | 5,039.59 | | | May 17, 2015 | | $ | 6,551.46 | |
| | | | | | | | | | | | | | |
5.75% (series A) cumulative convertible non-voting | | May 2010 | | $ | 1,000 | | | Any time | | 0.1918 | | | $ | 5,215.02 | | | May 17, 2015 | | $ | 6,779.52 | |
| | | | | | | | | | | | | | |
| 4.50% cumulative convertible | | September 2005 | | $ | 100 | | | Any time | | 0.0123 | | | $ | 8,142.99 | | | September 15, 2010 | | $ | 10,585.89 | |
| | | | | | | | | | | | | | |
| 5.00% cumulative convertible (series 2005B) | | November 2005 | | $ | 100 | | | Any time | | 0.0139 | | | $ | 7,208.51 | | | November 15, 2010 | | $ | 9,371.06 | |
(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.
|
| | | | | | | | | | | | | | | | | | | | |
| 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. |
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Outstanding shares of our preferred stock for the years ended December 31, 2018, 20172020, 2019 and 20162018 are detailed below:
|
| | | | | | | | | | | | |
| | | 5.75% | | 5.75% (Series A) | | 4.50% | | 5.00% (Series 2005B) |
| | | (in thousands) |
Shares outstanding as of January 1, 2018
and December 31, 2018 | | 770 |
| | 463 |
| | 2,559 |
| | 1,811 |
|
| | | | | | | | | |
| 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 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 5.75% | | 5.75% (Series A) | | 4.50% | | 5.00% (Series 2005B) |
| | (in thousands) |
Shares outstanding as of January 1, 2020
and December 31, 2020 | | 770 | | | 423 | | | 2,559 | | | 1,811 | |
| | | | | | | | |
| Shares outstanding as of January 1, 2019 | | 770 | | | 463 | | | 2,559 | | | 1,811 | |
Preferred stock exchanges(a) | | 0 | | | (40) | | | 0 | | | 0 | |
| Shares outstanding as of December 31, 2019 | | 770 | | | 423 | | | 2,559 | | | 1,811 | |
| | | | | | | | |
Shares outstanding as of January 1, 2018
and December 31, 2018 | | 770 | | | 463 | | | 2,559 | | | 1,811 | |
| |
(a) | 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. |
| |
(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(a)During 2019, we exchanged 51,839 shares of common stock for 40,000 shares of our 5.75% (Series A) Cumulative Convertible Preferred Stock. In connection with the exchange, 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 $17 million is reflected as a reduction to net income available to common stockholders for the purpose of calculating earnings per common share.
Dividends. Dividends declared on our preferred stock are reflected as adjustments to retained earnings to the extent a surplus of retained earnings exists after giving effect to the dividends. To the extent retained earnings are insufficient to fund the distributions, payments are reflected in our financial statements as a return of contributed capital rather than earnings and are accounted for as a reduction to paid-in capital.
Dividends 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.
In January 2016,On April 17, 2020, we suspended dividend payments on our convertible preferred stock to provide additional liquidity in the depressed commodity price environment. In the first quarter of 2017,announced that we reinstated thewere suspending payment of dividends on each series of our outstanding convertible preferred stock, and paidwere therefore currently in arrears on such dividend payments as of December 31, 2020. Suspension of the dividends did not constitute an event of default under any of our debt instruments. No dividends have been accrued on our convertible preferred stock subsequent to the Petition Date. Pursuant to the Plan, each holder of an equity interest in arrears.Chesapeake had such interest canceled, released and extinguished without any distribution. See Note 2 for additional information about the Chapter 11 Cases.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Accumulated Other Comprehensive Income (Loss)
. For the years ended December 31, 20182020 and 2017,2019, changes in accumulated other comprehensive income (loss) for cash flow hedges, net of tax, are detailed below:
| | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | 2019 |
| | ($ in millions) |
| Balance, as of January 1 | | $ | 12 | | | $ | (23) | |
Amounts reclassified from accumulated other comprehensive income(a) | | 33 | | | 35 | |
| Balance, as of December 31 | | $ | 45 | | | $ | 12 | |
|
| | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | 2017 |
| | | ($ in millions) |
| Balance, as of January 1 | | $ | (57 | ) | | $ | (96 | ) |
| Other comprehensive income before reclassifications | | — |
| | 5 |
|
Amounts reclassified from accumulated other comprehensive income(a) | | 34 |
| | 34 |
|
| Net other comprehensive income | | 34 |
| | 39 |
|
| Balance, as of December 31 | | $ | (23 | ) | | $ | (57 | ) |
| |
(a) | 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. |
Noncontrolling Interests
Chesapeake Granite Wash Trust.Interests. We ownowned 23,750,000 common units in the Chesapeake Granite Wash Trust (the Trust)“Trust”) representing a 51% beneficial interest. We have determined that the Trust iswas a VIE and that we arewere the primary beneficiary. As a result, the Trust iswas included in our consolidated financial statements. As of December 31, 2018In 2020, we sold our interests in the Mid-Continent operating area and 2017,the units we had $123 million and $124 million, respectively, of noncontrolling interests on our consolidated balance sheets attributable toowned in the Trust. Net income attributable to the Trust’s noncontrolling interest was $4 millionSee Note 3 for each of the years ended December 31, 2018 and 2017 and net loss attributable to the Trust’s noncontrolling interest was $9 million for the year ended December 31, 2016.additional discussion.The Trust’s legal existence iswas separate from Chesapeake and our other consolidated subsidiaries, and the Trust iswas not a guarantor of any of Chesapeake’s debt. The creditors or beneficial holders of the Trust havehad 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 cancould be used only to settle obligations of the Trust and the liabilities of the Trust for which creditors dodid not have recourse to the general credit of Chesapeake.
Post-Emergence Equity
New Common Stock. As discussed in Note 2, on the Effective Date, we issued an aggregate of approximately 97.9 million shares of New Common Stock, par value $0.01 per share, to the holders of allowed claims, as defined in the Plan, and approximately 2.1 million shares of New Common Stock were reserved for future distributions under the Plan. | |
11. | Share-Based Compensation |
Warrants. As discussed in Note 2, on the Emergence Date, we issued approximately 11.1 million Class A Warrants, 12.3 million Class B Warrants and 13.7 million 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 Emergence 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. 12. Share-Based Compensation
Our share-based compensation program consistshas consisted of restricted stock, stock options, performance share units (PSUs) and cash restricted stock units (CRSUs) granted to employees and restricted stock granted to non-employee directors under our Long Term Incentive Plan. The restricted stock and stock options arewere equity-classified awards and the PSUs and CRSUs arewere liability-classified awards.
Chapter 11 Proceedings
As discussed in Note 2, on the Effective Date, our current 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.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
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 71,600,000358,000 reverse stock split adjusted 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.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
directors. 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, 2018, 35,389,8252020, 474,123 reverse stock split adjusted shares of common stock remained issuable under the 2014 LTIP.
Equity-Classified Awards
Restricted Stock. We grant restricted stock to employees and non-employee directors. A summary of the changes in unvested restricted stock during 2018, 20172020, 2019 and 20162018 is presented below:
| | | | | | | | | | | | | | |
| | Shares of Unvested Restricted Stock(a) | | Weighted Average Grant Date Fair Value(a) |
| | (in thousands) | | |
| Unvested restricted stock as of January 1, 2020 | | 52 | | | $ | 710 | |
| Granted | | 68 | | | $ | 60 | |
| Vested | | (21) | | | $ | 792 | |
| Forfeited | | (98) | | | $ | 243 | |
| Unvested restricted stock as of December 31, 2020 | | 1 | | | $ | 617 | |
| | | | |
| Unvested restricted stock as of January 1, 2019 | | 59 | | | $ | 886 | |
| Granted | | 30 | | | $ | 530 | |
| Vested | | (30) | | | $ | 876 | |
| Forfeited | | (7) | | | $ | 744 | |
| Unvested restricted stock as of December 31, 2019 | | 52 | | | $ | 710 | |
| | | | |
| Unvested restricted stock as of January 1, 2018 | | 66 | | | $ | 1,274 | |
| Granted | | 30 | | | $ | 746 | |
| Vested | | (29) | | | $ | 1,534 | |
| Forfeited | | (8) | | | $ | 1,204 | |
| Unvested restricted stock as of December 31, 2018 | | 59 | | | $ | 886 | |
|
| | | | | | | |
| | | Shares of Unvested Restricted Stock | | Weighted Average Grant Date Fair Value |
| | | (in thousands) | | |
| Unvested restricted stock as of January 1, 2018 | | 13,178 |
| | $ | 6.37 |
|
| Granted | | 6,067 |
| | $ | 3.73 |
|
| Vested | | (5,808 | ) | | $ | 7.67 |
|
| Forfeited | | (1,579 | ) | | $ | 6.02 |
|
| Unvested restricted stock as of December 31, 2018 | | 11,858 |
| | $ | 4.43 |
|
| | | | | |
| 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 |
|
The aggregate intrinsic value of restricted stock that vested during 20182020 was approximately $20$1 million based on the stock price at the time of vesting.
As of December 31, 2018, there was approximately $33 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 2.02 years.
Stock Options. In 2018, 20172020, 2019 and 2016,2018, we granted members of management stock options that vest ratably over a three-yearthree-year period. Each stock option award has an exercise price equal to the closing price of our common stock on the grant date. Outstanding options expire seven years to ten years from the date of grant.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
We utilize the Black-Scholes option pricing model to measure the fair value of stock options. The expected life of an option is determined using the simplified method. Volatility assumptions are estimated based on the average of historical volatility of Chesapeake stock over the expected life of an option. The risk-free interest rate is 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 is based on an annual dividend yield, taking into account our dividend policy, over the expected life of the option. We used the following weighted average assumptions to estimate the grant date fair value of the stock options granted in 2018:
|
| | | | | | | |
| Expected option life – years | | 6.0 |
|
| Volatility | | 63.5565.61 | % |
| Risk-free interest rate | | 2.722.47 | % |
| Dividend yield | | —0 | % |
The following table provides information related to stock option activity for 2018, 20172020, 2019 and 2016:2018:
| | | | | | | | | | | | | | | | 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, 2020 | | Outstanding as of January 1, 2020 | | 90 | | | $ | 1,420 | | | 5.70 | | $ | 0 | |
| Granted | | Granted | | 0 | | | $ | 0 | | |
| Exercised | | Exercised | | 0 | | | $ | 0 | | | $ | 0 | |
| Expired | | Expired | | (23) | | | $ | 915 | | |
| Forfeited | | Forfeited | | (47) | | | $ | 1,666 | | |
| Outstanding as of December 31, 2020 | | Outstanding as of December 31, 2020 | | 20 | | | $ | 1,429 | | | 4.27 | | $ | 0 | |
| Exercisable as of December 31, 2020 | | Exercisable as of December 31, 2020 | | 19 | | | $ | 1,440 | | | 4.35 | | $ | 0 | |
| | Outstanding as of January 1, 2019 | | Outstanding as of January 1, 2019 | | 90 | | | $ | 1,440 | | | 7.15 | | $ | 0 | |
| Granted | | Granted | | 5 | | | $ | 594 | | |
| Exercised | | Exercised | | 0 | | | $ | 0 | | | $ | 0 | |
| Expired | | Expired | | (2) | | | $ | 1,272 | | |
| Forfeited | | Forfeited | | (3) | | | $ | 794 | | |
| Outstanding as of December 31, 2019 | | Outstanding as of December 31, 2019 | | 90 | | | $ | 1,420 | | | 5.70 | | $ | 0 | |
| Exercisable as of December 31, 2019 | | Exercisable as of December 31, 2019 | | 65 | | | $ | 1,656 | | | 4.86 | | $ | 0 | |
| | | (in thousands) | | | | ($ in millions) | | | |
| Outstanding as of January 1, 2018 | | 16,285 |
| | $ | 8.25 |
| | 7.73 | | $ | 1 |
| Outstanding as of January 1, 2018 | | 81 | | | $ | 1,650 | | | 7.73 | | $ | 1 | |
| Granted | | 3,611 |
| | $ | 3.01 |
| | | Granted | | 18 | | | $ | 602 | | |
| Exercised | | — |
| | $ | — |
| | $ | — |
| Exercised | | 0 | | | $ | 0 | | | $ | 0 | |
| Expired | | (602 | ) | | $ | 13.83 |
| | | Expired | | (3) | | | $ | 2,766 | | |
| Forfeited | | (1,198 | ) | | $ | 5.45 |
| | | Forfeited | | (6) | | | $ | 1,090 | | |
| Outstanding as of December 31, 2018 | | 18,096 |
| | $ | 7.20 |
| | 7.15 | | $ | — |
| Outstanding as of December 31, 2018 | | 90 | | | $ | 1,440 | | | 7.15 | | $ | 0 | |
| Exercisable as of December 31, 2018 | | 8,250 |
| | $ | 10.73 |
| | 5.73 | | $ | — |
| Exercisable as of December 31, 2018 | | 41 | | | $ | 2,146 | | | 5.73 | | $ | 0 | |
| | | | | | | | |
| Outstanding as of January 1, 2017 | | 8,593 |
| | $ | 11.88 |
| | 7.22 | | $ | 14 |
| |
| Granted | | 9,226 |
| | $ | 5.45 |
| | | |
| Exercised | | — |
| | $ | — |
| | $ | — |
| |
| Expired | | (435 | ) | | $ | 18.50 |
| | | |
| Forfeited | | (1,099 | ) | | $ | 9.12 |
| | | |
| 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 January 1, 2016 | | 5,377 |
| | $ | 19.37 |
| | 5.80 | | $ | — |
| |
| Granted | | 4,932 |
| | $ | 3.71 |
| | | |
| Exercised | | — |
| | $ | — |
| | $ | — |
| |
| Expired | | (771 | ) | | $ | 19.46 |
| | | |
| Forfeited | | (945 | ) | | $ | 5.66 |
| | | |
| 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 | | $ | — |
| |
| |
(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, 2018, there was $13 milliona stock option is the amount by which the current market value or the market value upon exercise of total unrecognized compensation expense related tothe underlying stock options. The expense is expected to be recognized over a weighted average periodexceeds the exercise price of approximately 1.56 years.the option.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Restricted Stock and Stock Option Compensation. We recognized the following compensation costs, net of actual forfeitures, related to restricted stock and stock options for the years ended December 31, 2018, 20172020, 2019 and 2016:2018:
| | | | | Years Ended December 31, | | | Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 | | | 2020 | | 2019 | | 2018 |
| | | ($ in millions) | | | ($ in millions) |
| General and administrative expenses | | $ | 28 |
| | $ | 37 |
| | $ | 38 |
| General and administrative expenses | | $ | 20 | | | $ | 26 | | | $ | 31 | |
| Oil and natural gas properties | | 6 |
| | 12 |
| | 16 |
| Oil and natural gas properties | | 1 | | | 2 | | | 2 | |
| Oil, natural gas and NGL production expenses | | 5 |
| | 12 |
| | 13 |
| Oil, natural gas and NGL production expenses | | 1 | | | 3 | | | 5 | |
| Marketing expenses | | — |
| | — |
| | 1 |
| |
| Exploration expenses | | Exploration expenses | | 0 | | | 1 | | | 1 | |
| Total restricted stock and stock option compensation | | $ | 39 |
| | $ | 61 |
| | $ | 68 |
| Total restricted stock and stock option compensation | | $ | 22 | | | $ | 32 | | | $ | 39 | |
Liability-Classified Awards
Performance Share Units. We In 2019, we granted PSUs to senior management that vest ratably over a three-yearthree-year performance period and are settled in cash. The ultimate amount earned is based on achievement of performance metrics established by the Compensation Committee of the Board of Directors. Compensation expense associated with PSU awards 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.
For PSUs granted in 2017 and 2016, performance metrics include a total shareholder return (TSR) component, which can range from 0% to 100% and an operational performance component based on finding and development costs, which can range from 0% to 100%, resulting in a maximum payout of 200%. The payout percentage for the 2016 and 2017 PSU awards is capped at 100% if our absolute TSR is less than zero. The PSUs are settled in cash on the third anniversary of the awards. We utilized a Monte Carlo simulation for the TSR performance measure and the following assumptions to determine the grant date fair value and the reporting date fair value of the 2017 awards. The performance period for the 2016 awards ended on December 31, 2018 and the TSR component has been finalized.
|
| | | |
Grant Date Assumptions |
Assumption | | 2017 Awards |
Volatility | | 80.65 | % |
Risk-free interest rate | | 1.54 | % |
Dividend yield for value of awards | | — | % |
|
| | | |
Reporting Date Assumptions |
Assumption | | 2017 Awards |
Volatility | | 64.69 | % |
Risk-free interest rate | | 2.63 | % |
Dividend yield for value of awards | | — | % |
As the above assumptions and expected satisfaction of performance metrics change, the PSU liabilities will be adjusted quarterly through the end of the performance period.
For PSUs granted in 2018, performance metrics include an operational performance component based on a ratio of cumulative earnings before interest expense, income taxes, and depreciation, depletion and amortization expense (EBITDA) to capital expenditures, for which payout can range from 0% to 200%. The vested PSUs are settled in cash on each of the three annual vesting dates. We used the closing price of our common stock on the grant date to determine the grant date fair value of the PSUs. The PSU liability will be adjusted quarterly, based on changes in our stock price and expected satisfaction of performance metrics, through the end of each vesting period.
Cash Restricted Stock Units. In 2018, we granted CRSUs to employees that vest straight-line over a three-year period and are settled in cash on each of the three3 annual vesting dates. The ultimate amount earned is based on the closing price of our common stock on each of the vesting dates. We used the closing price of our common stock on
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
the grant date to determine the grant date fair value of the CRSUs. The CRSU liability will be adjusted quarterly, based on changes in our stock price, through the end of eachthe vesting period.
The following table presents a summary of our liability-classified awards:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Grant Date Fair Value | | December 31, 2020 |
| | Units(a) | | | Fair Value | | Vested Liability |
| | | | ($ in millions) | | ($ in millions) |
| 2018 CRSU Awards: | | | | | | | | |
| Payable 2021 | | 13,351 | | | $ | 8 | | | $ | 0 | | | $ | 0 | |
____________________________________________(a) Amount has been retroactively adjusted to reflect a 1-for-200 (1:200) reverse stock split effective April 14, 2020. See Note 11 for additional information.
|
| | | | | | | | | | | | | | | |
| | | | | Grant Date Fair Value | | December 31, 2018 |
| | | Units | | | Fair Value | | Vested Liability |
| | | | | ($ in millions) | | ($ in millions) |
| 2018 PSU Awards: | | | | | | | | |
| Payable 2019, 2020 and 2021 | | 3,959,647 |
| | $ | 12 |
| | $ | 11 |
| | $ | — |
|
| 2017 PSU Awards: | | | | | | | | |
| Payable 2020 | | 1,217,774 |
| | $ | 8 |
| | $ | 3 |
| | $ | 1 |
|
| 2016 PSU Awards: | | | | | | | | |
| Payable 2019 | | 2,348,893 |
| | $ | 10 |
| | $ | 6 |
| | $ | 4 |
|
| 2018 CRSU Awards: | | | | | | | | |
| Payable 2019, 2020 and 2021 | | 15,189,197 |
| | $ | 46 |
| | $ | 32 |
| | $ | — |
|
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
We recognized the following compensation costs (credits), net of actual forfeitures, related to our liability-classified awards for the years ended December 31, 2018, 20172020, 2019 and 2016:2018:
| | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2020 | | 2019 | | 2018 |
| | | ($ in millions) |
| General and administrative expenses | | $ | (3) | | | $ | 5 | | | $ | 9 | |
| Oil and natural gas properties | | 0 | | | 1 | | | 1 | |
| Oil, natural gas and NGL production expenses | | (1) | | | 3 | | | 2 | |
| Separation and other termination costs | | 0 | | | 1 | | | 0 | |
| Total liability-classified awards compensation | | $ | (4) | | | $ | 10 | | | $ | 12 | |
2020 Compensation Adjustments
On May 5, 2020, all of the outstanding share-based compensation, including restricted stock, stock options, PSUs and CRSUs, granted to our executive officers and designated vice presidents was canceled and replaced with cash retention incentives. The cash retention incentives granted to executive officers are equally weighted between achievement of certain specified performance metrics and a service period. The cash retention incentives may be clawed back if an executive officer or vice president terminates employment for any reason other than a qualifying termination prior to the earlier of (i) the effective date of a plan of reorganization under Chapter 11 of the Bankruptcy Code or (ii) May 8, 2021. The transactions were considered a modification to the previously issued equity-classified awards. As such, the remaining unrecognized expense related to restricted stock and stock options will result in $18 million of share-based compensation expense to be amortized over the relevant service period of the new cash retention incentives. The $15 million after-tax fair value of the cash retention incentives was capitalized to other current assets in the consolidated balance sheets and will be amortized over the relevant service period. The difference between the cash and after-tax value of the cash retention incentives of approximately $10 million, which is not subject to the claw back provisions contained within the agreements, was expensed to general and administrative expenses in the consolidated statements of operations for the year ended December 31, 2020.
Post-Emergence Stock-Based Compensation
As of the Effective Date, the Board adopted the 2021 Long Term Incentive Plan (the 2021 LTIP) with a share reserve equal to 6,800,000 shares of New Common Stock. The 2021 LTIP provides for the grant of restricted stock units, restricted stock awards, stock options, stock appreciation rights, performance awards and other stock awards to the Company’s employees and non-employee directors.
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| | | ($ in millions) |
| General and administrative expenses | | $ | 7 |
| | $ | (4 | ) | | $ | 14 |
|
| Oil and natural gas properties | | 3 |
| | — |
| | — |
|
| Oil, natural gas and NGL production expenses | | 2 |
| | — |
| | — |
|
| Restructuring and other termination costs | | — |
| | — |
| | 1 |
|
| Total liability-classified awards compensation | | $ | 12 |
| | $ | (4 | ) | | $ | 15 |
|
12.13. Employee Benefit Plans
Our qualified 401(k) profit sharing 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% of an employee's base salary and performance bonus) in cash. We contributed $31$24 million, $35$29 million and $39$31 million to the 401(k) Plan in 2018, 20172020, 2019 and 2016,2018, respectively.
We also maintainmaintained a nonqualified deferred compensation plan (DC Plan). To be eligible to participate which we terminated in January 2020 in accordance with its terms. Accordingly, we derecognized 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 precedingasset associated with the year in whichplan after the employee is able to participate, or be designated as 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.participants’ investments were liquidated. 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. The participant may choose separate deferral election percentages for both plans. We contributed $7 million, $8 million and $9 millioncash was distributed to the DC Plan during 2018, 2017participants, and 2016, respectively, to fundwe extinguished the match. 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.corresponding $43 million accrued liability.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Any assets placed in trust by us to fund future obligations of our DC Plan are subject to the claims of creditors in the event of insolvency or bankruptcy,14. Derivative and participants are general creditors of the Company as to their deferred compensation in the plan.Hedging Activities
| |
13. | 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, 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. NoneNaN of our open oil, natural gas and NGL derivative instruments were designated for hedge accounting as of December 31, 20182020 and 2017.2019.
Oil, Natural Gas and NGL Derivatives
As of December 31, 20182020 and 2017,2019, our oil, 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.
•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 in exchange for a premium thatpremium. Swaptions allow the counterparty, on a specific date, to extend an existing fixed-price swap for a certain period of time.
time or to increase the notional volumes of an existing fixed-price swap.•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 pay 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 pay the floating market price differential to the counterparty for the hedged commodity.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The estimated fair values of our oil, natural gas and NGL derivative instrument assets (liabilities) as of December 31, 20182020 and 20172019 are provided below:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | December 31, 2020 | | December 31, 2019 |
| | Notional Volume | | Fair Value | | Notional Volume | | Fair Value |
| | | | ($ in millions) | | | | ($ in millions) |
| Oil (mmbbl): | | | | | | | | |
| Fixed-price swaps | | 27 | | | $ | (136) | | | 24 | | | $ | (7) | |
| Collars | | 0 | | | 0 | | | 2 | | | 14 | |
| Basis protection swaps | | 7 | | | (1) | | | 8 | | | (2) | |
| Total oil | | 34 | | | (137) | | | 34 | | | 5 | |
| Natural gas (bcf): | | | | | | | | |
| Fixed-price swaps | | 728 | | | 10 | | | 265 | | | 125 | |
| Collars | | 53 | | | 8 | | | 0 | | | 0 | |
| Call options (sold) | | 0 | | | 0 | | | 22 | | | 0 | |
| Call swaptions | | 0 | | | 0 | | | 29 | | | (2) | |
| Basis protection swaps | | 66 | | | 1 | | | 30 | | | 2 | |
| Total natural gas | | 847 | | | 19 | | | 346 | | | 125 | |
| Total estimated fair value | | | | $ | (118) | | | | | $ | 130 | |
|
| | | | | | | | | | | | | | |
| | | December 31, 2018 | | December 31, 2017 |
| | | Notional Volume | | Fair Value | | Notional Volume | | Fair Value |
| | | | | ($ in millions) | | | | ($ in millions) |
| Oil (mmbbl): | | | | | | | | |
| Fixed-price swaps | | 12 |
| | $ | 157 |
| | 21 |
| | $ | (151 | ) |
| Collars | | 8 |
| | 98 |
| | — |
| | — |
|
| Three-way collars | | — |
| | — |
| | 2 |
| | (10 | ) |
| Call swaptions | | — |
| | — |
| | 2 |
| | (13 | ) |
| Basis protection swaps | | 7 |
| | 5 |
| | 11 |
| | (9 | ) |
| Total oil | | 27 |
| | 260 |
| | 36 |
| | (183 | ) |
| Natural gas (bcf): | | | | | | | | |
| Fixed-price swaps | | 623 |
| | 26 |
| | 532 |
| | 149 |
|
| Three-way collars | | 88 |
| | 1 |
| | — |
| | — |
|
| Collars | | 55 |
| | (3 | ) | | 47 |
| | 11 |
|
| Call options | | 44 |
| | — |
| | 110 |
| | (3 | ) |
| Call swaptions | | 106 |
| | (9 | ) | | — |
| | — |
|
| Basis protection swaps | | 50 |
| | — |
| | 65 |
| | (7 | ) |
| Total natural gas | | 966 |
| | 15 |
| | 754 |
| | 150 |
|
| NGL (mmgal): | | | | | | | | |
| Fixed-price swaps | | — |
| | — |
| | 33 |
| | (2 | ) |
| Contingent Consideration: | | | | | | | | |
| Utica divestiture | | | | 7 |
| | | | — |
|
| Total estimated fair value | | | | $ | 282 |
| | | | $ | (35 | ) |
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).
Contingent Consideration Arrangements
In 2018, we sold our Utica Shale position to Encino. The agreement includes additional contingent payments to us of up to $100 million comprised of $50 million in consideration in each case if, on or prior to December 31, 2019, there is a period of twenty (20) trading days out of a period of thirty (30) consecutive trading days where (i) the average of the NYMEX natural gas strip prices for the months comprising the year 2022 equals or exceeds $3.00/mmbtu as calculated pursuant to the purchase agreement, and (ii) the average of the NYMEX natural gas strip price for the months comprising the year 2023 equals or exceeds $3.25/mmbtu as calculated pursuant to the purchase agreement. See Note 14 for further details regarding the transaction.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.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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 revenue as a realized gain. We reversed the cumulative unrealized gains, resulting in an unrealized loss of $297 million.
Effect of Derivative Instruments – Consolidated Balance Sheets
The following table presents the fair value and location of each classification of derivative instrument included in the consolidated balance sheets as of December 31, 20182020 and 20172019 on a gross basis and after same-counterparty netting:
| | | | | | | | | | | | | | | | | | | | |
| Balance Sheet Classification | | Gross Fair Value | | Amounts Netted in the Consolidated Balance Sheets | | Net Fair Value Presented in the Consolidated Balance Sheets |
| | ($ in millions) |
| As of December 31, 2020 | | | | | | |
| Commodity Contracts: | | | | | | |
| Short-term derivative asset | | $ | 84 | | | $ | (65) | | | $ | 19 | |
| Long-term derivative asset | | 5 | | | (5) | | | 0 | |
| Short-term derivative liability | | (158) | | | 65 | | | (93) | |
| Long-term derivative liability | | (49) | | | 5 | | | (44) | |
| Total derivatives | | $ | (118) | | | $ | 0 | | | $ | (118) | |
| | | | | | |
| As of December 31, 2019 | | | | | | |
| Commodity Contracts: | | | | | | |
| Short-term derivative asset | | $ | 174 | | | $ | (40) | | | $ | 134 | |
| Short-term derivative liability | | (42) | | | 40 | | | (2) | |
| Long-term derivative liability | | (2) | | | 0 | | | (2) | |
| Total derivatives | | $ | 130 | | | $ | 0 | | | $ | 130 | |
|
| | | | | | | | | | | | |
| Balance Sheet Classification | | Gross Fair Value | | Amounts Netted in the Consolidated Balance Sheets | | Net Fair Value Presented in the Consolidated Balance Sheets |
| | | ($ in millions) |
| As of December 31, 2018 | | | | | | |
| Commodity Contracts: | | | | | | |
| Short-term derivative asset | | $ | 306 |
| | $ | (104 | ) | | $ | 202 |
|
| Long-term derivative asset | | 117 |
| | (41 | ) | | 76 |
|
| Short-term derivative liability | | (107 | ) | | 104 |
| | (3 | ) |
| Long-term derivative liability | | (41 | ) | | 41 |
| | — |
|
| Contingent Consideration: | | | | | | |
| Short-term derivative asset | | 7 |
| | — |
| | 7 |
|
| Total derivatives | | $ | 282 |
| | $ | — |
| | $ | 282 |
|
| | | | | | | |
| 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 derivatives | | $ | (35 | ) | | $ | — |
| | $ | (35 | ) |
As of December 31, 20182020 and 2017,2019, we did not0t have any cash collateral balances for these derivatives.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Effect of Derivative Instruments – Consolidated Statements of Operations
The components of oil, natural gas and NGL revenues for the years ended December 31, 2018, 20172020, 2019 and 20162018 are presented below:
| | | | | Years Ended December 31, | | | Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 | | | 2020 | | 2019 | | 2018 |
| | | ($ in millions) | | ($ in millions) |
| Oil, natural gas and NGL revenues | | $ | 5,189 |
| | $ | 4,574 |
| | $ | 3,866 |
| Oil, natural gas and NGL revenues | | $ | 2,745 | | | $ | 4,517 | | | $ | 5,189 | |
Gains (losses) on undesignated oil, natural gas and NGL derivatives | | — |
| | 445 |
| | (545 | ) | |
| Gains on undesignated oil, natural gas and NGL derivatives | | Gains on undesignated oil, natural gas and NGL derivatives | | 629 | | | 40 | | | 0 | |
| Losses on terminated cash flow hedges | | (34 | ) | | (34 | ) | | (33 | ) | Losses on terminated cash flow hedges | | (33) | | | (35) | | | (34) | |
| Total oil, natural gas and NGL revenues | | $ | 5,155 |
| | $ | 4,985 |
| | $ | 3,288 |
| Total oil, natural gas and NGL revenues | | $ | 3,341 | | | $ | 4,522 | | | $ | 5,155 | |
The components of marketing revenues for the years ended December 31, 2018, 20172020, 2019 and 20162018 are presented below:
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| | | ($ in millions) |
| Marketing revenues | | $ | 5,069 |
| | $ | 4,511 |
| | $ | 4,881 |
|
| Gains on undesignated marketing natural gas derivatives | | 7 |
| | — |
| | — |
|
| Losses on undesignated supply contract derivatives | | — |
| | — |
| | (297 | ) |
| Total marketing revenues | | $ | 5,076 |
| | $ | 4,511 |
| | $ | 4,584 |
|
Gains as a result of changes in the fair value of our contingent consideration arrangements are recognized in loss on sale of oil and natural gas properties in the consolidated statement of operations. | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2020 | | 2019 | | 2018 |
| | ($ in millions) |
| Marketing revenues | | $ | 1,869 | | | $ | 3,971 | | | $ | 5,069 | |
| Gains (losses) on undesignated marketing natural gas derivatives | | 0 | | | (4) | | | 7 | |
| Total marketing revenues | | $ | 1,869 | | | $ | 3,967 | | | $ | 5,076 | |
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:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2020 | | 2019 | | 2018 |
| | | Before Tax | | After
Tax | | Before Tax | | After
Tax | | Before Tax | | After
Tax |
| | | ($ in millions) |
| Balance, beginning of period | | $ | (45) | | | $ | 12 | | | $ | (80) | | | $ | (23) | | | $ | (114) | | | $ | (57) | |
| Losses reclassified to income | | 33 | | | 33 | | | 35 | | | 35 | | | 34 | | | 34 | |
| Balance, end of period | | $ | (12) | | | $ | 45 | | | $ | (45) | | | $ | 12 | | | $ | (80) | | | $ | (23) | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| | | Before
Tax | | After
Tax | | Before
Tax | | After
Tax | | Before
Tax | | After
Tax |
| | | ($ in millions) |
| Balance, beginning of period | | $ | (114 | ) | | $ | (57 | ) | | $ | (153 | ) | | $ | (96 | ) | | $ | (160 | ) | | $ | (99 | ) |
| Net change in fair value | | — |
| | — |
| | 5 |
| | 5 |
| | (27 | ) | | (13 | ) |
| Losses reclassified to income | | 34 |
| | 34 |
| | 34 |
| | 34 |
| | 34 |
| | 16 |
|
| Balance, end of period | | $ | (80 | ) | | $ | (23 | ) | | $ | (114 | ) | | $ | (57 | ) | | $ | (153 | ) | | $ | (96 | ) |
The accumulated other comprehensive loss as of December 31, 20182020 represents 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. Remaining deferred gain or loss amounts will be recognized in earnings in the month for which the original contract months are to occur. As we early adopted ASU 2019-12 in 2020, the tax effect will be recognized in earnings in the year ended December 31, 2022. As of December 31, 2018,2020, we expect to transfer approximately $34$8 million of net loss included in accumulated other comprehensive income to net income (loss) during the next 12 months. The remaining amounts will be transferred by December 31, 2022.
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
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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, 2018,2020, our oil, natural gas and NGL derivative instruments were spread among 117 counterparties.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
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 the Chesapeake revolving credit facility.our DIP Credit Facility. The contracts entered into with these counterparties are secured by the same collateral that secures the Chesapeakepre-petition revolving credit facility. In addition, we enter into bilateral hedging agreements with other counterparties. The counterparties’ and our obligations under the bilateral hedging agreements 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. As of December 31, 2018, we posted an immaterial amount in letters of credit as collateral for our commodity derivatives. No cash was 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. Since oil, natural gas and NGL swaps 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, 20182020 and 2017:2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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, 2020 | | | | | | | | |
| Derivative Assets (Liabilities): | | | | | | | | |
| Commodity assets | | $ | 0 | | | $ | 78 | | | $ | 10 | | | $ | 88 | |
| Commodity liabilities | | 0 | | | (204) | | | (2) | | | (206) | |
| Total derivatives | | $ | 0 | | | $ | (126) | | | $ | 8 | | | $ | (118) | |
| | | | | | | | |
| As of December 31, 2019 | | | | | | | | |
| Derivative Assets (Liabilities): | | | | | | | | |
| Commodity assets | | $ | 0 | | | $ | 160 | | | $ | 14 | | | $ | 174 | |
| Commodity liabilities | | 0 | | | (42) | | | (2) | | | (44) | |
| Total derivatives | | $ | 0 | | | $ | 118 | | | $ | 12 | | | $ | 130 | |
|
| | | | | | | | | | | | | | | | |
| | | 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, 2018 | | | | | | | | |
| Derivative Assets (Liabilities): | | | | | | | | |
| Commodity assets | | $ | — |
| | $ | 319 |
| | $ | 103 |
| | $ | 422 |
|
| Commodity liabilities | | — |
| | (131 | ) | | (16 | ) | | (147 | ) |
| Utica divestiture contingent consideration | | — |
| | — |
| | 7 |
| | 7 |
|
| Total derivatives | | $ | — |
| | $ | 188 |
| | $ | 94 |
| | $ | 282 |
|
| | | | | | | | | |
| As of December 31, 2017 | | | | | | | | |
| Derivative Assets (Liabilities): | | | | | | | | |
| Commodity assets | | $ | — |
| | $ | — |
| | $ | 8 |
| | $ | 8 |
|
| Commodity liabilities | | — |
| | (20 | ) | | (23 | ) | | (43 | ) |
| Total derivatives | | $ | — |
| | $ | (20 | ) | | $ | (15 | ) | | $ | (35 | ) |
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
A summary of the changes in the fair values of our financial assets (liabilities) classified as Level 3 during 20182020 and 20172019 is presented below:
| | | | | | | | | | | | | | |
| | | Commodity Derivatives | | Utica Contingent Consideration |
| | | ($ in millions) |
| Balance, as of January 1, 2020 | | $ | 12 | | | $ | 0 | |
| Total gains (losses) (realized/unrealized): | | | | |
Included in earnings(a) | | 11 | | | 0 | |
| Total purchases, issuances, sales and settlements: | | | | |
| Settlements | | (15) | | | 0 | |
| Balance, as of December 31, 2020 | | $ | 8 | | | $ | 0 | |
| | | | |
| Balance, as of January 1, 2019 | | $ | 87 | | | $ | 7 | |
| Total gains (losses) (realized/unrealized): | | | | |
Included in earnings(a) | | (59) | | | (7) | |
| Total purchases, issuances, sales and settlements: | | | | |
| Settlements | | (16) | | | 0 | |
| Balance, as of December 31, 2019 | | $ | 12 | | | $ | 0 | |
|
| | | | | | | | |
| | | Commodity Derivatives | | Utica Contingent Consideration |
| | | ($ in millions) | | |
| Balance, as of January 1, 2018 | | $ | (15 | ) | | $ | — |
|
| Total gains (losses) (realized/unrealized): | | | | |
Included in earnings(a) | | 77 |
| | 7 |
|
| Total purchases, issuances, sales and settlements: | | | | |
| Settlements | | 25 |
| | — |
|
| Balance, as of December 31, 2018 | | $ | 87 |
| | $ | 7 |
|
| | | | | |
| 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 | ) | | $ | — |
|
|
| | | | | | | | | | | | | | | | | |
| (a) | | | Commodity Derivatives | | Utica Contingent Consideration |
| | |
| | | | 2018 | | 2017 | | 2018 | | 2017 |
| | | | ($ in millions) | | | | |
| | Total gains included in earnings for the period | | $ | 77 |
| | $ | 2 |
| | $ | 7 |
| | $ | — |
|
| | Change in unrealized gains (losses) related to assets still held at reporting date | | $ | 86 |
| | $ | (14 | ) | | $ | 7 |
| | $ | — |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (a) | | | Commodity Derivatives | | Utica Contingent Consideration |
| |
| | | 2020 | | 2019 | | 2020 | | 2019 |
| | | ($ in millions) |
| Total gains (losses) included in earnings for the period | | $ | 11 | | | $ | (59) | | | $ | 0 | | | $ | (7) | |
| Change in unrealized gains (losses) related to assets still held at reporting date | | $ | 0 | | | $ | (19) | | | $ | 0 | | | $ | 0 | |
Qualitative and Quantitative Disclosures about Unobservable Inputs for Level 3 Fair Value Measurements
The significant unobservable inputs for Level 3 derivative contracts include market volatility. Changes in market volatility 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. The following table presents quantitative information about Level 3 inputs used in the fair value measurement of our commodity derivative contracts as of December 31, 2018:2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Instrument Type | | Unobservable Input | | Range | | Weighted Average | | Fair Value
December 31, 2020 |
| | | | | | | | | ($ in millions) |
| Natural gas trades | | Natural gas price volatility curves | | 24% – 71% | | 38% | | $ | 8 | |
|
| | | | | | | | | | |
Instrument Type | | Unobservable Input | | Range | | Weighted Average | | Fair Value
December 31, 2018 |
| | | | | | | | | ($ in millions) |
| Oil trades | | Oil price volatility curves | | 23.70% – 42.17% | | 32.51% | | $ | 98 |
|
| Natural gas trades | | Natural gas price volatility curves | | 12.88% – 90.93% | | 24.93% | | $ | (11 | ) |
| Utica contingent consideration | | Natural gas price volatility curves | | 10.36% – 57.66% | | — | | $ | 7 |
|
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
15. Capitalized Exploratory Well Costs
| |
14. | Oil and Natural Gas Property Transactions |
Under full cost accounting rules, we accountedA summary of the changes in our capitalized well costs for the salesyears ended December 31, 2020, 2019 and 2018 is detailed below. Additions pending the determination of oil and natural gas properties as adjustments to capitalized costs, with no recognition of gain or loss unless a sale involves a significant change in proved reserves excludes amounts capitalized and significantly alterssubsequently charged to expense within the relationship betweensame year.
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| | | (in millions) |
| Balance as of January 1 | | $ | 7 | | | $ | 36 | | | $ | 36 | |
| Additions pending the determination of proved reserves | | 0 | | | 7 | | | 74 | |
| Divestitures and other | | 0 | | | (3) | | | 0 | |
| Reclassifications to proved properties | | 0 | | | (17) | | | (40) | |
| Charges to exploration expense | | (7) | | | (16) | | | (34) | |
| Balance as of December 31 | | $ | 0 | | | $ | 7 | | | $ | 36 | |
The following table provides an aging of capitalized costs and proved reserves.
2018 Transactions
We sold allthe number of our approximately 1,500,000 gross (900,000 net) acres in Ohio, ofprojects for which approximately 320,000 net acres are prospectiveexploratory well costs have been capitalized for the Utica Shale with approximately 920 producing wells, along with related property and equipment (collectively, the “Designated Properties”) for net proceeds of $1.868 billion to Encino, with additional contingent payments to us of up to $100 million comprised of $50 million in consideration in each case if, on or prior to December 31, 2019, there is a period greater than one year since the completion of twenty (20) trading days out of a period of thirty (30) consecutive trading days where (i) the average of the NYMEX natural gas strip prices for the months comprising the year 2022 equals or exceeds $3.00/mmbtu as calculated pursuant to the purchase agreement, and (ii) the average of the NYMEX natural gas strip prices for the months comprising the year 2023 equals or exceeds $3.25/mmbtu as calculated pursuant to the purchase agreement.drilling.
The sale of our Designated Properties to Encino involved a significant change in proved reserves and significantly altered the relationship between costs and proved reserves and therefore resulted in the recognition of loss of approximately $578 million. Under SEC rules for full cost companies, a transaction is deemed to be significant if the properties being sold represent 25% or more of the reserve quantities of the divesting company. | | | | | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 | | 2018 |
| | | (in millions) |
| Exploratory well costs capitalized for a period of one year or less | | $ | 0 | | | $ | 7 | | | $ | 34 | |
| Exploratory well costs capitalized for a period greater than one year | | 0 | | | 0 | | | 2 | |
| Balance as of December 31 | | $ | 0 | | | $ | 7 | | | $ | 36 | |
| | | | | | |
| Number of projects with exploratory well costs capitalized for a period greater than one year | | 0 | | | 0 | | | 7 | |
In 2018, we sold portions of our acreage, producing properties and other related property and equipment in the Mid-Continent, including our Mississippian Lime assets, for approximately $491 million, subject to certain customary closing adjustments. Included in the sales were approximately 238,500 net acres and interests in approximately 3,200 wells. Also, in 2018, we received proceeds of approximately $37 million subject to customary closing adjustments, for the sale of other oil and natural gas properties covering various operating areas.
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. 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.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
We sold certain of our other noncore oil16. Other Property 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.Equipment
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.
As of December 31, 2018, 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, 2018 were as follows:
|
| | | | | | | | | | | | | | |
| | | | | Volume Remaining as of December 31, 2018 |
| VPP # | | Term Remaining | | Oil | | Natural Gas | | NGL | | Total |
| | | (in months) | | (mmbbl) | | (bcf) | | (mmbbl) | | (bcfe) |
| 9 | | 26 | | 0.2 |
| | 23.1 |
| | 0.6 |
| | 28.1 |
|
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| |
15. | 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:
| | | | | December 31, | | Estimated Useful Life | | December 31, | | Estimated Useful Life |
| | | 2018 | | 2017 | | | 2020 | | 2019 | |
| | | ($ in millions) | | (in years) | | ($ in millions) | | (in years) |
| Buildings and improvements | | $ | 1,053 |
| | $ | 1,093 |
| | 10 – 39 | Buildings and improvements | | $ | 1,038 | | | $ | 1,058 | | | 10 – 39 |
| Computer equipment | | 353 |
| | 345 | | 5 | Computer equipment | | 356 | | | 355 | | | 5 |
| Sand mine | | Sand mine | | 81 | | | 78 | | | 10 – 30 |
Natural gas compressors(a) | | 48 |
| | 235 | | 3 – 20 | Natural gas compressors(a) | | 36 | | | 48 | | | 3 – 20 |
| Land | | 106 |
| | 126 |
| | | Land | | 113 | | | 115 | | | |
| Other | | 161 |
| | 187 |
| | 5 – 20 | Other | | 130 | | | 156 | | | 5 – 20 |
| Total other property and equipment, at cost | | 1,721 |
| | 1,986 |
| | Total other property and equipment, at cost | | 1,754 | | | 1,810 | | |
| Less: accumulated depreciation | | (630 | ) | | (672 | ) | | Less: accumulated depreciation | | (799) | | | (692) | | |
| Total other property and equipment, net | | $ | 1,091 |
| | $ | 1,314 |
| | Total other property and equipment, net | | $ | 955 | | | $ | 1,118 | | |
(a) Includes assets under capitalfinance lease of $27 million, less accumulated depreciation of $1$18 million and $10 million, as of December 31, 2018.2020 and 2019, respectively. The related amortization expense for assets under capitalfinance lease is included in depreciation, depletion and amortization expense on our consolidated statement of operations.
17. Investments
FTS International, Inc. (NYSE: FTSI). In 2018, FTS International, Inc. (NYSE: FTSI) completed an initial public offering. Due to the offering, the ownership percentage of our equity method investment in FTSI decreased from approximately 29% to 24% and resulted in a gain of $78 million. In addition, we sold approximately 4.3 million shares of FTSI in the offering for net proceeds of approximately $74 million and recognized a gain of $61 million decreasing our ownership percentage to approximately 20%. We continue to hold approximately 22.0 million shares
In 2019, the hydraulic fracturing industry experienced challenging operating conditions resulting in the publicly traded company. current 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 is other-than-temporary, and recognized an impairment of our investment in FTSI of approximately $43 million.
In 2016,2020, the hydraulic fracturing industry continued experiencing challenging operating conditions resulting in FTSI filing for Chapter 11 bankruptcy and we recognized an other-than-temporary impairment of $119 million related to our Sundrop investment.
Impairmentsentire investment of Oil$23 million. FTSI emerged from bankruptcy on November 19, 2020 and Natural Gas Properties
Our proved oil and natural gas properties are subject to quarterly full cost ceiling tests. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sumthis restructuring resulted in a reduction of the presentcommon 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 estimated future net revenues (adjusted for cash flow hedges) less estimated future expenditures to be incurredDecember 31, 2020.
JWH Midstream LLC (JWH). In 2019, in developing and producingconnection with the proved reserves, less any related income tax effects. Estimated future net revenues for the quarterly ceiling limit are calculated using the averageacquisition of commodity prices on the first day of the month over the trailing 12-month period. In 2018 and 2017,WildHorse, we did not have an impairment for our oil and natural gas properties. In 2016, capitalized costs of oil and natural gas properties exceeded the ceiling, resultingobtained a 50% membership interest in an impairment in theJWH Midstream LLC (JWH). The carrying value of our oilinvestment in JWH, which was being accounted for as an equity method investment, was approximately $17 million. In 2019, 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, natural gas propertiestherefore, we impaired the full value of $2.564 billion.the investment and recognized approximately $24 million of impairment expense in 2019.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
18. Impairments
Impairments of Oil and Natural Gas Properties
A summary of our impairments of oil and natural gas properties for the years ended December 31, 2020, 2019 and 2018 is as follows:
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| | | ($ in millions) |
| Impairments due to lower forecasted commodity prices | | $ | 8,446 | | | $ | 8 | | | $ | 23 | |
| Impairments due to anticipated sale | | 0 | | | 0 | | | 55 | |
| Total impairments of oil and natural gas properties | | $ | 8,446 | | | $ | 8 | | | $ | 78 | |
During 2020, 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 current and 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 based on the NYMEX strip pricing escalated by an inflationary rate after 2 years, (ii) pricing adjustments for differentials, (iii) operating costs, (iv) capital investment plans, (v) future production volumes, and (vi) estimated proved reserves.
•Unprecedented volatility in the price of oil due to the decrease in demand has led us to rely on NYMEX strip pricing, which represents a Level 1 input.
Certain oil and gas properties in our Eagle Ford, Brazos Valley, Powder River Basin, and Mid-Continent and other non-core operating areas failed the Step 1 assessment. For these assets, we used a discounted cash flow analysis to estimate fair value. The expected future net cash flows were discounted using a rate of 11%, which we believe represents the estimated weighted average cost of capital of a theoretical market participant. Based on Step 2 of our long-lived assets impairment test, we recognized an $8.446 billion impairment because the carrying value exceeded estimated fair market value as of March 31, 2020.
•Significant inputs associated with the calculation of discounted future net cash flows include estimates of (i) recoverable reserves, (ii) production rates, (iii) future operating and development costs, (iv) future commodity prices escalated by an inflationary rate after two years, adjusted for differentials, and (v) a market-based weighted average cost of capital. We utilized NYMEX strip pricing, adjusted for differentials, to value the reserves. The NYMEX strip pricing inputs used are classified as Level 1 fair value assumptions and all other inputs are classified as Level 3 fair value assumptions.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Impairments of Fixed Assets
We review our long-lived assets, other than oil and natural gas properties, for recoverability whenever events or changes in circumstances indicate that carrying amounts may not be recoverable. We recognize an impairment if the carrying amount of a long-lived asset is not recoverable and exceeds its fair value. A summary of our impairments of fixed assets by asset class and other charges for the years ended December 31, 2018, 20172020, 2019 and 20162018 is as follows:
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| | | ($ in millions) |
| Sand mine | | $ | 76 | | | $ | 0 | | | $ | 0 | |
| Natural gas compressors | | 13 | | | 0 | | | 45 | |
| Buildings and land | | 0 | | | 1 | | | 4 | |
| Other | | 0 | | | 2 | | | 4 | |
| Total impairments of fixed assets and other | | $ | 89 | | | $ | 3 | | | $ | 53 | |
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| | | ($ in millions) |
| Natural gas compressors | | $ | 45 |
| | $ | — |
| | $ | 21 |
|
| Barnett Shale exit costs | | — |
| | — |
| | 284 |
|
| Devonian Shale exit costs | | — |
| | — |
| | 142 |
|
| Gathering systems | | — |
| | — |
| | 3 |
|
| Buildings and land | | 4 |
| | 5 |
| | 11 |
|
| Other | | 4 |
| | — |
| | — |
|
| Total impairments of fixed assets and other | | $ | 53 |
| | $ | 5 |
| | $ | 461 |
|
Natural Gas Compressors.In 2020, we recorded a $76 million impairment of our sand mine assets that support our Brazos Valley operating area for the difference between the fair value and carrying value of the assets as well as a $13 million impairment of compressor inventory due to a lack of a current market for compressors. In 2018, we recorded a $45 million impairment related to 890 compressors for the difference between carrying value and the fair value of the assets.
19. Exploration Expense
A summary of our exploration expense for the years ended December 31, 2020, 2019 and 2018 is as follows:
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| | | ($ in millions) |
| Impairments of unproved properties | | $ | 411 | | | $ | 32 | | | $ | 59 | |
| Dry hole expense | | 7 | | | 25 | | | 37 | |
| Geological and geophysical expense and other | | 9 | | | 27 | | | 66 | |
| Exploration expense | | $ | 427 | | | $ | 84 | | | $ | 162 | |
Unproved oil and natural gas properties 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 2020 are primarily the result of non-cash impairment charges in unproved properties, primarily in our Brazos Valley, Haynesville, Powder River Basin and Mid-Continent operating areas. The decrease in geological and geophysical expense in 2019 and 2020 was due to fewer exploratory geological and geophyscial projects.
20. Other Operating Expense
In 2016,2020, we recordedterminated certain gathering, processing and transportation contracts and recognized a $13non-recurring $80 million impairmentexpense related to obsolescencethe contract terminations. The contract terminations removed approximately $169 million of 205 compressors. Additionally in 2016, we recorded an $8 million impairment related to 155 compressors for the difference between the aggregate sales price and carrying value.
Barnett Shale Exit Costs. In 2016, we conveyed our interests in the Barnett Shale operating area located in north central Texas and recognized an impairment charge of $284 million 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.
Nonrecurring Fair Value Measurements. Fair value measurements 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.
| |
18. | Other Operating Expense |
In 2017, we terminated future natural gas transportation commitments related to divested assets for cash paymentsgathering, processing and transportation agreements.
In 2019, we recorded approximately $37 million of $126 million. Also in 2017,costs related to our acquisition of WildHorse which consisted of consulting fees, financial advisory fees, legal fees and travel and lodging expenses. In addition, we paid $290recorded approximately $38 million to assign an oil transportation agreement to a third party. 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. Asseverance expense as a result of this transaction, we recognized $361 millionthe acquisition of charges relatedWildHorse. A majority of the WildHorse executives and employees were terminated on the date of acquisition. These executives and employees were entitled to the termination of natural gas gathering and transportationseverance benefits in accordance with existing employment agreements.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
21. Separation and Other Termination Costs
| |
19. | Restructuring and Other Termination Costs |
Workforce Reductions
In 2020, 2019 and 2018, we underwent a reductionincurred charges of approximately $44 million, $12 million and $38 million related to one-time termination benefits for certain employees.
Subsequent to December 31, 2020, we reduced our workforce by 220 employees or approximately 15%, primarily in workforce impacting approximately 13% of employees across all functions, primarily on our Oklahoma City campus. In connection with the reduction, weand incurred a total chargecharges of approximately $38 million for one-time termination benefits. The following table summarizes our restructuring liabilities:$20 million.
|
| | | | |
| | Other Current Liabilities |
| | ($ in millions) |
Balance as of December 31, 2017 | | $ | — |
|
Initial restructuring recognition on January 30, 2018 | | 38 |
|
Termination benefits paid | | (38 | ) |
Balance as of December 31, 2018 | | $ | — |
|
22.Asset Retirement ObligationsIn 2016, we recognized $6 million of charges related to a reduction in workforce in connection with the restructuring of our compressor manufacturing subsidiary and the reductions in workforce resulting from the conveyance of our interests in the Barnett Shale and Devonian Shale operating areas.
| |
20. | Fair Value Measurements |
Recurring Fair Value Measurements
Other Current Assets. Assets related to our deferred compensation plan are included in other current assets. The fair value of these assets is determined using quoted market prices as they consist of exchange-traded securities.
Other Current Liabilities. Liabilities related to our deferred compensation plan are included in other current liabilities. The fair values of these liabilities are determined using quoted market prices as the plan consists of exchange-traded mutual funds.
Financial Assets (Liabilities). The following table provides fair value measurement information for the above-noted financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2018 and 2017:
|
| | | | | | | | | | | | | | | | |
| | | Quoted Prices in Active Markets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Total Fair Value |
| | | ($ in millions) |
| As of December 31, 2018 | | | | | | | | |
| Financial Assets (Liabilities): | | | | | | | | |
| Other current assets | | $ | 50 |
| | $ | — |
| | $ | — |
| | $ | 50 |
|
| Other current liabilities | | (51 | ) | | — |
| | — |
| | (51 | ) |
| Total | | $ | (1 | ) | | $ | — |
| | $ | — |
| | $ | (1 | ) |
| | | | | | | | | |
| As of December 31, 2017 | | | | | | | | |
| Financial Assets (Liabilities): | | | | | | | | |
| Other current assets | | $ | 57 |
| | $ | — |
| | $ | — |
| | $ | 57 |
|
| Other current liabilities | | (60 | ) | | — |
| | — |
| | (60 | ) |
| Total | | $ | (3 | ) | | $ | — |
| | $ | — |
| | $ | (3 | ) |
See Note 3 for information regarding fair value measurement of our debt instruments. See Note 13 for information regarding fair value measurement of our derivatives.Nonrecurring Fair Value Measurements
See Note 17 regarding nonrecurring fair value measurements.CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| |
21. | Asset Retirement Obligations |
The components of the change in our asset retirement obligations are shown below:
| | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | 2019 |
| | ($ in millions) |
| Asset retirement obligations, beginning of period | | $ | 211 | | | $ | 166 | |
Additions(a) | | 1 | | | 21 | |
| Revisions | | (14) | | | 18 | |
Settlements and disposals(b) | | (66) | | | (5) | |
| Accretion expense | | 12 | | | 11 | |
| Asset retirement obligations, end of period | | 144 | | | 211 | |
| Less current portion | | 5 | | | 11 | |
| Asset retirement obligation, long-term | | $ | 139 | | | $ | 200 | |
(a) During 2019, approximately $17 million of additions relate to the acquisition of WildHorse.
(b) During 2020, approximately $49 million and $14 million of disposals related to our Mid-Continent and Haynesville assets, respectively. See Note 3 for further discussion of these transactions. 23. Major Customers
|
| | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | 2017 |
| | | ($ in millions) |
| Asset retirement obligations, beginning of period | | $ | 177 |
| | $ | 261 |
|
| Additions | | 3 |
| | 5 |
|
| Revisions | | 11 |
| | (34 | ) |
| Settlements and disposals | | (35 | ) | | (70 | ) |
| Accretion expense | | 10 |
| | 15 |
|
| Asset retirement obligations, end of period | | 166 |
| | 177 |
|
| Less current portion | | 11 |
| | 15 |
|
| Asset retirement obligation, long-term | | $ | 155 |
| | $ | 162 |
|
Sales to Valero Energy Corporation constituted approximately 17%, 12% and 10% of our total revenues (before the effects of hedging for the year ended December 31, 2018. 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% of our total revenues (before the effects of hedging) for the years ended December 31, 2016.
| |
23. | Condensed Consolidating Financial Information |
Chesapeake Energy Corporation is a holding company, owns no operating assets2020, 2019 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 certain2018, respectively. No other purchasers accounted for more than 10% 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, 2018 and 2017 and for the years ended December 31, 2018 and 2017. This financial information may not necessarily be indicative of our results of operations, cash flowstotal revenues in 2020, 2019 or financial position had these subsidiaries operated as independent entities.2018.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
24. Condensed Combined Debtor-in-Possession Financial Information
CONDENSED CONSOLIDATING BALANCE SHEETThe financial statements below represent the combined financial statements of the Debtors as of December 31, 2020 and 2019 and the years ended December 31, 2020, 2019 and 2018.
AS OF DECEMBER 31, 2018 | | | | | | | | | | | | | | |
| Condensed Combined Balance Sheets | | Total Combined Debtor Entities |
| | December 31, |
| | 2020 | | 2019 |
| | ($ in millions) |
| ASSETS | | | | |
| CURRENT ASSETS: | | | | |
| Cash and cash equivalents | | $ | 278 | | | $ | 4 | |
| Other current assets | | 829 | | | 1,244 | |
| Total Current Assets | | 1,107 | | | 1,248 | |
| PROPERTY AND EQUIPMENT: | | | | |
Oil and natural gas properties at cost, based on successful efforts
accounting, net | | 4,277 | | | 13,586 | |
| Other property and equipment, net | | 955 | | | 1,118 | |
| Property and equipment held for sale, net | | 10 | | | 10 | |
| Total Property and Equipment, Net | | 5,242 | | | 14,714 | |
| Other long-term assets | | 234 | | | 187 | |
| Investments in subsidiaries and intercompany advances | | 1 | | | 6 | |
| TOTAL ASSETS | | $ | 6,584 | | | $ | 16,155 | |
| | | | |
| LIABILITIES AND EQUITY (DEFICIT): | | | | |
| CURRENT LIABILITIES: | | | | |
| Current liabilities | | $ | 3,094 | | | $ | 2,391 | |
| Total Current Liabilities | | 3,094 | | | 2,391 | |
| Long-term debt, net | | 0 | | | 9,073 | |
| Deferred income tax liabilities | | 0 | | | 10 | |
| Other long-term liabilities | | 188 | | | 317 | |
| Liabilities subject to compromise | | 8,643 | | | 0 | |
| Total Liabilities | | 11,925 | | | 11,791 | |
| EQUITY (DEFICIT): | | | | |
| Stockholders’ equity (deficit) | | (5,341) | | | 4,364 | |
| Total Equity (Deficit) | | (5,341) | | | 4,364 | |
| TOTAL LIABILITIES AND EQUITY (DEFICIT) | | $ | 6,584 | | | $ | 16,155 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Parent | | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | Eliminations | | Consolidated |
| CURRENT ASSETS: | | | | | | | | | | |
| Cash and cash equivalents | | $ | 4 |
| | $ | 1 |
| | $ | 1 |
| | $ | (2 | ) | | $ | 4 |
|
| Other current assets | | 60 |
| | 1,532 |
| | 2 |
| | — |
| | 1,594 |
|
| Intercompany receivable, net | | 6,098 |
| | 203 |
| | — |
| | (6,301 | ) | | — |
|
| Total Current Assets | | 6,162 |
| | 1,736 |
| | 3 |
| | (6,303 | ) | | 1,598 |
|
| PROPERTY AND EQUIPMENT: | | | | | | | | | | |
Oil and natural gas properties at cost, based on full cost accounting, net | | 598 |
| | 7,302 |
| | 24 |
| | — |
| | 7,924 |
|
| Other property and equipment, net | | — |
| | 1,091 |
| | — |
| | — |
| | 1,091 |
|
Property and equipment held for sale, net | | — |
| | 15 |
| | — |
| | — |
| | 15 |
|
Total Property and Equipment, Net | | 598 |
| | 8,408 |
| | 24 |
| | — |
| | 9,030 |
|
| LONG-TERM ASSETS: | | | | | | | | | | |
| Other long-term assets | | 26 |
| | 293 |
| | — |
| | — |
| | 319 |
|
Investments in subsidiaries and intercompany advances | | 1,500 |
| | (97 | ) | | — |
| | (1,403 | ) | | — |
|
| TOTAL ASSETS | | $ | 8,286 |
| | $ | 10,340 |
| | $ | 27 |
| | $ | (7,706 | ) | | $ | 10,947 |
|
| | | | | | | | | | | |
| CURRENT LIABILITIES: | | | | | | | | | | |
| Current liabilities | | $ | 523 |
| | $ | 2,306 |
| | $ | 1 |
| | $ | (2 | ) | | $ | 2,828 |
|
| Intercompany payable, net | | 25 |
| | 6,276 |
| | — |
| | (6,301 | ) | | — |
|
| Total Current Liabilities | | 548 |
| | 8,582 |
| | 1 |
| | (6,303 | ) | | 2,828 |
|
| LONG-TERM LIABILITIES: | | | | | | | | | | |
| Long-term debt, net | | 7,341 |
| | — |
| | — |
| | — |
| | 7,341 |
|
| Other long-term liabilities | | 53 |
| | 258 |
| | — |
| | — |
| | 311 |
|
| Total Long-Term Liabilities | | 7,394 |
| | 258 |
| | — |
| | — |
| | 7,652 |
|
| EQUITY: | | | | | | | | | | |
| Chesapeake stockholders’ equity | | 344 |
| | 1,500 |
| | (97 | ) | | (1,403 | ) | | 344 |
|
| Noncontrolling interests | | — |
| | — |
| | 123 |
| | — |
| | 123 |
|
| Total Equity | | 344 |
| | 1,500 |
| | 26 |
| | (1,403 | ) | | 467 |
|
| TOTAL LIABILITIES AND EQUITY | | $ | 8,286 |
| | $ | 10,340 |
| | $ | 27 |
| | $ | (7,706 | ) | | $ | 10,947 |
|
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 2017
($ in millions) | | | | | | | | | | | | | | | | | | | | |
| Condensed Combined Statements of Operations | | Total Combined Debtor Entities |
| | Years Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| | ($ in millions) |
| REVENUES AND OTHER: | | | | | | |
| Oil, natural gas and NGL | | $ | 3,334 | | | $ | 4,508 | | | $ | 5,136 | |
| Marketing | | 1,869 | | | 3,967 | | | 5,076 | |
| Total Revenues | | 5,203 | | | 8,475 | | | 10,212 | |
| Other | | 56 | | | 63 | | | 63 | |
| Gains (losses) on sales of assets | | 30 | | | 43 | | | (264) | |
| Total Revenues and Other | | 5,289 | | | 8,581 | | | 10,011 | |
| OPERATING EXPENSES: | | | | | | |
| Oil, natural gas and NGL production | | 373 | | | 520 | | | 474 | |
| Oil, natural gas and NGL gathering, processing and transportation | | 1,079 | | | 1,076 | | | 1,391 | |
| Severance and ad valorem taxes | | 149 | | | 224 | | | 188 | |
| Exploration | | 427 | | | 84 | | | 162 | |
| Marketing | | 1,889 | | | 4,003 | | | 5,158 | |
| General and administrative | | 266 | | | 314 | | | 334 | |
| Separation and other termination costs | | 44 | | | 12 | | | 38 | |
| Provision for legal contingencies | | 27 | | | 19 | | | 26 | |
| Depreciation, depletion and amortization | | 1,095 | | | 2,258 | | | 1,730 | |
| Impairments | | 8,501 | | | 11 | | | 131 | |
| Other operating expense | | 109 | | | 92 | | | 0 | |
| Total Operating Expenses | | 13,959 | | | 8,613 | | | 9,632 | |
| INCOME (LOSS) FROM OPERATIONS | | (8,670) | | | (32) | | | 379 | |
| OTHER INCOME (EXPENSE): | | | | | | |
| Interest expense | | (331) | | | (651) | | | (633) | |
| Gains (losses) on investments | | (20) | | | (71) | | | 139 | |
| Gains on purchases or exchanges of debt | | 65 | | | 75 | | | 263 | |
| Other income | | 16 | | | 39 | | | 67 | |
| Reorganization items, net | | (796) | | | 0 | | | 0 | |
| Equity in net earnings (losses) of subsidiary | | (17) | | | 1 | | | 1 | |
| Total Other Expense | | (1,083) | | | (607) | | | (163) | |
| INCOME (LOSS) BEFORE INCOME TAXES | | (9,753) | | | (639) | | | 216 | |
| INCOME TAX BENEFIT | | (19) | | | (331) | | | (10) | |
| NET INCOME (LOSS) | | (9,734) | | | (308) | | | 226 | |
| Other comprehensive income | | 33 | | | 35 | | | 34 | |
| COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE | | $ | (9,701) | | | $ | (273) | | | $ | 260 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | | 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 |
|
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| | | | | | | | | | | | | | | | | | | | |
| Condensed Combined Statements of Cash Flows | | Total Combined Debtor Entities |
| | Years Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| | ($ in millions) |
| CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
| Net Cash Provided By Operating Activities | | $ | 1,163 | | | $ | 1,618 | | | $ | 1,727 | |
| | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | |
| Drilling and completion costs | | (1,111) | | | (2,180) | | | (1,848) | |
| Business combination, net | | 0 | | | (353) | | | 0 | |
| Acquisitions of proved and unproved properties | | (9) | | | (35) | | | (128) | |
| Proceeds from divestitures of proved and unproved properties | | 136 | | | 130 | | | 2,231 | |
| Additions to other property and equipment | | (22) | | | (48) | | | (21) | |
| Proceeds from sales of other property and equipment | | 14 | | | 6 | | | 147 | |
| Proceeds from sales of investments | | 0 | | | 0 | | | 74 | |
| Net Cash Provided By (Used In) Investing Activities | | (992) | | | (2,480) | | | 455 | |
| | | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | |
| Proceeds from pre-petition revolving credit facility borrowings | | 3,656 | | | 10,676 | | | 11,697 | |
| Payments on pre-petition revolving credit facility borrowings | | (3,317) | | | (10,180) | | | (12,059) | |
| Proceeds from DIP credit facility borrowings | | 60 | | | 0 | | | 0 | |
| Payments on DIP credit facility borrowings | | (60) | | | 0 | | | 0 | |
| DIP credit facility and exit facilities financing costs | | (109) | | | 0 | | 0 |
| Proceeds from issuance of senior notes, net | | 0 | | | 108 | | | 1,236 | |
| Proceeds from issuance of term loan, net | | 0 | | | 1,455 | | | 0 | |
| Cash paid to purchase debt | | (94) | | | (1,073) | | | (2,813) | |
| Cash paid for preferred stock dividends | | (22) | | | (91) | | | (92) | |
| Other financing activities | | (11) | | | (32) | | | (149) | |
| Intercompany advances, net | | 0 | | | 0 | | | (2) | |
| Net Cash Provided by (Used In) Financing Activities | | 103 | | | 863 | | | (2,182) | |
| Net increase in cash and cash equivalents | | 274 | | | 1 | | | 0 | |
| Cash and cash equivalents, beginning of period | | 4 | | | 3 | | | 3 | |
| Cash and cash equivalents, end of period | | $ | 278 | | | $ | 4 | | | $ | 3 | |
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
YEAR ENDED DECEMBER 31, 2018
($ in millions)
|
| | | | | | | | | | | | | | | | | | | | |
| | | Parent | | Guarantor Subsidiaries | | Non- Guarantor Subsidiaries | | Eliminations | | Consolidated |
| REVENUES: | | | | | | | | | | |
| Oil, natural gas and NGL | | $ | — |
| | $ | 5,136 |
| | $ | 19 |
| | $ | — |
| | $ | 5,155 |
|
| Marketing | | — |
| | 5,076 |
| | — |
| | — |
| | 5,076 |
|
| Total Revenues | | — |
| | 10,212 |
| | 19 |
| | — |
| | 10,231 |
|
| OPERATING EXPENSES: | | | | | | | | | | |
| Oil, natural gas and NGL production | | — |
| | 539 |
| | — |
| | — |
| | 539 |
|
| Oil, natural gas and NGL gathering, processing and transportation | | — |
| | 1,391 |
| | 7 |
| | — |
| | 1,398 |
|
| Production taxes | | — |
| | 123 |
| | 1 |
| | — |
| | 124 |
|
| Marketing | | — |
| | 5,158 |
| | — |
| | — |
| | 5,158 |
|
| General and administrative | | 2 |
| | 277 |
| | 1 |
| | — |
| | 280 |
|
| Restructuring and other termination costs | | — |
| | 38 |
| | — |
| | — |
| | 38 |
|
| Provision for legal contingencies, net | | — |
| | 26 |
| | — |
| | — |
| | 26 |
|
| Depreciation, depletion and amortization | | — |
| | 1,142 |
| | 3 |
| | — |
| | 1,145 |
|
| Loss on sale of oil and natural gas properties | | — |
| | 578 |
| | — |
| | — |
| | 578 |
|
| Impairments | | — |
| | 53 |
| | — |
| | — |
| | 53 |
|
| Other operating expense | | — |
| | 10 |
| | — |
| | — |
| | 10 |
|
| Total Operating Expenses | | 2 |
| | 9,335 |
| | 12 |
| | — |
| | 9,349 |
|
| INCOME (LOSS) FROM OPERATIONS | | (2 | ) | | 877 |
| | 7 |
| | — |
| | 882 |
|
| OTHER INCOME (EXPENSE): | | | | | | | | | | |
| Interest expense | | (485 | ) | | (2 | ) | | — |
| | — |
| | (487 | ) |
| Gains on investments | | — |
| | 139 |
| | — |
| | — |
| | 139 |
|
| Gains on purchases or exchanges of debt | | 263 |
| | — |
| | — |
| | — |
| | 263 |
|
| Other income | | 3 |
| | 67 |
| | — |
| | — |
| | 70 |
|
| Equity in net earnings of subsidiary | | 1,084 |
| | 3 |
| | — |
| | (1,087 | ) | | — |
|
| Total Other Income (Expense) | | 865 |
| | 207 |
| | — |
| | (1,087 | ) | | (15 | ) |
| INCOME BEFORE INCOME TAXES | | 863 |
| | 1,084 |
| | 7 |
| | (1,087 | ) | | 867 |
|
| INCOME TAX BENEFIT | | (10 | ) | | — |
| | — |
| | — |
| | (10 | ) |
| NET INCOME | | 873 |
| | 1,084 |
| | 7 |
| | (1,087 | ) | | 877 |
|
Net income attributable to noncontrolling interests | | — |
| | — |
| | (4 | ) | | — |
| | (4 | ) |
NET INCOME ATTRIBUTABLE TO CHESAPEAKE | | 873 |
| | 1,084 |
| | 3 |
| | (1,087 | ) | | 873 |
|
| Other comprehensive income | | — |
| | 34 |
| | — |
| | — |
| | 34 |
|
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE | | $ | 873 |
| | $ | 1,118 |
| | $ | 3 |
| | $ | (1,087 | ) | | $ | 907 |
|
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
25. Subsequent Events
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONSOn February 2, 2021, 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 as part of a series of exit financing transactions being 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. Additionally, on the Effective Date, we entered into the Exit Credit Facility, a reserve-based credit facility with an initial borrowing base of $2.5 billion collateralized by our oil and gas properties. The aggregate initial elected commitments of the lenders under the Exit Credit Facility will be $1.75 billion of revolving Tranche A Loans and $220 million of fully funded Tranche B Loans on the Effective Date. See Note 5 for more information on our exit facilities.YEAR ENDED DECEMBER 31, 2017On February 3, 2021, we reduced our workforce by 220 employees or approximately 15%, primarily in Oklahoma City and incurred charges of approximately $20 million. See Note 21 for more information regarding our workforce reduction.($We completed our financial restructuring and emerged from Chapter 11 bankruptcy proceedings on February 9, 2021. In support of the Plan, the enterprise value of the Successor was estimated and approved by the Bankruptcy Court to be in millions)the range of $3.5 billion to $4.7 billion. We cannot currently estimate the financial effect of emergence from bankruptcy on our financial statements, although we expect to record material adjustments related to our Plan and the application of fresh-start reporting guidance upon the Effective Date. See Note 2 for more information regarding Chapter 11 proceedings including effects of the Plan. |
| | | | | | | | | | | | | | | | | | | | |
| | | Parent | | Guarantor Subsidiaries | | Non- Guarantor Subsidiaries | | Eliminations | | Consolidated |
| REVENUES: | | | | | | | | | | |
| Oil, natural gas and NGL | | $ | — |
| | $ | 4,962 |
| | $ | 23 |
| | $ | — |
| | $ | 4,985 |
|
| Marketing | | — |
| | 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 | | — |
| | 4,598 |
| | — |
| | — |
| | 4,598 |
|
| General and administrative | | 1 |
| | 259 |
| | 2 |
| | — |
| | 262 |
|
| Provision for legal contingencies, net | | (79 | ) | | 41 |
| | — |
| | — |
| | (38 | ) |
| Depreciation, depletion and amortization | | — |
| | 991 |
| | 4 |
| | — |
| | 995 |
|
| Impairments | | — |
| | 5 |
| | — |
| | — |
| | 5 |
|
| Other operating expense | | — |
| | 413 |
| | — |
| | — |
| | 413 |
|
| 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 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 | | 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 |
|
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31, 2018
($ in millions)
|
| | | | | | | | | | | | | | | | | | | | |
| | | Parent | | Guarantor Subsidiaries | | Non- Guarantor Subsidiaries | | Eliminations | | Consolidated |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | | | |
Net Cash Provided By Operating Activities | | $ | 85 |
| | $ | 1,912 |
| | $ | 10 |
| | $ | (7 | ) | | $ | 2,000 |
|
| | | | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | |
| Drilling and completion costs | | — |
| | (1,958 | ) | | — |
| | — |
| | (1,958 | ) |
| Acquisitions of proved and unproved properties | | — |
| | (288 | ) | | — |
| | — |
| | (288 | ) |
| Proceeds from divestitures of proved and unproved properties | | — |
| | 2,231 |
| | — |
| | — |
| | 2,231 |
|
| Additions to other property and equipment | | — |
| | (21 | ) | | — |
| | — |
| | (21 | ) |
| Proceeds from sales of other property and equipment | | — |
| | 147 |
| | — |
| | — |
| | 147 |
|
| Proceeds from sales of investments | | — |
| | 74 |
| | — |
| | — |
| | 74 |
|
Net Cash Provided by Investing Activities | | — |
| | 185 |
| | — |
| | — |
| | 185 |
|
| | | | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | |
| Proceeds from revolving credit facility borrowings | | 11,697 |
| | — |
| | — |
| | — |
| | 11,697 |
|
| Payments on revolving credit facility borrowings | | (12,059 | ) | | — |
| | — |
| | — |
| | (12,059 | ) |
| Proceeds from issuance of senior notes, net | | 1,236 |
| | — |
| | — |
| | — |
| | 1,236 |
|
| Cash paid to purchase debt | | (2,813 | ) | | — |
| | — |
| | — |
| | (2,813 | ) |
| Cash paid for preferred stock dividends | | (92 | ) | | — |
| | — |
| | — |
| | (92 | ) |
| Other financing activities | | (26 | ) | | (123 | ) | | (13 | ) | | 7 |
| | (155 | ) |
| Intercompany advances, net | | 1,971 |
| | (1,974 | ) | | 2 |
| | 1 |
| | — |
|
Net Cash Used In Financing Activities | | (86 | ) | | (2,097 | ) | | (11 | ) | | 8 |
| | (2,186 | ) |
| Net decrease in cash and cash equivalents | | (1 | ) | | — |
| | (1 | ) | | 1 |
| | (1 | ) |
Cash and cash equivalents, beginning of period | | 5 |
| | 1 |
| | 2 |
| | (3 | ) | | 5 |
|
| Cash and cash equivalents, end of period | | $ | 4 |
| | $ | 1 |
| | $ | 1 |
| | $ | (2 | ) | | $ | 4 |
|
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
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 |
|
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
On January 31, 2019, our shareholders approved a proposal to amend our restated certificate of incorporation to increase the number of authorized shares of our stock from 2,000,000,000 shares to 3,000,000,000 shares.
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 717.3 million shares of our common stock and $381 million in cash, and the assumption of WildHorse’s debt of $1.4 billion as of February 1, 2019. We funded the cash portion of the consideration through borrowings under our revolving credit facility.
On February 1, 2019, we entered into a first amendment (the “Chesapeake facility amendment”) to our Chesapeake revolving credit facility. Among other things, the Chesapeake facility amendment (i) designated Brazos Valley Longhorn and its subsidiaries as unrestricted subsidiaries under the Chesapeake revolving credit facility and (ii) expressly permitted our initial investment in WildHorse under the limitations on investments covenant. As a result of Brazos Valley Longhorn and its subsidiaries being designated as unrestricted subsidiaries under the Chesapeake revolving credit facility, transactions between Brazos Valley Longhorn and its subsidiaries, on the one hand, and Chesapeake and its subsidiaries other than Brazos Valley Longhorn, BVL Finance Corp. and the other BVL Guarantors, on the other hand, are required to be on an arm’s-length basis, subject to certain exceptions, and Chesapeake is limited in the amount of investments it can make in Brazos Valley Longhorn and its subsidiaries.
On February 1, 2019, Brazos Valley Longhorn, as successor by merger to WildHorse, entered into a sixth amendment (the “WildHorse facility amendment”) to the Wildhorse revolving credit facility. Among other things, the WildHorse facility amendment (i) amended the merger covenant and the definition of change of control to permit our acquisition of WildHorse and (ii) permits borrowings under the WildHorse revolving credit facility to be used to redeem or repurchase the WildHorse senior notes so long as certain conditions are met.
On February 1, 2019, Brazos Valley Longhorn, as successor by merger to WildHorse, and BVL Finance Corp., entered into a fourth supplemental indenture (the “WildHorse supplemental indenture”) to the WildHorse indenture. Pursuant to the Wildhorse supplemental indenture, (i) Brazos Valley Longhorn assumed the rights and obligations of WildHorse as issuer under the WildHorse indenture and (ii) BVL Finance Corp. was named as a co-issuer of the WildHorse senior notes under the WildHorse indenture. We will account for the WildHorse acquisition by applying the acquisition method of accounting, which requires the acquired assets and liabilities to be recorded at fair value as of the acquisition date.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
SUPPLEMENTARY INFORMATION
Quarterly Financial Data (unaudited)
Summarized unaudited quarterly financial data for 20182020 and 20172019 are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2020 First Quarter(a) | | 2020
Second Quarter | | 2020
Third Quarter | | 2020
Fourth Quarter |
| | ($ in millions except per share data) |
| Total revenues | | $ | 2,541 | | | $ | 521 | | | $ | 975 | | | $ | 1,259 | |
| Income (loss) from operations | | $ | (8,227) | | | $ | (541) | | | $ | (111) | | | $ | 176 | |
Net loss attributable to Chesapeake | | $ | (8,297) | | | $ | (276) | | | $ | (745) | | | $ | (416) | |
| Net loss available to common stockholders | | $ | (8,319) | | | $ | (276) | | | $ | (745) | | | $ | (416) | |
| | | | | | | | |
Net loss per common share(b): | | | | | | | | |
| Basic | | $ | (852.97) | | | $ | (28.22) | | | $ | (76.18) | | | $ | (42.54) | |
| Diluted | | $ | (852.97) | | | $ | (28.22) | | | $ | (76.18) | | | $ | (42.54) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2019
First Quarter | | 2019
Second Quarter | | 2019
Third Quarter | | 2019
Fourth Quarter |
| | ($ in millions except per share data) |
| Total revenues | | $ | 2,196 | | | $ | 2,386 | | | $ | 2,087 | | | $ | 1,926 | |
| Income (loss) from operations | | $ | (182) | | | $ | 278 | | | $ | 46 | | | $ | (173) | |
Net income (loss) attributable to Chesapeake | | $ | (21) | | | $ | 98 | | | $ | (61) | | | $ | (324) | |
| Net income (loss) available to common stockholders | | $ | (44) | | | $ | 75 | | | $ | (101) | | | $ | (346) | |
| | | | | | | | |
Net income (loss) per common share(b): | | | | | | | | |
| Basic | | $ | (6.37) | | | $ | 9.21 | | | $ | (11.89) | | | $ | (35.53) | |
| Diluted | | $ | (6.37) | | | $ | 9.21 | | | $ | (11.89) | | | $ | (35.53) | |
(a)Includes $8.446 billion of impairment charges as a result of the decrease in demand for crude oil primarily due to COVID-19 and sharp decline in commodity prices related to the combined impact of falling demand and increases in production from OPEC+ which resulted in decreases in crude oil and NGL sales prices.
(b)All per share information has been retroactively adjusted to reflect the 1-for-200 (1:200) reverse stock split effective April 14, 2020. See Note 11 for additional information. |
| | | | | | | | | | | | | | | | |
| | | 2018 First Quarter | | 2018 Second Quarter | | 2018 Third Quarter | | 2018 Fourth Quarter |
| | | ($ in millions except per share data) |
| Total revenues | | $ | 2,489 |
| | $ | 2,255 |
| | $ | 2,418 |
| | $ | 3,069 |
|
| Income from operations | | $ | 278 |
| | $ | 30 |
| | $ | 280 |
| | $ | 294 |
|
Net income (loss) attributable to Chesapeake | | $ | 293 |
| | $ | (17 | ) | | $ | 84 |
| | $ | 513 |
|
| Net income (loss) available to common stockholders | | $ | 268 |
| | $ | (40 | ) | | $ | 60 |
| | $ | 486 |
|
| | | | | | | | | |
| Net income (loss) per common share: | | | | | | | | |
| Basic | | $ | 0.30 |
| | $ | (0.04 | ) | | $ | 0.07 |
| | $ | 0.53 |
|
| Diluted | | $ | 0.29 |
| | $ | (0.04 | ) | | $ | 0.07 |
| | $ | 0.49 |
|
|
| | | | | | | | | | | | | | | | |
| | | 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 |
|
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
SUPPLEMENTARY INFORMATION –- (Continued)
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, | | December 31, |
| | | 2018 | | 2017 | | 2020 | | 2019 |
| | | ($ in millions) | | ($ in millions) |
| Oil and oil and natural gas properties: | | | | | Oil and oil and natural gas properties: | |
| Proved | | $ | 69,642 |
| | $ | 68,858 |
| Proved | | $ | 25,734 | | | $ | 30,765 | |
| Unproved | | 2,337 |
| | 3,484 |
| Unproved | | 1,550 | | | 2,173 | |
| Total | | 71,979 |
| | 72,342 |
| Total | | 27,284 | | | 32,938 | |
| Less accumulated depreciation, depletion and amortization | | (64,055 | ) | | (62,992 | ) | Less accumulated depreciation, depletion and amortization | | (23,007) | | | (19,310) | |
| Net capitalized costs | | $ | 7,924 |
| | $ | 9,350 |
| Net capitalized costs | | $ | 4,277 | | | $ | 13,628 | |
Unproved properties not subject to amortization as of December 31, 20182020 and 2017,2019, consisted mainly of leasehold acquired through direct purchases of significant oil and natural gas property interests. We capitalized approximately $162 million, $194 million and $242 million of interest during 2018, 2017 and 2016, respectively, on significant investments in unproved properties that were not yet included in the amortization base of the full cost pool. We will continue to evaluate our unproved properties, and although the timing of the ultimate evaluation or disposition of the properties cannot be determined, we can expect the majority of our unproved properties not held by production to be transferred into the amortization base over the next five years.
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development
Costs incurred in oil and natural gas property acquisition, exploration and development, activities which have beenincluding capitalized interest and asset retirement costs, are summarized as follows:
| | | | | | | | | | | | | | | Years Ended December 31, |
| | | Years Ended December 31, | | 2020 | | 2019 | | 2018 |
| | | 2018 | | 2017 | | 2016 | | ($ in millions) |
| | | ($ in millions) | |
| Acquisition of Properties: | | | | | | | |
Acquisition of Properties(a): | | Acquisition of Properties(a): | |
| Proved properties | | $ | 80 |
| | $ | 23 |
| | $ | 403 |
| Proved properties | | $ | 3 | | | $ | 3,264 | | | $ | 80 | |
| Unproved properties | | 216 |
| | 271 |
| | 403 |
| Unproved properties | | 6 | | | 792 | | | 56 | |
| Exploratory costs | | 132 |
| | 21 |
| | 52 |
| Exploratory costs | | 8 | | | 42 | | | 80 | |
| Development costs | | 2,009 |
| | 2,146 |
| | 1,312 |
| Development costs | | 887 | | | 2,177 | | | 1,954 | |
Costs incurred(a) | | $ | 2,437 |
| | $ | 2,461 |
| | $ | 2,170 |
| |
| Costs incurred | | Costs incurred | | $ | 904 | | | $ | 6,275 | | | $ | 2,170 | |
| |
(a) | Includes capitalized interest and asset retirement obligations as follows: |
|
| | | | | | | | | | | | |
| Capitalized interest | | $ | 162 |
| | $ | 194 |
| | $ | 242 |
|
Asset retirement obligations(b) | | $ | 8 |
| | $ | (34 | ) | | $ | (57 | ) |
| |
(b) | Activity in 2017 and 2016 primarily reflects revisions as the result of decreased plugging and abandonment costs in certain of our operating areas. |
In 2018, we invested approximately $807(a) Includes $3.264 billion and $756 million of proved and unproved property acquisitions, respectively, related to convert 115 mmboeour acquisition of PUDs to proved developed reserves.WildHorse in 2019.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
SUPPLEMENTARY INFORMATION –- (Continued)
Results of Operations from Oil, Natural Gas and NGL Producing Activities
Our results of operations from oil, natural gas and NGL producing activities are presented below for 2018, 20172020, 2019 and 2016.2018. The following table includes revenues and expenses associated directly with our oil, natural gas and NGL producing activities. It does not include any interest costs or indirect general and administrative costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of our oil, natural gas and NGL operations.
| | | | | Years Ended December 31, | | Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 | | 2020 | | 2019 | | 2018 |
| | | ($ in millions) | | ($ in millions) |
| Oil, natural gas and NGL sales | | $ | 5,155 |
| | $ | 4,985 |
| | $ | 3,288 |
| Oil, natural gas and NGL sales | | $ | 3,341 | | | $ | 4,522 | | | $ | 5,155 | |
| Other revenue | | Other revenue | | 56 | | | 63 | | | 63 | |
| Oil, natural gas and NGL production expenses | | (539 | ) | | (562 | ) | | (710 | ) | Oil, natural gas and NGL production expenses | | (373) | | | (520) | | | (474) | |
Oil, natural gas and NGL gathering, processing and transportation expenses | | (1,398 | ) | | (1,471 | ) | | (1,855 | ) | Oil, natural gas and NGL gathering, processing and transportation expenses | | (1,082) | | | (1,082) | | | (1,398) | |
| Production taxes | | (124 | ) | | (89 | ) | | (74 | ) | |
| Severance and ad valorem taxes | | Severance and ad valorem taxes | | (149) | | | (224) | | | (189) | |
| Exploration | | Exploration | | (427) | | | (84) | | | (162) | |
| Depletion and depreciation | | Depletion and depreciation | | (1,026) | | | (2,188) | | | (1,665) | |
| Impairment of oil and natural gas properties | | — |
| | — |
| | (2,564 | ) | Impairment of oil and natural gas properties | | (8,446) | | | (8) | | | (78) | |
| Depletion and depreciation | | (1,073 | ) | | (913 | ) | | (1,003 | ) | |
Imputed income tax provision(a) | | (525 | ) | | (768 | ) | | 1,027 |
| Imputed income tax provision(a) | | 1,840 | | | (125) | | | (326) | |
Results of operations from oil, natural gas and NGL producing
activities | | $ | 1,496 |
| | $ | 1,182 |
| | $ | (1,891 | ) | Results of operations from oil, natural gas and NGL producing
activities | | $ | (6,266) | | | $ | 354 | | | $ | 926 | |
| |
(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 firmfirms estimated all of our proved reserves as of December 31, 2018, 20172020, 2019 and 2016. Our independent2018. Independent petroleum engineering firm Software Integrated Solutions, Division of Schlumberger Technology Corporation,LaRoche Petroleum Consultants, Ltd. estimated an aggregate of 80%, 83% and 70%87% of our estimated proved reserves (by volume) as of December 31, 2018, 2017 and 2016.2020.
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 highest known oil elevation and the potential exists for an 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
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
SUPPLEMENTARY INFORMATION - (Continued)
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
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
SUPPLEMENTARY INFORMATION – (Continued)
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 2018, 20172020, 2019 and 2016: |
| | | | | | | | | | | | |
| | | Oil | | Gas | | NGL | | Total |
| | | (mmbbl) | | (bcf) | | (mmbbl) | | (mmboe) |
| December 31, 2018 | | | | | | | | |
| Proved reserves, beginning of period | | 260.2 |
| | 8,600 |
| | 218.6 |
| | 1,912 |
|
| Extensions, discoveries and other additions | | 56.3 |
| | 1,162 |
| | 19.8 |
| | 270 |
|
| Revisions of previous estimates | | (30.5 | ) | | 242 |
| | 5.4 |
| | 15 |
|
| Production | | (32.7 | ) | | (832 | ) | | (18.9 | ) | | (190 | ) |
| Sale of reserves-in-place | | (37.8 | ) | | (2,395 | ) | | (121.6 | ) | | (559 | ) |
| Purchase of reserves-in-place | | — |
| | — |
| | — |
| | — |
|
Proved reserves, end of period(a) | | 215.5 |
| | 6,777 |
| | 103.3 |
| | 1,448 |
|
| Proved developed reserves: | | | | | | | | |
| Beginning of period | | 150.9 |
| | 4,980 |
| | 134.9 |
| | 1,116 |
|
| End of period | | 127.6 |
| | 3,314 |
| | 67.9 |
| | 748 |
|
| Proved undeveloped reserves: | | | | | | | | |
| Beginning of period | | 109.3 |
| | 3,620 |
| | 83.6 |
| | 796 |
|
End of period(b) | | 87.9 |
| | 3,463 |
| | 35.4 |
| | 700 |
|
| | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Oil | | Natural Gas | | NGL | | Total |
| | (mmbbl) | | (bcf) | | (mmbbl) | | (mmboe) |
| December 31, 2020 | | | | | | | | |
| Proved reserves, beginning of period | | 358.0 | | | 6,566 | | | 120.0 | | | 1,572 | |
| Extensions, discoveries and other additions | | 1.1 | | | 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 | | 161.3 | | | 3,530 | | | 52.0 | | | 802 | |
| Proved developed reserves: | | | | | | | | |
| Beginning of period | | 201.4 | | | 3,377 | | | 82.1 | | | 846 | |
| End of period | | 158.1 | | | 3,196 | | | 51.4 | | | 742 | |
| Proved undeveloped reserves: | | | | | | | | |
| Beginning of period | | 156.6 | | | 3,189 | | | 37.9 | | | 726 | |
End of period(a) | | 3.2 | | | 334 | | | 0.6 | | | 60 | |
| | | | | | | | |
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
SUPPLEMENTARY INFORMATION –- (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Oil | | Natural Gas | | NGL | | Total |
| | (mmbbl) | | (bcf) | | (mmbbl) | | (mmboe) |
| December 31, 2019 | | | | | | | | |
| Proved reserves, beginning of period | | 215.5 | | | 6,777 | | | 103.3 | | | 1,448 | |
| Extensions, discoveries and other additions | | 52.2 | | | 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-place | | 176.0 | | | 159 | | | 32.3 | | | 235 | |
| Proved reserves, end of period | | 358.0 | | | 6,566 | | | 120.0 | | | 1,572 | |
| Proved developed reserves: | | | | | | | | |
| Beginning of period | | 127.6 | | | 3,314 | | | 67.9 | | | 748 | |
| End of period | | 201.4 | | | 3,377 | | | 82.1 | | | 846 | |
| Proved undeveloped reserves: | | | | | | | | |
| Beginning of period | | 87.9 | | | 3,463 | | | 35.4 | | | 700 | |
End of period(a) | | 156.6 | | | 3,189 | | | 37.9 | | | 726 | |
| | | | | | | | |
| December 31, 2018 | | | | | | | | |
| Proved reserves, beginning of period | | 260.2 | | | 8,600 | | | 218.6 | | | 1,912 | |
| Extensions, discoveries and other additions | | 56.3 | | | 1,162 | | | 19.8 | | | 270 | |
| Revisions of previous estimates | | (30.5) | | | 242 | | | 5.4 | | | 15 | |
| Production | | (32.7) | | | (832) | | | (18.9) | | | (190) | |
| Sale of reserves-in-place | | (37.8) | | | (2,395) | | | (121.6) | | | (559) | |
| Purchase of reserves-in-place | | — | | | — | | | — | | | — | |
| Proved reserves, end of period | | 215.5 | | | 6,777 | | | 103.3 | | | 1,448 | |
| Proved developed reserves: | | | | | | | | |
| Beginning of period | | 150.9 | | | 4,980 | | | 135.0 | | | 1,116 | |
| End of period | | 127.6 | | | 3,314 | | | 67.9 | | | 748 | |
| Proved undeveloped reserves: | | | | | | | | |
| Beginning of period | | 109.3 | | | 3,620 | | | 83.6 | | | 796 | |
End of period(a) | | 87.9 | | | 3,463 | | | 35.4 | | | 700 | |
___________________________________________(a) As of December 31, 2020, 2019 and 2018, there were no PUDs that had remained undeveloped for five years or more.
During 2020, we recorded extension and discoveries of 18 mmboe primarily in the Marcellus and Gulf Coast primarily related to successfully drilled new well additions. We sold 39 mmboe of proved reserves for approximately $136 million primarily in the Mid-Continent. We recorded 586 mmboe of downward revisions of previous estimates consisting of 423 mmboe of 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 development of our proved reserves over a five-year period, downward revisions of 208 mmboe due to lower oil, natural gas and NGL prices in 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, 2020, were $39.57 per bbl and $1.98 per mcf, respectively, before price differentials.
|
| | | | | | | | | | | | |
| | | 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(c) | | 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 |
|
| | | | | | | | | |
| 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(d) | | 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 |
|
136
| |
(a) | Includes 1 mmbbl of oil, 17 bcf of natural gas and 2 mmbbls of NGL reserves owned by the Chesapeake Granite Wash Trust, of which 1 mmbbl of oil, 8 bcf of natural gas and 1 mmbbl of NGL are attributable to noncontrolling interest holders. |
| |
(b) | As of December 31, 2018, 2017 and 2016, there were no PUDs that had remained undeveloped for five years or more. |
| |
(c) | 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 the noncontrolling interest holders. |
| |
(d) | Includes 1 mmbbl of oil, 23 bcf of natural gas and 2 mmbbls of NGL reserves owned by the Chesapeake Granite Wash Trust, of which 1 mmbbl of oil, 12 bcf of natural gas and 1 mmbbl of NGL are attributable to the noncontrolling interest holders. |
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
SUPPLEMENTARY INFORMATION –- (Continued)
During 2019, we acquired 235 mmboe primarily related to the acquisition of WildHorse. We recorded extensions and discoveries of 216 mmboe, primarily related to undeveloped well additions in the Marcellus and Brazos Valley operating areas. In addition, we recorded downward revisions of 110 mmboe due to lower oil, natural gas and NGL prices in 2019, and downward revisions of 33 mmboe 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, 2019, were $55.69 per bbl and $2.58 per mcf, respectively, before price differentials.
During 2018, we sold 559 mmboe of proved reserves for approximately $1.8 billion primarily in the Utica and MidContinent.Mid-Continent. We recorded extensions and discoveries of 270 mmboe, primarily related to undeveloped well additions located in Marcellus and Powder River Basin operating areas. In addition, we recorded upward revisions of 28 mmboe due to higher oil, natural gas and NGL prices in 2018 partially offset by downward revisions of 13 mmboe due to ongoing portfolio evaluation including longer lateral and spacing adjustments. The oil and natural gas prices used in computing our reserves as of December 31, 2018, were $65.56 per bbl and $3.10 per mcf, respectively, before price differentials.
During 2017, we recorded extensions and discoveries of 723 mmboe primarily in the Gulf Coast, Marcellus and Utica due to longer lateral, successful drilling and additional allocated capital in our 5-year development plan. We recorded a downward revision of 327 mmboe from previous estimates due to an updated development plan in the Eagle Ford aligning up-spacing, our activity schedule and well performance. Additionally, PUDs 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 improved oil, natural gas and NGL prices in 2017 resulting in a 75 mmboe upward revision. The oil and natural gas prices used in computing our reserves as of December 31, 2017, were $51.34 per bbl and $2.98 per mcf, respectively, before price differentials.
During 2016, we sold 241 mmboe of proved reserves for approximately $898 million. We recorded extensions and discoveries 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 70 mmboe which were primarily the result of lower oil, natural gas and NGL prices in 2016. The oil and natural gas prices used in computing our reserves as of December 31, 2016, were $42.75 per bbl and $2.49 per mcf, respectively, before price differentials.
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, 2018, 20172020, 2019 and 20162018 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.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)
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, | | | Years Ended December 31, | |
| | | 2018 | | 2017 | | 2016 | | | 2020 | | 2019 | | 2018 | |
| | | ($ in millions) | | | ($ in millions) | |
| Future cash inflows | | $ | 27,312 |
| (a) | $ | 26,412 |
| (b) | $ | 19,835 |
| (c) | Future cash inflows | | $ | 8,247 | | (a) | $ | 29,857 | | (b) | $ | 27,312 | | (c) |
| Future production costs | | (5,946 | ) | | (7,044 | ) | | (6,800 | ) | | Future production costs | | (2,963) | | | (6,956) | | | (5,946) | | |
| Future development costs | | (4,032 | ) | | (4,977 | ) | | (3,621 | ) | | Future development costs | | (563) | | | (5,757) | | | (4,032) | | |
| Future income tax provisions | | (331 | ) | | — |
| | (79 | ) | | Future income tax provisions | | (9) | | | (75) | | | (331) | | |
| Future net cash flows | | 17,003 |
| | 14,391 |
| | 9,335 |
| | Future net cash flows | | 4,712 | | | 17,069 | | | 17,003 | | |
| Less effect of a 10% discount factor | | (7,508 | ) | | (6,901 | ) | | (4,956 | ) | | Less effect of a 10% discount factor | | (1,626) | | | (8,069) | | | (7,508) | | |
Standardized measure of discounted future net cash flows(d) | | $ | 9,495 |
| | $ | 7,490 |
| | $ | 4,379 |
| | Standardized measure of discounted future net cash flows(d) | | $ | 3,086 | | | $ | 9,000 | | | $ | 9,495 | | |
| |
(a) | Calculated using prices of $65.56 per bbl of oil and $3.10 per mcf of natural gas, before field differentials. |
| |
(b) | Calculated using prices of $51.34 per bbl of oil and $2.98 per mcf of natural gas, before field differentials. |
| |
(c) | Calculated using prices of $42.75 per bbl of oil and $2.49 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 14.(a) Calculated using prices of $39.57 per bbl of oil and $1.98 per mcf of natural gas, before field differentials. (b) Calculated using prices of $55.69 per bbl of oil and $2.58 per mcf of natural gas, before field differentials. (c) Calculated using prices of $65.56 per bbl of oil and $3.10 per mcf of natural gas, before field differentials. (d) Excludes discounted future net cash inflows attributable to production volumes sold to VPP buyers. See Note 7. |
The principal sources of change in the standardized measure of discounted future net cash flows are as follows:
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| | ($ in millions) |
Standardized measure, beginning of period(a) | | $ | 9,000 | | | $ | 9,495 | | | $ | 7,490 | |
Sales of oil and natural gas produced, net of production costs and gathering, processing and transportation(b) | | (1,140) | | | (2,691) | | | (3,128) | |
| Net changes in prices and production costs | | (5,576) | | | (3,457) | | | 3,317 | |
Extensions and discoveries, net of production and development costs | | 71 | | | 991 | | | 1,666 | |
| Changes in estimated future development costs | | 1,933 | | | 366 | | | 1,113 | |
| Previously estimated development costs incurred during the period | | 665 | | | 775 | | | 973 | |
| Revisions of previous quantity estimates | | (1,839) | | | (793) | | | 47 | |
| Purchase of reserves-in-place | | — | | | 3,435 | | | — | |
| Sales of reserves-in-place | | (112) | | | (57) | | | (2,052) | |
| Accretion of discount | | 902 | | | 953 | | | 749 | |
| Net change in income taxes | | 14 | | | 17 | | | (32) | |
| Changes in production rates and other | | (832) | | | (34) | | | (648) | |
Standardized measure, end of period(a) | | $ | 3,086 | | | $ | 9,000 | | | $ | 9,495 | |
(a) The impact of cash flow hedges has not been included in any of the periods presented.
(b) Excludes gains and losses on derivatives.
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| | | ($ in millions) |
Standardized measure, beginning of period(a) | | $ | 7,490 |
| | $ | 4,379 |
| | $ | 4,693 |
|
Sales of oil and natural gas produced, net of production costs and gathering, processing and transportation(b) | | (3,128 | ) | | (2,452 | ) | | (1,227 | ) |
| Net changes in prices and production costs | | 3,317 |
| | 3,977 |
| | (1,210 | ) |
Extensions and discoveries, net of production and development costs | | 1,666 |
| | 1,951 |
| | 1,042 |
|
| Changes in estimated future development costs | | 1,113 |
| | 614 |
| | 323 |
|
| Previously estimated development costs incurred during the period | | 973 |
| | 775 |
| | 664 |
|
| Revisions of previous quantity estimates | | 47 |
| | (1,255 | ) | | 145 |
|
| Purchase of reserves-in-place | | — |
| | 3 |
| | 394 |
|
| Sales of reserves-in-place | | (2,052 | ) | | (116 | ) | | 13 |
|
| Accretion of discount | | 749 |
| | 441 |
| | 473 |
|
| Net change in income taxes | | (32 | ) | | 26 |
| | (8 | ) |
| Changes in production rates and other | | (648 | ) | | (853 | ) | | (923 | ) |
Standardized measure, end of period(a)(c) | | $ | 9,495 |
| | $ | 7,490 |
| | $ | 4,379 |
|
| |
(a) | 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. |
ITEM 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure
| |
ITEM 9. | Changes In and Disagreements with Accountants on Accounting and Financial Disclosure |
Not applicable.
| |
ITEM 9A. | Controls and Procedures |
ITEM 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, 20182020 that our disclosure controls and procedures were effective.
This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit us to provide only management’s report in this annual report.
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, 20182020 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
Management’s Report on 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 Over Financial Reporting is set forthControl-Integrated Framework (2013) in Item 8conducting the required assessment of this Annual Report on Form 10-K.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, 2020. | | | | | | | | | | | | | | |
ITEM 9B./s/ ROBERT D. LAWLER | Other Information |
| 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 |
| | | | |
| | | | |
| March 1, 2021 |
| | | | |
Not applicable.
ITEM 9B.Other Information
Not applicable.
PART III
| |
ITEM 10. | Directors, Executive Officers and Corporate Governance |
ITEM 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, 20192021 (the 2019“2021 Proxy Statement)Statement”).
| |
ITEM 11. | Executive Compensation |
ITEM 11. Executive Compensation
The information called for by this Item 11 is incorporated herein by reference to the 20192021 Proxy Statement.
| |
ITEM 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information called for by this Item 12 is incorporated herein by reference to the 20192021 Proxy Statement.
| |
ITEM 13. | Certain Relationships and Related Transactions and Director Independence |
ITEM 13. Certain Relationships and Related Transactions and Director Independence
The information called for by this Item 13 is incorporated herein by reference to the 20192021 Proxy Statement.
| |
ITEM 14. | Principal Accountant Fees and Services |
ITEM 14. Principal Accountant Fees and Services
The information called for by this Item 14 is incorporated herein by reference to the 20192021 Proxy Statement.
PART IV
| |
ITEM 15. | Exhibits and Financial Statement Schedules |
ITEM 15. Exhibits 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 |
| 2.1 | | | | 10-Q | | 001-13726 | | 2.1 | | 10/30/2018 | | |
| | | | | | | | | | | | | |
| 2.2.1* | | | | 8-K | | 001-13726 | | 2.1 | | 10/30/2018 | | |
| | | | | | | | | | | | | |
| 2.2.2 | | | | S-4/A | | 333-228679 | | Annex A | | 12/19/2018 | | |
| | | | | | | | | | | | | |
| 3.1.1 | | | | | | | | | | | | X |
| | | | | | | | | | | | | |
| 3.1.2 | | | | 10-Q | | 001-13726 | | 3.1.4 | | 11/10/2008 | | |
| | | | | | | | | | | | | |
| 3.1.3 | | | | 10-Q | | 001-13726 | | 3.1.6 | | 8/11/2008 | | |
| | | | | | | | | | | | | |
| 3.1.4 | | | | 8-K | | 001-13726 | | 3.2 | | 5/20/2010 | | |
| | | | | | | | | | | | | |
| 3.1.5 | | | | 10-Q | | 001-13726 | | 3.1.5 | | 8/9/2010 | | |
| | | | | | | | | | | | | |
| 3.2 | | | | 8-K | | 001-13726 | | 3.2 | | 6/19/2014 | | |
| | | | | | | | | | | | | |
| 4.1** | | | | 8-K | | 001-13726 | | 4.1.1 | | 11/15/2005 | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Incorporated by Reference | | |
Exhibit Number | | Exhibit Description | | Form | | SEC File Number | | Exhibit | | Filing Date | | Filed or Furnished Herewith |
| 2.1 | | | | 8-K | | 001-13726 | | 2.1 | | 1/19/2021 | | |
| | | | | | | | | | | | |
| 3.1 | | | | 8-K | | 001-13726 | | 3.1 | | 2/9/2021 | | |
| | | | | | | | | | | | |
| 3.2 | | | | 8-K | | 001-13726 | | 3.2 | | 2/9/2021 | | |
| | | | | | | | | | | | |
| 3.3 | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 4.1 | | | | 8-A | | 001-13726 | | N/A | | 2/9/2021 | | |
| | | | | | | | | | | | |
| 10.1 | | | | 8-K | | 001-13726 | | 10.1 | | 6/29/2020 | | |
| | | | | | | | | | | | |
| 10.2 | | | | 8-K | | 001-13726 | | 10.1 | | 6/29/2020 | | |
| | | | | | | | | | | | |
| 10.3 | | | | 8-K | | 001-13726 | | 10.1 | | 2/9/2021 | | |
| | | | | | | | | | | | |
10.4
| | | | 8-K | | 001-13726 | | 10.2 | | 2/9/2021 | | |
| | | | | | | | | | | | |
| 10.5 | | | | 8-K | | 001-13726 | | 10.3 | | 2/9/2021 | | |
| | | | | | | | | | | | |
| 10.6 | | | | 8-K | | 001-13726 | | 10.4 | | 2/9/2021 | | |
| | | | | | | | | | | | |
| 10.7 | | | | 8-K | | 001-13726 | | 10.5 | | 2/9/2021 | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| 10.8 | | | | 8-K | | 001-13726 | | 10.6 | | 2/9/2021 | | |
| | | | | | | | | | | | |
| 10.9† | | | | 8-K | | 001-13726 | | 10.7 | | 2/9/2021 | | |
| | | | | | | | | | | | |
| 10.10 | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 10.11 | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 10.12* | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 10.13 | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 21 | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 23.1 | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 23.2 | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 31.1 | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 31.2 | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 32.1 | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 32.2 | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 95.1 | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 99.1 | | | | 8-K | | 001-13726 | | 99.2 | | 2/2/2021 | | |
| | | | | | | | | | | | |
| 101 INS | | Inline XBRL Instance Document. | | | | | | | | | | X |
| | | | | | | | | | | | |
|
| | | | | | | | | | | | |
| 4.2.1** | | | | S-3 | | 333-168509 | | 4.1 | | 8/3/2010 | | |
| | | | | | | | | | | | | |
| 4.2.2 | | | | 8-A | | 001-13726 | | 4.3 | | 9/24/2010 | | |
| | | | | | | | | | | | | |
| 4.2.3 | | | | 8-A | | 001-13726 | | 4.2 | | 2/22/2011 | | |
| | | | | | | | | | | | | |
| 4.2.4 | | | | S-3 | | 333-168509 | | 4.17 | | 3/18/2013 | | |
| | | | | | | | | | | | | |
| 4.2.5 | | | | 8-A | | 001-13726 | | 4.3 | | 4/8/2013 | | |
| | | | | | | | | | | | | |
| 4.2.6 | | | | 8-A | | 001-13726 | | 4.4 | | 4/8/2013 | | |
| | | | | | | | | | | | | |
| 4.3.1** | | | | 8-K | | 001-13726 | | 4.1 | | 4/29/2014 | | |
| | | | | | | | | | | | | |
| 4.3.2 | | | | 8-K | | 001-13726 | | 4.2 | | 4/29/2014 | | |
| | | | | | | | | | | | | |
| 4.3.3 | | | | 8-K | | 001-13726 | | 4.3 | | 4/29/2014 | | |
| | | | | | | | | | | | | |
| 4.4.1 | | 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 | | |
| | | | | | | | | | | | | |
|
| | | | | | | | | | | | |
| 4.4.2 | | | | 10-Q | | 001-13726 | | 4.1 | | 11/4/2015 | | |
| | | | | | | | | | | | | |
| 4.4.3 | | | | 8-K | | 001-13726 | | 10.1 | | 12/16/2015 | | |
| | | | | | | | | | | | | |
| 4.4.4†† | | | | 10-Q | | 001-13726 | | 4.2 | | 8/4/2016 | | |
| | | | | | | | | | | | | |
| 4.4.5 | | | | 8-K | | 001-13726 | | 10.1 | | 5/22/2017 | | |
| | | | | | | | | | | | | |
| 4.4.6 | | Amended and Restated Credit Agreement, dated as of September 12, 2018, by and among: (i) the Company, as borrower; (ii) MUFG Union Bank N.A., as the administrative agent, a swingline lender and a letter of credit issuer; (iii) Wells Fargo Bank, National Association, as co-syndication agent, a swingline lender and a letter of credit issuer; (iv) JPMorgan Chase Bank, N.A., as co-syndication agent, a swingline lender and a letter of credit issuer; and (v) certain other lenders and letter of credit issuers named therein. | | 8-K | | 001-13726 | | 10.1 | | 9/12/2018 | | |
| | | | | | | | | | | | | |
| 4.5 | | | | 8-K | | 001-13726 | | 10.1 | | 12/23/2015 | | |
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| 4.6 | | | | 8-K | | 001-13726 | | 10.2 | | 12/23/2015 | | |
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| 4.7 | | | | 8-K | | 001-13726 | | 4.1 | | 10/5/2016 | | |
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|
| | | | | | | | | | | | |
| 4.8 | | | | 8-K | | 001-13726 | | 4.2 | | 12/20/2016 | | |
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| 4.9 | | | | 8-K | | 001-13726 | | 4.4 | | 12/20/2016 | | |
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| 4.10 | | | | 8-K | | 001-13726 | | 10.1 | | 5/23/2017 | | |
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| 4.11 | | | | 8-K | | 001-13726 | | 4.2 | | 6/7/2017 | | |
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| 4.12 | | | | 8-K | | 001-13726 | | 4.4 | | 6/7/2017 | | |
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| 4.13 | | | | 8-K | | 001-13726 | | 10.1 | | 9/28/2017 | | |
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| 4.14 | | | | 8-K | | 001-13726 | | 4.4 | | 10/12/2017 | | |
| | | | | | | | | | | | | |
| 4.15 | | | | 8-K | | 001-13726 | | 4.5 | | 10/12/2017 | | |
| | | | | | | | | | | | | |
| 4.16 | | | | 8-K | | 001-13726 | | 4.2 | | 9/27/2018 | | |
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| 4.17 | | | | 8-K | | 001-13726 | | 4.3 | | 9/27/2018 | | |
| | | | | | | | | | | | | |
| 4.18.1 | | | | 8-K | | 001-37964 | | 4.1 | | 2/1/2017 | | |
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|
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| 4.18.2 | | | | 10-Q | | 001-37964 | | 4.6 | | 8/10/2017 | | |
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| 4.18.3 | | | | 10-K | | 001-37964 | | 4.6 | | 3/12/2018 | | |
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| 4.18.4 | | | | 10-Q | | 001-37964 | | 4.6 | | 8/9/2018 | | |
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| 4.18.5 | | | | 8-K | | 001-13726 | | 4.1 | | 2/1/2019 | | |
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| 10.1.1† | | | | 10-Q | | 001-13726 | | 10.1.1 | | 11/9/2009 | | |
| | | | | | | | | | | | | |
| 10.1.2† | | | | 10-K | | 001-13726 | | 10.1.3 | | 3/1/2013 | | |
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| 10.2.1† | | | | 8-K | | 001-13726 | | 10.1 | | 6/20/2013 | | |
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| 10.2.2† | | | | 8-K | | 001-13726 | | 10.3 | | 2/4/2013 | | |
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| 10.2.3† | | | | 8-K | | 001-13726 | | 10.1 | | 2/4/2013 | | |
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| 10.2.4† | | | | 8-K | | 001-13726 | | 10.2 | | 2/4/2013 | | |
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10.2.5†
| | | | 10-K | | 001-13726 | | 10.13.7 | | 3/1/2013 | | |
| | | | | | | | | | | | | |
10.2.6†
| | | | 10-K | | 001-13726 | | 10.13.9 | | 3/1/2013 | | |
| | | | | | | | | | | | | |
10.2.7†
| | | | 10-K | | 001-13726 | | 10.4.7 | | 2/27/2014 | | |
| | | | | | | | | | | | | |
10.2.8†
| | | | 10-Q | | 001-13726 | | 10.8 | | 8/6/2013 | | |
| | | | | | | | | | | | | |
10.2.9†
| | | | 10-Q | | 001-13726 | | 10.9 | | 8/6/2013 | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 101 SCH | | Inline XBRL Taxonomy Extension Schema Document. | | | | | | | | | | X |
| | | | | | | | | | | | |
| 101 CAL | | Inline XBRL Taxonomy Extension Calculation Linkbase Document. | | | | | | | | | | X |
| | | | | | | | | | | | |
| 101 DEF | | Inline XBRL Taxonomy Extension Definition Linkbase Document. | | | | | | | | | | X |
| | | | | | | | | | | | |
| 101 LAB | | Inline XBRL Taxonomy Extension Labels Linkbase Document. | | | | | | | | | | X |
| | | | | | | | | | | | |
| 101 PRE | | Inline XBRL Taxonomy Extension Presentation Linkbase Document. | | | | | | | | | | X |
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| 104 | | Cover 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 | | | | | | | | | | |
| | | | | | | | | | | | |
10.2.10†
| | | | 10-Q | | 001-13726 | | 10.10 | | 8/6/2013 | | |
| | | | | | | | | | | | |
10.3.1†
| | | | 10-K | | 001-13726 | | 10.3 | | 2/25/2016 | | |
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10.3.2†
| | | | | | | | | | | | X |
| | | | | | | | | | | | |
10.4.1†
| | | | 10-K | | 001-13726 | | 10.16 | | 3/1/2013 | | |
| | | | | | | | | | | | |
10.4.2† | | | | 10-K | | 001-13726 | | 10.3.2 | | 3/3/2017 | | |
| | | | | | | | | | | | |
10.5.1†
| | | | 8-K | | 001-13726 | | 10.1 | | 5/23/2013 | | |
| | | | | | | | | | | | |
10.5.2† | | | | 8-K | | 001-13726 | | 10.1 | | 6/17/2016 | | |
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10.5.3† | | | | 8-K | | 001-13726 | | 10.1 | | 1/4/2019 | | |
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10.5.4† | | | | 10-Q | | 001-13726 | | 10.1 | | 8/1/2018 | | |
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10.6†
| | | | 8-K | | 001-13726 | | 10.2 | | 1/4/2019 | | |
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10.7†
| | | | 8-K | | 001-13726 | | 10.3 | | 1/4/2019 | | |
| | | | | | | | | | | | |
10.8†
| | | | 8-K | | 001-13726 | | 10.4 | | 1/4/2019 | | |
| | | | | | | | | | | | |
10.9†
| | | | 8-K | | 001-13726 | | 10.5 | | 1/4/2019 | | |
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10.10†
| | | | | | | | | | | | X |
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10.11† | | | | | | | | | | | | X |
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10.12†
| | | | 8-K | | 001-13726 | | 10.3 | | 6/27/2012 | | |
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10.13†
| | | | DEF 14A | | 001-13726 | | Exhibit G | | 5/3/2013 | | |
|
| | | | | | | | | | | | |
| | | | | | | | | | | | | |
10.13.1†
| | | | 10-Q | | 001-13726 | | 10.1 | | 8/3/2017 | | |
| | | | | | | | | | | | | |
10.13.2†
| | | | 10-Q | | 001-13726 | | 10.2 | | 8/6/2014 | | |
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| 10.13.3† | | | | 10-Q | | 001-13726 | | 10.3 | | 8/6/2014 | | |
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10.13.4†
| | | | 10-Q | | 001-13726 | | 10.4 | | 8/6/2014 | | |
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10.13.5†
| | | | 10-Q | | 001-13726 | | 10.5 | | 8/6/2014 | | |
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10.13.6†
| | | | 10-Q | | 001-13726 | | 10.6 | | 8/6/2014 | | |
| | | | | | | | | | | | | |
| 10.14.1 | | Voting and Support Agreement, by and among Jay Carlton Graham, Esquisto Holdings, LLC, WHE AcqCo Holdings, LLC, WHR Holdings, LLC, NGP XI US Holdings, L.P., Chesapeake Energy Corporation and WildHorse Resource Development Corporation, dated as of October 29, 2018. | | 8-K | | 001-13726 | | 10.1 | | 10/30/2018 | | |
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| 10.14.2 | | | | 8-K | | 001-13726 | | 10.2 | | 10/30/2018 | | |
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| 10.14.3 | | Registration Rights Agreement, by and among Esquisto Holdings, LLC, WHE AcqCo Holdings, LLC, WHR Holdings, LLC, NGP XI US Holdings, L.P., CP VI Eagle Holdings, L.P. and Chesapeake Energy Corporation, dated as of October 29, 2018. | | 8-K | | 001-13726 | | 10.3 | | 10/30/2018 | | |
| | | | | | | | | | | | | |
| 10.15.1 | | Credit Agreement, dated December 19, 2016, by and among WildHorse Resource Development Corporation, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, BMO Harris Bank, N.A., as Syndication Agent, the Lenders party thereto and the other parties party thereto. | | 8-K | | 001-37964 | | 10.3 | | 12/22/2016 | | |
| | | | | | | | | | | | | |
| 10.15.2 | | First Amendment to Credit Agreement, dated as of April 4, 2017, by and among WildHorse Resource Development Corporation, each of the guarantors party thereto, and Wells Fargo Bank, National Association, as Administrative Agent for the Lenders party thereto, BMO Harris Bank, N.A., as Syndication Agent, the Lenders party thereto and the other parties party thereto. | | 10-Q | | 001-37964 | | 10.1 | | 5/15/2017 | | |
| | | | | | | | | | | | | |
| 10.15.3 | | Second Amendment to Credit Agreement, dated as of June 30, 2017, by and among WildHorse Resource Development Corporation, each of the guarantors party thereto, and Wells Fargo Bank, National Association, as Administrative Agent for the Lenders party thereto, BMO Harris Bank, N.A., as Syndication Agent, the Lenders party thereto and the other parties party thereto. | | 8-K | | 001-37964 | | 10.1 | | 7/7/2017 | | |
|
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| | | | | | | | | | | | | |
| 10.15.4 | | Third Amendment to Credit Agreement, dated as of October 4, 2017, by and among WildHorse Resource Development Corporation, each of the guarantors party thereto, and Wells Fargo Bank, National Association, as Administrative Agent for the Lenders party thereto, BMO Harris Bank, N.A., as Syndication Agent, the Lenders party thereto and the other parties party thereto. | | 8-K | | 001-37964 | | 10.1 | | 10/5/2017 | | |
| | | | | | | | | | | | | |
| 10.15.5 | | Fourth Amendment to Credit Agreement, dated as of March 23, 2018 by and among WildHorse Resource Development Corporation, each of the guarantors party thereto, and Wells Fargo Bank, National Association, as Administrative Agent for the Lenders party thereto, BMO Harris Bank, N.A., as Syndication Agent, the Lenders party thereto and the other parties party thereto. | | 8-K | | 001-37964 | | 10.1 | | 3/27/2018 | | |
| | | | | | | | | | | | | |
| 10.15.6 | | Fifth Amendment to Credit Agreement, dated as of October 15, 2018 by and among WildHorse Resource Development Corporation, each of the guarantors party thereto, and Wells Fargo Bank, National Association, as Administrative Agent for the Lenders party thereto, BMO Harris Bank, N.A., as Syndication Agent, the Lenders party thereto and the other parties party thereto. | | 10-Q | | 001-37964 | | 10.1 | | 11/8/2018 | | |
| | | | | | | | | | | | | |
| 10.15.7 | | Sixth Amendment to Credit Agreement, dated as of February 1, 2019, by and among Brazos Valley Longhorn, L.L.C. (as successor by merger to WildHorse Resource Development Corporation), each of each of the guarantors party thereto, and Wells Fargo Bank, National Association, as Administrative Agent for the Lenders party thereto, BMO Harris Bank, N.A., as Syndication Agent, the Lenders party thereto and the other parties party thereto. | | 8-K | | 001-13726 | | 10.1 | | 2/1/2019 | | |
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| 21 | | | | | | | | | | | | X |
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| 23.1 | | | | | | | | | | | | X |
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| 23.2 | | | | | | | | | | | | X |
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| 31.1 | | | | | | | | | | | | X |
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| 31.2 | | | | | | | | | | | | X |
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| 32.1 | | | | | | | | | | | | X |
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| 32.2 | | | | | | | | | | | | X |
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99 | | | | | | | | | | | | X |
| | | | | | | | | | | | |
101 INS | | XBRL Instance Document. | | | | | | | | | | X |
| | | | | | | | | | | | |
101 SCH | | XBRL Taxonomy Extension Schema Document. | | | | | | | | | | X |
| | | | | | | | | | | | |
101 CAL | | XBRL Taxonomy Extension Calculation Linkbase Document. | | | | | | | | | | X |
| | | | | | | | | | | | |
101 DEF | | XBRL Taxonomy Extension Definition Linkbase Document. | | | | | | | | | | X |
| | | | | | | | | | | | |
101 LAB | | XBRL Taxonomy Extension Labels Linkbase Document. | | | | | | | | | | X |
| | | | | | | | | | | | |
101 PRE | | XBRL Taxonomy Extension Presentation Linkbase Document. | | | | | | | | | | X |
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| | | | | | | | | | | | |
| * | | Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The registrant hereby undertakes to furnish supplemental copies of any of the omitted schedules upon request by the SEC. |
** | | 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 |
ITEM 16. Form 10-K Summary
Not applicable.
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: March 1, 2021 | CHESAPEAKE ENERGY CORPORATION |
| By: | | | |
Date: February 27, 2019 | By: | | /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-fact and agents, 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-fact and agents, and each of them, 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.
|
| | | | | | | | | | | | | |
| Signature | | Capacity | | Date |
| /s/ ROBERT D. LAWLER | | President and Chief Executive Officer (Principal Executive Officer) | | February 27, 2019March 1, 2021 |
| Robert D. Lawler |
| | | | |
| /s/ DOMENIC J. DELL'OSSO, JR. | | Executive Vice President and Chief Financial Officer (Principal Financial Officer) | | February 27, 2019March 1, 2021 |
| Domenic J. Dell'Osso, Jr. |
| | | | |
| /s/ WILLIAM M. BUERGLER | | Senior Vice President and Chief Accounting Officer (Principal Accounting Officer) | | February 27, 2019March 1, 2021 |
| William M. Buergler |
| | | | |
/s/ R. BRAD MARTINMICHAEL WICHTERICH | | Chairman of the Board | | February 27, 2019March 1, 2021 |
R. Brad MartinMichael Wichterich |
| | | | |
/s/ ARCHIE W. DUNHAMTIMOTHY S. DUNCAN | | Director and Chairman Emeritus | | February 27, 2019March 1, 2021 |
Archie W. DunhamTimothy S. Duncan |
| | | | |
/s/ GLORIA R. BOYLANDBENJAMIN C. DUSTER, IV | | Director | | February 27, 2019March 1, 2021 |
Gloria R. BoylandBenjamin C. Duster, IV |
| | | | |
/s/ LUKE R. CORBETTSARAH EMERSON | | Director | | February 27, 2019March 1, 2021 |
Luke R. CorbettSarah Emerson |
| | | | |
/s/ MARK A. EDMUNDSMATTHEW M. GALLAGHER | | Director | | February 27, 2019March 1, 2021 |
Mark A. EdmundsMatthew M. Gallagher |
| | | | |
/s/ DAVID W. HAYESBRIAN STECK | | Director | | February 27, 2019March 1, 2021 |
David W. Hayes | | |
| | | | |
/s/ LESLIE S. KEATING | | Director | | February 27, 2019 |
Leslie S. Keating |
| | | | |
/s/ MERRILL A. MILLER, JR. | | Director | | February 27, 2019 |
Merrill A. Miller, Jr. |
| | | | |
/s/ THOMAS L. RYAN | | Director | | February 27, 2019 |
Thomas L. RyanBrian Steck |