Expand Energy (EXE) 10-K risk factor changes: FY2019 vs FY2018

[removed: There] [added: *There] are numerous factors that affect our business and operating results, many of which are beyond our control.

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 [removed: securities.][added: securities.*]

[removed: Oil,] [added: 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 [removed: business.][added: business.]

In addition, periods of low oil and natural gas prices may result in [removed: ceiling test write-downs] [added: a reduction] of [added: the carrying value of] our oil and natural gas [added: properties due to recognizing impairments in proved and unproved] properties.

For example, during the period from January 1, 2014 to December 31, [removed: 2018,] [added: 2019,] 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 [removed: MMBtu] [added: mmbtu] to a low of $1.64 per [removed: MMBtu.][added: mmbtu.]

As of February [removed: 22, 2019,] [added: 19, 2020,] the NYMEX WTI oil price was [removed: $57.08] [added: $53.29] per bbl and the NYMEX Henry Hub natural gas price was [removed: $2.72] [added: $1.99] per [removed: MMBtu.][added: mmbtu.]

| • | the ability of the members of the Organization of Petroleum Exporting Countries [added: and others] to agree to and maintain oil price and production controls; |

These factors and the volatility of the energy markets make it extremely difficult to predict future oil, natural gas and NGL price [removed: movements with any certainty.][added: movements.]

As of February [removed: 22, 2019,] [added: 19, 2020,] including January and February derivative contracts that have settled, approximately [removed: 63%] [added: 70%] of our [added: 2020] forecasted oil, natural gas and NGL production revenue was [removed: 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.][added: hedged.]

Even with oil, natural gas and NGL derivatives currently in place to mitigate price risks associated with a portion of our [removed: 2019] [added: 2020] cash flows, we have substantial exposure to oil, natural gas and NGL prices in 2020 and [added: 2021 and] beyond.

[removed: We] [added: We] 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 [removed: due.][added: due.]

As of December 31, [removed: 2018,] [added: 2019,] we had approximately [removed: $8.2] [added: $8.916] billion in principal amount of debt outstanding (including [removed: $381] [added: $301] million of current maturities and [removed: $419 million] [added: $1.590 billion] drawn under our senior secured revolving credit facility).

As of December 31, [removed: 2018,] [added: 2019,] we had approximately [removed: $107] [added: $59] million of letters of credit issued and borrowing capacity of approximately [removed: $2.5] [added: $1.351] billion under our $3.0 billion senior secured revolving credit [removed: facility (the “Chesapeake revolving credit facility”).][added: facility.]

See [Note [removed: 3](#sC20F8462A7E65B2593065C408D3503D2)] [added: 5](#s5D137AEEA9A851B8B3C3DB703BCD831D)] 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.

| • | expose us to the risk of increased interest rates as certain of our borrowings, including borrowings under the Chesapeake revolving credit [removed: facility and the WildHorse revolving credit] facility, bear interest at floating rates; |

We have drawn on our [added: $3.0 billion] credit [removed: facilities] [added: facility] for liquidity, and the borrowing [removed: bases under our $3.0 billion Chesapeake credit facility and our $1.3 billion WildHorse revolving credit facility are] [added: base is] subject to [removed: redeterminations] [added: a redetermination] in the second quarter of [removed: 2019.][added: 2020.]

If our borrowing [removed: bases] [added: base] under our revolving credit [removed: facilities decrease] [added: facility decreases] 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 [removed: either or both of] our credit [removed: facilities] [added: facility] declines as a result of lower oil and natural gas prices, asset dispositions or otherwise, we may be required to pledge additional collateral [removed: 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, our ability to comply with the financial and other restrictive covenants in our indebtedness [removed: 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 [added: 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.]

[removed: We] [added: 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 [removed: conditions.][added: conditions.]

[removed: If] [added: If] we are unable to generate enough cash flow from operations to service our indebtedness or are unable to use future borrowings to refinance our indebtedness or fund other capital needs, we may have to undertake alternative financing plans, which may have onerous terms or may be [removed: unavailable.][added: unavailable.]

| • | reducing or delaying capital [removed: investments;] [added: investments, including by curtailing our drilling program;] or |

[removed: Our] [added: Our] variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to [removed: increase.][added: increase.]

Borrowings under our revolving credit [removed: facilities] [added: facility] and [removed: floating rate senior notes due 2019] [added: term loan facility] bear interest at [added: a] variable [removed: rates] [added: rate] and expose us to interest rate risk.

As of December 31, [removed: 2018,] [added: 2019,] we had [removed: $799 million] [added: $3.1 billion] of variable rate indebtedness outstanding.

[removed: Restrictive] [added: 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 [removed: interests.][added: interests.]

[removed: Declines] [added: Further declines] in oil, NGL and natural gas prices, or a prolonged period of low oil, NGL and natural gas prices [removed: 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 [removed: facilities,] [added: facility,] which could require us to refinance or amend such obligations resulting in the payment of consent fees or higher interest rates, or require us to raise additional capital at an inopportune time or on terms not favorable to us.

A breach of any of these covenants or our inability to comply with the required financial ratios or financial condition tests could result in a default under our credit [removed: facilities] [added: facility] that, if not cured or waived, could result in acceleration of all indebtedness outstanding thereunder and cross-default rights under our other debt.

In addition, in the event of an event of default under [removed: one of] the credit [removed: facilities,] [added: facility or other indebtedness,] the affected lenders could foreclose on the collateral securing [removed: such] [added: the] credit facility and require repayment of all borrowings outstanding thereunder.

[removed: 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.

[removed: Our] [added: Our] credit rating could negatively impact our availability and cost of capital and could require us to post more collateral under certain commercial [removed: arrangements.][added: arrangements.]

As of February [removed: 22, 2019,] [added: 24, 2020,] we have [removed: received requests and] posted approximately [removed: $162] [added: $60] 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 [removed: $355] [added: $220] 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 [removed: facilities,] [added: facility,] and negatively impact our liquidity.

[removed: Declines in] [added: If] commodity prices [removed: could result in] [added: remain depressed or drilling efforts are unsuccessful, we may be required to record] write downs of the carrying value of our oil and natural gas [removed: properties.][added: properties.]

See [removed: Impairment] [added: *Impairment] of Oil and Natural Gas [removed: Properties] [added: Properties*] included in Item 7 of this report for further information.

[removed: Significant] [added: Significant] capital expenditures are required to replace our reserves and conduct our [removed: business.][added: business.]

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 [removed: facilities.][added: facility.]

| • | changes in the level of consumer and industrial demand, including impacts from global or national health epidemics and concerns, such as the recent coronavirus; |

| • | increased use of competing energy products, including alternative energy sources; |

We had approximately 76% downside oil price protection through swaps and collars at an average price of $59.90 per bbl.

We

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had 39% downside gas price protection through swaps at $2.76 per mcf and 14% under put spread arrangements based on an average bought put NYMEX price of $2.05 per mcf and exposure below an average sold put NYMEX price of $1.80 per mcf.

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could be affected by our future performance and events or circumstances beyond our control.

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Also, our credit facility requires us to maintain compliance with specified financial ratios and satisfy certain financial condition tests, including a leverage ratio as of the end of each fiscal quarter of not greater than 4.50 to1 through the fiscal quarter ending December 31, 2021, with step-downs to 4.25 to 1 for the fiscal quarter ending March 31, 2022 and to 4.00 to 1 for each fiscal quarter ending thereafter, a first lien secured leverage ratio of not greater than 2.50 to 1 as of the end of each fiscal quarter, and a fixed charge coverage ratio of not less than 2.00 to 1 as of the end of the fiscal quarter ending December 31, 2019, 2.25 to 1 as of the end of each fiscal quarter ending March 31 and June 30, 2020, and 2.50 to 1 as of the end of each fiscal quarter ending September 30, 2020 and thereafter.

Our ability to comply with these ratios and financial condition tests may be affected by events beyond our control and, as a result, we may be unable to meet these ratios and financial condition tests.

These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a continued downturn in our business or a downturn in the economy in general or otherwise conduct necessary corporate activities.

If that should occur, we may be unable to pay all such debt or to borrow sufficient funds to refinance it.

Even if new financing were then available, it may not be on terms that are acceptable to us.

If the amounts outstanding under the credit facility or any of our

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If we cannot meet the continued listing requirements of the NYSE, the NYSE may delist our common stock, which would have an adverse impact on the trading volume, liquidity and market price of our common stock and allow holders of our convertible senior notes to require us to repurchase their notes.

On December 10, 2019, we were notified by the New York Stock Exchange (the “NYSE”) that the average closing price of our common stock, $0.01 par value per share (the “Common Stock”), over a prior 30 consecutive trading day period was below $1.00 per share, which is the minimum average closing price per share required to maintain listing on the NYSE under Section 802.01C of the NYSE Listed Company Manual.

We have a period of six months following the receipt of the notice to regain compliance with the minimum share price requirement, with the possibility of extension at the discretion of the NYSE.

In order to regain compliance, on the last trading day in any calendar month during the cure period, the Common Stock must have: (i) a closing price of at least $1.00 per share; and (ii) an average closing price of at least $1.00 per share over the 30 trading day period ending on the last trading day of such month.

If we fail to regain compliance with Section 802.01C of the NYSE Listed Company Manual by the end of the cure period, the Common Stock will be subject to the NYSE’s suspension and delisting procedures.

To regain compliance with NYSE listing standards we intend to implement a reverse stock split, subject to approval of our board of directors and shareholders.

If the Common Stock ultimately were to be delisted for any reason, it could negatively impact us as it would likely reduce the liquidity and market price of the Common Stock; reduce the number of investors willing to hold or acquire the Common Stock; and negatively impact our ability to access equity markets and obtain financing.

If the Common Stock were to be removed from listing on the NYSE (and the Common Stock were not to become listed on other specified stock exchanges), holders of our convertible senior notes would have a right to require us to repurchase their notes.

As of December 31, 2019, there was $1.06 billion aggregate principal amount of convertible senior notes outstanding, and there can be no assurance we would be able to repurchase such notes if required to do so in connection with a delisting.

We have been required to write down the carrying value of certain of our oil and natural gas properties in the past and there is a risk that we will be required to take additional writedowns in the future.

Writedowns may occur in the future when oil and natural gas prices are low, or if we have downward adjustments to our estimated proved reserves, increases in our estimates of operating or development costs, or due to the anticipated sale of properties.

The successful efforts method of accounting requires that we periodically review the carrying value of our oil and natural gas properties for possible impairment.

Impairment is recognized for the excess of book value over fair value when the book value of a proven property is greater than the expected undiscounted future net cash flows from that property and on acreage when conditions indicate the carrying value is not recoverable.

We may be required to write down the carrying value of a property based on oil and natural gas prices at the time of the impairment review, or as a result of continuing evaluation of drilling results, production data, economics, divestiture activity, and other factors.

A writedown constitutes a non-cash charge to earnings and does not impact cash or cash flows from operating activities; however, it reflects our long-term ability to recover an investment, reduces our reported earnings and increases certain leverage ratios.

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Interest

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| • | fires, explosions, blowouts, cratering or loss of well control, such as the January 30, 2020 well control incident at a wellsite located in Burleson County, Texas, causing the deaths of three of our contractors’ employees and injuring a fourth; |

Moreover, certain of these events could result in environmental pollution and impact to third parties, including persons living in proximity to our operations, our employees and employees of our contractors, leading to possible injuries, death or significant damage to property and natural resources.

At this time, we cannot

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| • | changes in the level of consumer and industrial demand; |

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.

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.

Also, our credit facilities require us to maintain compliance with specified financial ratios and satisfy certain financial condition tests.

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.

Under the full cost method of accounting for costs related to our oil and natural gas properties, we are required to write down the carrying value of our oil and natural gas assets if capitalized costs exceed the present value of future net revenues of our proved reserves, which is based on the average of commodity prices on the first day of the month over the trailing 12-month period.

Such write-downs could 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 exceeds the carrying value of our oil and natural gas properties.

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.

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.

able to conduct our operations as planned.

Pipeline Safety.

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.

Seismic Activity.

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.

Hydraulic Fracturing.

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.

Climate Change.

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.

Cap and trade programs offer greenhouse gas emission allowances that are gradually reduced over time.

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.

[removed: Overview][added: Overview]

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 [removed: “Item 8.][added: Item 8 of this report.]

[removed: Highlights] [added: Recent highlights] include the following:

| • | acquired WildHorse, an oil and gas company with operations in the Eagle Ford Shale and Austin Chalk formations in southeast Texas, for approximately [removed: 717.3] [added: 717.4] 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 anticipate the acquisition to materially increase our oil production and enhance our oil production mix as well as significantly reduce costs due to operational synergies that we believe the combined company will achieve. We [added: achieved $250 million of cost savings in 2019 and 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; |

In [removed: 2019,] [added: 2020 and beyond,] our focus remains concentrated on four [added: long-term] strategic priorities:

| • | reduce total leverage to achieve [removed: long term] [added: long-term] net [removed: debt/EBITDA] [added: debt/EBITDAX] of 2x; |

[removed: Business] [added: *Business] and Industry [removed: Outlook][added: Outlook*]

[added: As a result of this increase] in domestic supply of crude oil and natural gas, commodity prices for these products are meaningfully lower than they were a decade ago, and may remain volatile for the foreseeable future.

[removed: Liquidity] [added: Liquidity] and Capital [removed: Resources][added: Resources]

[removed: Liquidity Overview][added: *Liquidity Overview*]

Historically, oil and natural gas prices have been [removed: volatile,] [added: volatile] and may be subject to wide fluctuations in the future.

As of December 31, [removed: 2018,] [added: 2019,] we had a cash balance of [removed: $4] [added: $6] million compared to [removed: $5] [added: $4] million as of December 31, [removed: 2017,] [added: 2018,] and a net working capital deficit of [removed: $1.230] [added: $1.141] billion as of December 31, [removed: 2018,] [added: 2019,] compared to a net working capital deficit of [removed: $831 million] [added: $1.289 billion] as of December 31, [removed: 2017.][added: 2018.]

As of December 31, [removed: 2018,] [added: 2019,] our working capital deficit includes [removed: $381] [added: $385] million of debt due in the next 12 months.

Our total principal debt as of December 31, [removed: 2018] [added: 2019] was [removed: $8.168] [added: $8.916] billion compared to [removed: $9.981] [added: $8.168] billion as of December 31, [removed: 2017.][added: 2018.]

As of December 31, [removed: 2018,] [added: 2019,] we had [removed: $2.474] [added: $1.351] billion of borrowing capacity available under [removed: the Chesapeake] [added: our] revolving credit facility, with outstanding borrowings of [removed: $419 million] [added: $1.590 billion] and [removed: $107] [added: $59] million utilized for various letters of credit.

See [Note [removed: 3](#sC20F8462A7E65B2593065C408D3503D2)] [added: 5](#s5D137AEEA9A851B8B3C3DB703BCD831D)] 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.

[removed: Derivative] [added: *Derivative] and Hedging [removed: Activities][added: Activities*]

To mitigate a portion of [removed: the] [added: our] exposure to adverse market [added: price] changes, we [removed: have entered] [added: enter] 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 [added: better] predict [removed: with greater certainty] the total revenue we [removed: will] [added: expect to] receive.

As of February [removed: 22, 2019,] [added: 19, 2020,] including January and February derivative contracts that have settled, approximately [removed: 63%] [added: 70%] of our [added: 2020] forecasted oil, natural gas and NGL production revenue was [removed: 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.][added: hedged.]

| [removed: Oil Derivatives(a)] [added: Oil Derivatives(a)] | | | | | | | |

| [removed: Year] [added: Year] | | [removed: Type] [added: Type] of Derivative [removed: Instrument] [added: Instrument] | | [removed: Notional Volume] [added: Notional Volume] | | | [removed: Average] [added: Average] NYMEX [removed: Price] [added: Price] |

| | | | | [removed: (mmbbls)] [added: (mmbbls)] | | | |

| [removed: 2019] [added: 2020] | | Basis protection swaps | | [removed: 7] [added: 12] | | | [removed: $6.01] [added: $2.57] |

| 2020 | | Swaps | | [removed: 7] [added: 30] | | | [removed: $58.28] [added: $59.59] |

| [removed: Natural] [added: Natural] Gas [removed: Derivatives(a)] [added: Derivatives(a)] | | | | | | | |

| | | | | [removed: (bcf)] [added: (bcf)] | | | |

| [removed: 2019] [added: 2020] | | Basis protection swaps | | [removed: 50] [added: 53] | | | [removed: ($0.56)] [added: $0.03] |

| (a) | Includes amounts settled in January and February [removed: 2019.] [added: 2020.] |

See [Note [removed: 13](#s7B9DB25C2E9655D29E4197494F88AB7D)] [added: 14](#sF6FF4D83C9BA56118FB13A517F864CAC)] of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of derivatives and hedging activities.

[removed: Debt][added: *Debt*]

We [removed: are seeking] [added: continue] to [added: seek opportunities to] reduce cash costs (production, gathering, processing and [removed: transportation, general] [added: transportation] and [removed: administrative] [added: general] and [removed: interest expenses),] [added: administrative),] improve our production volumes from existing wells, and achieve additional operating and capital efficiencies with a focus on growing our oil volumes.

[removed: Also] [added: 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 [removed: make-whole] [added: call] premium.

We may continue to use a combination of cash, borrowings and issuances of our common stock or other securities [added: and the proceeds from asset sales] to retire our outstanding [removed: debt, including any] debt [removed: assumed in connection with the completion with the WildHorse acquisition,] [added: or preferred stock] through privately negotiated transactions, open market repurchases, redemptions, [added: exchanges,] tender offers or otherwise, but we are under no obligation to do so.

[removed: Chesapeake Revolving] [added: *Revolving] Credit [removed: Facility][added: Facility*]

Our next borrowing base redetermination is scheduled for the second quarter of [removed: 2019.][added: 2020.]

As of December 31, [removed: 2018,] [added: 2019,] we had outstanding borrowings of [removed: $419 million] [added: $1.590 billion] under [removed: the Chesapeake] [added: our] revolving credit facility and had used [removed: $107] [added: $59] million [removed: of the Chesapeake revolving credit facility] for various letters of credit.

See [Note [removed: 3](#sC20F8462A7E65B2593065C408D3503D2)] [added: 5](#s5D137AEEA9A851B8B3C3DB703BCD831D)] of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of the terms of [removed: the Chesapeake] [added: our] revolving credit facility.

As of December 31, [removed: 2018,] [added: 2019,] we were in compliance with all applicable financial covenants under the credit agreement.

[removed: WildHorse Revolving Credit Facility][added: | Interest expense on revolving credit facility | | 96 | | | | 37 | | | | 39 | | |]

| • | entered into a secured 4.5-year term loan facility for $1.5 billion to finance a tender offer for unsecured notes issued by Brazos Valley Longhorn and Brazos Valley Longhorn Finance Corp., each a wholly owned subsidiary of Chesapeake, and to fund the retirement of Brazos Valley Longhorn’s secured revolving credit facility; |

| • | exchanged new 11.5% Senior Secured Second Lien Notes due 2025 for 8.00% Senior Notes due 2027, 8.00% Senior Notes due 2026, 8.00% Senior Notes due 2025, 7.50% Senior Notes due 2026 and 7.00% Senior Notes due 2024. Also, 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. These transactions resulted in the removal of approximately $900 million principal amount of debt from the company’s balance sheet. |

| • | privately negotiated exchanges of approximately $507 million principal amount of our outstanding senior notes for 235,563,519 shares of common stock and $186 million principal amount of our outstanding convertible senior notes for 73,389,094 shares of common stock, reducing annual interest payments; |

| • | exchanged 40,000 shares of our 5.75% (Series A) Cumulative Convertible Preferred Stock for 10,367,950 shares of common stock, reducing annual preferred stock dividend payments; |

| • | extended our debt maturity profile by privately exchanging approximately $884 million aggregate principal amount of our existing 6.625% Senior Notes due 2020, 6.875% Senior Notes due 2020, 6.125% Senior Notes due 2021 and 5.375% Senior Notes due 2021 for approximately $919 million aggregate principal amount of new 8.00% Senior Notes due 2026; and |

| • | improved our cost structure by reducing combined production, gathering, processing and transportation and general and administrative expenses by approximately $0.79 per boe, or $290 million in 2019 compared to 2018, or 13%. The primary driver in the reduction is lower gathering, processing and transportation expenses due to certain 2018 divestitures and recently renegotiated contracts. |

| • | achieve sustained free cash flow generation; |

Natural gas prices are at their lowest levels since the first half of 2016.

Accordingly, a majority of our 2020 capital will be allocated to our higher margin oil assets with total expected 2020 capital expenditures being approximately 30% lower than 2019 while maintaining flat oil production.

We plan to seek the lowest capital program possible to reach and sustain positive cash flow.

[TABLE OF CONTENTS](#sacd31288082644189dc9f32fd0d5ad4e)

We believe the prolonged lower commodity price environment has fundamentally changed the expectations of capital markets, resulting in new capital being both more difficult and more expensive to access.

Currently, capital markets are no longer willing to fund organic growth.

We believe our strategic priorities are consistent with these expectations as we look to continue to increase our cash flow and expand our margins by focusing on high-return drilling locations and reduced capital and operating costs using cash generated from operations and asset sales.

We look to continue to reduce debt on our balance sheet with asset sales and liability management activities similar to those completed in 2019.

*Change in Accounting Principle*

During the first quarter of 2019, we changed our method of accounting for our oil and natural gas exploration and development activities from the full cost method to the successful efforts method of accounting.

Financial information for all periods presented has been recast to reflect retrospective application of the successful efforts method of accounting.

See [Notes 1](#sC7C4FA668F9552D5B9ABF0E64A4C7A72) and [2](#s5CE524823841503782AD9252035013B5) of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of the change in accounting principle.

[TABLE OF CONTENTS](#sacd31288082644189dc9f32fd0d5ad4e)

We had approximately 76% downside oil price protection through swaps and collars at an average price of $59.90 per bbl.

We had 39% downside gas price protection through swaps at $2.76 per mcf and 14% under put spread arrangements based on an average bought put NYMEX price of $2.05 per mcf and exposure below an average sold put NYMEX price of $1.80 per mcf.

| 2021 | | Calls | | 4 | | | $61.58 |

| 2022 | | Calls | | 4 | | | $61.58 |

| Year | | Type of Derivative Instrument | | Notional Volume | | | Average NYMEX Price |

| 2020 | | Swaps | | 265 | | | $2.76 |

| 2020 | | Put spread(b) | | 94 | | | $1.80/$2.05 |

| 2021 | | Call swaptions | | 15 | | | $2.80 |

| 2021 | | Calls | | 96 | | | $2.75 |

| 2022 | | Call swaption | | 15 | | | $2.80 |

| (b) | *Put spread:* These instruments contain a fixed floor price (bought put) and sub floor price (sold put). If the market price exceeds the bought put strike, we receive the market price. If the market price is between the bought put and sold put strike prices, we receive the bought put price. If the market price falls below the subfloor, we receive the market price plus the difference between the sold put and bought put. |

[TABLE OF CONTENTS](#sacd31288082644189dc9f32fd0d5ad4e)

We are committed to reducing total leverage to achieve long-term net debt/EBITDAX of 2x.

To accomplish this goal, we intend to allocate our capital expenditures to projects we believe offer the highest return and value regardless of the commodity price environment, to deploy leading drilling and completion technology throughout our portfolio, and to take advantage of acquisition and divestiture opportunities to strengthen our cost structure and our portfolio.

Increasing our margins means not only increasing our absolute level of cash flows from operations, but also increasing our cash flows from operations generated per barrel of oil equivalent production.

Our revolving credit facility matures in September 2023 and the current aggregate commitment of the lenders and borrowing base under the facility is $3.0 billion.

The 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.

Scheduled borrowing base redeterminations will continue to occur semiannually.

As of December 31, 2019, our leverage ratio was approximately 3.43 to 1, our first lien leverage ratio was approximately 1.21 to 1 and our fixed charge coverage ratio was approximately 3.64 to 1.

*Term Loan*

Financial Statements and Supplementary Data” of this report.

The transformation of Chesapeake over the past five years has been significant and our progress accelerated in 2018 and early 2019.

We believe our recent accomplishments and achievements have made our company stronger.

| • | sold our interests in the Utica Shale operating area located in Ohio for approximately $1.9 billion, and used the proceeds 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 proceeds from the disposition of certain non-core assets and other property sales in addition to 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 position for oil and natural gas that provides stability and certainty in our cash generating capability should commodity prices experience volatility.

| • | increase net cash provided by operating activities to fund capital expenditures; |

As a result of this increase

We have undergone a mutli-year effort to reduce our cost structure significantly and improve the profitability 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 such that we are currently experiencing higher profitability than compared to periods when commodity prices were much higher.

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 advantage 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 shareholder value by growing cash flow through the development of our extensive portfolio of drilling opportunities.

We intend to maintain capital discipline as we target cash flow growth rates that can be sustainable with internally generated resources.

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.

Although we have taken measures 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 portion of our outstanding indebtedness to improve our liquidity.

We utilize various oil, natural gas and NGL derivative instruments to protect a portion of our cash flow against downside risk.

| 2019 | | Swaps | | 17 | | | $57.16 |

| 2019 | | Two-way collars | | 6 | | | $58.00/$67.75 |

| 2019 | | Puts | | 2 | | | $53.83 |

| 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 |

| 2020 | | Swaps | | 217 | | | $2.75 |

| 2020 | | Call swaptions | | 106 | | | $2.77 |

___________________________________________

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.

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.

[removed: Oil,] [added: *Oil,] Natural Gas and NGL [removed: Derivatives][added: Derivatives*]

Our results of operations and cash flows are impacted by changes in market prices for oil, natural gas and [removed: NGL.][added: NGL, which have historically been volatile.]

To mitigate a portion of our exposure to adverse price changes, we [removed: have entered] [added: enter] into various derivative instruments.

We [removed: have determined] [added: determine] the fair value of our derivative instruments utilizing established index prices, volatility curves and discount factors.

See [Note [removed: 13](#s7B9DB25C2E9655D29E4197494F88AB7D)] [added: 14](#sF6FF4D83C9BA56118FB13A517F864CAC)] 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 December 31, [added: 2019, and] 2018, our oil, natural gas and NGL derivative instruments consisted of the following types of instruments:

| [removed: •] [added: *•*] | [removed: Swaps:] [added: *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. |

| • | [removed: Options:] [added: *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 [removed: options,] [added: 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. |

| • | [removed: Call Swaptions:] [added: *Call Swaptions*:] We sell call swaptions to counterparties in exchange for a [removed: premium that] [added: premium. Swaptions] allow the counterparty, on a specific date, to extend an existing fixed-price swap for a certain period of time [added: or to increase the notional volumes of an existing fixed-price swap.] |

| • | [removed: Collars:] [added: *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. |

| [removed: •] [added: *•*] | [removed: Basis] [added: *Basis] Protection [removed: Swaps:] [added: 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. |

| | | | | | [removed: Weighted] [added: Weighted] Average [removed: Price] [added: Price] | | | | | | | | | | | | | | | | [removed: Fair Value] [added: Fair Value] | | |

| | | [removed: Volume] [added: Volume] | | | [removed: Fixed] [added: Fixed] | | | | [removed: Call] [added: Call] | | | | [removed: Put] [added: Put] | | | | [removed: Differential] [added: Differential] | | | | [removed: Asset (Liability)] [added: Asset (Liability)] | | |

| | | [removed: (mmbbl)] [added: (mmbbl)] | | | [removed: ($] [added: ($] per [removed: bbl)] [added: bbl)] | | | | | | | | | | | | | | | | [removed: ($] [added: ($] in [removed: millions)] [added: millions)] | | |

| [removed: Oil:] [added: Oil:] | | | | | | | | | | | | | | | | | | | | | | | |

| [removed: Swaps:] [added: Swaps:] | | | | | | | | | | | | | | | | | | | | | | | |

| [removed: Collars:] [added: Collars:] | | | | | | | | | | | | | | | | | | | | | | | |

| [removed: Basis] [added: Basis] Protection [removed: Swaps:] [added: Swaps:] | | | | | | | | | | | | | | | | | | | | | | | |

| | | [removed: (bcf)] [added: (bcf)] | | | [removed: ($] [added: ($] per [removed: mcf)] [added: mcf)] | | | | | | | | | | | | | | | | | | |

| [removed: Natural Gas:] [added: Natural Gas:] | | | | | | | | | | | | | | | | | | | | | | | |

| [removed: Three-Way Collars:] [added: Three-Way Collars:] | | | | | | | | | | | | | | | | | | | | | | | |

| [removed: Call] [added: Call] Options [removed: (sold):] [added: (sold):] | | | | | | | | | | | | | | | | | | | | | | | |

| [removed: Call Swaptions:] [added: Call Swaptions:] | | | | | | | | | | | | | | | | | | | | | | | |

| [removed: Contingent Consideration:] [added: Contingent Consideration:] | | | | | | | | | | | | | | | | | | | | | | | |

| [removed: Utica Divestiture:] [added: Utica Divestiture:] | | | | | | | | | | | | | | | | | | | | | | | |

| | [removed: | ($] [added: ($] in [removed: millions)] [added: millions)] | | | [added: | | | | | | | | | | | | | | | | | | | | | | | |]

| Short-term | | [added: 24 | | |] $ | [removed: (23] [added: 58.54] | [added: | | $ | — | | | $ | — | | | $ | — | | | $ | (7 |] ) |

| Long-term | | [removed: (33] [added: 29] | | [added: | $ | 2.80 | | | $ | — | | | $ | — | | | $ | — | | | (2 | |] ) |

| Total [added: Oil] | | [removed: $] | [removed: (56] | [removed: )] | [added: | | | | | | | | | | | | | | | | 5 | | |]

[removed: Interest] [added: *Interest] Rate [removed: Risk][added: Risk*]

| | [removed: Years] [added: Years] of [removed: Maturity] [added: Maturity] | | | | | | | | | | | | | | | | | | | | | | | | | | |

| | [removed: 2019] [added: 2020] | | | | [removed: 2020] [added: 2021] | | | | [removed: 2021] [added: 2022] | | | | [removed: 2022] [added: 2023] | | | | [removed: 2023] [added: 2024] | | | | [removed: Thereafter] [added: Thereafter] | | | | [removed: Total] [added: Total] | | |

| [removed: Liabilities:] [added: Liabilities:] | | | | | | | | | | | | | | | | | | | | | | | | | | | |

Changes in interest rates affect the amount of interest we earn on our cash, cash equivalents and short-term investments and the interest rate we pay on borrowings under our revolving credit [removed: facilities] [added: facility] and our [removed: floating rate senior notes.][added: term loan facility.]

[removed: As of] [added: During the year ended] December 31, [removed: 2018, we had] [added: 2019,] $5 million of net gains related to settled interest rate derivative contracts [removed: that will be recorded within interest expense as realized gains or losses once they are] [added: were] transferred from our senior note liability or [added: unrealized gains or losses and recorded] within interest expense as [removed: unrealized] [added: realized] gains or [removed: losses over the remaining six-year term of our related senior notes.][added: losses.]

The 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 prices 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*

For the year ended December 31, 2019, oil, natural gas, and NGL revenue, excluding any effect of our derivative instruments, were $2.543 billion, $1.782 billion, and $192 million, respectively.

Based on 2019 production, oil, natural gas, and NGL revenue for the year ended December 31, 2019 would have increased or decreased by approximately $254 million, $178 million, and $19 million, respectively, for each 10% increase or decrease in prices.

As of December 31, 2019, the fair values of our oil and gas derivatives were net assets of $5 million and $125 million, respectively.

A 10% increase in forward oil prices would decrease the valuation of oil derivatives by $147 million while a 10% decrease would increase the valuation by $150 million.

A 10% increase in forward gas prices would decrease the valuation of gas derivatives by approximately $58 million while a 10% decrease would increase the valuation by $57 million.

This fair value change assumes volatility based on prevailing market parameters at December 31, 2019.

See [Note 14](#sF6FF4D83C9BA56118FB13A517F864CAC) of the notes to our consolidated financial statements included in Item 8 of this report for further information on our open derivative positions.

Beginning with this report, we have revised our commodity price risk disclosure alternative from the tabular format to a sensitivity analysis, which we believe is a more commonly used and easily understood disclosure alternative.

We have presented below the tabular analysis as of December 31, 2019 and 2018 for comparative purposes.

[TABLE OF CONTENTS](#sacd31288082644189dc9f32fd0d5ad4e)

As of December 31, 2019, we had the following open oil and natural gas derivative instruments:

| Short-term | | 2 | | | $ | — | | | $ | 83.25 | | | $ | 65.00 | | | $ | — | | | 14 | | |

| Short-term | | 8 | | | $ | — | | | $ | — | | | $ | — | | | $ | 2.49 | | | (2 | | ) |

| Swaps: | | | | | | | | | | | | | | | | | | | | | | | |

| Short-term | | 265 | | | $ | 2.76 | | | $ | — | | | $ | — | | | $ | — | | | 125 | | |

| Basis Protection Swaps: | | | | | | | | | | | | | | | | | | | | | | | |

| Short-term | | 30 | | | $ | — | | | $ | — | | | $ | — | | | $ | 0.08 | | | 2 | | |

| Total Natural Gas | | | | | | | | | | | | | | | | | | | | | 125 | | |

| Total Commodities | | | | | | | | | | | | | | | | | | | | | $ | 130 | |

[TABLE OF CONTENTS](#sacd31288082644189dc9f32fd0d5ad4e)

| | | | | | | | | | | | | | | | | | | | | | | | |

| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |

| | | | | | | | | | | | | | | | | | | | | | | | |

| | | | | | Weighted Average Price | | | | | | | | | | | | | | | | Fair Value | | |

| | | Volume | | | Fixed | | | | Call | | | | Put | | | | Differential | | | | Asset (Liability) | | |

| | | (mmbbl) | | | ($ per bbl) | | | | | | | | | | | | | | | | ($ in millions) | | |

| Oil: | | | | | | | | | | | | | | | | | | | | | | | |

| Swaps: | | | | | | | | | | | | | | | | | | | | | | | |

| Collars: | | | | | | | | | | | | | | | | | | | | | | | |

| Basis Protection Swaps: | | | | | | | | | | | | | | | | | | | | | | | |

| | | (bcf) | | | ($ per mcf) | | | | | | | | | | | | | | | | | | |

| Natural Gas: | | | | | | | | | | | | | | | | | | | | | | | |

| Swaps: | | | | | | | | | | | | | | | | | | | | | | | |

| Collars: | | | | | | | | | | | | | | | | | | | | | | | |

| Call Options (sold): | | | | | | | | | | | | | | | | | | | | | | | |

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.

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 within oil, natural gas and NGL revenues as realized gains (losses) on derivatives once they are transferred from either accumulated other comprehensive income or unrealized gains (losses) on derivatives in the month of related production, based on the terms specified in the original contract as noted below:

| | | | | |

| --- | --- | --- | --- | --- |

| | | December 31, 2018 | | |

The table below reconciles the changes in fair value of our oil and natural gas derivatives during 2018.

Of the $282 million 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 by December 31, 2020.

| 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 | |

| | ($ in millions) | | | | | | | | | | | | | | | | | | | | | | | | | | |

| 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 | | % |

Realized and unrealized gains or losses from interest rate derivative transactions are reflected as adjustments to interest expense on the consolidated statements of operations.

[removed: Our Business][added: Our Business]

We own a large and geographically diverse portfolio of onshore U.S. unconventional liquids and natural gas assets, including interests in approximately [removed: 13,200] [added: 13,500] oil and natural gas wells.

We have [removed: leading] [added: significant] 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.

In February 2019, we acquired WildHorse Resource Development Corporation, an oil and gas company with operations in the Eagle Ford Shale and Austin Chalk formations in southeast Texas, for approximately [removed: 717.3] [added: 717.4] million shares of our common stock and $381 million in cash, and the assumption of WildHorse’s debt of $1.4 billion as of the acquisition date of February 1, 2019.

The acquisition of WildHorse expands our oil growth platform and accelerates our progress toward our strategic and financial goals of enhancing our margins, achieving sustainable free cash flow [removed: generation,] [added: generation] and reducing our net debt to [removed: EBITDA] [added: EBITDAX] ratio.

[removed: Information] [added: Information] About [removed: Us][added: Us]

We make available, free of charge on our website at [removed: chk.com,] [added: *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.

[removed: Business Strategy][added: Business Strategy]

We continue to focus on reducing debt, increasing cash provided by operating activities, improving margins through financial discipline and operating efficiencies and [removed: improving] [added: maintaining exceptional] environmental and safety performance.

[added: To accomplish these goals, we intend to allocate our capital expenditures to projects we believe offer the highest return and value] regardless of the commodity price environment, to deploy leading drilling and completion technology throughout our portfolio, and to take advantage of acquisition and divestiture opportunities to strengthen our cost structure and our portfolio.

We continue to seek opportunities to reduce cash costs [added: per barrel of oil equivalent production] (production, gathering, processing and [removed: transportation, general] [added: transportation] and [removed: administrative] [added: general] and [removed: interest expenses)] [added: administrative)] through operational efficiencies, including [removed: but not limited to] improving our production volumes from existing wells.

We believe that our dedication to financial discipline, the flexibility and efficiency of our capital program and [removed: cost structure and] our continued focus on safety and environmental stewardship will provide opportunities to create value for us and our shareholders.

[removed: Operating Areas][added: Operating Areas]

[removed: Marcellus -] [added: *Marcellus -*] Northern Appalachian Basin in Pennsylvania.

[removed: Haynesville -] [added: *Haynesville -*] Northwestern Louisiana (Gulf Coast).

[removed: Eagle] [added: *Eagle] Ford [removed: -] [added: -*] South Texas.

[removed: Brazos Valley] [added: *Brazos Valley*] - Southeast Texas assets acquired in our WildHorse acquisition on February 1, 2019.

[removed: Powder] [added: *Powder] River Basin [removed: -] [added: -*] Stacked pay in Wyoming.

[removed: Mid-Continent -] [added: *Mid-Continent -*] Anadarko Basin in northwestern Oklahoma.

[removed: Well Data][added: Well Data]

As of December 31, [removed: 2018,] [added: 2019,] we held an interest in approximately [removed: 13,200] [added: 13,500] gross [removed: (5,600] [added: (6,800] net) productive wells, including [removed: 10,200] [added: 11,400] properties in which we held a working interest and [removed: 3,000] [added: 2,100] properties in which we held an overriding or royalty interest.

Of the [removed: 10,200] [added: 11,400] properties in which we had a working interest, we operated [removed: 7,200] [added: 8,500] wells, [removed: 6,800 gross (3,800 net),] of which [added: 7,000 gross (4,000 net),] were classified as productive natural gas wells and [removed: 3,400] [added: 4,400] gross [removed: (1,800] [added: (2,800] net) were classified as productive oil wells.

During [removed: 2018,] [added: 2019,] we drilled or participated in [removed: 351] [added: 370] gross [removed: (238] [added: (273] net) wells as operator and participated in another [removed: 26] [added: 49] gross [removed: (1] [added: (3] net) wells completed by other operators.

[removed: Drilling Activity][added: Drilling Activity]

| | | [removed: 2018] [added: 2019] | | | | | | | | | | | | [removed: 2017] [added: 2018] | | | | | | | | | | | | [removed: 2016] [added: 2017] | | | | | | | | | | |

| | | [removed: Gross] [added: Gross] | | | [removed: %] [added: %] | | | [removed: Net] [added: Net] | | | [removed: %] [added: %] | | | [removed: Gross] [added: Gross] | | | [removed: %] [added: %] | | | [removed: Net] [added: Net] | | | [removed: %] [added: %] | | | [removed: Gross] [added: Gross] | | | [removed: %] [added: %] | | | [removed: Net] [added: Net] | | | [removed: %] [added: %] | |

| Productive | | [removed: 363] [added: 414] | | | [removed: 99] [added: 100] | | | [removed: 227] [added: 271] | | | [removed: 99] [added: 100] | | | [removed: 462] [added: 363] | | | 99 | | | [removed: 292] [added: 227] | | | 99 | | | [removed: 431] [added: 462] | | | 99 | | | [removed: 236] [added: 292] | | | 99 | |

| Dry | | [removed: 2] [added: —] | | | [removed: 1] [added: —] | | | [removed: 1] [added: —] | | | [removed: 1] [added: —] | | | [removed: 4] [added: 2] | | | 1 | | | [removed: 2] [added: 1] | | | 1 | | | [removed: 1] [added: 4] | | | 1 | | | [removed: 1] [added: 2] | | | 1 | |

| Total | | [removed: 365] [added: 414] | | | 100 | | | [removed: 228] [added: 271] | | | 100 | | | [removed: 466] [added: 365] | | | 100 | | | [removed: 294] [added: 228] | | | 100 | | | [removed: 432] [added: 466] | | | 100 | | | [removed: 237] [added: 294] | | | 100 | |

| Productive | | [removed: 10] [added: 1] | | | [removed: 83] [added: 20] | | | [removed: 9] [added: 1] | | | [removed: 82] [added: 20] | | | [removed: 2] [added: 10] | | | [removed: 100] [added: 83] | | | [removed: 2] [added: 9] | | | [removed: 100] [added: 82] | | | [removed: 3] [added: 2] | | | 100 | | | 2 | | | 100 | |

| Dry | | [removed: 2] [added: 4] | | | [removed: 17] [added: 80] | | | [removed: 2] [added: 4] | | | [removed: 18] [added: 80] | | | [removed: —] [added: 2] | | | [removed: —] [added: 17] | | | [removed: —] [added: 2] | | | [removed: —] [added: 18] | | | — | | | — | | | — | | | — | |

| Total | | [removed: 12] [added: 5] | | | 100 | | | [removed: 11] [added: 5] | | | 100 | | | [removed: 2] [added: 12] | | | 100 | | | [removed: 2] [added: 11] | | | 100 | | | [removed: 3] [added: 2] | | | 100 | | | 2 | | | 100 | |

| | | [removed: 2018] [added: 2019] | | | | | | [removed: 2017] [added: 2018] | | | | | | [removed: 2016] [added: 2017] | | | | |

| | | [removed: Gross Wells] [added: Gross Wells] | | | [removed: Net Wells] [added: Net Wells] | | | [removed: Gross Wells] [added: Gross Wells] | | | [removed: Net Wells] [added: Net Wells] | | | [removed: Gross Wells] [added: Gross Wells] | | | [removed: Net Wells] [added: Net Wells] | |

| Marcellus | | [removed: 52] [added: 44] | | | [removed: 23] [added: 22] | | | [removed: 43] [added: 52] | | | [removed: 21] [added: 23] | | | [removed: 19] [added: 43] | | | [removed: 9] [added: 21] | |

| Haynesville | | [removed: 30] [added: 22] | | | [removed: 21] [added: 16] | | | [removed: 37] [added: 30] | | | [removed: 34] [added: 21] | | | [removed: 41] [added: 37] | | | 34 | |

| Eagle Ford | | [removed: 162] [added: 150] | | | [removed: 98] [added: 85] | | | [removed: 180] [added: 162] | | | [removed: 106] [added: 98] | | | [removed: 199] [added: 180] | | | [removed: 116] [added: 106] | |

| Powder River Basin | | [removed: 41] [added: 75] | | | [removed: 34] [added: 57] | | | [removed: 25] [added: 41] | | | [removed: 21] [added: 34] | | | [removed: 1] [added: 25] | | | [removed: 1] [added: 21] | |

| Mid-Continent | | [removed: 52] [added: 40] | | | [removed: 32] [added: 12] | | | [removed: 114] [added: 52] | | | [removed: 58] [added: 32] | | | [removed: 135] [added: 114] | | | [removed: 62] [added: 58] | |

| Utica | | [removed: 40] [added: —] | | | [removed: 31] [added: —] | | | [removed: 69] [added: 40] | | | [removed: 56] [added: 31] | | | [removed: 34] [added: 69] | | | [removed: 17] [added: 56] | |

[TABLE OF CONTENTS](#sacd31288082644189dc9f32fd0d5ad4e)

[TABLE OF CONTENTS](#sacd31288082644189dc9f32fd0d5ad4e)

| Brazos Valley | | 83 | | | 79 | | | — | | | — | | | — | | | — | |

[TABLE OF CONTENTS](#sacd31288082644189dc9f32fd0d5ad4e)

| | | December 31, 2019 | | | | | | | | | | |

| Proved developed | | 201 | | | 3,377 | | | 82 | | | 846 | |

| Proved undeveloped | | 157 | | | 3,189 | | | 38 | | | 726 | |

| Total proved(a) | | 358 | | | 6,566 | | | 120 | | | 1,572 | |

[TABLE OF CONTENTS](#sacd31288082644189dc9f32fd0d5ad4e)

| Developed | | (167 | ) |

| Purchase of reserves-in-place | | 136 | |

We recorded a downward revision of 128 mmboe from previous estimates due to lateral length adjustments, performance, updates to our five-year development plan and changes in commodity prices.

[TABLE OF CONTENTS](#sacd31288082644189dc9f32fd0d5ad4e)

[TABLE OF CONTENTS](#sacd31288082644189dc9f32fd0d5ad4e)

| Marcellus | | 547 | | | 350 | | | 253 | | | 172 | | | 16 | | | 16 | | | 816 | | | 538 | |

| Haynesville | | 293 | | | 263 | | | 36 | | | 29 | | | 1 | | | 1 | | | 330 | | | 293 | |

| Eagle Ford | | 310 | | | 186 | | | 68 | | | 46 | | | — | | | — | | | 378 | | | 232 | |

| Brazos Valley | | 411 | | | 321 | | | 302 | | | 156 | | | — | | | — | | | 713 | | | 477 | |

| Powder River Basin | | 96 | | | 77 | | | 166 | | | 128 | | | 1 | | | 1 | | | 263 | | | 206 | |

| Mid-Continent | | 900 | | | 582 | | | 211 | | | 138 | | | 17 | | | 16 | | | 1,128 | | | 736 | |

| Other(a) | | 167 | | | 132 | | | 967 | | | 912 | | | 431 | | | 427 | | | 1,565 | | | 1,471 | |

| Total | | 2,724 | | | 1,911 | | | 2,003 | | | 1,581 | | | 466 | | | 461 | | | 5,193 | | | 3,953 | |

| 2022 | | 28 | | | 28 | |

| After 2022 | | 88 | | | 86 | |

| Held-by-production(a) | | 1,742 | | | 1,334 | |

| Total | | 2,003 | | | 1,581 | |

[TABLE OF CONTENTS](#sacd31288082644189dc9f32fd0d5ad4e)

[TABLE OF CONTENTS](#sacd31288082644189dc9f32fd0d5ad4e)

| • | method of well completion and hydraulic fracturing; |

For further discussion, see Item *1A.

Risk Factors - We are subject to extensive governmental regulation, which can change and could adversely impact our business.*

[TABLE OF CONTENTS](#sacd31288082644189dc9f32fd0d5ad4e)

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.*

[TABLE OF CONTENTS](#sacd31288082644189dc9f32fd0d5ad4e)

*Robert D.

*Domenic J.

*Frank J.

*James R.

[TABLE OF CONTENTS](#sacd31288082644189dc9f32fd0d5ad4e)

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 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 and the notes thereto do not include or take into account the closing of the acquisition and its effects.

Our substantial inventory of hydrocarbon resources, including our undeveloped acreage position in each of our key basins, provides a strong foundation to create future value.

Concentrated blocks of undeveloped acreage give us the opportunity to apply what we believe are best in class well spacing analysis, completion techniques and lateral lengths to maximize capital efficiency.

We have greatly improved our capital and operating efficiency metrics over the last several years and today have what we believe is a leading cost structure in each of our major resource plays.

We believe our cost structure provides a significant competitive advantage in the current commodity price environment and it is our strategy to continue to seek capital and operating efficiencies to grow this advantage.

To accomplish these goals, we intend to allocate our capital expenditures to projects we believe offer the highest return

| | | | | | | | | | | | | | | | | | | |

| | | | | | | | | | | | | |

| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |

| | | December 31, 2018 | | | | | | | | | | |

| 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 | |

___________________________________________

| | |

| --- | --- |

| Developed | | (115 | ) |

| Sale of reserves-in-place | | (190 | ) |

We sold 190 mmboe of proved undeveloped reserves primarily in the divestiture of Utica Shale assets.

We recorded a downward revision of 27 mmboe from previous estimates due to ongoing portfolio evaluation including longer lateral and spacing adjustments.

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:

| 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) | | |

[removed: Litigation] [added: *Litigation] and Regulatory [removed: Proceedings][added: Proceedings*]

See [Note [removed: 4](#s481A135CD198534A8F4E1B49A1536C16)] [added: 6](#s9EFCCF5BF88C55D9B5003DAB6C06D6EC)] of the notes to our consolidated financial statements included in Item 8 of [removed: Part II of] this report for information regarding our estimation and provision for potential losses related to litigation and regulatory proceedings.

[added: *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.

[removed: Regarding royalty claims, we] [added: We] and other natural gas producers have been named in various lawsuits alleging [removed: royalty underpayments.][added: 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 [removed: royalties] [added: amounts owed] in connection with the production and sale of natural gas and NGL, or similar theories.

The lawsuits seek compensatory, consequential, treble, and punitive damages, restitution and disgorgement of profits, declaratory and injunctive relief regarding our [removed: royalty] payment practices, pre-and post-judgment interest, and attorney’s fees and costs.

We are currently defending numerous lawsuits seeking damages with respect to underpayment of royalties [added: or other shares of the proceeds of production] in multiple states where we have operated, including the matters set forth below.

[removed: 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.

On December 20, 2017 and August 9, 2018, we reached tentative settlements to resolve substantially all Pennsylvania civil royalty cases for a total of approximately [removed: $35] [added: $36] million.

[removed: Environmental Proceedings][added: *Environmental Proceedings*]

Our subsidiary Chesapeake Appalachia, LLC (CALLC) is engaged in discussions with the EPA, the [removed: U.S. Army Corps of Engineers] [added: USACE] and the Pennsylvania Department of Environmental Protection (PADEP) regarding potential violations of the permitting requirements of the federal [removed: Clean Water Act (CWA),] [added: 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.

We [removed: have begun] [added: are in] discussions with EPA aimed at resolving the allegations.

The lawsuit, which primarily relates to the Marcellus Shale and

[TABLE OF CONTENTS](#sacd31288082644189dc9f32fd0d5ad4e)

We intend to vigorously defend these claims.

We intend to vigorously defend these claims.

[TABLE OF CONTENTS](#sacd31288082644189dc9f32fd0d5ad4e)

Business Operations.

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 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.

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.

[removed: UNITED STATES][added: UNITED STATES]

[removed: SECURITIES] [added: SECURITIES] AND EXCHANGE [removed: COMMISSION][added: COMMISSION]

[removed: Washington,] [added: Washington,] D.C. [removed: 20549][added: 20549]

[removed: FORM 10-K][added: FORM 10-K]

[removed: \[X\] ANNUAL REPORT] [added: ☒ ANNUAL REPORT] PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF [removed: 1934][added: 1934]

For the Fiscal Year Ended December 31, [removed: 2018][added: 2019]

[removed: \[ \] TRANSITION] [added: ☐ TRANSITION] REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF [removed: 1934][added: 1934]

[removed: Commission] [added: Commission] File [removed: No. 1-13726][added: No. 1-13726]

[removed: CHESAPEAKE] [added: CHESAPEAKE] ENERGY [removed: CORPORATION][added: CORPORATION]

| [removed: Oklahoma] [added: Oklahoma] | | [removed: 73-1395733] | [added: 73-1395733 | |]

| (State or other jurisdiction of incorporation or organization) | | [added: |] (I.R.S. Employer Identification No.) | [added: |]

| [removed: 6100] [added: 6100] North Western [removed: Avenue, Oklahoma City, Oklahoma] [added: Avenue,] | [added: Oklahoma City,] | [removed: 73118] [added: Oklahoma] | [added: 73118 | |]

| (Address of principal executive offices) | | [added: |] (Zip Code) | [added: |]

| [removed: (405) 848-8000] | | [added: (405)] | [added: 848-8000 | |]

| (Registrant’s telephone number, including area code) | | | [added: | |]

| [removed: Securities] [added: Securities] Registered Pursuant to Section 12(b) of the [removed: Act:] [added: Act:] | | | [added: | |]

| [removed: Title] [added: Title] of Each [removed: Class] [added: Class] | | [removed: Name] [added: Trading Symbol(s) | | Name] of Each Exchange on Which [removed: Registered] [added: Registered] |

| Common Stock, par value $0.01 | | [added: CHK | |] New York Stock Exchange |

| [removed: Floating Rate] [added: 6.625%] Senior Notes due [removed: 2019] [added: 2020] | | [added: CHK20A | |] New York Stock Exchange |

| [removed: 6.625%] [added: 6.875%] Senior Notes due 2020 | | [added: CHK20 | |] New York Stock Exchange |

| [removed: 6.875%] [added: 6.125%] Senior Notes due [removed: 2020] [added: 2021] | | [added: CHK21 | |] New York Stock Exchange |

| [removed: 6.125%] [added: 5.375%] Senior Notes due 2021 | | [added: CHK21A | |] New York Stock Exchange |

| [removed: 5.375%] [added: 4.875%] Senior Notes due [removed: 2021] [added: 2022] | | [added: CHK22 | |] New York Stock Exchange |

| [removed: 4.875%] [added: 5.75%] Senior Notes due [removed: 2022] [added: 2023] | | [added: CHK23 | |] New York Stock Exchange |

| 4.5% Cumulative Convertible Preferred Stock | | [added: CHK Pr D | |] New York Stock Exchange |

[removed: |] Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. [removed: YES \[X\] NO \[ \] | | | | |]

[removed: |] Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the [added: Securities] Exchange Act. [removed: YES \[ \] NO \[X\] | | | | |]

[removed: |] 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. [removed: YES \[X\] NO \[ \] | | | | |]

[removed: |] 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). [removed: YES \[X\] NO \[ \] | | | | |]

[removed: |] 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. [removed: See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and “emerging growth company” in Rule 12b-2 of the Exchange Act. | | | | |]

[removed: | Large Accelerated Filer \[X\] Accelerated Filer \[ \] Non-accelerated Filer \[ \]] Smaller Reporting Company [removed: \[ \]] [added: ☐] Emerging Growth Company [removed: \[ \] | | | | |][added: ☐]

[removed: |] 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. [removed: \[ \] | | | | |]

[removed: |] Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). [removed: YES \[ \] NO \[X\] | | | | |]

The aggregate market value of our common stock held by non-affiliates on June [removed: 29, 2018,] [added: 28, 2019,] was approximately [removed: $4.7] [added: $2.2] billion.

As of February [removed: 12, 2019,] [added: 19, 2020,] there were [removed: 1,631,724,765] [added: 1,954,583,780] shares of our $0.01 par value common stock outstanding.

[removed: DOCUMENTS] [added: DOCUMENTS] INCORPORATED BY [removed: REFERENCE][added: REFERENCE]

Portions of the proxy statement for the [removed: 2018] [added: 2020] Annual Meeting of Shareholders are incorporated by reference in Part III.

[removed: TABLE] [added: [TABLE] OF [removed: CONTENTS][added: CONTENTS](#sacd31288082644189dc9f32fd0d5ad4e)]

| | [removed: [PART I](#s96285105B93B5BC491D697C0EE69C59E)] [added: [PART I](#s96285105B93B5BC491D697C0EE69C59E)] | | [removed: Page] [added: Page] | |

| [Item [removed: 1.](#sA56F370FD4E852C8B4EC076BC1B1DE94)] [added: 1.](#se71a22679ca0457498e754029b7c1a9c)] | [removed: [Business](#sA56F370FD4E852C8B4EC076BC1B1DE94)] [added: [Business](#se71a22679ca0457498e754029b7c1a9c)] | | [removed: [7](#sA56F370FD4E852C8B4EC076BC1B1DE94)] [added: [8](#se71a22679ca0457498e754029b7c1a9c)] | |

Yes ☒ No ☐

Yes ☐ No ☒

Yes ☒ No ☐

Yes ☒ No ☐

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 ☐

Yes ☐ No ☒

__________________________________________

| | | | | |

| --- | --- | --- | --- | --- |

| | | | | |

| [Item 15.](#s272b62630d904cdc8ab9c94779c4c2ac) | [Exhibits and Financial Statement Schedules](#s272b62630d904cdc8ab9c94779c4c2ac) | | [146](#s272b62630d904cdc8ab9c94779c4c2ac) | |

| | | | | |

| [Signatures](#saed4531f5b4e43a4ba48590c5f47c2e6) | | | [153](#saed4531f5b4e43a4ba48590c5f47c2e6) | |

*Bboe*.

*Bcfe*.

*Btu*.

*Boe*.

*Completion*.

*Dry Well*.

*Mcf*.

*Mmbbl*.

*Mmboe*.

*Mmbtu*.

*NYMEX*.

*Play*.

[TABLE OF CONTENTS](#sacd31288082644189dc9f32fd0d5ad4e)

*Proved Properties*.

*Proved Reserves*.

*Reservoir*.

*Royalty Interest*.

[TABLE OF CONTENTS](#sacd31288082644189dc9f32fd0d5ad4e)

*Seismic*.

*Shale*.

*SEC*.

*Standardized Measure*.

*Undeveloped Acreage*.

*Unproved Properties*.

*Working Interest*.

[TABLE OF CONTENTS](#sacd31288082644189dc9f32fd0d5ad4e)

10-K 1 chk-20181231_10k.htm 10-K

| | | |

| --- | --- | --- |

| 5.75% Senior Notes due 2023 | | New York Stock Exchange |

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

| None | | |

| 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. \[X\] | | | | |

__________________________________________

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

2018 ANNUAL REPORT ON FORM 10-K

| [Item 15.](#s214187F989715776B4DAA88291CB9AAA) | [Exhibits](#s214187F989715776B4DAA88291CB9AAA) | | [127](#s214187F989715776B4DAA88291CB9AAA) | |

| [Signatures](#s84DB3D5E05A55FA7BCE021495D3C29DC) | | | [136](#s84DB3D5E05A55FA7BCE021495D3C29DC) | |

Bbl.

Bboe.

Bcf.

Bcfe.

Btu.

Boe.

Completion.

Developed Acreage.

Dry Well.

Exploratory Well.

Formation.

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.

Mboe.

Mcf.

Mmbbl.

Mmboe.

Mmbtu.

Mmcf.

Natural Gas Liquids (NGL).

NYMEX.

Play.

Price Differential.

Productive Well.

Information regarding our properties is included in Item 1 and in the Supplementary Information included in Item 8 of [removed: Part II of] this report.

[removed: PART II][added: PART II]

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 Annual Report on Form 10-K.

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

Common Stock

Our common stock trades on the NYSE under the symbol "CHK".

Shareholders

As of February 19, 2020, there were approximately 1,940 holders of record of our common stock and approximately 308,000 beneficial owners.

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.

Unregistered Sales of Equity Securities and Use of Proceeds

The following table presents information about repurchases of our common stock during the quarter ended December 31, 2019:

| | | | | | | | | | | | | | | |

| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |

| | | | | | | | | | | | | | | |

| 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 | | |

| | | | | | | | | | | | | ($ in millions) | | |

| October 1, 2019 through October 31, 2019 | | 44,323 | | | $ | 1.44 | | | — | | | $ | — | |

| November 1, 2019 through November 30, 2019 | | — | | | $ | — | | | — | | | $ | — | |

| December 1, 2019 through December 31, 2019 | | — | | | $ | — | | | — | | | $ | — | |

| Total | | 44,323 | | | $ | — | | | — | | | | | |

___________________________________________

| | |

| --- | --- |

| (a) | Includes shares of common stock purchased on behalf of our deferred compensation plan. |

[TABLE OF CONTENTS](#sacd31288082644189dc9f32fd0d5ad4e)

| | |

| --- | --- |

Not applicable.

The following table sets forth selected consolidated financial data of Chesapeake as of and for the years ended December 31, [added: 2019,] 2018, 2017, [removed: 2016, 2015] [added: 2016] and [removed: 2014.][added: 2015.]

The table below should be read in conjunction with [removed: Management's] [added: *Management's] Discussion and Analysis of Financial Condition and Results of [removed: Operations] [added: Operations*] and our consolidated financial statements, including the notes thereto, appearing in Items 7 and 8, respectively, of this report.

| | | [removed: Years] [added: Years] Ended December [removed: 31,] [added: 31,] | | | | | | | | | | | | | | | | | | |

| | | [removed: 2018] [added: 2019] | | | | [removed: 2017] [added: 2018] | | | | [removed: 2016] [added: 2017] | | | | [removed: 2015] [added: 2016] | | | | [removed: 2014] [added: 2015] | | |

| | | [removed: ($] [added: ($] in millions, except per share [removed: data)] [added: data)] | | | | | | | | | | | | | | | | | | |

| [removed: STATEMENT] [added: STATEMENT] OF OPERATIONS [removed: DATA:] [added: DATA:] | | | | | | | | | | | | | | | | | | | | |

| [removed: EARNINGS] [added: EARNINGS] (LOSS) PER COMMON [removed: SHARE:] [added: SHARE:] | | | | | | | | | | | | | | | | | | | | |

| [removed: CASH] [added: CASH] DIVIDEND DECLARED PER COMMON [removed: SHARE] [added: SHARE] | | $ | — | | | $ | — | | | $ | — | | | $ | [removed: 0.0875] [added: —] | | | $ | [removed: 0.35] [added: 0.0875] | |

| [removed: BALANCE] [added: BALANCE] SHEET DATA (AT END OF [removed: PERIOD):] [added: PERIOD):] | | | | | | | | | | | | | | | | | | | | |

| Long-term debt, net of current maturities | | $ | [removed: 7,341] [added: 9,073] | | | $ | [removed: 9,921] [added: 7,341] | | | $ | [removed: 9,938] [added: 9,921] | | | $ | [removed: 10,311] [added: 9,938] | | | $ | [removed: 11,058] [added: 10,311] | |

Financial information for prior periods has been recast to reflect retrospective application of the successful efforts method of accounting.

See [Notes 1](#sC7C4FA668F9552D5B9ABF0E64A4C7A72) and [2](#s5CE524823841503782AD9252035013B5) of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of the change in accounting principle.

| Total revenues | | $ | 8,595 | | | $ | 10,030 | | | $ | 10,039 | | | $ | 8,705 | | | $ | 13,794 | |

| Net income (loss) available to common stockholders(a) | | $ | (416 | ) | | $ | 133 | | | $ | (631 | ) | | $ | (4,018 | ) | | $ | (11,383 | ) |

| Basic | | $ | (0.25 | ) | | $ | 0.15 | | | $ | (0.70 | ) | | $ | (5.26 | ) | | $ | (17.18 | ) |

| Diluted | | $ | (0.25 | ) | | $ | 0.15 | | | $ | (0.70 | ) | | $ | (5.26 | ) | | $ | (17.18 | ) |

| Total assets | | $ | 16,193 | | | $ | 12,735 | | | $ | 14,925 | | | $ | 17,048 | | | $ | 21,432 | |

| Total equity | | $ | 4,401 | | | $ | 2,133 | | | $ | 1,943 | | | $ | 2,565 | | | $ | 5,256 | |

| (a) | Includes $11 million, $131 million, $814 million, $563 million and $11.590 billion of impairments of oil and gas properties and other fixed assets for the years ended December 31, 2019, 2018, 2017, 2016 and 2015, respectively. |

[TABLE OF CONTENTS](#sacd31288082644189dc9f32fd0d5ad4e)

The data are derived from our audited consolidated financial statements.

| 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 | |

| Basic | | $ | 0.85 | | | $ | 0.90 | | | $ | (6.43 | ) | | $ | (22.26 | ) | | $ | 1.93 | |

| Diluted | | $ | 0.85 | | | $ | 0.90 | | | $ | (6.43 | ) | | $ | (22.26 | ) | | $ | 1.87 | |

| Total assets | | $ | 10,947 | | | $ | 12,425 | | | $ | 13,028 | | | $ | 17,314 | | | $ | 40,655 | |

| Total equity (deficit) | | $ | 467 | | | $ | (372 | ) | | $ | (1,203 | ) | | $ | 2,397 | | | $ | 18,205 | |

| (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. |

| | [removed: INDEX] [added: INDEX] TO FINANCIAL [removed: STATEMENTS CHESAPEAKE] [added: STATEMENTS CHESAPEAKE] ENERGY [removed: CORPORATION] [added: CORPORATION] | | | |

| | | | [removed: Page] [added: Page] | |

[removed: | [Management’s Report on Internal Control Over Financial Reporting](#sA8A4CB28D99857E791D3638A2DDD310F) | | | [62](#sA8A4CB28D99857E791D3638A2DDD310F) | |][added: MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING]

[removed: | [Report] [added: Report] of Independent Registered Public Accounting [removed: Firm](#s39D010217F655504AD7FE60A6741B305) | | | [63](#s39D010217F655504AD7FE60A6741B305) | |][added: Firm]

| | [Consolidated Balance [removed: Sheets](#s846D3A4913385F50BDE99FC41249AE16)] [added: Sheets](#s438A5A5B760C5752BA38B754B358846B)] as of December 31, [removed: 2018] [added: 2019] and [removed: 2017] [added: 2018] | | [removed: [65](#s846D3A4913385F50BDE99FC41249AE16)] [added: [67](#s438A5A5B760C5752BA38B754B358846B)] | |

| | [Consolidated Statements of [removed: Operations](#s6AB21BFABD7757CBA0AE98FE11C7705D)] [added: Operations](#s07F862AC712D5968BEC58B8C638D0E3F)] for the Years Ended December 31, [removed: 2018, 2017] [added: 2019, 2018] and [removed: 2016] [added: 2017] | | [removed: [67](#s6AB21BFABD7757CBA0AE98FE11C7705D)] [added: [69](#s07F862AC712D5968BEC58B8C638D0E3F)] | |

| | [Consolidated Statements of Comprehensive Income [removed: (Loss)](#s2AC870F4806858A3B0D72B888DFA28A7)] [added: (Loss)](#s351F3AFF2A6F587D8BEA52DF21113083)] for the Years Ended December 31, [removed: 2018, 2017] [added: 2019, 2018] and [removed: 2016] [added: 2017] | | [removed: [68](#s2AC870F4806858A3B0D72B888DFA28A7)] [added: [70](#s351F3AFF2A6F587D8BEA52DF21113083)] | |

| | [Consolidated Statements of Cash [removed: Flows](#sC88E2386F69A55A4B182F451AD79C739)] [added: Flows](#sFA503CCFA84F596D88286F2F1E681B57)] for the Years Ended December 31, [removed: 2018, 2017] [added: 2019, 2018] and [removed: 2016] [added: 2017] | | [removed: [69](#sC88E2386F69A55A4B182F451AD79C739)] [added: [71](#sFA503CCFA84F596D88286F2F1E681B57)] | |

| | [Consolidated Statements of Stockholders’ [removed: Equity](#sF45D022C3851566FB7236BB1354C3D1E)] [added: Equity](#sACFD04A538A550F0A24BB68BCD44FC15)] for the Years Ended December 31, [removed: 2018, 2017] [added: 2019, 2018] and [removed: 2016] [added: 2017] | | [removed: [71](#sF45D022C3851566FB7236BB1354C3D1E)] [added: [73](#sACFD04A538A550F0A24BB68BCD44FC15)] | |

| | [Note 1. Basis of Presentation and Summary of Significant Accounting [removed: Policies](#s62FC13408F5959989C0F326D8B62DA87)] [added: Policies](#sC7C4FA668F9552D5B9ABF0E64A4C7A72)] | | [removed: [73](#s62FC13408F5959989C0F326D8B62DA87)] [added: [75](#sC7C4FA668F9552D5B9ABF0E64A4C7A72)] | |

| | [Note [removed: 2.] [added: 4.] Earnings per [removed: Share](#sC236B287E9485EFD88C4AD1F1E22282D)] [added: Share](#s4D92F1335D2E5ED38821491F256C8C05)] | | [removed: [78](#sC236B287E9485EFD88C4AD1F1E22282D)] [added: [94](#s4D92F1335D2E5ED38821491F256C8C05)] | |

| | [Note [removed: 3. Debt](#sC20F8462A7E65B2593065C408D3503D2)] [added: 5. Debt](#s5D137AEEA9A851B8B3C3DB703BCD831D)] | | [removed: [79](#sC20F8462A7E65B2593065C408D3503D2)] [added: [95](#s5D137AEEA9A851B8B3C3DB703BCD831D)] | |

| [added: CONTINGENCIES AND COMMITMENTS ([Note 6](#s9EFCCF5BF88C55D9B5003DAB6C06D6EC))] | [removed: [Note 4. Contingencies and Commitments](#s481A135CD198534A8F4E1B49A1536C16)] | | [removed: [83](#s481A135CD198534A8F4E1B49A1536C16)] | | [added: | | | |]

| | [Note [removed: 5.] [added: 7.] Other [removed: Liabilities](#s54053950971D5628BE7FE28C260CCB9A)] [added: Liabilities](#s3719DECD192C5C92A8DD5297F971C3BD)] | | [removed: [85](#s54053950971D5628BE7FE28C260CCB9A)] [added: [103](#s3719DECD192C5C92A8DD5297F971C3BD)] | |

| | [Note [removed: 7.] [added: 9.] Revenue [removed: Recognition](#s47584fc5b90d4d8397e59bfbcca9d373)] [added: Recognition](#s1B97998F662858408C4A150EBAE8C1AF)] | | [removed: [86](#s47584fc5b90d4d8397e59bfbcca9d373)] [added: [106](#s1B97998F662858408C4A150EBAE8C1AF)] | |

| | [Note [removed: 8.] [added: 10.] Income [removed: Taxes](#s12B473DA5C695A9FB0EC9FEEE884776E)] [added: Taxes](#s28236513BF6756ADB6839DA93E4629FF)] | | [removed: [87](#s12B473DA5C695A9FB0EC9FEEE884776E)] [added: [108](#s28236513BF6756ADB6839DA93E4629FF)] | |

| | [Note [removed: 9.] [added: 24.] Related Party [removed: Transactions](#sBEB8BCC07E41583ABD9D8FB7072426B6)] [added: Transactions](#sECFA9F80747355D4BEAF2D97617B9624)] | | [removed: [91](#sBEB8BCC07E41583ABD9D8FB7072426B6)] [added: [128](#sECFA9F80747355D4BEAF2D97617B9624)] | |

[removed: | | [Note 11. Share-Based Compensation](#sF60FBFFAB87A5E4083AB300C7ECD9E15) | | [94](#sF60FBFFAB87A5E4083AB300C7ECD9E15) | |][added: *Share-Based Compensation*]

[removed: | | [Note 12.] Employee Benefit [removed: Plans](#s48A8CBD83AFC5184B3E711DEFC93E2D4) | | [98](#s48A8CBD83AFC5184B3E711DEFC93E2D4) | |][added: Plans]

| | [Note [removed: 13.] [added: 14.] Derivative and Hedging [removed: Activities](#s7B9DB25C2E9655D29E4197494F88AB7D)] [added: Activities](#sF6FF4D83C9BA56118FB13A517F864CAC)] | | [removed: [99](#s7B9DB25C2E9655D29E4197494F88AB7D)] [added: [119](#sF6FF4D83C9BA56118FB13A517F864CAC)] | |

| | [Note [removed: 14.] [added: 3.] Oil and Natural Gas Property [removed: Transactions](#s609B44C8E99650F79B2851FA9053539B)] [added: Transactions](#s6C24CA5E58825CA3A04F97A858628395)] | | [removed: [105](#s609B44C8E99650F79B2851FA9053539B)] [added: [91](#s6C24CA5E58825CA3A04F97A858628395)] | |

[removed: | | [Note 15. Other] [added: *Other] Property and [removed: Equipment](#sD75713C8B304569088653F83C89F0BFB) | | [107](#sD75713C8B304569088653F83C89F0BFB) | |][added: Equipment*]

| [removed: | [Note 18.] Other [removed: Operating Expenses](#s8ce4aded4a144d59b993cccfd13636e7)] [added: operating expenses] | | [removed: [108](#s8ce4aded4a144d59b993cccfd13636e7)] [added: $] | [added: 10] | [added: | | $ | (10 | ) | | $ | — | |]

| [removed: | [Note 19.] Restructuring and [removed: Other Termination Costs](#s69E95AB8BA865E9BBFDD63AA3055640A)] [added: other termination costs] | | [removed: [109](#s69E95AB8BA865E9BBFDD63AA3055640A)] [added: 12] | | [added: | | 38 | | | | — | | |]

[removed: | | [Note 20. Fair] [added: *Fair] Value [removed: Measurements](#s90B74F715D00593192F54AFC472B6AB1) | | [109](#s90B74F715D00593192F54AFC472B6AB1) | |][added: Measurements*]

[removed: | | [Note 21. Asset] [added: *Asset] Retirement [removed: Obligations](#s0337A1BE34BB5DB5BBDBCD881F13B427) | | [110](#s0337A1BE34BB5DB5BBDBCD881F13B427) | |][added: Obligations*]

| | [Note [removed: 23.] [added: 25.] Condensed Consolidating Financial [removed: Information](#s59A0A4F938775085A5026289174C93C9)] [added: Information](#s0BB0F8E62C9253A5B9D55272DB7D4B50)] | | [removed: [110](#s59A0A4F938775085A5026289174C93C9)] [added: [128](#s0BB0F8E62C9253A5B9D55272DB7D4B50)] | |

[removed: | | [Quarterly] [added: Quarterly] Financial Data [removed: (unaudited)](#sCCEF024A8D6651F983E9CE1474CC5611) | | [118](#sCCEF024A8D6651F983E9CE1474CC5611) | |][added: (unaudited)]

[removed: | | [Supplemental] [added: Supplemental] Disclosures About Oil, Natural Gas and NGL Producing [removed: Activities](#s035ED2A15E14543683786811B8198EDB) (unaudited) | | [119](#s035ED2A15E14543683786811B8198EDB) | |][added: Activities (unaudited)]

[removed: MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING][added: | [Management’s Report on Internal Control Over Financial Reporting](#sab43129e66344a5a879da4bd367b2c93) | | | [62](#sab43129e66344a5a879da4bd367b2c93) | |]

Management utilized the Committee of Sponsoring Organizations of the Treadway Commission's [removed: Internal] [added: *Internal] Control-Integrated [removed: Framework] [added: 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, [removed: 2018.][added: 2019.]

The effectiveness of the Company's internal control over financial reporting, as of December 31, [removed: 2018,] [added: 2019,] has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report, which appears herein.

[removed: Report] [added: | [Report] of Independent Registered Public Accounting [removed: Firm][added: Firm](#sC9F78F185827547AB882D35521EF3A26) | | | [63](#sC9F78F185827547AB882D35521EF3A26) | |]

[removed: Opinions] [added: Opinions] on the Financial Statements and Internal Control over Financial [removed: Reporting][added: Reporting]

We have audited the accompanying consolidated balance sheets of Chesapeake Energy Corporation and its subsidiaries (the “Company”) as of December 31, [removed: 2018] [added: 2019] and [removed: 2017,] [added: 2018,] and the related consolidated statements of operations, [added: of] comprehensive income (loss), [removed: cash flows and] [added: of] stockholders’ equity [added: and of cash flows] for each of the three years in the period ended December 31, [removed: 2018,] [added: 2019,] 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, [removed: 2018,] [added: 2019,] based on criteria established in [removed: Internal] [added: *Internal] Control - Integrated [removed: Framework] [added: 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, [removed: 2018] [added: 2019] and [removed: 2017,] [added: 2018,] and the results of its operations and its cash flows for each of the three years in the period ended December 31, [removed: 2018] [added: 2019] 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, [removed: 2018,] [added: 2019,] based on criteria established in [removed: Internal] [added: *Internal] Control - Integrated [removed: Framework] [added: Framework*] (2013) issued by the COSO.

[removed: Basis] [added: Basis] for [removed: Opinions][added: Opinions]

| | [Note 2. Change in Accounting Principle](#s5CE524823841503782AD9252035013B5) | | [82](#s5CE524823841503782AD9252035013B5) | |

| | [Note 8. Leases](#sB7855621DE1051A397BB2EAC606A767A) | | [104](#sB7855621DE1051A397BB2EAC606A767A) | |

| | [Note 11. Equity](#s38DBCE803446596493C9AD360CD1BCA7) | | [112](#s38DBCE803446596493C9AD360CD1BCA7) | |

| | [Note 12. Share-Based Compensation](#s7C376DDD52025594AF62918778CB4B5D) | | [114](#s7C376DDD52025594AF62918778CB4B5D) | |

| | [Note 15. Fair Value Measurements](#sDB6BA4DE4A33526BB5EAC6E53AC63DBD) | | [125](#sDB6BA4DE4A33526BB5EAC6E53AC63DBD) | |

| | [Note 16. Capitalized Exploratory Well Costs](#sDACD73D148B45457B26875DFD985C3D3) | | [125](#sDACD73D148B45457B26875DFD985C3D3) | |

| | [Note 17. Other Property and Equipment](#s45BDEBB7603F5B20A53EE6286F9F9118) | | [126](#s45BDEBB7603F5B20A53EE6286F9F9118) | |

| | [Note 18. Investments](#s8775182193B8539CA2D110EE4B10877A) | | [126](#s8775182193B8539CA2D110EE4B10877A) | |

| | [Note 19. Impairments](#sC3417EB9010F5476B2714C9342942A5A) | | [127](#sC3417EB9010F5476B2714C9342942A5A) | |

| | [Note 20. Other Operating Expense](#s6EA2FE9466AC5EF29710F61A14F218E4) | | [127](#s6EA2FE9466AC5EF29710F61A14F218E4) | |

| | [Note 21. Restructuring and Other Termination Costs](#sB8B9EF2B68F45C2FBEF6157BC456B599) | | [127](#sB8B9EF2B68F45C2FBEF6157BC456B599) | |

| | [Note 23. Major Customers](#s707C7549E1E7554E8C0493995ADA15C1) | | [128](#s707C7549E1E7554E8C0493995ADA15C1) | |

[TABLE OF CONTENTS](#sacd31288082644189dc9f32fd0d5ad4e)

| | [Note 26. Subsequent Events](#s1DDBFA4FE05F57D3B0843416FB2FBE7F) | | [137](#s1DDBFA4FE05F57D3B0843416FB2FBE7F) | |

[TABLE OF CONTENTS](#sacd31288082644189dc9f32fd0d5ad4e)

[TABLE OF CONTENTS](#sacd31288082644189dc9f32fd0d5ad4e)

*Change in Accounting Principle*

As discussed in Note 2 to the consolidated financial statements, the Company changed the manner in which it accounts for oil and natural gas exploration and development activities from the full cost method to the successful efforts method in 2019.

This matter is also discussed below as a critical audit matter.