Expand Energy 10-K 2018-12-31

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

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the Fiscal Year Ended December 31, 2018

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

For the transition period from to

Commission File No. 1-13726

CHESAPEAKE ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

Oklahoma		73-1395733
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
6100 North Western Avenue, Oklahoma City, Oklahoma		73118
(Address of principal executive offices)		(Zip Code)
(405) 848-8000
(Registrant’s telephone number, including area code)

Securities Registered Pursuant to Section 12(b) of the Act:
Title of Each Class		Name of Each Exchange on Which Registered
Common Stock, par value $0.01		New York Stock Exchange
Floating Rate Senior Notes due 2019		New York Stock Exchange
6.625% Senior Notes due 2020		New York Stock Exchange
6.875% Senior Notes due 2020		New York Stock Exchange
6.125% Senior Notes due 2021		New York Stock Exchange
5.375% Senior Notes due 2021		New York Stock Exchange
4.875% Senior Notes due 2022		New York Stock Exchange
5.75% Senior Notes due 2023		New York Stock Exchange
4.5% Cumulative Convertible Preferred Stock		New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES [X] NO [ ]
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. YES [ ] NO [X]
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES [X] NO [ ]
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). YES [X] NO [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer [X] Accelerated Filer [ ] Non-accelerated Filer [ ] Smaller Reporting Company [ ] Emerging Growth Company [ ]
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES [ ] NO [X]

The aggregate market value of our common stock held by non-affiliates on June 29, 2018, was approximately $4.7 billion. As of February 12, 2019, there were 1,631,724,765 shares of our $0.01 par value common stock outstanding.

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DOCUMENTS INCORPORATED BY REFERENCE

Portions of the proxy statement for the 2018 Annual Meeting of Shareholders are incorporated by reference in Part III.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

2018 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

	PART I		Page
Item 1.	Business		7
Item 1A.	Risk Factors		18
Item 1B.	Unresolved Staff Comments		33
Item 2.	Properties		33
Item 3.	Legal Proceedings		34
Item 4.	Mine Safety Disclosures		35
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		36
Item 6.	Selected Financial Data		37
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		38
	Liquidity and Capital Resources		39
	Results of Operations, for the Years Ended December 31, 2018, 2017 and 2016		47
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		56
Item 8.	Financial Statements and Supplementary Data		60
Item 9.	Changes In and Disagreements With Accountants on Accounting and Financial Disclosure		125
Item 9A.	Controls and Procedures		125
Item 9B.	Other Information		125
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance		126
Item 11.	Executive Compensation		126
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		126
Item 13.	Certain Relationships and Related Transactions and Director Independence		126
Item 14.	Principal Accountant Fees and Services		126
	PART IV
Item 15.	Exhibits		127
Item 16.	Form 10-K Summary		135
Signatures			136

Glossary of Oil and Gas Terms

The terms defined in this section are used throughout this report.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

Bboe. One billion barrels of oil equivalent.

Bcf. One billion cubic feet of natural gas.

Bcfe. One billion cubic feet of natural gas equivalent.

Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Boe. Barrel of oil equivalent. Natural gas proved reserves and production are converted to boe at 14.73 psia and 60 degrees. Boe is based on six mcf of natural gas to one bbl of oil or one bbl of NGL. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Despite holding this ratio constant at six mcf to one bbl, prices have historically often been higher or substantially higher for oil than natural gas on an energy equivalent basis, although there have been periods in which they have been lower or substantially lower.

Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of oil, natural gas or natural gas liquids, or in the case of a dry well, the reporting to the appropriate authority that the well has been abandoned.

Developed Acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.

Dry Well. A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

Exploratory Well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

Formation. A succession of sedimentary beds that were deposited under the same general geologic conditions.

Full Cost. The full cost method of accounting, as governed by SEC Regulation S-X 4-10(c), consists of capitalizing all costs associated with property acquisition, exploration and development activities into a full cost pool. The full cost pool is tested for impairment quarterly using the “ceiling test” described in Regulation S-X 4-10(c). Additionally, any internal costs that can be directly identified with acquisition, exploration and development activities are included. Any costs related to production, general corporate overhead or similar activities are not included.

GAAP. Generally Accepted Accounting Principles in the United States.

Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which a working interest is owned.

Mboe. One thousand barrels of oil equivalent.

Mcf. One thousand cubic feet.

Mmbbl. One million barrels of crude oil or other liquid hydrocarbons.

Mmboe. One million barrels of oil equivalent.

Mmbtu. One million btus.

Mmcf. One million cubic feet.

Natural Gas Liquids (NGL). Hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation, adsorption or other methods in gas processing or cycling plants. Natural gas liquids primarily include ethane, propane, butane, isobutene, pentane, hexane and natural gasoline.

Net Acres or Net Wells. The sum of the fractional working interests owned in gross acres or gross wells.

NYMEX. New York Mercantile Exchange.

Play. A term applied to a portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential oil, natural gas and NGL reserves.

Present Value of Estimated Future Net Revenues or PV-10 (non-GAAP). When used with respect to oil, natural gas and NGL reserves, present value of estimated future net revenues, or PV-10, means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices calculated as the average oil and natural gas price during the preceding 12-month period prior to the end of the current reporting period, (determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period) and costs in effect at the determination date (unless such costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%.

Price Differential. The difference in the price of oil, natural gas or NGL received at the sales point and the NYMEX price.

Productive Well. A well that is not a dry well. Productive wells include producing wells and wells that are mechanically capable of production.

Proved Developed Reserves. Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

Proved Properties. Properties with proved reserves.

Proved Reserves. As used in this report, proved reserves has the meaning given to such term in Rule 4-10(a)(22) of Regulation S-X, which states in part proved oil and natural gas reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

Proved Undeveloped Reserves (PUDs). Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

Realized and Unrealized Gains and Losses on Oil, Natural Gas and NGL Derivatives. Realized gains and losses include the following items:(i) settlements and accruals for settlements of non-designated derivatives related to current period notional production revenues, (ii) prior period settlements for option premiums and for early-terminated derivatives originally scheduled to settle against current period notional production revenues, and (iii) gains and losses related to de-designated cash flow hedges originally designated to settle against current period notional production revenues. Unrealized gains and losses include the change in fair value of open derivatives scheduled to settle against future period notional production revenues (including current period settlements for option premiums and early-terminated derivatives) offset by amounts reclassified as realized gains and losses during the period. Although we no longer designate our derivatives as cash flow hedges for accounting purposes, we believe these definitions are useful to management and investors in determining the effectiveness of our price risk management program.

Realized and Unrealized Gains and Losses on Interest Rate Derivatives. Realized gains and losses include interest rate derivative settlements related to current period interest and the effect of gains and losses on early-terminated trades. Settlements of early-terminated trades are reflected in realized gains and losses over the original life of the hedged item. Unrealized gains and losses include changes in the fair value of open interest rate derivatives offset by amounts reclassified to realized gains and losses during the period.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Royalty Interest. An interest in an oil and natural gas property entitling the owner to a share of oil, natural gas or NGL production free of costs of production.

Seismic. An exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of subsurface rock formations.

Shale. Fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most frequently occurring sedimentary rock.

SEC. The United States Securities and Exchange Commission.

Standardized Measure. The discounted future net cash flows relating to proved reserves based on the means of the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices calculated as the average oil and natural gas price during the preceding 12-month period prior to the end of the current reporting period (determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period). The standardized measure differs from the PV-10 measure only because the former includes the effects of estimated future income tax expenses.

Undeveloped Acreage. Acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and natural gas regardless of whether the acreage contains proved reserves.

Unproved Properties. Properties with no proved reserves.

Volumetric Production Payment (VPP). As we use the term, a volumetric production payment represents a limited-term overriding royalty interest in oil and natural gas reserves that: (i) entitles the purchaser to receive scheduled production volumes over a period of time from specific lease interests; (ii) is free and clear of all associated future production costs and capital expenditures; (iii) is nonrecourse to the seller (i.e., the purchaser's only recourse is to the reserves acquired); (iv) transfers title of the reserves to the purchaser; and (v) allows the seller to retain the remaining reserves, if any, after the scheduled production volumes have been delivered.

WildHorse. WildHorse Resource Development Corporation. Immediately following the completion of our acquisition of WildHorse (the “First Merger”), WildHorse merged with and into Brazos Valley Longhorn, L.L.C., a newly formed Delaware limited liability company and wholly owned subsidiary of Chesapeake, which, together with the First Merger, we refer to as the “WildHorse Merger.” For ease of reference, we use the term “WildHorse” to refer to WildHorse Resource Development Corporation prior to the acquisition and Brazos Valley Longhorn, L.L.C. or “Brazos Valley Longhorn” after the acquisition, as applicable.

Working Interest. The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

Forward-Looking Statements

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). Forward-looking statements include our current expectations or forecasts of future events. In this context, forward-looking statements often address our expected future business and financial performance and financial condition, and often contain words such as "expect," “could,” “may,” "anticipate," "intend," "plan," “ability,” "believe," "seek," "see," "will," "would," “estimate,” “forecast,” "target," “guidance,” “outlook,” “opportunity” or “strategy.”

Although we believe the expectations and forecasts reflected in our forward-looking statements are reasonable, they are inherently subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. No assurance can be given that such forward-looking statements will be correct or achieved or that the assumptions are accurate or will not change over time. Particular uncertainties that could cause our actual results to be materially different than those expressed in our forward-looking statements include:

•	the volatility of oil, natural gas and NGL prices;

•	uncertainties inherent in estimating quantities of oil, natural gas and NGL reserves and projecting future rates of production and the amount and timing of development expenditures;

•	our ability to replace reserves and sustain production;

•	drilling and operating risks and resulting liabilities;

•	our ability to generate profits or achieve targeted results in drilling and well operations;

•	the limitations our level of indebtedness may have on our financial flexibility;

•	our inability to access the capital markets on favorable terms;

•	the availability of cash flows from operations and other funds to finance reserve replacement costs or satisfy our debt obligations;

•	adverse developments or losses from pending or future litigation and regulatory proceedings, including royalty claims;

•	effects of environmental protection laws and regulation on our business;

•	terrorist activities and/or cyber-attacks adversely impacting our operations;

•	effects of acquisitions and dispositions, including our acquisition of WildHorse and our ability to realize related synergies;

•	effects of purchase price adjustments and indemnity obligations; and

•	other factors that are described under Risk Factors in Item 1A of this Form 10-K.

We caution you not to place undue reliance on the forward-looking statements contained in this report, which speak only as of the filing date, and we undertake no obligation to update this information. We urge you to carefully review and consider the disclosures in this report and our other filings with the SEC that attempt to advise interested parties of the risks and factors that may affect our business.

PART I

Unless the context otherwise requires, references to “Chesapeake”, the “Company”, “us”, “we” and “our” in this report are to Chesapeake Energy Corporation together with its subsidiaries. Our principal executive offices are located at 6100 North Western Avenue, Oklahoma City, Oklahoma 73118, and our main telephone number at that location is (405) 848-8000.

Our Business

We are an independent exploration and production company engaged in the acquisition, exploration and development of properties to produce oil, natural gas and NGL from underground reservoirs. We own a large and geographically diverse portfolio of onshore U.S. unconventional liquids and natural gas assets, including interests in approximately 13,200 oil and natural gas wells. We have leading positions in the liquids-rich resource plays of the Eagle Ford Shale in South Texas, the stacked pay in the Powder River Basin in Wyoming and the Anadarko Basin in northwestern Oklahoma. Our natural gas resource plays are the Marcellus Shale in the northern Appalachian Basin in Pennsylvania and the Haynesville/Bossier Shales in northwestern Louisiana.

In October 2018, we sold our interests in the Utica Shale operating area located in Ohio for approximately $1.9 billion to Encino Acquisition Partners (“Encino”), a private oil and gas company headquartered in Houston, Texas. We used the net proceeds to reduce debt.

In February 2019, we acquired WildHorse Resource Development Corporation, an oil and gas company with operations in the Eagle Ford Shale and Austin Chalk formations in southeast Texas, for approximately 717.3 million shares of our common stock and $381 million in cash, and the assumption of WildHorse’s debt of $1.4 billion as of 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 generation, and reducing our net debt to EBITDA ratio. In conjunction with the acquisition under terms of the merger agreement, David W. Hayes, partner for NGP Energy Capital Management, L.L.C. (“NGP”), has joined our board and another designee of NGP is expected to be appointed to fill the next vacancy on our board.

Because the acquisition of WildHorse occurred after December 31, 2018, Chesapeake’s consolidated financial statements and the notes thereto do not include or take into account the closing of the acquisition and its effects.

Information About Us

We make available, free of charge on our website at chk.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. From time to time, we also post announcements, updates, events, investor information and presentations on our website in addition to copies of all recent news releases. Documents and information on our website are not incorporated by reference herein.

The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers, including Chesapeake, that file electronically with the SEC.

Business Strategy

Our strategy is to create shareholder value through the development of our significant resource plays. Our substantial inventory of hydrocarbon resources, including our undeveloped acreage position in each of our key basins, provides a strong foundation to create future value. Concentrated blocks of undeveloped acreage give us the opportunity to apply what we believe are best in class well spacing analysis, completion techniques and lateral lengths to maximize capital efficiency. We have greatly improved our capital and operating efficiency metrics over the last several years and today have what we believe is a leading cost structure in each of our major resource plays. We believe our cost structure provides a significant competitive advantage in the current commodity price environment and it is our strategy to continue to seek capital and operating efficiencies to grow this advantage.

We continue to focus on reducing debt, increasing cash provided by operating activities, improving margins through financial discipline and operating efficiencies and improving environmental and safety performance. To accomplish these goals, we intend to allocate our capital expenditures to projects we believe offer the highest return

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 flow from operations, but also increasing our cash flow from operations generated per barrel of oil equivalent production. We continue to seek opportunities to reduce cash costs (production, gathering, processing and transportation, general and administrative and interest expenses) through operational efficiencies, including 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 cost structure and our continued focus on safety and environmental stewardship will provide opportunities to create value for us and our shareholders.

Operating Areas

We focus our exploration, development, acquisition and production efforts in the six geographic operating areas described below.

Marcellus - Northern Appalachian Basin in Pennsylvania.

Haynesville - Northwestern Louisiana (Gulf Coast).

Eagle Ford - South Texas.

Brazos Valley - Southeast Texas assets acquired in our WildHorse acquisition on February 1, 2019.

Powder River Basin - Stacked pay in Wyoming.

Mid-Continent - Anadarko Basin in northwestern Oklahoma.

Well Data

As of December 31, 2018, we held an interest in approximately 13,200 gross (5,600 net) productive wells, including 10,200 properties in which we held a working interest and 3,000 properties in which we held an overriding or royalty interest. Of the 10,200 properties in which we had a working interest, we operated 7,200 wells, 6,800 gross (3,800 net), of which were classified as productive natural gas wells and 3,400 gross (1,800 net) were classified as productive oil wells. During 2018, we drilled or participated in 351 gross (238 net) wells as operator and participated in another 26 gross (1 net) wells completed by other operators. We operate approximately 97% of our current daily production volumes.

Drilling Activity

The following table sets forth the wells we drilled or participated in during the periods indicated. In the table, "gross" refers to the total wells in which we had a working interest and "net" refers to gross wells multiplied by our working interest:

		2018												2017												2016
		Gross			%			Net			%			Gross			%			Net			%			Gross			%			Net			%
Development:
Productive		363			99			227			99			462			99			292			99			431			99			236			99
Dry		2			1			1			1			4			1			2			1			1			1			1			1
Total		365			100			228			100			466			100			294			100			432			100			237			100
Exploratory:
Productive		10			83			9			82			2			100			2			100			3			100			2			100
Dry		2			17			2			18			—			—			—			—			—			—			—			—
Total		12			100			11			100			2			100			2			100			3			100			2			100

The following table shows the wells we drilled or participated in by operating area:

		2018						2017						2016
		Gross Wells			Net Wells			Gross Wells			Net Wells			Gross Wells			Net Wells
Marcellus		52			23			43			21			19			9
Haynesville		30			21			37			34			41			34
Eagle Ford		162			98			180			106			199			116
Powder River Basin		41			34			25			21			1			1
Mid-Continent		52			32			114			58			135			62
Utica		40			31			69			56			34			17
Other		—			—			—			—			6			—
Total		377			239			468			296			435			239

As of December 31, 2018, we had 149 gross (82 net) wells in the process of being drilled or completed.

Production, Sales Prices, Production and Gathering, Processing and Transportation Expenses

The following table sets forth information regarding our net production volumes, average sales price received for our production, average sales price of our production combined with our realized gains or losses on derivatives and production and gathering, processing and transportation expenses per boe for the periods indicated:

		Years Ended December 31,
		2018				2017				2016
Net Production:
Oil (mmbbl)		33				33				33
Natural gas (bcf)		832				878				1,049
NGL (mmbbl)		19				21				24
Oil equivalent (mmboe)		190				200				233
Average Sales Price of Production:
Oil ($ per bbl)		$	67.25			$	51.03			$	40.65
Natural gas ($ per mcf)		$	2.99			$	2.76			$	2.05
NGL ($ per bbl)		$	26.50			$	23.18			$	14.76
Oil equivalent ($ per boe)		$	27.27			$	22.88			$	16.63
Average Sales Price (including realized gains (losses) on derivatives):
Oil ($ per bbl)		$	57.42			$	53.19			$	43.58
Natural gas ($ per mcf)		$	3.00			$	2.75			$	2.20
NGL ($ per bbl)		$	25.84			$	22.98			$	14.43
Oil equivalent ($ per boe)		$	25.56			$	23.17			$	17.66
Expenses ($ per boe):
Oil, natural gas and NGL production		$	2.84			$	2.81			$	3.05
Oil, natural gas and NGL gathering, processing and transportation		$	7.35			$	7.36			$	7.98

Oil, Natural Gas and NGL Reserves

The tables below set forth information as of December 31, 2018, with respect to our estimated proved reserves, the associated estimated future net revenue, the present value of estimated future net revenue (“PV-10”) and the standardized measure of discounted future net cash flows (“standardized measure”). None of the estimated future net revenue, PV-10 nor the standardized measure are intended to represent the current market value of the estimated oil, natural gas and NGL reserves we own. All of our estimated reserves are located within the United States.

		December 31, 2018
		Oil			Natural Gas			NGL			Total
		(mmbbl)			(bcf)			(mmbbl)			(mmboe)
Proved developed		127.6			3,314			67.9			748
Proved undeveloped		87.9			3,463			35.4			700
Total proved(a)		215.5			6,777			103.3			1,448

		Proved Developed				Proved Undeveloped				Total Proved
		($ in millions)
Estimated future net revenue(b)		$	10,214			$	7,120			$	17,334
Present value of estimated future net revenue (PV-10)(b)		$	6,177			$	3,350			$	9,527
Standardized measure(b)										$	9,495

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(a)	Marcellus, Haynesville and Eagle Ford accounted for approximately 40%, 27%, and 22%, respectively, of our estimated proved reserves by volume as of December 31, 2018.

(b)

Estimated future net revenue represents the estimated future revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs under existing economic conditions as of December 31, 2018, and assuming commodity prices as set forth below. For the purpose of determining prices used in our reserve reports, we used the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended December 31, 2018. The prices used in our PV-10 measure were $65.56 of oil and $3.10 of natural gas, before basis differential adjustments. These prices should not be interpreted as a prediction of future prices, nor do they reflect the value of our commodity derivative instruments in place as of December 31, 2018. The amounts shown do not give effect to non-property-related expenses, such as corporate general and administrative expenses and debt service, or to depreciation, depletion and amortization. The present value of estimated future net revenue typically differs from the standardized measure because the former does not include the effects of estimated future income tax expense of $32 million as of December 31, 2018.

Management uses PV-10, which is calculated without deducting estimated future income tax expenses, as a measure of the value of the Company's current proved reserves and to compare relative values among peer companies. We also understand that securities analysts and rating agencies use this measure in similar ways. While estimated future net revenue and the present value thereof are based on prices, costs and discount factors which may be consistent from company to company, the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each individual company. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows or any other measure of a company's financial or operating performance presented in accordance with GAAP.

A reconciliation of the standardized measure of discounted future net cash flows to PV-10 is presented above. Neither PV-10 nor the standardized measure of discounted future net cash flows purport to represent the fair value of our proved oil and gas reserves.

As of December 31, 2018, our proved reserve estimates included 700 mmboe of reserves classified as proved undeveloped, compared to 796 mmboe as of December 31, 2017. Presented below is a summary of changes in our proved undeveloped reserves (PUDs) for 2018:

		Total
		(mmboe)
Proved undeveloped reserves, beginning of period		796
Extensions and discoveries		236
Revisions of previous estimates		(27	)
Developed		(115	)
Sale of reserves-in-place		(190	)
Proved undeveloped reserves, end of period		700

As of December 31, 2018, all PUDs were planned to be developed within five years. In 2018, we invested approximately $807 million to convert 115 mmboe of PUDs to proved developed reserves. In 2019, we estimate that we will invest approximately $1.2 billion for PUD conversion. We added 236 mmboe of proved undeveloped reserves through extensions and discoveries primarily as a result of longer planned lateral lengths and additional allocated capital in our five-year development plan. 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.

The future net revenue attributable to our estimated PUDs was $7.1 billion and the present value was $3.3 billion as of December 31, 2018. These values were calculated assuming that we will expend approximately $3.6 billion to develop these reserves ($1.2 billion in 2019, $984 million in 2020, $901 million in 2021, $337 million in 2022 and $166 million in 2023). The amount and timing of these expenditures will depend on a number of factors, including actual drilling results, service costs, commodity prices and the availability of capital. Our developmental drilling schedules are subject to revision and reprioritization throughout the year resulting from unknowable factors such as unexpected developmental drilling results, title issues and infrastructure availability or constraints.

Of our 748 mmboe of proved developed reserves as of December 31, 2018, approximately 20 mmboe, or 3%, were non-producing.

Our ownership interest used for calculating proved reserves and the associated estimated future net revenue assumes maximum participation by other parties to our farm-out and participation agreements.

Our estimated proved reserves and the standardized measure of discounted future net cash flows of the proved reserves as of December 31, 2018, 2017 and 2016, along with the changes in quantities and standardized measure of the reserves for each of the three years then ended, are shown in Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities included in Item 8 of Part II of this report. No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency other than the SEC.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. The reserve data represents only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of these estimates, and these revisions may be material. Accordingly, reserve estimates often differ from the actual quantities of oil, natural gas and NGL that are ultimately recovered. Furthermore, the estimated future net revenue from proved reserves and the associated present value are based upon certain assumptions, including prices, future production levels and costs that may not prove correct. Future prices and costs may be materially higher or lower than the prices and costs as of the date of any estimate. See Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities included in Item 8 of Part II of this report for further discussion of our reserve quantities.

Reserves Estimation

Our Corporate Reserves Department prepared approximately 20% by volume, and approximately 18% by value, of our estimated proved reserves disclosed in this report. Those estimates were based upon the best available production, engineering and geologic data.

Our Director – Corporate Reserves, is the technical person primarily responsible for overseeing the preparation of our reserve estimates and for coordinating any reserves work conducted by a third-party engineering firm. Her qualifications include the following:

•	Over 15 years of practical experience in the oil and gas industry, with 12 years in reservoir engineering;

•	Bachelor of Science degree in Geology and Environmental Sciences;

•	Master’s Degree in Petroleum and Natural Gas Engineering;

•	Executive MBA; and

•	Member in good standing of the Society of Petroleum Engineers.

We ensure that the key members of our Corporate Reserves Department have appropriate technical qualifications to oversee the preparation of reserves estimates. Each of our Corporate Reserves Engineers has significant engineering experience in reserve estimation. Our engineering technicians have a minimum of a four-year degree in mathematics, economics, finance or other technical/business/science field. We maintain a continuous education program for our engineers and technicians on new technologies and industry advancements as well as refresher training on basic skills and analytical techniques.

We maintain internal controls such as the following to ensure the reliability of reserves estimations:

•	We follow comprehensive SEC-compliant internal policies to estimate and report proved reserves. Reserve estimates are made by experienced reservoir engineers or under their direct supervision. All material changes are reviewed and approved by Corporate Reserves Engineers.

•	The Corporate Reserves Department reviews our proved reserves at the close of each quarter.

•	Each quarter, Reservoir Managers, the Director – Corporate Reserves, the Vice Presidents of our business units, the Vice President of Corporate and Strategic Planning and the Executive Vice President – Exploration and Production review all significant reserves changes and all new proved undeveloped reserves additions.

•	The Corporate Reserves Department reports independently of our operations.

•	The five-year PUD development plan is reviewed and approved annually by the Director – Corporate Reserves and the Vice President of Corporate and Strategic Planning.

We engaged Software Integrated Solutions, Division of Schlumberger Technology Corporation, a third-party engineering firm, to prepare approximately 80% by volume, and approximately 82% by value, of our estimated proved reserves as of December 31, 2018. A copy of the report issued by the engineering firm is filed with this report as Exhibit 99.1. The qualifications of the technical person at the firm primarily responsible for overseeing the preparation of our reserve estimates are set forth below.

•	over 30 years of practical experience in the estimation and evaluation of reserves;

•	registered professional geologist license in the Commonwealth of Pennsylvania;

•	member in good standing of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers; and

•	Bachelor of Science degree in Geological Sciences.

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development

The following table sets forth historical costs incurred in oil and natural gas property acquisition, exploration and development activities during the periods indicated:

		Years Ended December 31,
		2018				2017				2016
		($ in millions)
Acquisition of Properties:
Proved properties		$	80			$	23			$	403
Unproved properties		216				271				403
Exploratory costs		132				21				52
Development costs		2,009				2,146				1,312
Costs incurred(a)		$	2,437			$	2,461			$	2,170

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(a)	Includes capitalized interest and asset retirement obligations as follows:

Capitalized interest		$	162			$	194			$	242
Asset retirement obligations(b)		$	8			$	(34	)		$	(57	)

(b)	Activity in 2017 and 2016 primarily reflects revisions as the result of decreased plugging and abandonment costs in certain of our operating areas.

A summary of our exploration and development, acquisition and divestiture activities in 2018 by operating area is as follows:

		Gross Wells Drilled			Net Wells Drilled			Exploration and Development				Acquisition of Unproved Properties				Acquisition of Proved Properties				Sales of Unproved Properties				Sales of Proved Properties(a)				Total(b)
		($ in millions)
Marcellus		52			23			$	170			$	5			$	1			$	(2	)		$	—			$	174
Haynesville		30			21			346				6				—				(5		)		(8		)		339
Eagle Ford		162			98			696				14				—				(2		)		—				708
Powder River Basin		41			34			395				73				—				(28		)		—				440
Mid-Continent		52			32			201				19				1				(123		)		(262		)		(164		)
Utica		40			31			301				90				77				(325		)		(2,039		)		(1,896		)
Other		—			—			32				9				1				—				(6		)		36
Total		377			239			$	2,141			$	216			$	80			$	(485	)		$	(2,315	)		$	(363	)

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(a)	Includes asset retirement disposal of $28 million related to divestitures.

(b)	Includes capitalized internal costs of $121 million and capitalized interest of $162 million.

Acreage

The following table sets forth our gross and net developed and undeveloped oil and natural gas leasehold and fee mineral acreage as of December 31, 2018. Gross acres are the total number of acres in which we own a working interest. Net acres refer to gross acres multiplied by our fractional working interest. Acreage numbers do not include our unexercised options to acquire additional acreage.

		Developed Leasehold						Undeveloped Leasehold						Fee Minerals						Total
		Gross Acres			Net Acres			Gross Acres			Net Acres			Gross Acres			Net Acres			Gross Acres			Net Acres
		(in thousands)
Marcellus		541			347			265			177			16			16			822			540
Haynesville		302			270			99			67			—			—			401			337
Eagle Ford		308			183			77			52			—			—			385			235
Powder River Basin		73			58			244			189			1			1			318			248
Mid-Continent		926			602			200			132			38			34			1,164			768
Other(a)		184			146			1,066			983			435			431			1,685			1,560
Total		2,334			1,606			1,951			1,600			490			482			4,775			3,688

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(a)	Includes 1.3 million net acres retained in the 2016 fourth quarter divestiture of our Devonian Shale assets, in which we retained all rights below the base of the Kope formation.

Most of our leases have a three- to five-year primary term, and we manage lease expirations to ensure that we do not experience unintended material expirations. Our leasehold management efforts include scheduling our drilling to establish production in paying quantities in order to hold leases by production, timely exercising our contractual rights to pay delay rentals to extend the terms of leases we value, planning noncore divestitures to high-grade our lease inventory and letting some leases expire that are no longer part of our development plans. The following table sets forth the expiration periods of gross and net undeveloped leasehold acres as of December 31, 2018:

		Acres Expiring
		Gross Acres			Net Acres
		(in thousands)
Years Ending December 31:
2019		108			87
2020		49			44
2021		37			27
After 2021		53			51
Held-by-production(a)		1,704			1,391
Total		1,951			1,600

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(a)	Held-by-production acres will remain in force as production continues on the subject leases.

Marketing

The principal function of our marketing operations is to provide oil, natural gas and NGL marketing services, including commodity price structuring, securing and negotiating of gathering, hauling, processing and transportation services, contract administration and nomination services for us and other interest owners in Chesapeake-operated wells. The marketing operations also provide other services for our exploration and production activities, including services to enhance the value of oil and natural gas production by aggregating volumes sold to various intermediary markets, end markets and pipelines. This aggregation allows us to attract larger, more creditworthy customers that in turn assist in maximizing the prices received. In addition, we periodically enter into a variety of oil, natural gas and NGL purchase and sale contracts with third parties for various commercial purposes, including credit risk mitigation and satisfaction of our pipeline delivery commitments.

Generally, our oil production is sold under market-sensitive short-term or spot price contracts. Natural gas and NGL production is sold to purchasers under percentage-of-proceeds contracts, percentage-of-index contracts or spot price contracts. Under the terms of our percentage-of-proceeds contracts, we receive a percentage of the resale price received from the ultimate purchaser. Under our percentage-of-index contracts, the price we receive is tied to published indices.

We have entered into long-term gathering, processing, and transportation contracts with various parties that require us to deliver fixed, determinable quantities of production over specified periods of time. Certain of our contracts require us to make payments for any shortfalls in delivering or transporting minimum volumes under these commitments. See Note 4 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of commitments.

Major Customers

Sales to Valero Energy Corporation constituted approximately 10% of our total revenues (before the effects of hedging) for the year ended December 31, 2018. No other purchasers accounted for more than 10% of our total revenues for 2018. Sales to Royal Dutch Shell PLC constituted approximately 10% of our total revenues (before the effects of hedging) for the year ended December 31, 2017. Sales to BP PLC constituted approximately 10% of our total revenues (before the effects of hedging) for the year ended December 31, 2016.

Competition

We compete with both major integrated and other independent oil and natural gas companies in all aspects of our business to explore, develop and operate our properties and market our production. Some of our competitors may have larger financial and other resources than us. Competitive conditions may be affected by future legislation and regulations as the United States develops new energy and climate-related policies. In addition, some of our competitors may have a competitive advantage when responding to factors that affect demand for oil and natural gas production, such as changing prices, domestic and foreign political conditions, weather conditions, the price and availability of alternative fuels, the proximity and capacity of natural gas pipelines and other transportation facilities and overall economic conditions. We also face indirect competition from alternative energy sources, including wind, solar and electric power. We believe that our technological expertise, combined with our exploration, land, drilling and production capabilities and the experience of our management team, enables us to compete effectively.

Public Policy and Government Regulation

All of our operations are conducted onshore in the United States. Our industry is subject to a wide range of regulations, laws, rules, taxes, fees and other policy implementation actions that have been pervasive and are under constant review for amendment or expansion. Numerous government agencies have issued extensive regulations which are binding on our industry, some of which carry substantial penalties for failure to comply. These laws and regulations increase the cost of doing business and consequently affect profitability. Additionally, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. We actively monitor regulatory developments applicable to our industry in order to anticipate, design and implement required compliance activities and systems. The following are significant areas of government control and regulation affecting our operations.

Regulation – Environment, Health and Safety

Exploration and Production, Environmental, Health and Safety, and Occupational Laws and Regulations

Our operations are subject to federal, tribal, state, and local laws and regulations. These laws and regulations relate to matters that include, but are not limited to, the following:

•	reporting of workplace injuries and illnesses;

•	industrial hygiene monitoring;

•	worker protection and workplace safety;

•	approval or permits to drill and to conduct operations;

•	provision of financial assurances (such as bonds) covering drilling and well operations;

•	calculation and disbursement of royalty payments and production taxes;

•	seismic operations and data;

•	location, drilling, cementing and casing of wells;

•	well design and construction of pad and equipment;

•	construction and operations activities in sensitive areas, such as wetlands, coastal regions or areas that contain endangered or threatened species, their habitats, or sites of cultural significance;

•	method of completing wells;

•	hydraulic fracturing;

•	water withdrawal;

•	well production and operations, including processing and gathering systems;

•	emergency response, contingency plans and spill prevention plans;

•	air emissions and fluid discharges;

•	climate change;

•	use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations;

•	surface usage, maintenance, monitoring and the restoration of properties associated with well pads, pipelines, impoundments and access roads;

•	plugging and abandoning of wells; and

•	transportation of production.

Failure to comply with these laws and regulations can lead to the imposition of remedial liabilities, fines, or criminal penalties or to injunctions limiting our operations in affected areas. Moreover, multiple environmental laws provide for citizen suits which allow environmental organizations to act in the place of the government and sue operators for alleged violations of environmental law. We consider the costs of environmental protection and of safety and health compliance to be necessary, manageable parts of our business. We have been able to plan for and comply with environmental, safety and health laws and regulations without materially altering our operating strategy or incurring significant unreimbursed expenditures. However, based on regulatory trends and increasingly stringent laws, our capital expenditures and operating expenses related to compliance with the protection of the environment, safety and health have increased over the years and may continue to increase. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters. See the Risk Factors described in Item 1A of this report for further discussion of governmental regulation and ongoing regulatory changes, including with respect to environmental matters,

Our operations are also subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in a unit, the rate of production allowable from oil and gas wells, and the unitization or pooling of oil and gas properties. In the United States, some states allow the forced pooling or integration of tracts to facilitate exploration. Other states rely on voluntary pooling of lands and leases which may make it more difficult to develop oil and gas properties. In addition, federal and state conservation laws generally limit the venting or flaring of natural gas, and state conservation laws impose certain requirements regarding the ratable purchase of production. These regulations limit the amounts of oil and gas we can produce from our wells and the number of wells or the locations at which we can drill.

Regulatory proposals in some states and local communities have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. Federal and state agencies have continued to assess the potential impacts of hydraulic fracturing, which could spur further action toward federal, state and/or local legislation and regulation. Further restrictions of hydraulic fracturing could reduce the amount of oil, natural gas and NGL that we are ultimately able to produce in commercial quantities from our properties.

Certain of our U.S. natural gas and oil leases are granted or approved by the federal government and administered by the Bureau of Land Management (BLM) or Bureau of Indian Affairs (BIA) of the Department of the Interior. Such leases require compliance with detailed federal regulations and orders that regulate, among other matters, drilling and operations on lands covered by these leases and calculation and disbursement of royalty payments to the federal government, tribes or tribal members. The federal government has been particularly active in recent years in evaluating and, in some cases, promulgating new rules and regulations regarding competitive lease bidding, venting and flaring, oil and gas measurement and royalty payment obligations for production from federal lands. In addition, permitting activities on federal lands are subject to frequent delays.

Delays in obtaining permits or an inability to obtain new permits or permit renewals could inhibit our ability to execute our drilling and production plans. Failure to comply with applicable regulations or permit requirements could result in revocation of our permits, inability to obtain new permits and the imposition of fines and penalties.

Title to Properties

Our title to properties is subject to royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the oil and natural gas industry, to liens for current taxes not yet due and to other encumbrances. As is customary in the industry in the case of undeveloped properties, only cursory investigation of record title is made at the time of acquisition. Drilling title opinions are usually prepared before commencement of drilling operations. We believe we have satisfactory title to substantially all of our active properties in accordance with standards generally accepted in the oil and natural gas industry. Nevertheless, we are involved in title disputes from time to time that may result in litigation.

Operating Hazards and Insurance

The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, natural gas leaks, ruptures or discharges of toxic gases. If any of these should occur, we could incur legal defense costs and could suffer substantial losses due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations. Our horizontal and deep drilling activities involve greater risk of mechanical problems than vertical and shallow drilling operations.

We maintain a control of well insurance policy with a $50 million single well limit and a $100 million multiple wells limit that insures against certain sudden and accidental risks associated with drilling, completing and operating our wells. This insurance may not be adequate to cover all losses or exposure to liability. We also carry a $250 million comprehensive general liability umbrella insurance policy. In addition, we maintain a $75 million pollution liability insurance policy providing coverage for gradual pollution related risks and in excess of the general liability policy for sudden and accidental pollution risks. We provide workers' compensation insurance coverage to employees in all states in which we operate. While we believe these policies are customary in the industry, they do not provide complete coverage against all operating risks, and policy limits scale to our working interest percentage in certain situations. In addition, our insurance does not cover penalties or fines that may be assessed by a governmental authority. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. Our insurance coverage may not be sufficient to cover every claim made against us or may not be commercially available for purchase in the future.

Facilities

We own an office complex in Oklahoma City and we own or lease various field offices in cities or towns in the areas where we conduct our operations.

Executive Officers

Robert D. Lawler, President, Chief Executive Officer and Director

Robert D. (“Doug”) Lawler, 52, has served as President and Chief Executive Officer since June 2013. Prior to joining Chesapeake, Mr. Lawler served in multiple engineering and leadership positions at Anadarko Petroleum Corporation. His positions at Anadarko included Senior Vice President, International and Deepwater Operations and member of Anadarko’s Executive Committee from July 2012 to May 2013; Vice President, International Operations from December 2011 to July 2012; Vice President, Operations for the Southern and Appalachia Region from March 2009 to July 2012; and Vice President, Corporate Planning from August 2008 to March 2009. Mr. Lawler began his career with Kerr-McGee Corporation in 1988 and joined Anadarko following its acquisition of Kerr-McGee in 2006.

Domenic J. Dell'Osso, Jr., Executive Vice President and Chief Financial Officer

Domenic J. (“Nick”) Dell'Osso, Jr., 42, has served as Executive Vice President and Chief Financial Officer since November 2010. Mr. Dell'Osso served as our Vice President – Finance and Chief Financial Officer of our wholly owned midstream subsidiary, Chesapeake Midstream Development, L.P., from August 2008 to November 2010.

Frank J. Patterson, Executive Vice President – Exploration and Production

Frank J. Patterson, 60, has served as Executive Vice President - Exploration and Production since August 2016. Previously, he served as Executive Vice President – Exploration and Northern Division since April 2016 and as Executive Vice President – Exploration, Technology & Land since May 2015. Before joining Chesapeake, Mr. Patterson served in various roles at Anadarko from 2006 to 2015, most recently as Senior Vice President – International Exploration. Prior to that he was Vice President – Deepwater Exploration at Kerr-McGee and Manager – Geology at Sun E&P/Oryx Energy.

M. Jason Pigott, Executive Vice President – Operations and Technical Services

M. Jason Pigott, 45, has served as Executive Vice President – Operations and Technical Services since August 2016. Previously, he served as Executive Vice President – Operations, Southern Division since January 2015 and Senior Vice President – Operations, Southern Division since August 2013. Before joining Chesapeake, Mr. Pigott served in various positions at Anadarko and focused on all aspects of developing unconventional resources. His positions at Anadarko included General Manager Eagle Ford from June to August 2013; General Manager East Texas and North Louisiana from October 2010 to June 2013; Southern & Appalachia Planning Manager from October 2009 to October 2010; Reservoir Engineering Manager East Texas and North Louisiana from July to October 2009; and Reservoir Engineering Manager Bossier from 2007 to July 2009.

James R. Webb, Executive Vice President – General Counsel and Corporate Secretary

James R. Webb, 51, has served as Executive Vice President – General Counsel and Corporate Secretary since January 2014. Previously, he served as Senior Vice President – Legal and General Counsel since October 2012 and as Corporate Secretary since August 2013. Mr. Webb first joined Chesapeake in May 2012 on a contract basis as Chief Legal Counsel. Prior to joining Chesapeake, Mr. Webb was an attorney with the law firm of McAfee & Taft from 1995 to October 2012.

William M. Buergler – Senior Vice President and Chief Accounting Officer

William Buergler, 46, has served as Senior Vice President and Chief Accounting Officer since August 2017. Previously, he served as Vice President - Tax since July 2014. Before joining Chesapeake, he worked for Ernst & Young LLP, where he served as a Partner since 2009.

Employees

We had approximately 2,350 employees as of December 31, 2018.

There are numerous factors that affect our business and operating results, many of which are beyond our control. The following is a description of significant factors that might cause our future results to differ materially from those currently expected. The risks described below are not the only risks facing our company. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also affect our business operations. If any of these risks actually occur, our business, financial position, operating results, cash flows, reserves and/or our ability to pay our debts and other liabilities could suffer, the trading price and liquidity of our securities could decline and you may lose all or part of your investment in our securities.

Oil, natural gas and NGL prices fluctuate widely, and lower prices for an extended period of time are likely to have a material adverse effect on our business.

Our revenues, operating results, profitability, liquidity and ability to grow depend primarily upon the prices we receive for the oil, natural gas and NGL we sell. We incur substantial expenditures to replace reserves, sustain production and fund our business plans. Low oil, natural gas and NGL prices can negatively affect the amount of cash available for capital expenditures, debt service and debt repayment and our ability to borrow money or raise additional capital and, as a result, could have a material adverse effect on our financial condition, results of operations, cash flows and reserves. In addition, periods of low oil and natural gas prices may result in ceiling test write-downs of our oil and natural gas properties.

Historically, the markets for oil, natural gas and NGL have been volatile, and they are likely to continue to be volatile. For example, during the period from January 1, 2014 to December 31, 2018, NYMEX WTI oil prices ranged from a high of $107.26 per bbl to a low of $26.21 per bbl and NYMEX Henry Hub natural gas prices ranged from a high of $6.15 per MMBtu to a low of $1.64 per MMBtu. As of February 22, 2019, the NYMEX WTI oil price was $57.08 per bbl and the NYMEX Henry Hub natural gas price was $2.72 per MMBtu.

Wide fluctuations in oil, natural gas and NGL prices may result from factors that are beyond our control, including:

•	domestic and worldwide supplies of oil, natural gas and NGL, including U.S. inventories of oil and natural gas reserves;

•	weather conditions;

•	changes in the level of consumer and industrial demand;

•	the price and availability of alternative fuels;

•	technological advances affecting energy consumption;

•	the effectiveness of worldwide conservation measures;

•	the availability, proximity and capacity of pipelines, other transportation facilities and processing facilities;

•	the level and effect of trading in commodity futures markets, including by commodity price speculators and others;

•	U.S. exports of oil, natural gas, liquefied natural gas and NGL;

•	the price and level of foreign imports;

•	the nature and extent of domestic and foreign governmental regulations and taxes;

•	the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

•	political instability or armed conflict in oil and natural gas producing regions;

•	acts of terrorism; and

•	domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil, natural gas and NGL price movements with any certainty. As of February 22, 2019, including January and February derivative contracts that have settled, approximately 63% of our forecasted oil, natural gas and NGL production revenue was hedged, including 56% and 81% of our forecasted 2019 oil and natural gas production (including WildHorse production from February 1, 2019) at average prices of $57.12 per barrel and $2.85 per mcf, respectively. Even with oil, natural gas and NGL derivatives currently in place to mitigate price risks associated with a portion of our 2019 cash flows, we have substantial exposure to oil, natural gas and NGL prices in 2020 and beyond. In addition, a prolonged extension of lower prices could reduce the quantities of reserves that we may economically produce.

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 due.

As of December 31, 2018, we had approximately $8.2 billion in principal amount of debt outstanding (including $381 million of current maturities and $419 million drawn under our senior secured revolving credit facility). As of December 31, 2018, we had approximately $107 million of letters of credit issued and borrowing capacity of approximately $2.5 billion under our $3.0 billion senior secured revolving credit facility (the “Chesapeake revolving credit facility”). In addition, on February 1, 2019, we acquired $1.4 billion principal amount of debt upon the closing of the WildHorse Merger (including $675 million drawn under the WildHorse senior secured revolving credit facility (the “WildHorse revolving credit facility”)). We had approximately $47 million of letters of credit issued and borrowing capacity of approximately $578 million under the $1.3 billion WildHorse revolving credit facility. See Note 3 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our debt obligations, including debt maturities for the next five years and thereafter.

The level of and terms and conditions governing our debt:

•	require us to dedicate a substantial portion of our cash flow from operations to service our existing debt obligations and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate;

•	increase our vulnerability to the cyclical nature of our business, economic downturns or other adverse developments in our business;

•	could limit our ability to access capital markets, refinance our existing indebtedness, raise capital on favorable terms, or obtain additional financing for working capital, capital expenditures, acquisitions, debt service requirements, execution of our business strategy, or for other purposes;

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

•	place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations;

•	place us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size, or those that have less restrictive terms governing their indebtedness, thereby enabling competitors to take advantage of opportunities that our indebtedness may prevent us from pursuing;

•	limit management’s discretion in operating our business; and

•	increase our cost of borrowing.

Any of the above listed factors could have a material adverse effect on our business, fi

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Not applicable.

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

Litigation and Regulatory Proceedings

We are involved in a number of litigation and regulatory proceedings including those described below. Many of these proceedings are in early stages, and many of them seek or may seek damages and penalties, the amount of which is currently indeterminate. See Note 4 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for information regarding our estimation and provision for potential losses related to litigation and regulatory proceedings.

Business Operations. We are involved in various lawsuits and disputes incidental to our business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions.

Regarding royalty claims, we and other natural gas producers have been named in various lawsuits alleging royalty underpayments. The lawsuits against us allege, among other things, that we used below-market prices, made improper deductions, utilized improper measurement techniques, entered into arrangements with affiliates that resulted in underpayment of royalties in connection with the production and sale of natural gas and NGL, or similar theories. These lawsuits include cases filed by individual royalty owners and putative class actions, some of which seek to certify a statewide class. The lawsuits seek compensatory, consequential, treble, and punitive damages, restitution and disgorgement of profits, declaratory and injunctive relief regarding our royalty payment practices, pre-and post-judgment interest, and attorney’s fees and costs. Plaintiffs have varying royalty provisions in their respective leases, oil and gas law varies from state to state, and royalty owners and producers differ in their interpretation of the legal effect of lease provisions governing royalty calculations. We have resolved a number of these claims through negotiated settlements of past and future royalty obligations and have prevailed in various other lawsuits. We are currently defending numerous lawsuits seeking damages with respect to underpayment of royalties in multiple states where we have operated, including the matters set forth below.

On December 9, 2015, the Commonwealth of Pennsylvania, by the Office of Attorney General, filed a lawsuit in the Bradford County Court of Common Pleas related to royalty underpayment and lease acquisition and accounting practices with respect to properties in Pennsylvania. The lawsuit, which primarily relates to the Marcellus Shale and Utica Shale, alleges that we violated the Pennsylvania Unfair Trade Practices and Consumer Protection Law (UTPCPL) by making improper deductions and entering into arrangements with affiliates that resulted in underpayment of royalties. The lawsuit includes other UTPCPL claims and antitrust claims, including that a joint exploration agreement to which we are a party established unlawful market allocation for the acquisition of leases. The lawsuit seeks statutory restitution, civil penalties and costs, as well as a temporary injunction from exploration and drilling activities in Pennsylvania until restitution, penalties and costs have been paid, and a permanent injunction from further violations of the UTPCPL.

Putative statewide class actions in Pennsylvania and Ohio and purported class arbitrations in Pennsylvania have been filed on behalf of royalty owners asserting various claims for damages related to alleged underpayment of royalties as a result of our divestiture of substantially all of our midstream business and most of our gathering assets in 2012 and 2013. These cases include claims for violation of and conspiracy to violate the federal Racketeer Influenced and Corrupt Organizations Act and for an unlawful market allocation agreement for mineral rights, intentional interference with contractual relations, and violations of antitrust laws related to purported markets for gas mineral rights, operating rights and gas gathering sources. These lawsuits seek in aggregate compensatory, consequential, treble, and punitive damages, restitution and disgorgement of profits, declaratory and injunctive relief regarding our royalty payment practices, pre-and post-judgment interest, and attorney’s fees and costs. On December 20, 2017 and August 9, 2018, we reached tentative settlements to resolve substantially all Pennsylvania civil royalty cases for a total of approximately $35 million.

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.

On July 24, 2018, Healthcare of Ontario Pension Plan (HOOPP) filed a demand for arbitration with the American Arbitration Association regarding HOOPP’s purchase of our interest in Chaparral Energy, Inc. stock for $215 million on January 5, 2014. HOOPP claims that we engaged in material misrepresentations and fraud, and that we violated the Exchange Act and Oklahoma Uniform Securities Act. HOOPP seeks either rescission or $215 million in monetary damages, and in either case, interest, attorney’s fees, disgorgement and punitive damages. We intend to vigorously defend these claims.

In February 2019, a putative class action lawsuit in the District Court of Dallas County, Texas was filed against FTS International, Inc. (“FTSI”), certain investment banks, FTSI’s directors including certain of our officers and certain shareholders of FTSI including us. The lawsuit alleges various violations of Sections 11 (with respect to certain of our officers in their capacities as directors of FTSI) and 15 (with respect to such officers and us) of the Securities Act of 1933 in connection with public disclosure made during the initial public offering of FTSI. The suit seeks damages in excess of $1,000,000 and attorneys’ fees and other expenses. We intend to vigorously defend these claims.

Environmental Proceedings

Our subsidiary Chesapeake Appalachia, LLC (CALLC) is engaged in discussions with the EPA, the U.S. Army Corps of Engineers and the Pennsylvania Department of Environmental Protection (PADEP) regarding potential violations of the permitting requirements of the federal Clean Water Act (CWA), the Pennsylvania Clean Streams Law and the Pennsylvania Dam Safety and Encroachments Act in connection with the placement of dredge and fill material during construction of certain sites in Pennsylvania. CALLC identified the potential violations in connection with an internal review of its facilities siting and construction processes and voluntarily reported them to the regulatory agencies. Resolution of the matter may result in monetary sanctions of more than $100,000.

We are also in discussions with PADEP regarding gas migration in the vicinity of certain of our wells in Bradford County, Pennsylvania. We believe we are close to identifying agreed-upon steps to resolve PADEP’s concerns regarding the issue.

On December 27, 2016, we received a Finding of Violation from the EPA alleging violations of the CAA at a number of locations in Ohio. We have exchanged information with the EPA and are engaged in discussions aimed at resolving the allegations. Resolution of the matter may result in monetary sanctions of more than $100,000. We received another Finding of Violation from EPA on December 20, 2018 alleging violations of the CAA and violations of the Ohio State Implementation Plan at a number of our Ohio facilities. We have begun discussions with EPA aimed at resolving the allegations. Resolution of this matter may result in monetary sanctions of more than $100,000.

We are named as a defendant in numerous lawsuits in Oklahoma alleging that we and other companies have engaged in activities that have caused earthquakes. These lawsuits seek compensation for injury to real and personal property, diminution of property value, economic losses due to business interruption, interference with the use and enjoyment of property, annoyance and inconvenience, personal injury and emotional distress. In addition, they seek the reimbursement of insurance premiums and the award of punitive damages, attorneys’ fees, costs, expenses and interest.

Not applicable.

PART II

Common Stock

Our common stock trades on the New York Stock Exchange under the symbol "CHK".

Shareholders

As of February 12, 2019, there were approximately 2,000 holders of record of our common stock and approximately 307,000 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, 2018:

Period		Total Number of Shares Purchased(a)			Average Price Paid Per Share(a)				Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs			Maximum Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs(b)
												($ in millions)
October 1, 2018 through October 31, 2018		10,989			$	4.60			—			$	1,000
November 1, 2018 through November 30, 2018		—			$	—			—			$	1,000
December 1, 2018 through December 31, 2018		—			$	—			—			$	1,000
Total		10,989			$	—			—

---

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

(b)	In December 2014, our Board of Directors authorized the repurchase of up to $1 billion of our common stock from time to time. The repurchase program does not have an expiration date. As of December 31, 2018, there have been no repurchases under the program.

The following table sets forth selected consolidated financial data of Chesapeake as of and for the years ended December 31, 2018, 2017, 2016, 2015 and 2014. The data are derived from our audited consolidated financial statements. The table below should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations and our consolidated financial statements, including the notes thereto, appearing in Items 7 and 8, respectively, of this report.

		Years Ended December 31,
		2018				2017				2016				2015				2014
		($ in millions, except per share data)
STATEMENT OF OPERATIONS DATA:
Total revenues		$	10,231			$	9,496			$	7,872			$	12,764			$	23,125
Net income (loss) available to common stockholders(a)		$	775			$	813			$	(4,915	)		$	(14,738	)		$	1,273
EARNINGS (LOSS) PER COMMON SHARE:
Basic		$	0.85			$	0.90			$	(6.43	)		$	(22.26	)		$	1.93
Diluted		$	0.85			$	0.90			$	(6.43	)		$	(22.26	)		$	1.87
CASH DIVIDEND DECLARED PER COMMON SHARE		$	—			$	—			$	—			$	0.0875			$	0.35
BALANCE SHEET DATA (AT END OF PERIOD):
Total assets		$	10,947			$	12,425			$	13,028			$	17,314			$	40,655
Long-term debt, net of current maturities		$	7,341			$	9,921			$	9,938			$	10,311			$	11,058
Total equity (deficit)		$	467			$	(372	)		$	(1,203	)		$	2,397			$	18,205

---

(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.

Overview

The following discussion and analysis presents management’s perspective of our business, financial condition and overall performance. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future and should be read in conjunction with “Item 8. Financial Statements and Supplementary Data” 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. 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 717.3 million shares of our common stock and $381 million in cash, and the assumption of WildHorse’s debt of $1.4 billion as of February 1, 2019. We 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 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;

•	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.

In 2019, our focus remains concentrated on four strategic priorities:

•	reduce total leverage to achieve long term net debt/EBITDA of 2x;

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

•	improve margins through financial discipline and operating efficiencies; and

•	maintain industry leading environmental and safety performance.

Business and Industry Outlook

Over the past decade, the landscape of energy production has changed dramatically in the United States. Domestic energy production capabilities have increased the nation’s supply of both crude oil and natural gas, primarily driven by advances in technology, horizontal drilling and hydraulic fracture stimulation techniques. 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.

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.

Liquidity and Capital Resources

Liquidity Overview

Our ability to grow, make capital expenditures and service our debt depends primarily upon the prices we receive for the oil, natural gas and NGL we sell. Substantial expenditures are required to replace reserves, sustain production and fund our business plans. Historically, oil and natural gas prices have been volatile, and may be subject to wide fluctuations in the future. A decline in oil, natural gas and NGL prices could negatively affect the amount of cash we generate and have available for capital expenditures and debt service and could have a material impact on our financial position, results of operations, cash flows and on the quantities of reserves that we can economically produce or provide as collateral to our credit facility lenders. Other risks and uncertainties that could affect our liquidity include, but are not limited to, counterparty credit risk for our receivables, access to capital markets, regulatory risks and our ability to meet financial covenants in our financing agreements.

Based on our cash balance, forecasted cash flows from operating activities and availability under our revolving credit facilities, we expect to be able to fund our planned capital expenditures, meet our debt service requirements and fund our other commitments and obligations for the next 12 months.

As of December 31, 2018, we had a cash balance of $4 million compared to $5 million as of December 31, 2017, and a net working capital deficit of $1.230 billion as of December 31, 2018, compared to a net working capital deficit of $831 million as of December 31, 2017. As of December 31, 2018, our working capital deficit includes $381 million of debt due in the next 12 months. Our total principal debt as of December 31, 2018 was $8.168 billion compared to $9.981 billion as of December 31, 2017. As of December 31, 2018, we had $2.474 billion of borrowing capacity available under the Chesapeake revolving credit facility, with outstanding borrowings of $419 million and $107 million utilized for various letters of credit. As of the WildHorse acquisition date of February 1, 2019, we had $578 million of borrowing capacity available under the WildHorse revolving credit facility, with outstanding borrowings of $675 million and $47 million utilized as a letter of credit. See Note 3 of the notes to our consolidated financial statements included in Item 8 of this

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Oil, Natural Gas and NGL Derivatives

Our results of operations and cash flows are impacted by changes in market prices for oil, natural gas and NGL. To mitigate a portion of our exposure to adverse price changes, we have entered into various derivative instruments. Our oil, natural gas and NGL derivative activities, when combined with our sales of oil, natural gas and NGL, allow us to predict with greater certainty the revenue we will receive. We believe our derivative instruments continue to be highly effective in achieving our risk management objectives.

Our general strategy for protecting short-term cash flow and attempting to mitigate exposure to adverse oil, natural gas and NGL price changes is to hedge into strengthening oil, natural gas and NGL futures markets when prices reach levels that management believes are unsustainable for the long term, have material downside risk in the short term or provide reasonable rates of return on our invested capital. Information we consider in forming an opinion about future prices includes general economic conditions, industrial output levels and expectations, producer breakeven cost structures, liquefied natural gas trends, oil and natural gas storage inventory levels, industry decline rates for base production and weather trends. Executive management is involved in all risk management activities and the Board of Directors reviews our derivative program at its quarterly board meetings. We believe we have sufficient internal controls to prevent unauthorized trading.

We use derivative instruments to achieve our risk management objectives, including swaps, collars and options. All of these are described in more detail below. We typically use swaps and collars for a large portion of the oil and natural gas price risk we hedge. We have also sold calls, taking advantage of premiums associated with market price volatility.

We determine the notional volume potentially subject to derivative contracts by reviewing our overall estimated future production levels, which are derived from extensive examination of existing producing reserve estimates and estimates of likely production from new drilling. Production forecasts are updated at least monthly and adjusted if necessary to actual results and activity levels. We do not enter into derivative contracts for volumes in excess of our share of forecasted production, and if production estimates were lowered for future periods and derivative instruments are already executed for some volume above the new production forecasts, the positions would be reversed. The actual fixed price on our derivative instruments is derived from the reference NYMEX price, as reflected in current NYMEX trading. The pricing dates of our derivative contracts follow NYMEX futures. All of our commodity derivative instruments are net settled based on the difference between the fixed price as stated in the contract and the floating-price, resulting in a net amount due to or from the counterparty.

We review our derivative positions continuously and if future market conditions change and prices are at levels we believe could jeopardize the effectiveness of a position, we will mitigate this risk by either negotiating a cash settlement with our counterparty, restructuring the position or entering into a new trade that effectively reverses the current position. The factors we consider in closing or restructuring a position before the settlement date are identical to those we review when deciding to enter into the original derivative position. Gains or losses related to closed positions will be recognized in the month specified in the original contract.

We have determined the fair value of our derivative instruments utilizing established index prices, volatility curves and discount factors. These estimates are compared to counterparty valuations for reasonableness. Derivative transactions are also subject to the risk that counterparties will be unable to meet their obligations. This non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives. Future risk related to counterparties not being able to meet their obligations has been partially mitigated under our commodity hedging arrangements that require counterparties to post collateral if their obligations to us are in excess of defined thresholds. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. See Note 13 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, 2018, our oil, natural gas and NGL derivative instruments consisted of the following types of instruments:

•	Swaps: We receive a fixed price and pay a floating market price to the counterparty for the hedged commodity. In exchange for higher fixed prices on certain of our swap trades, we may sell call options and call swaptions.

•	Options: We sell, and occasionally buy, call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, we pay the counterparty the excess on sold call options, and we receive the excess on bought call options. If the market price settles below the fixed price of the call option, no payment is due from either party.

•	Call Swaptions: We sell call swaptions to counterparties in exchange for a premium that allow the counterparty, on a specific date, to extend an existing fixed-price swap for a certain period of time

•

Collars: These instruments contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the put and the call strike prices, no payments are due from either party. Three-way collars include the sale by us of an additional put option in exchange for a more favorable strike price on the call option. This eliminates the counterparty’s downside exposure below the second put option strike price.

•	Basis Protection Swaps: These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point. We receive the fixed price differential and pay the floating market price differential to the counterparty for the hedged commodity.

As of December 31, 2018, we had the following open oil and natural gas derivative instruments:

					Weighted Average Price																Fair Value
		Volume			Fixed				Call				Put				Differential				Asset (Liability)
		(mmbbl)			($ per bbl)																($ in millions)
Oil:
Swaps:
Short-term		10			$	58.97			$	—			$	—			$	—			$	117
Long-term		2			$	68.14			$	—			$	—			$	—			40
Collars:
Short-term		6			$	—			$	67.75			$	58.00			$	—			68
Long-term		2			$	—			$	83.25			$	65.00			$	—			30
Basis Protection Swaps:
Short-term		7			$	—			$	—			$	—			$	6.01			5
Total Oil																					260
		(bcf)			($ per mcf)
Natural Gas:
Swaps:
Short-term		447			$	2.87			$	—			$	—			$	—			11
Long-term		176			$	2.75			$	—			$	—			$	—			15
Three-Way Collars:
Short-term		88			$	—			$	3.10			$ 2.50/2.80				$	—			1
Collars:
Short-term		55			$	—			$	3.02			$	2.75			$	—			(3		)
Call Options (sold):
Short-term		22			$	—			$	12.00			$	—			$	—			—
Long-term		22			$	—			$	12.00			$	—			$	—			—
Call Swaptions:
Long-term		106			$	2.77			$	—			$	—			$	—			(9		)
Basis Protection Swaps:
Short-term		50			$	—			$	—			$	—			$	(0.56	)		—
Total Natural Gas																					15
Total Commodities																					275
Contingent Consideration:
Utica Divestiture:
Short-term		—			$	—			$	—			$	—			$	—			7
Total Derivative Asset																					$	282

In addition to the open derivative positions disclosed above, as of December 31, 2018, we had $56 million of net derivative losses related to settled contracts for future periods that will be recorded 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
		($ in millions)
Short-term		$	(23	)
Long-term		(33		)
Total		$	(56	)

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.

		December 31, 2018
		($ in millions)
Fair value of contracts outstanding, as of January 1, 2018		$	(35	)
Change in fair value of contracts		644
Contracts realized or otherwise settled		(327		)
Fair value of contracts outstanding, as of December 31, 2018		$	282

Interest Rate Risk

The table below presents principal cash flows and related weighted average interest rates by expected maturity dates, using the earliest demand repurchase date for contingent convertible senior notes.

	Years of Maturity
	2019				2020				2021				2022				2023				Thereafter				Total
	($ in millions)
Liabilities:
Debt – fixed rate	$	1			$	664			$	815			$	451			$	338			$	5,100			$	7,369
Average interest rate	2.25		%		6.71		%		5.88		%		4.88		%		5.75		%		7.18		%		6.79		%
Debt – variable rate	$	380			$	—			$	—			$	—			$	419			$	—			$	799
Average interest rate	5.68		%		—		%		—		%		—		%		3.89		%		—		%		4.74		%

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 facilities and our floating rate senior notes. All of our other indebtedness is fixed rate and, therefore, does not expose us to the risk of fluctuations in earnings or cash flow due to changes in market interest rates. However, changes in interest rates do affect the fair value of our fixed-rate debt.

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

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

	INDEX TO FINANCIAL STATEMENTS CHESAPEAKE ENERGY CORPORATION
			Page
Management’s Report on Internal Control Over Financial Reporting			62
Report of Independent Registered Public Accounting Firm			63
Consolidated Financial Statements:
	Consolidated Balance Sheets as of December 31, 2018 and 2017		65
	Consolidated Statements of Operations for the Years Ended December 31, 2018, 2017 and 2016		67
	Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2018, 2017 and 2016		68
	Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017 and 2016		69
	Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2018, 2017 and 2016		71
Notes to the Consolidated Financial Statements:
	Note 1. Basis of Presentation and Summary of Significant Accounting Policies		73
	Note 2. Earnings per Share		78
	Note 3. Debt		79
	Note 4. Contingencies and Commitments		83
	Note 5. Other Liabilities		85
	Note 6. Capital Lease Obligations		86
	Note 7. Revenue Recognition		86
	Note 8. Income Taxes		87
	Note 9. Related Party Transactions		91
	Note 10. Equity		92
	Note 11. Share-Based Compensation		94
	Note 12. Employee Benefit Plans		98
	Note 13. Derivative and Hedging Activities		99
	Note 14. Oil and Natural Gas Property Transactions		105
	Note 15. Other Property and Equipment		107
	Note 16. Investments		107
	Note 17. Impairments		107
	Note 18. Other Operating Expenses		108
	Note 19. Restructuring and Other Termination Costs		109
	Note 20. Fair Value Measurements		109
	Note 21. Asset Retirement Obligations		110
	Note 22. Major Customers		110
	Note 23. Condensed Consolidating Financial Information		110
	Note 24. Subsequent Events		117

Supplementary Information:
	Quarterly Financial Data (unaudited)		118
	Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities (unaudited)		119

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

It is the responsibility of the management of Chesapeake Energy Corporation to establish and maintain adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). Management utilized the Committee of Sponsoring Organizations of the Treadway Commission's Internal Control-Integrated Framework (2013) in conducting the required assessment of effectiveness of the Company's internal control over financial reporting.

Management has performed an assessment of the effectiveness of the Company's internal control over financial reporting and has determined the Company’s internal control over financial reporting was effective as of December 31, 2018.

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

/s/ ROBERT D. LAWLER
Robert D. Lawler
President and Chief Executive Officer
/s/ DOMENIC J. DELL'OSSO, JR.
Domenic J. Dell'Osso, Jr.
Executive Vice President and Chief Financial Officer
February 27, 2019

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Chesapeake Energy Corporation

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of Chesapeake Energy Corporation and its subsidiaries (the “Company”) as of December 31, 2018 and 2017, and the related consolidated statements of operations, comprehensive income (loss), cash flows and stockholders’ equity for each of the three years in the period ended December 31, 2018, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018,

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Not applicable.

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures designed to ensure that information required to be disclosed in reports we file or submit under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that such information is accumulated and communicated to management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure.

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(b). Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded as of December 31, 2018 that our disclosure controls and procedures were effective.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

Management’s Report on Internal Control Over Financial Reporting is set forth in Item 8 of this Annual Report on Form 10-K.

Not applicable.

PART III

The names of executive officers and certain other senior officers of the Company and their ages, titles and biographies as of the date hereof are incorporated by reference from Item 1 of Part I of this report. The other information called for by this Item 10 is incorporated herein by reference to the definitive proxy statement to be filed by Chesapeake pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 2019 (the 2019 Proxy Statement).

The information called for by this Item 11 is incorporated herein by reference to the 2019 Proxy Statement.

The information called for by this Item 12 is incorporated herein by reference to the 2019 Proxy Statement.

The information called for by this Item 13 is incorporated herein by reference to the 2019 Proxy Statement.

The information called for by this Item 14 is incorporated herein by reference to the 2019 Proxy Statement.

PART IV

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(a)	The following financial statements, financial statement schedules and exhibits are filed as a part of this report:

1.	Financial Statements. Chesapeake's consolidated financial statements are included in Item 8 of Part II of this report. Reference is made to the accompanying Index to Financial Statements.

2.	Financial Statement Schedules. No financial statement schedules are applicable or required.

3.	Exhibits. The exhibits listed below in the Index of Exhibits are filed, furnished or incorporated by reference pursuant to the requirements of Item 601 of Regulation S-K.

INDEX OF EXHIBITS

				Incorporated by Reference
Exhibit Number		Exhibit Description		Form		SEC File Number		Exhibit		Filing Date		Filed or Furnished Herewith
2.1		Purchase and Sale Agreement by and among certain subsidiaries of Chesapeake Energy Corporation and EAP Ohio, LLC dated July 26, 2018.		10-Q		001-13726		2.1		10/30/2018
2.2.1*		Agreement and Plan of Merger by and among Chesapeake Energy Corporation, Coleburn Inc. and WildHorse Resource Development Corporation, dated as of October 29, 2018, as amended.		8-K		001-13726		2.1		10/30/2018
2.2.2		Amendment No. 1 to Agreement and Plan of Merger, dated as of December 12, 2018, by and among Chesapeake Energy Corporation, Coleburn Inc. and WildHorse Resource Development Corporation.		S-4/A		333-228679		Annex A		12/19/2018
3.1.1		Chesapeake Energy Corporation Restated Certificate of Incorporation.										X
3.1.2		Certificate of Designation of 5% Cumulative Convertible Preferred Stock (Series 2005B), as amended.		10-Q		001-13726		3.1.4		11/10/2008
3.1.3		Certificate of Designation of 4.5% Cumulative Convertible Preferred Stock, as amended.		10-Q		001-13726		3.1.6		8/11/2008
3.1.4		Certificate of Designation of 5.75% Cumulative Non-Voting Convertible Preferred Stock (Series A).		8-K		001-13726		3.2		5/20/2010
3.1.5		Certificate of Designation of 5.75% Cumulative Non-Voting Convertible Preferred Stock, as amended.		10-Q		001-13726		3.1.5		8/9/2010
3.2		Chesapeake Energy Corporation Amended and Restated Bylaws.		8-K		001-13726		3.2		6/19/2014
4.1**		Indenture dated as of November 8, 2005 among Chesapeake Energy Corporation, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York Mellon Trust Company, N.A., as Trustee, with respect to 6.875% Senior Notes due 2020.		8-K		001-13726		4.1.1		11/15/2005

4.2.1**		Indenture dated as of August 2, 2010 among Chesapeake Energy Corporation, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors, and the Bank of New York Mellon Trust Company, N.A., as Trustee.		S-3		333-168509		4.1		8/3/2010
4.2.2		Second Supplemental Indenture, dated as of August 17, 2010 to Indenture dated as of August 2, 2010 with respect to 6.625% Senior Notes due 2020.		8-A		001-13726		4.3		9/24/2010
4.2.3		Fifth Supplemental Indenture dated February 11, 2011 to Indenture dated as of August 2, 2010 with respect to 6.125% Senior Notes due 2021.		8-A		001-13726		4.2		2/22/2011
4.2.4		Fourteenth Supplemental Indenture dated March 18, 2013 among Chesapeake Energy Corporation, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors, and Deutsche Bank Trust Company Americas, as Trustee, to Indenture dated as of August 2, 2010.		S-3		333-168509		4.17		3/18/2013
4.2.5		Sixteenth Supplemental Indenture dated April 1, 2013 to Indenture dated as of August 2, 2010 with respect to 5.375% Senior Notes due 2021.		8-A		001-13726		4.3		4/8/2013
4.2.6		Seventeenth Supplemental Indenture dated April 1, 2013 to Indenture dated as of August 2, 2010 with respect to 5.75% Senior Notes due 2023.		8-A		001-13726		4.4		4/8/2013
4.3.1**		Indenture dated as of April 24, 2014 by and among Chesapeake Energy Corporation, as Issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors, and Deutsche Bank Trust Company Americas, as Trustee.		8-K		001-13726		4.1		4/29/2014
4.3.2		First Supplemental Indenture dated as of April 24, 2014 to Indenture dated as of April 24, 2014 with respect to Floating Rate Senior Notes due 2019.		8-K		001-13726		4.2		4/29/2014
4.3.3		Second Supplemental Indenture dated as of April 24, 2014 to Indenture dated as of April 24 2014 with respect to 4.875% Senior Notes due 2022.		8-K		001-13726		4.3		4/29/2014
4.4.1		Credit Agreement dated December 15, 2014 by and among: Chesapeake Energy Corporation, as borrower; MUFG Union Bank N.A., as administrative agent, co-syndication agent, a swingline lender and a letter of credit issuer; Wells Fargo Bank and National Association, as co-syndication agent, a swingline lender and a letter of credit issuer; Bank of America, N.A., Crédit Agricole Corporate and Investment Bank and JPMorgan Chase Bank, N.A., as co-documentation agents and letter of credit issuers; and certain other lenders named therein.		10-Q		001-13726		4.1		8/14/2016

4.4.2		First Amendment to Credit Agreement dated September 30, 2015 among Chesapeake, as borrower, MUFG Union Bank N.A., as administrative agent, co-syndication agent, a swingline lender and a letter of credit issuer; Wells Fargo Bank, National Association, as co-syndication agent, a swingline lender and a letter of credit issuer; and certain other lenders named therein.		10-Q		001-13726		4.1		11/4/2015
4.4.3		Second Amendment to Credit Agreement dated December 15, 2015 among Chesapeake, as borrower, MUFG Union Bank N.A., as administrative agent, co-syndication agent, a swingline lender and a letter of credit issuer; Wells Fargo Bank, National Association, as co-syndication agent, a swingline lender and a letter of credit issuer; and certain other lenders named therein.		8-K		001-13726		10.1		12/16/2015
4.4.4††		Third Amendment to Credit Agreement dated April 8, 2016 among Chesapeake Energy Corporation, as borrower; MUFG Union Bank N.A., as administrative agent, a swingline lender and a letter of credit issuer; and certain other lenders named therein.		10-Q		001-13726		4.2		8/4/2016
4.4.5		Fourth Amendment to Credit Agreement dated May 19, 2017 among Chesapeake Energy Corporation, as borrower; MUFG Union Bank N.A., as administrative agent, a swingline lender and a letter of credit issuer; and certain other lenders named therein.		8-K		001-13726		10.1		5/22/2017
4.4.6		Amended and Restated Credit Agreement, dated as of September 12, 2018, by and among: (i) the Company, as borrower; (ii) MUFG Union Bank N.A., as the administrative agent, a swingline lender and a letter of credit issuer; (iii) Wells Fargo Bank, National Association, as co-syndication agent, a swingline lender and a letter of credit issuer; (iv) JPMorgan Chase Bank, N.A., as co-syndication agent, a swingline lender and a letter of credit issuer; and (v) certain other lenders and letter of credit issuers named therein.		8-K		001-13726		10.1		9/12/2018
4.5		Intercreditor Agreement dated as of December 23, 2015 between MUFG Bank, N.A., as Priority Lien Agent, and Deutsche Bank Trust Company Americas, as Second Lien Collateral Trustee, and acknowledged by Chesapeake and certain of its subsidiaries.		8-K		001-13726		10.1		12/23/2015
4.6		Collateral Trust Agreement, dated as of December 23, 2015, by and among Chesapeake, the guarantors named therein, and Deutsche Bank Trust Company Americas as the representative of the holders of the Second Lien Notes and as collateral trustee.		8-K		001-13726		10.2		12/23/2015
4.7		Indenture dated as of October 5, 2016, among Chesapeake Energy Corporation, the subsidiary guarantors named therein and Deutsche Bank Trust Company Americas, as trustee, with respect to the 5.5% Convertible Senior Notes due 2026.		8-K		001-13726		4.1		10/5/2016

4.8		Sixth Supplemental indenture dated as of December 20, 2016 to indenture dated as of April 24, 2014 with respect to 8.00% Senior Notes due 2025.		8-K		001-13726		4.2		12/20/2016
4.9		Registration Rights Agreement dated as of December 20, 2016, among Chesapeake Energy Corporation, the subsidiary guarantors named therein and Deutsche Bank Securities, Inc.		8-K		001-13726		4.4		12/20/2016
4.10		Purchase Agreement, dated May 22, 2017, by and among Chesapeake Energy Corporation, the subsidiary guarantors named therein and Citigroup Global Markets Inc., as representative of the initial purchasers named therein, relating to the private placement of the 8.00% Senior Notes due 2027.		8-K		001-13726		10.1		5/23/2017
4.11		Seventh Supplemental Indenture dated as of June 6, 2017 to Indenture dated as of April 24, 2014 with respect to 8.00% Senior Notes due 2027.		8-K		001-13726		4.2		6/7/2017
4.12		Registration Rights Agreement dated as of June 6, 2017, among Chesapeake Energy Corporation, the subsidiary guarantors named therein and Citigroup Global Markets Inc.		8-K		001-13726		4.4		6/7/2017
4.13		Purchase Agreement, dated September 27, 2017, by and among Chesapeake Energy Corporation, the subsidiary guarantors named therein and Morgan Stanley & Co. LLC, as representative of the initial purchasers named therein, relating to the private placement of the 8.00% Senior Notes due 2025 and 8.00% Senior Notes due 2027.		8-K		001-13726		10.1		9/28/2017
4.14		Registration Rights Agreement, dated as of October 12, 2017, among Chesapeake Energy Corporation, the subsidiary guarantors named therein and Morgan Stanley & Co. LLC with respect to 8.00% Senior Notes due 2025.		8-K		001-13726		4.4		10/12/2017
4.15		Registration Rights Agreement, dated as of October 12, 2017, among Chesapeake Energy Corporation, the subsidiary guarantors named therein and Morgan Stanley & Co. LLC with respect to 8.00% Senior Notes due 2027.		8-K		001-13726		4.5		10/12/2017
4.16		Eighth Supplemental Indenture, dated as of September 27, 2018 to Indenture dated as of April 24, 2014 with respect to 7.00% Senior Notes due 2024.		8-K		001-13726		4.2		9/27/2018
4.17		Ninth Supplemental Indenture, dated as of September 27, 2018 to Indenture dated as of April 24, 2014 with respect to 7.50% Senior Notes due 2026.		8-K		001-13726		4.3		9/27/2018
4.18.1		Indenture dated as of February 1, 2017 by and among WildHorse Resource Development Corporation, as Issuer, each of the guarantors party thereto, and U.S. Bank National Association, as Trustee.		8-K		001-37964		4.1		2/1/2017

4.18.2		First Supplemental Indenture, dated as of June 30, 2017, by and among WHR Eagle Ford LLC, WildHorse Resource Development Corporation, the other subsidiary guarantors named therein and U.S. Bank National Association, as Trustee.		10-Q		001-37964		4.6		8/10/2017
4.18.3		Second Supplemental Indenture, dated as of January 8, 2018 among Burleson Sand LLC, WildHorse Resource Development Corporation, the other subsidiary guarantors named therein and U.S. Bank National Association, as Trustee.		10-K		001-37964		4.6		3/12/2018
4.18.4		Third Supplemental Indenture, dated as of August 2, 2018 among WHCC Infrastructure, a subsidiary of WildHorse Resource Development Corporation, the other Guarantors (as defined in the Indenture referred to therein) and U.S. Bank National Association, as Trustee.		10-Q		001-37964		4.6		8/9/2018
4.18.5		Fourth Supplemental Indenture, dated as February 1, 2019 among Brazos Valley Longhorn, L.L.C., as Successor Issuer, Brazos Valley Longhorn Finance Corp., as Co-Issuer, the Guarantors (as defined in the Indenture referred to therein) and U.S. Bank National Association, as Trustee.		8-K		001-13726		4.1		2/1/2019
10.1.1†		Chesapeake’s 2003 Stock Incentive Plan, as amended.		10-Q		001-13726		10.1.1		11/9/2009
10.1.2†		Form of 2013 Restricted Stock Award Agreement for Chesapeake’s 2003 Stock Incentive Plan.		10-K		001-13726		10.1.3		3/1/2013
10.2.1†		Chesapeake’s 2005 Amended and Restated Long Term Incentive Plan.		8-K		001-13726		10.1		6/20/2013
10.2.2†		Form of 2013 Restricted Stock Award Agreement for 2005 Amended and Restated Long Term Incentive Plan.		8-K		001-13726		10.3		2/4/2013
10.2.3†		Form of Nonqualified Stock Option Agreement for 2005 Amended and Restated Long Term Incentive Plan.		8-K		001-13726		10.1		2/4/2013
10.2.4†		Form of Retention Nonqualified Stock Option Agreement for 2005 Amended and Restated Long Term Incentive Plan.		8-K		001-13726		10.2		2/4/2013
10.2.5†		Form of 2013 Non-Employee Director Restricted Stock Award Agreement for 2005 Amended and Restated Long Term Incentive Plan.		10-K		001-13726		10.13.7		3/1/2013
10.2.6†		Form of 2013 Performance Share Unit Award Agreement for 2005 Amended and Restated Long Term Incentive Plan.		10-K		001-13726		10.13.9		3/1/2013
10.2.7†		Form of 2014 Performance Share Unit Award Agreement for 2005 Amended and Restated Long Term Incentive Plan.		10-K		001-13726		10.4.7		2/27/2014
10.2.8†		Form of Restricted Stock Unit Award Agreement for 2005 Amended and Restated Long Term Incentive Plan.		10-Q		001-13726		10.8		8/6/2013
10.2.9†		Form of Non-Employee Director Restricted Stock Unit Award Agreement for 2005 Amended and Restated Long Term Incentive Plan.		10-Q		001-13726		10.9		8/6/2013

10.2.10†		Form of Pension and Equity Makeup Restricted Stock Award Agreement for 2005 Amended and Restated Long Term Incentive Plan for Robert D. Lawler.		10-Q		001-13726		10.10		8/6/2013
10.3.1†		Chesapeake Energy Corporation Deferred Amended and Restated Deferred Compensation Plan, effective January 1, 2016.		10-K		001-13726		10.3		2/25/2016
10.3.2†		Amendment to the Chesapeake Energy Corporation Deferred Compensation Plan, effective January 1, 2019.										X
10.4.1†		Chesapeake Energy Corporation Deferred Compensation Plan for Non-Employee Directors.		10-K		001-13726		10.16		3/1/2013
10.4.2†		Amendment to the Chesapeake Energy Corporation Deferred Compensation Plan for Non-Employee Directors, effective January 1, 2017.		10-K		001-13726		10.3.2		3/3/2017
10.5.1†		Employment Agreement dated as of May 20, 2013 between Robert D. Lawler and Chesapeake Energy Corporation.		8-K		001-13726		10.1		5/23/2013
10.5.2†		Amendment to Employment Agreement between Robert D. Lawler and Chesapeake Energy Corporation dated as of June 16, 2016.		8-K		001-13726		10.1		6/17/2016
10.5.3†		Amendment to Employment Agreement between Robert D. Lawler and Chesapeake Energy Corporation dated as of December 31, 2018.		8-K		001-13726		10.1		1/4/2019
10.5.4†		Pension Makeup Restricted Stock Award Agreement for Robert D. Lawler, dated June 17, 2018.		10-Q		001-13726		10.1		8/1/2018
10.6†		Employment Agreement dated as of January 1, 2019 between Domenic J. Dell’Osso, Jr. and Chesapeake Energy Corporation.		8-K		001-13726		10.2		1/4/2019
10.7†		Employment Agreement dated as of January 1, 2019 between James R. Webb and Chesapeake Energy Corporation.		8-K		001-13726		10.3		1/4/2019
10.8†		Employment Agreement dated as of January 1, 2019 between Frank J. Patterson and Chesapeake Energy Corporation.		8-K		001-13726		10.4		1/4/2019
10.9†		Employment Agreement dated as of January 1, 2019 between M. Jason Pigott and Chesapeake Energy Corporation.		8-K		001-13726		10.5		1/4/2019
10.10†		Employment Agreement dated as of January 1, 2019 between Chesapeake Energy Corporation and William M. Buergler.										X
10.11†		Form of Employment Agreement dated as of January 1, 2019 between Executive Vice President/Senior Vice President and Chesapeake Energy Corporation.										X
10.12†		Form of Indemnity Agreement for officers and directors of Chesapeake Energy Corporation and its subsidiaries.		8-K		001-13726		10.3		6/27/2012
10.13†		Chesapeake Energy Corporation 2013 Annual Incentive Plan.		DEF 14A		001-13726		Exhibit G		5/3/2013

10.13.1†		Chesapeake Energy Corporation Restated 2014 Long Term Incentive Plan.		10-Q		001-13726		10.1		8/3/2017
10.13.2†		Form of Restricted Stock Unit Award Agreement for 2014 Long Term Incentive Plan.		10-Q		001-13726		10.2		8/6/2014
10.13.3†		Form of Restricted Stock Award Agreement for 2014 Long Term Incentive Plan.		10-Q		001-13726		10.3		8/6/2014
10.13.4†		Form of Nonqualified Stock Option Agreement for 2014 Long Term Incentive Plan.		10-Q		001-13726		10.4		8/6/2014
10.13.5†		Form of Performance Share Unit Award Agreement for 2014 Long Term Incentive Plan.		10-Q		001-13726		10.5		8/6/2014
10.13.6†		Form of Director Restricted Stock Unit Award Agreement for 2014 Long Term Incentive Plan.		10-Q		001-13726		10.6		8/6/2014
10.14.1		Voting and Support Agreement, by and among Jay Carlton Graham, Esquisto Holdings, LLC, WHE AcqCo Holdings, LLC, WHR Holdings, LLC, NGP XI US Holdings, L.P., Chesapeake Energy Corporation and WildHorse Resource Development Corporation, dated as of October 29, 2018.		8-K		001-13726		10.1		10/30/2018
10.14.2		Voting and Support Agreement, by and among CP VI Eagle Holdings, L.P., Chesapeake Energy Corporation and WildHorse Resource Development Corporation, dated as of October 29, 2018.		8-K		001-13726		10.2		10/30/2018
10.14.3		Registration Rights Agreement, by and among Esquisto Holdings, LLC, WHE AcqCo Holdings, LLC, WHR Holdings, LLC, NGP XI US Holdings, L.P., CP VI Eagle Holdings, L.P. and Chesapeake Energy Corporation, dated as of October 29, 2018.		8-K		001-13726		10.3		10/30/2018
10.15.1		Credit Agreement, dated December 19, 2016, by and among WildHorse Resource Development Corporation, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, BMO Harris Bank, N.A., as Syndication Agent, the Lenders party thereto and the other parties party thereto.		8-K		001-37964		10.3		12/22/2016
10.15.2		First Amendment to Credit Agreement, dated as of April 4, 2017, by and among WildHorse Resource Development Corporation, each of the guarantors party thereto, and Wells Fargo Bank, National Association, as Administrative Agent for the Lenders party thereto, BMO Harris Bank, N.A., as Syndication Agent, the Lenders party thereto and the other parties party thereto.		10-Q		001-37964		10.1		5/15/2017
10.15.3		Second Amendment to Credit Agreement, dated as of June 30, 2017, by and among WildHorse Resource Development Corporation, each of the guarantors party thereto, and Wells Fargo Bank, National Association, as Administrative Agent for the Lenders party thereto, BMO Harris Bank, N.A., as Syndication Agent, the Lenders party thereto and the other parties party thereto.		8-K		001-37964		10.1		7/7/2017

10.15.4		Third Amendment to Credit Agreement, dated as of October 4, 2017, by and among WildHorse Resource Development Corporation, each of the guarantors party thereto, and Wells Fargo Bank, National Association, as Administrative Agent for the Lenders party thereto, BMO Harris Bank, N.A., as Syndication Agent, the Lenders party thereto and the other parties party thereto.		8-K		001-37964		10.1		10/5/2017
10.15.5		Fourth Amendment to Credit Agreement, dated as of March 23, 2018 by and among WildHorse Resource Development Corporation, each of the guarantors party thereto, and Wells Fargo Bank, National Association, as Administrative Agent for the Lenders party thereto, BMO Harris Bank, N.A., as Syndication Agent, the Lenders party thereto and the other parties party thereto.		8-K		001-37964		10.1		3/27/2018
10.15.6		Fifth Amendment to Credit Agreement, dated as of October 15, 2018 by and among WildHorse Resource Development Corporation, each of the guarantors party thereto, and Wells Fargo Bank, National Association, as Administrative Agent for the Lenders party thereto, BMO Harris Bank, N.A., as Syndication Agent, the Lenders party thereto and the other parties party thereto.		10-Q		001-37964		10.1		11/8/2018
10.15.7		Sixth Amendment to Credit Agreement, dated as of February 1, 2019, by and among Brazos Valley Longhorn, L.L.C. (as successor by merger to WildHorse Resource Development Corporation), each of each of the guarantors party thereto, and Wells Fargo Bank, National Association, as Administrative Agent for the Lenders party thereto, BMO Harris Bank, N.A., as Syndication Agent, the Lenders party thereto and the other parties party thereto.		8-K		001-13726		10.1		2/1/2019
21		Subsidiaries of Chesapeake Energy Corporation.										X
23.1		Consent of PricewaterhouseCoopers LLP.										X
23.2		Consent of Software Integrated Solutions, Division of Schlumberger Technology Corporation.										X
31.1		Robert D. Lawler, President and Chief Executive Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.										X
31.2		Domenic J. Dell’Osso, Jr., Executive Vice President and Chief Financial Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.										X
32.1		Robert D. Lawler, President and Chief Executive Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.										X
32.2		Domenic J. Dell’Osso, Jr., Executive Vice President and Chief Financial Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.										X

99		Report of Software Integrated Solutions, Division of Schlumberger Technology Corporation.										X
101 INS		XBRL Instance Document.										X
101 SCH		XBRL Taxonomy Extension Schema Document.										X
101 CAL		XBRL Taxonomy Extension Calculation Linkbase Document.										X
101 DEF		XBRL Taxonomy Extension Definition Linkbase Document.										X
101 LAB		XBRL Taxonomy Extension Labels Linkbase Document.										X
101 PRE		XBRL Taxonomy Extension Presentation Linkbase Document.										X
*		Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The registrant hereby undertakes to furnish supplemental copies of any of the omitted schedules upon request by the SEC.
**		The Company agrees to furnish a copy of any of its unfiled long-term debt instruments to the Securities and Exchange Commission upon request.
†		Management contract or compensatory plan or arrangement.
††		Confidential treatment has been requested for portions of this exhibit. These portions have been omitted and submitted separately to the Securities and Exchange Commission.
PLEASE NOTE: Pursuant to the rules and regulations of the Securities and Exchange Commission, we have filed or incorporated by reference the agreements referenced above as exhibits to this Annual Report on Form 10-K. The agreements have been filed to provide investors with information regarding their respective terms. The agreements are not intended to provide any other factual information about Chesapeake Energy Corporation or its business or operations. In particular, the assertions embodied in any representations, warranties and covenants contained in the agreements may be subject to qualifications with respect to knowledge and materiality different from those applicable to investors and may be qualified by information in confidential disclosure schedules not included with the exhibits. These disclosure schedules may contain information that modifies, qualifies and creates exceptions to the representations, warranties and covenants set forth in the agreements. Moreover, certain representations, warranties and covenants in the agreements may have been used for the purpose of allocating risk between the parties, rather than establishing matters as facts. In addition, information concerning the subject matter of the representations, warranties and covenants may have changed after the date of the respective agreement, which subsequent information may or may not be fully reflected in our public disclosures. Accordingly, investors should not rely on the representations, warranties and covenants in the agreements as characterizations of the actual state of facts about Chesapeake Energy Corporation or its business or operations on the date hereof.