Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Overview

Introduction

The following discussion and analysis presents management’s perspective of our business, financial condition and overall performance. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future and should be read in conjunction with “Item 8. Financial Statements and Supplementary Data” of this report.

Overview of 2017 Results

The transformation of Chesapeake over the past four years has been significant and our progress continued in 2017. Our progress has been guided by our strategies of financial discipline, pursuing profitable and efficient growth from our captured resources, leveraging technology and our operational expertise to unlock additional domestic resources through exploration and development and optimizing our portfolio through business development. Our strategies have not changed through the price cycles of the past several years, and we believe our recent accomplishments and achievements in 2017 have made our company stronger. Highlights include the following:

•	grew estimated proved reserves volumes by 16% in 2017, net of divestitures;

•	improved cash flow from operations by $949 million;

•	grew production by 3%, adjusted for asset sales, and met our targeted goal of reaching 100,000 barrels of average net oil production per day in the fourth quarter of 2017, a significant accomplishment representing 11% growth from our 2016 fourth quarter oil volumes;

•	improved our cost structure by reducing our production, general and administrative, and gathering, processing and transportation expenses by $510 million, or 18%;

•	generated approximately $1.3 billion in net proceeds from the disposition of certain non-core assets and other property sales;

•	reduced outstanding secured term debt by approximately $1.3 billion, or 32%;

•	continued to reduce legal obligations;

•	exchanged approximately 10.0 million shares of common stock for approximately $100 million of liquidation value of our preferred stock, eliminating approximately $6 million of annual dividend obligations; and

•	achieved company record health, safety and environmental performance by lowering total recordable incident rates to 0.045 and reducing reportable spills by 15% compared to 2016.

		Years Ended December 31,
		2017				change			2016				change			2015
		($ in millions)
Net income (loss) available to common stockholders		$	813			n/m			$	(4,915	)		67	%		$	(14,738	)
Net earnings (loss) per diluted common share		$	0.90			n/m			$	(6.43	)		71	%		$	(22.26	)
Adjusted production(a) (mboe per day)		541				3	%		525				3	%		511
Total production (mboe per day)		548				(14	)%		635				(6	)%		679
Average sales price (per boe)		$	22.88			38	%		$	16.63			(14	)%		$	19.23
Oil, natural gas and NGL production expenses		$	562			(21	)%		$	710			(32	)%		$	1,046
Oil, natural gas and NGL gathering, processing and transportation expenses		$	1,471			(21	)%		$	1,855			(12	)%		$	2,119
General and administrative expenses		$	262			9	%		$	240			2	%		$	235
Total debt (principal amount)		$	9,981			—	%		$	9,989			3	%		$	9,706
Estimated proved reserves (mmboe)		1,912				12	%		1,708				14	%		1,504

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(a)	Adjusted for assets sold.

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, but may remain volatile for the foreseeable future. To this end, we will always strive to protect a portion of our projected cash flow through our commodity hedging program as we see appropriate.

As of February 22, 2018, including January and February derivative contracts that are settled, approximately 74% of our projected full year 2018 crude oil production was hedged through swaps and open collars at an average of $52.41 per barrel and approximately 68% of our projected full year 2018 natural gas production was hedged through swaps and collars at an average of $3.10 per mcf. Our crude oil hedges are below current 2018 NYMEX crude oil strip prices of approximately $60.00 per barrel, and our natural gas hedges currently sit in a profitable position, above current 2018 NYMEX natural gas strip prices of approximately $2.80 per mcf. While we cannot predict the future movements of commodity prices with complete accuracy, we believe it is prudent to protect a portion of our projected cash flow through hedging and plan to continue to do so in the future.

In 2018, our focus is concentrated on three strategic priorities:

•	reduce total debt by $2 - $3 billion;

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

•	improve margins through financial discipline and operating efficiencies.

With regard to our debt, we are committed to decreasing the amount of debt outstanding. To accomplish this objective, we intend to allocate our capital expenditures to the highest-return projects, deploy leading drilling and completion technology throughout our portfolio to profitably and efficiently grow, and divest additional large assets to strengthen our cost structure and our portfolio. Increasing our margins means not only increasing our level of cash flow from operations, but also increasing our cash flow from operations generated per barrel of equivalent production. We are seeking to reduce cash costs (production, general and administrative and gathering, processing and transportation expenses), improve our production volumes from existing wells, and achieve additional operating and capital efficiencies with a focus on growing our oil volumes. Finally, we seek to maintain our high level of health, safety, and environmental performance and stewardship.

We have already made significant progress towards achieving our strategic priorities to date in 2018. So far we have:

•	signed agreements for the sale of properties in the Mid-Continent, including our Mississippian Lime assets, for an expected aggregate amount of approximately $500 million in proceeds that we expect to close by the end of the 2018 second quarter; and

•	received net proceeds of approximately $74 million from the sale of approximately 4.3 million shares of FTS International, Inc. (NYSE: FTSI). After the sale, we own approximately 22 million shares of FTSI.

The proceeds from these divestitures will be used to repay debt and fund our development program, based on market conditions.

Over the last four years, we have fundamentally transformed substantially all aspects of our business, removing financial and operational complexity, significantly improving our balance sheet and addressing numerous legacy issues. Our 2018 capital expenditures program, while planned to be approximately 12% lower than our 2017 program, is expected to generate greater capital efficiency as we focus on expanding our margins by investing in the highest-return projects. In January, we reduced our workforce by approximately 13% as part of an overall plan to reduce costs and better align our workforce to the needs of our business. We are committed to reducing our debt and improving cash flow from operations, and believe we can make material advances in both of these areas in 2018.

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 very volatile, and may be subject to wide fluctuations in the future. The substantial decline in oil, natural gas and NGL prices from 2014 levels has negatively, and will continue to have, affected the amount of cash we generate and have available for capital expenditures and debt service and has had a material impact on our financial position, results of operations, cash flows and on the quantities of reserves that we can economically produce. Other risks and uncertainties that could affect our liquidity include, but are not limited to, counterparty credit risk for our receivables, access to capital markets, regulatory risks, our ability to meet financial ratios and covenants in our financing agreements and the availability of lenders’ commitments as a result of regulatory pressures in the lending market.

As of December 31, 2017, we had a cash balance of $5 million compared to $882 million as of December 31, 2016, and we had a net working capital deficit of $831 million as of December 31, 2017, compared to a net working capital deficit of $1.506 billion as of December 31, 2016. As of December 31, 2017, we had total principal debt of $9.981 billion, compared to $9.989 billion as of December 31, 2016. As of December 31, 2017, we had $2.888 billion of borrowing capacity available under our senior secured revolving credit facility, with outstanding borrowings of $781 million and $116 million utilized for various letters of credit. Based on our cash balance, forecasted cash flows from operating activities and availability under our revolving credit facility, we expect to be able to fund our planned capital expenditures, meet our debt service requirements and fund our other commitments and obligations for the next 12 months. 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 principal and carrying amounts of our notes.

Even though we have taken measures to mitigate the liquidity concerns facing us for the next 12 months, as outlined above in Overview of 2017 Results and Business and Industry Outlook, there can be no assurance that these measures will be sufficient for periods beyond the next 12 months. If needed, we may seek to access the capital markets or otherwise refinance a portion of our outstanding indebtedness to improve our liquidity. We closely monitor the amounts and timing of our sources and uses of funds, particularly as they affect our ability to maintain compliance with the financial covenants of our revolving credit facility. Furthermore, our ability to generate operating cash flow in the current commodity price environment, sell assets, access capital markets or take any other action to improve our liquidity and manage our debt is subject to the risks discussed above and the other risks and uncertainties that exist in our industry, some of which we may not be able to anticipate at this time or control.

Capital Expenditures

We have significant control and flexibility over the timing and execution of our development plan, enabling us to reduce our capital spending as needed. Our forecasted 2018 capital expenditures, inclusive of capitalized interest, are $2.0 – $2.4 billion compared to our 2017 capital spending level of $2.5 billion. Management continues to review operational plans for 2018 and beyond, which could result in changes to projected capital expenditures and projected revenues from sales of oil, natural gas and NGL.

We may continue to use a combination of cash, borrowings and issuances of our common stock or other securities to retire our outstanding debt and/or preferred stock through privately negotiated transactions, open market repurchases, redemptions, tender offers or otherwise, but we are under no obligation to do so.

Derivative and Hedging Activities

Our results of operations and cash flows are impacted by changes in market prices for oil, natural gas and NGL. To mitigate a portion of the exposure to adverse market 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 NGLs, allow us to predict with greater certainty the total revenue we will receive.

We utilize various oil, natural gas and NGL derivative instruments to protect a portion of our cash flow against downside risk. As of February 22, 2018, we have downside price protection in 2018 and 2019 through the following oil, natural gas and NGL derivative instruments:

Oil Derivatives(a)
Year		Type of Derivative Instrument		Notional Volume			% of Forecasted Production (if applicable)		Average NYMEX Price
				(mbbls)
2018		Swaps		21,710			68%		$52.87
2018		Three-way collars		1,825			6%		$39.15/$47.00/$55.00
2018		Calls		1,840			6%		$52.87
2018		Basis protection swaps		10,769			34%		$3.32
2019		Swaps		3,273			Not disclosed		$56.04
Natural Gas Derivatives(a)
Year		Type of Derivative Instrument		Notional Volume			% of Forecasted Production (if applicable)		Average NYMEX Price
				(mmcf)
2018		Swaps		531,613			63%		$3.11
2018		Two-way collars		47,450			6%		$3.00/$3.25
2018		Calls		65,700			8%		$6.27
2018		Basis protection swaps		64,589			8%		($0.52)
NGL Derivatives(a)
Year		Type of Derivative Instrument		Notional Volume			% of Forecasted Production (if applicable)		Average NYMEX Price
				(mmgal)
2018		Butane swaps		5			1%		$0.88
2018		Butane % of WTI swaps		5			1%		70.5% of WTI
2018		Propane swaps		15			2%		$0.73
2018		Ethane swaps		8			1%		$0.28

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(a)	Includes amounts settled in January and February 2018.

See Note 11 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of derivatives and hedging activities.

Contractual Obligations and Off-Balance Sheet Arrangements

From time to time, we enter into arrangements and transactions that can give rise to contractual obligations and off-balance sheet commitments. The table below summarizes our contractual cash obligations for both recorded obligations and certain off-balance sheet arrangements and commitments as of December 31, 2017:

		Payments Due By Period
		Total				Less Than 1 Year				1-3 Years				3-5 Years				More Than 5 Years
		($ in millions)
Long-term debt:
Principal(a)		$	9,981			$	53			$	1,825			$	3,915			$	4,188
Interest		3,774				653				1,258				924				939
Operating lease obligations(b)		14				6				7				1				—
Operating commitments(c)		9,190				1,102				2,030				1,654				4,404
Unrecognized tax benefits(d)		101				—				4				97				—
Standby letters of credit		116				116				—				—				—
Other		22				4				8				8				2
Total contractual cash obligations(e)		$	23,198			$	1,934			$	5,132			$	6,599			$	9,533

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(a)	See Note 3 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our long-term debt.

(b)	See Note 4 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our operating lease obligations.

(c)	See Note 4 of the notes to our consolidated financial statements included in Item 8 of this report for a description of gathering, processing and transportation agreements, drilling contracts and pressure pumping contracts.

(d)	See Note 6 of the notes to our consolidated financial statements included in Item 8 of this report for an analysis of unrecognized tax benefits.

(e) This table does not include derivative liabilities or the estimated discounted liability for future dismantlement, abandonment and restoration costs of oil and natural gas properties. See Notes 11 and 19, respectively, of the notes to our consolidated financial statements included in Item 8 of this report for more information on our derivatives and asset retirement obligations. This table also does not include our costs to produce reserves attributable to non-expense-bearing royalty and other interests in our properties, including VPPs, which are discussed in Note 12 of the notes to our consolidated financial statements included in Item 8 of this report.

Credit Risk

Derivative instruments that enable us to manage our exposure to oil, natural gas and NGL prices expose us to credit risk from our counterparties. To mitigate this risk, we enter into oil, natural gas and NGL derivative contracts only with counterparties that we deem to have acceptable credit strength and are deemed by management to be competent and competitive market-makers, and we attempt to limit our exposure to non-performance by any single counterparty. As of December 31, 2017, our oil, natural gas and NGL derivative instruments were spread among 11 counterparties. Additionally, the counterparties under these arrangements are required to secure their obligations in excess of defined thresholds.

Our accounts receivable are primarily from purchasers of oil, natural gas and NGL ($959 million as of December 31, 2017) and exploration and production companies that own interests in properties we operate ($209 million as of December 31, 2017). This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We generally require letters of credit or parent guarantees for receivables from parties deemed to have sub-standard credit, unless the credit risk can otherwise be mitigated. During 2017, 2016 and 2015, we recognized $9 million, $10 million and $4 million, respectively, of bad debt expense related to potentially uncollectible receivables.

Some of our counterparties have requested or required us to post collateral as financial assurance of our performance under certain contractual arrangements, such as gathering, processing, transportation and hedging agreements. As of February 20, 2018, we have received requests and posted approximately $151 million of collateral related to certain of our marketing and other contracts. We may be requested or required by other counterparties to post additional collateral in an aggregate amount of approximately $486 million, which may be in the form of additional letters of credit, cash or other acceptable collateral. However, we have substantial long-term business relationships with each of these counterparties, and we may be able to mitigate any collateral requests through ongoing business arrangements and by offsetting amounts that the counterparty owes us. Any posting of collateral consisting of cash or letters of credit reduces availability under our revolving credit facility and negatively impacts our liquidity.

Sources of Funds

The following table presents the sources of our cash and cash equivalents for the years ended December 31, 2017, 2016 and 2015. See Note 12 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of divestitures of oil and natural gas assets.

		Years Ended December 31,
		2017				2016				2015
		($ in millions)
Cash provided by (used in) operating activities		$	745			$	(204	)		$	1,234
Proceeds from credit facility borrowings, net		781				—				—
Proceeds from issuance of a term loan, net		—				1,476				—
Proceeds from issuances of senior notes, net		1,585				2,210				—
Proceeds from divestitures of proved and unproved properties, net		1,249				1,406				189
Proceeds from sales of other property and equipment, net		55				131				89
Other		—				—				52
Total sources of cash and cash equivalents		$	4,415			$	5,019			$	1,564

Cash Flow from Operating Activities

Cash provided by operating activities was $745 million in 2017 compared to cash used in operating activities of $204 million in 2016 and cash provided by operating activities of $1.234 billion in 2015. The increase in 2017 is primarily the result of higher prices for the oil, natural gas and NGL we sold and decreases in certain of our operating expenses, partially offset by lower volumes of oil, natural gas and NGL sold, the payment related to the litigation involving the early redemption of our 6.775% Senior Notes due 2019 and payments for terminations of transportation contracts. The decrease from 2015 is primarily the result of lower prices for the oil and natural gas we sold, lower volumes of oil, natural gas and NGL sold, less gain from our commodity derivatives, partially offset by decreases in certain of our operating expenses. Changes in cash flow from operations are largely due to the same factors that affect our net income, excluding various non-cash items, such as depreciation, depletion and amortization, certain impairments, gains or losses on sales of fixed assets, deferred income taxes and mark-to-market changes in our derivative instruments. See further discussion below under Results of Operations.

Revolving Credit Facility

We have a senior secured revolving credit facility currently subject to a $3.8 billion borrowing base that matures in December 2019. As of December 31, 2017, we had $2.888 billion of borrowing capacity available under our revolving credit facility. Our next borrowing base redetermination is scheduled for the second quarter of 2018. As of December 31, 2017, we had outstanding borrowings of $781 million under the revolving credit facility and had used $116 million of the revolving credit facility for various letters of credit. Borrowings under the facility bear interest at a variable rate. See Note 3 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of the terms of the revolving credit facility. As of December 31, 2017, we were in compliance with all applicable financial covenants under the credit agreement. Our first lien secured leverage ratio was approximately 0.52 to 1.00, our interest coverage ratio was approximately 2.51 to 1.00 and our debt to capitalization ratio was approximately 0.38 to 1.00.

We currently plan to use cash flow from operations to fund our capital expenditures for 2018. We expect to generate additional liquidity with proceeds from future sales of assets that do not fit our strategic priorities. Under our revolving credit facility, we borrowed $7.771 billion and repaid $6.990 billion in 2017, we borrowed and repaid $5.146 billion in 2016 and we had no borrowings or repayments in 2015.

Debt issuances

The following table reflects the proceeds received from issuances of debt in 2017, 2016 and 2015. See Note 3 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion.

		Years Ended December 31,
		2017								2016								2015
		Principal Amount of Debt Issued				Net Proceeds				Principal Amount of Debt Issued				Net Proceeds				Principal Amount of Debt Issued				Net Proceeds
		($ in millions)
Convertible senior notes		$	—			$	—			$	1,250			$	1,235			$	—			$	—
Senior notes		1,600				1,585				1,000				975				—				—
Term loans		—				—				1,500				1,476				—				—
Total		$	1,600			$	1,585			$	3,750			$	3,686			$	—			$	—

Divestitures of Proved and Unproved Properties

During 2017, we divested certain non-core assets for approximately $1.249 billion. Proceeds from these transactions were used to repay debt and fund our development program. See Note 12 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion.

Uses of Funds

The following table presents the uses of our cash and cash equivalents for the years ended December 31, 2017, 2016 and 2015:

		Years Ended December 31,
		2017				2016				2015
		($ in millions)
Oil and Natural Gas Expenditures:
Drilling and completion costs		$	2,186			$	1,295			$	3,095
Acquisitions of proved and unproved properties		101				552				123
Interest capitalized on unproved leasehold		184				236				410
Total oil and natural gas expenditures		2,471				2,083				3,628
Other Uses of Cash and Cash Equivalents:
Cash paid to repurchase debt		2,592				2,734				508
Cash paid for title defects		—				69				—
Cash paid to repurchase noncontrolling interest		—				—				143
Additions to other property and equipment		21				37				143
Dividends paid		183				—				289
Distributions to noncontrolling interest owners		8				10				85
Other		17				29				51
Total other uses of cash and cash equivalents		2,821				2,879				1,219
Total uses of cash and cash equivalents		$	5,292			$	4,962			$	4,847

Oil and Natural Gas Expenditures

Our drilling and completion costs increased in 2017 compared to 2016 primarily as a result of increased drilling and completion activity as well as higher service and supply costs. During 2017, our average operated rig count was 17 rigs compared to an average operated rig count of ten rigs in 2016 and we completed 401 operated wells in 2017 compared to 382 in 2016. Our acquisitions of proved and unproved properties were higher in 2016 compared to 2017 and 2015, primarily resulting from purchases of oil and natural gas interests previously sold to third parties in connection with five of our VPP transactions for approximately $387 million.

Repurchase of Debt

In 2017, we used $2.592 billion of cash to repurchase $2.389 billion principal amount of debt. In 2016, we used $2.734 billion of cash to repurchase $2.884 billion principal amount of debt. In 2015, we used $508 million of cash to repurchase $513 million principal amount of debt.

Dividends

We paid dividends of $183 million on our preferred stock during 2017, including $92 million of dividends in arrears that had been suspended throughout 2016. We did not pay dividends on our preferred stock in 2016 and paid $171 million of preferred stock dividends in 2015. We paid dividends of $118 million on our common stock in 2015. We eliminated common stock dividends in the 2015 third quarter and do not anticipate paying any common stock dividends in the foreseeable future.

Results of Operations

Oil, Natural Gas and NGL Production and Average Sales Prices

		2017
		Oil						Natural Gas						NGL						Total
		mbbl per day			$/bbl			mmcf per day			$/mcf			mbbl per day			$/bbl			mboe per day			%			$/boe
Marcellus		—			—			810			2.44			—			—			135			25			14.65
Haynesville		—			—			785			2.85			—			—			131			24			17.12
Eagle Ford		58			52.34			142			3.30			18			22.95			100			18			39.24
Utica		10			46.04			427			3.00			26			23.06			107			19			21.80
Mid-Continent		16			49.66			163			2.78			10			22.89			53			10			27.55
Powder River Basin		6			49.97			37			3.01			3			27.33			15			3			32.58
Retained assets		90			51.04			2,364			2.76			57			23.20			541			99			22.97
Divested assets		—			46.25			42			2.63			—			13.36			7			1			16.24
Total		90			51.03			2,406			2.76			57			23.18			548			100	%		22.88
		2016
		Oil						Natural Gas						NGL						Total
		mbbl per day			$/bbl			mmcf per day			$/mcf			mbbl per day			$/bbl			mboe per day			%			$/boe
Marcellus		—			—			759			1.59			—			—			126			20			9.56
Haynesville		—			—			681			2.31			—			—			114			18			13.87
Eagle Ford		56			42.19			140			2.61			17			14.85			97			15			30.97
Utica		13			34.17			480			2.34			32			14.44			125			20			16.17
Mid-Continent		13			41.60			163			2.21			8			16.87			48			8			21.48
Powder River Basin		6			39.58			37			2.36			3			17.27			15			2			24.78
Retained assets		88			40.78			2,260			2.09			60			15.01			525			83			17.54
Divested assets		3			36.62			607			1.92			7			12.41			110			17			12.26
Total		91			40.65			2,867			2.05			67			14.76			635			100	%		16.63
		2015
		Oil						Natural Gas						NGL						Total
		mbbl per day			$/bbl			mmcf per day			$/mcf			mbbl per day			$/bbl			mboe per day			%			$/boe
Marcellus		—			—			739			1.89			—			—			123			18			11.32
Haynesville		—			—			524			2.66			—			—			88			13			15.97
Eagle Ford		65			47.01			148			2.73			16			14.13			106			16			34.70
Utica		13			36.82			423			2.35			33			14.93			116			17			16.92
Mid-Continent		16			47.37			199			2.60			10			15.08			59			9			24.14
Powder River Basin		9			43.34			49			2.77			3			14.09			20			3			28.15
Retained assets		103			45.44			2,082			2.32			62			14.70			512			76			20.35
Divested assets		11			48.78			849			2.26			15			11.38			167			24			15.77
Total		114			45.77			2,931			2.31			77			14.06			679			100	%		19.23

Natural gas and NGL production decreased primarily as a result of the sale of certain of our Barnett, Mid-Continent and Devonian assets in 2016 and the sale of certain of our Haynesville assets in 2017.

Oil, Natural Gas and NGL Sales

		Years Ended December 31,
		2017				change			2016				change			2015
		($ in millions)
Oil		$	1,668			23	%		$	1,351			(29	)%		$	1,904
Natural gas		2,422				12	%		2,155				(13	)%		2,470
NGL		484				34	%		360				(8	)%		393
Oil, natural gas and NGL sales		$	4,574			18	%		$	3,866			(19	)%		$	4,767

2017 vs. 2016. The increase in the price received per boe in 2017 resulted in a $1.25 billion increase in revenues, and decreased sales volumes resulted in a $542 million decrease in revenues, for a total net increase in revenues of $708 million.

2016 vs. 2015. The decrease in the price received per boe in 2016 resulted in a $606 million decrease in revenues, and decreased sales volumes resulted in a $295 million decrease in revenues, for a total net decrease in revenues of $901 million.

Oil, Natural Gas and NGL Derivatives

		Years Ended December 31,
		2017				change			2016				change			2015
		($ in millions)
Oil derivatives – realized gains (losses)		$	70			(28	)%		$	97			(89	)%		$	880
Oil derivatives – unrealized gains (losses)		(134		)		58	%		(318		)		41	%		(536		)
Total gains (losses) on oil derivatives		(64		)					(221		)					344
Natural gas derivatives – realized gains (losses)		(9		)		n/m			151				(65	)%		437
Natural gas derivatives – unrealized gains (losses)		489				n/m			(500		)		n/m			(157		)
Total gains (losses) on natural gas derivatives		480							(349		)					280
NGL derivatives – realized gains (losses)		(4		)		50	%		(8		)		—	%		—
NGL derivatives – unrealized gains (losses)		(1		)		—	%		—				—	%		—
Total gains (losses) on NGL derivatives		(5		)					(8		)					—
Total gains (losses) on oil, natural gas and NGL derivatives		$	411						$	(578	)					$	624

See Note 11 of the notes to our consolidated financial statements included in Item 8 of this report for a complete discussion of our derivative activity.

A change in oil, natural gas and NGL prices has a significant impact on our revenues and cash flows. Assuming our 2017 production levels and without considering the effect of derivatives, an increase or decrease of $1.00 per barrel of oil sold would have resulted in an increase or decrease in 2017 revenues and cash flows from operations of approximately $33 million and $31 million, respectively, an increase or decrease of $0.10 per mcf of natural gas sold would have resulted in an increase or decrease in 2017 revenues and cash flows from operations of approximately $88 million and $87 million, respectively, and an increase or decrease of $1.00 per barrel of NGL sold would have resulted in an increase or decrease in 2017 revenues and cash flows from operations of approximately $21 million and $20 million, respectively.

Marketing, Gathering and Compression Revenues and Expenses. Marketing, gathering and compression revenues primarily consist of marketing services, including commodity price structuring, securing and negotiating gathering, hauling, processing and transportation services, contract administration and nomination services for Chesapeake and other interest owners in Chesapeake-operated wells. Expenses related to our marketing, gathering and compression operations consist of third-party expenses and exclude depreciation and amortization, general and administrative expenses, impairments of fixed assets and other, net gains or losses on sales of fixed assets and interest expense.

		Years Ended December 31,
		2017				change			2016				change			2015
		($ in millions)
Marketing, gathering and compression revenues		$	4,511			(2	)%		$	4,584			(38	)%		$	7,373
Marketing, gathering and compression expenses		4,598				(4	)%		4,778				(33	)%		7,130
Marketing, gathering and compression gross margin		$	(87	)		55	%		$	(194	)		180	%		$	243

2017 vs. 2016. Gross margin increased primarily as a result of the reversal of cumulative unrealized gains associated with the termination of a supply contract derivative in 2016 as well as the sale of a significant portion of our gathering and compression assets in 2016.

2016 vs. 2015. Gross margin decreased primarily as a result of lower oil, natural gas and NGL prices paid and received in our marketing operations. Additionally, the 2015 amount included unrealized gains of $296 million on the fair value of our supply contract derivative.

Oil, Natural Gas and NGL Production Expenses

		Years Ended December 31,
		2017				change			2016				change			2015
Oil, natural gas and NGL production expenses		($ in millions)
Marcellus		$	20			11	%		$	18			(18	)%		$	22
Haynesville		53				36	%		39				(24	)%		51
Eagle Ford		187				28	%		146				(19	)%		181
Utica		37				(16	)%		44				(24	)%		58
Mid-Continent		180				15	%		157				(29	)%		221
Powder River Basin		27				35	%		20				(35	)%		31
Retained Assets(a)		504				19	%		424				(25	)%		564
Divested Assets		14				(94	)%		243				(42	)%		422
Total		518				(22	)%		667				(32	)%		986
Ad valorem tax(b)		44				2	%		43				(28	)%		60
Total oil, natural gas and NGL production expenses		$	562			(21	)%		$	710			(32	)%		$	1,046
Oil, natural gas and NGL production expenses		($ per boe)
Marcellus		$	0.41			5	%		$	0.39			(20	)%		$	0.49
Haynesville		$	1.10			17	%		$	0.94			(41	)%		$	1.59
Eagle Ford		$	5.12			24	%		$	4.13			(12	)%		$	4.71
Utica		$	0.94			(2	)%		$	0.96			(29	)%		$	1.36
Mid-Continent		$	9.39			6	%		$	8.87			(14	)%		$	10.31
Powder River Basin		$	4.90			35	%		$	3.64			(15	)%		$	4.27
Retained Assets(a)		$	2.55			15	%		$	2.21			(27	)%		$	3.02
Divested Assets		$	5.44			(10	)%		$	6.02			(13	)%		$	6.90
Total		$	2.59			(10	)%		$	2.87			(28	)%		$	3.98
Ad valorem tax(b)		$	0.23			5	%		$	0.22			(31	)%		$	0.32
Total oil, natural gas and NGL production expenses per boe		$	2.81			(8	)%		$	3.05			(28	)%		$	4.22

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(a) Includes assets retained as of December 31, 2017.

(b) Excludes ad valorem tax expense on divested assets.

2017 vs. 2016. The absolute and per unit decrease was the result of the sale of certain oil and natural gas properties in 2016, partially offset by increased workover costs in the Eagle Ford and increased water disposal costs in the Eagle Ford and Mid-Continent. Production expenses in 2017 and 2016 included approximately $19 million and $44 million associated with VPP production volumes. We anticipate a continued decrease in production expenses associated with VPP production volumes as the contractually scheduled volumes under our remaining VPP agreement decrease and operating efficiencies generally improve.

2016 vs. 2015. The absolute and per unit decrease was the result of a reduction in repairs and maintenance expense as well as operating efficiencies across most of our operating areas.

Oil, Natural Gas, and NGL Gathering, Processing and Transportation Expenses

		Years Ended December 31,
		2017				2016				2015
		($ in millions, except per unit)
Oil, natural gas and NGL gathering, processing and transportation expenses		$	1,471			$	1,855			$	2,119
Oil ($ per bbl)		$	3.94			$	3.61			$	3.38
Natural gas ($ per mcf)		$	1.34			$	1.47			$	1.66
NGL ($ per bbl)		$	7.88			$	7.83			$	7.37
Total ($ per boe)		$	7.36			$	7.98			$	8.55

2017 vs. 2016. The absolute decrease was primarily due to lower volumes. The per unit decrease was due to contract improvements and asset sales.

2016 vs. 2015. The absolute decrease was primarily due to lower volumes. The per unit decrease was primarily due to contract improvements and asset sales.

Production Taxes

		Years Ended December 31,
		2017				change			2016				change			2015
		($ in millions, except per unit)
Production taxes		$	89			20	%		$	74			(25	)%		$	99
Production taxes per boe		$	0.44			38	%		$	0.32			(20	)%		$	0.40

2017 vs. 2016. The absolute and per unit increase in production taxes was primarily due to higher prices received for our oil, natural gas and NGL production, offset by lower production volumes.

2016 vs. 2015. The absolute and per unit decrease in production taxes was primarily due to lower production volumes and lower prices received for our oil, natural gas and NGL production.

General and Administrative Expenses

		Years Ended December 31,
		2017				change			2016				change			2015
		($ in millions, except per unit)
Gross overhead		$	791			(12	)%		$	900			(18	)%		$	1,102
Allocated to production expenses		(177		)		(15	)%		(209		)		(16	)%		(248		)
Allocated to marketing, gathering and compression expenses		(29		)		(47	)%		(55		)		(32	)%		(81		)
Capitalized		(137		)		(8	)%		(149		)		(23	)%		(193		)
Reimbursed from third parties		(186		)		(25	)%		(247		)		(28	)%		(345		)
General and administrative expenses, net		$	262			9	%		$	240			2	%		$	235
General and administrative expenses, net per boe		$	1.31			27	%		$	1.03			8	%		$	0.95

2017 vs. 2016. Gross overhead decreased primarily due to lower compensation costs and lower legal fees. The absolute and per unit net expense increase was primarily due to less overhead allocated to production expenses, marketing, gathering, and compression expenses and capitalized general and administrative costs, as well as less overhead billed to third party working interest owners, due to certain divestitures in 2016 and 2017.

2016 vs. 2015. Gross overhead decreased primarily due to lower compensation costs. The absolute and per unit increase was primarily due to less overhead allocated to production expenses, marketing, gathering, and compression expenses and capitalized general and administrative costs, as well as less overhead billed to third party working interest owners, due to certain divestitures in 2016.

Restructuring and Other Termination Costs. We recorded expenses of $6 million and $36 million in 2016 and 2015, respectively. See Note 15 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our restructuring and termination costs.

Provision for Legal Contingencies, Net

		Years Ended December 31,
		2017				change			2016				change			2015
		($ in millions)
Provision for legal contingencies, net		$	(38	)		(131	)%		$	123			(65	)%		$	353

2017 vs. 2016. The 2017 amount consists of the recovery of a legal settlement, partially offset by accruals for loss contingencies primarily related to royalty claims. See Note 4 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of royalty claims.

2016 vs. 2015. The decrease was primarily the result of the resolution of litigation we were defending against the state of Michigan and $339 million related to litigation involving the early redemption of our 6.775% Senior Notes due 2019.

Oil, Natural Gas and NGL Depreciation, Depletion and Amortization

		Years Ended December 31,
		2017				change			2016				change			2015
		($ in millions, except per unit)
Oil, natural gas and NGL depreciation, depletion and amortization		$	913			(9	)%		$	1,003			(52	)%		$	2,099
Oil, natural gas and NGL depreciation, depletion and amortization per boe		$	4.56			6	%		$	4.31			(49	)%		$	8.47

2017 vs. 2016. The absolute decrease was primarily the result of the sale of certain of our Barnett and Mid-Continent assets in 2016 and the sale of certain of our Haynesville assets in 2017.

2016 vs. 2015. The absolute and per unit decrease was primarily the result of a lower amortization base, which is due to the 2016 and 2015 impairments of our oil and natural gas properties.

Depreciation and Amortization of Other Assets

		Years Ended December 31,
		2017				change			2016				change			2015
		($ in millions, except per unit)
Depreciation and amortization of other assets		$	82			(21	)%		$	104			(20	)%		$	130
Depreciation and amortization of other assets per boe		$	0.41			(9	)%		$	0.45			(15	)%		$	0.53

The absolute and per unit decrease for each year was primarily the result of the sale of other assets. See Note 13 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of other assets.

Impairment of Oil and Natural Gas Properties

		Years Ended December 31,
		2017				change			2016				change			2015
		($ in millions)
Impairment of oil and natural gas properties		$	—			(100	)%		$	2,564			(86	)%		$	18,238

In 2017, we did not have an impairment for our oil and natural gas properties. In 2016 and 2015, capitalized costs of oil and natural gas properties exceeded the ceiling, resulting in an impairment in the carrying value of our oil and natural gas properties of $2.564 billion and $18.238 billion, respectively. See Note 14 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our impairments.

Impairments of Fixed Assets and Other

		Years Ended December 31,
		2017				change			2016				change			2015
		($ in millions)
Impairment of fixed assets and other		$	421			(50	)%		$	838			332	%		$	194

The amounts consist of costs incurred to terminate various gathering and transportation agreements, including those associated with oil and gas asset divestitures, as well as impairments of building and other fixed assets. See Note 14 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our impairments and other expense.

Interest Expense

		Years Ended December 31,
		2017				2016				2015
		($ in millions)
Interest expense on senior notes		$	551			$	588			$	682
Interest expense on term loan		127				46				—
Amortization of loan discount, issuance costs and other		40				33				62
Amortization of premium		(138		)		(165		)		(3		)
Interest expense on revolving credit facility		39				35				12
Realized gains on interest rate derivatives(a)		(3		)		(11		)		(6		)
Unrealized (gains) losses on interest rate derivatives(b)		4				21				(6		)
Capitalized interest		(194		)		(251		)		(424		)
Total interest expense		$	426			$	296			$	317
Average senior notes borrowings		$	7,714			$	8,749			$	11,705
Average credit facilities borrowings		$	443			$	195			$	—
Average term loan borrowings		$	1,446			$	537			$	—

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(a)	Includes settlements related to the interest accrual for the period and the effect of (gains) losses on early-terminated trades. Settlements of early-terminated trades are reflected in realized (gains) losses over the original life of the hedged item.

(b)	Includes changes in the fair value of interest rate derivatives offset by amounts reclassified to realized (gains) losses during the period.

The 2017 increase in interest expense is primarily due to an increase in term loan interest expense and a decrease in capitalized interest as a result of lower average balances of unproved oil and natural gas properties, the primary asset on which interest is capitalized. The overall increase in interest expense is offset in part by a decrease in interest expense on senior notes due to the decrease in the average outstanding principal amount of senior notes. The 2016 decreases in capitalized interest resulted from lower average balances of unproved oil and natural gas properties, the primary asset on which interest is capitalized. The 2016 decrease in interest expense on senior notes is due to the decrease in the average outstanding principal amount of senior notes. The 2016 increase in the amortization of premium associated with troubled debt restructuring is due to a full year of amortization on our second lien notes. See Note 3 of the notes to our consolidated financial statements included in Item 8 of this report for a discussion of our debt refinancing. Interest expense, excluding unrealized gains or losses on interest rate derivatives and net of amounts capitalized, was $2.11 per boe in 2017 compared to $1.18 per boe in 2016 and $1.30 per boe in 2015.

Impairment of Investments. In 2016 and 2015, we recognized impairments of investments of $119 million and $53 million, respectively. The 2016 amount consisted of an other-than-temporary impairment of our Sundrop investment. The 2015 amount consisted of an other-than-temporary impairment of our FTSI International, Inc. (FTSI) investment due to the extended decrease in the oil and natural gas pricing environment.

Gains (Losses) on Purchases or Exchanges of Debt. In 2017, we retired $2.389 billion principal amount of our outstanding senior notes, senior secured second lien notes and contingent convertible notes through purchases in the open market, tender offers, redemptions or repayment upon maturity for $2.592 billion, which included the maturity of our 6.25% Euro-denominated Senior Notes due 2017 and the corresponding cross currency swap. We recorded an aggregate gain of approximately $233 million associated with the repurchases and tender offers.

In 2016, we used the proceeds from our term loan facility, convertible notes issuance and senior notes issuance, together with cash on hand, to purchase and retire $2.884 billion principal amount of our outstanding senior notes and contingent convertible senior notes through purchases in the open market, tender offers or repayment upon maturity for $2.734 billion. Additionally, we privately negotiated an exchange of approximately $577 million principal amount of our outstanding senior notes and contingent convertible senior notes for 109,351,707 common shares. We recorded an aggregate gain of approximately $236 million associated with the repurchases and exchanges.

In December 2015, we privately exchanged newly issued 8.00% Senior Secured Second Lien Notes due 2022 for certain outstanding senior unsecured notes and contingent convertible notes. For certain of the notes exchanged, we are accounting for these exchanges as a trouble debt restructuring (TDR). For exchanges classified as TDR, if the future undiscounted cash flows of the newly issued debt are less than the net carrying value of the original debt, a gain is recorded for the difference and the carrying value of the newly issued debt is adjusted to the future undiscounted cash flow amount, with no interest expense recorded going forward. For the remaining TDR exchanges, where the future undiscounted cash flows are greater than the net carrying value of the original debt, no gain is recognized and a new effective interest rate is established. Accordingly, we recognized a gain of $304 million in our consolidated statement of operations. Direct costs incurred of $29 million related to the notes exchange were also recognized. Additionally, we purchased in the open market approximately $119 million aggregate principal amount of our 3.25% Senior Notes due 2016 for cash. We recorded a gain of approximately $5 million associated with this repurchase.

Income Tax Expense (Benefit). We recorded income tax expense of $2 million in 2017, and income tax benefits of $190 million and $4.463 billion in 2016 and 2015, respectively. Our effective income tax rate was 0.2% in 2017 compared to 4.1% in 2016 and 23.4% in 2015. The decrease in the effective income tax rate from 2016 to 2017 is primarily due to the intraperiod tax allocation provisions under GAAP applicable to 2016 which are not applicable in 2017. Further, our effective tax rate can fluctuate as a result of the impact of state income taxes and permanent differences. See Note 6 of the notes to our consolidated financial statements included in Item 8 of this report for a discussion of income tax expense (benefit).

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States require us to make estimates and assumptions. The accounting estimates and assumptions we consider to be most significant to our financial statements are discussed below. Our management has discussed each critical accounting estimates with the Audit Committee of our Board of Directors.

Impairment of Oil and Natural Gas Properties. The accounting for our business is subject to special accounting rules that are unique to the oil and natural gas industry. There are two allowable methods of accounting for oil and natural gas business activities: the successful efforts method and the full cost method. We follow the full cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized. We also capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not capitalize any costs related to production, general corporate overhead or similar activities.

Under the full cost method, capitalized costs are amortized on a composite unit-of-production method based on proved oil and natural gas reserves. If we maintain the same level of production year over year, the depreciation, depletion and amortization expense may be significantly different if our estimate of remaining reserves or future development costs changes significantly.

We review the carrying value of our oil and natural gas properties under the full cost method of accounting prescribed by the SEC on a quarterly basis. This quarterly review is referred to as a ceiling test. Under the ceiling test,

capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for oil and natural gas cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects.

Two primary factors impacting this test are reserve levels and oil and natural gas prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of oil and natural gas reserves and/or an increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value, less deferred income taxes, is generally written off as an expense. See Oil and Natural Gas Properties in Note 1 of the notes to our consolidated financial statements included in Item 8 of this report for further information on the full cost method of accounting.

Oil and Natural Gas Reserves. Estimates of oil and natural gas reserves and their values, future production rates and future costs and expenses require significant estimation and assumption. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. These revisions could materially affect our financial statements. The volatility of commodity prices results in increased uncertainty inherent in these estimates and assumptions. Changes in oil, natural gas or NGL prices could result in actual results differing significantly from our estimates. See Supplemental Disclosures About Oil, Natural Gas, and NGL Producing Activities included in Item 8 of this report for further information.

Derivatives. We use commodity price and financial risk management instruments to mitigate a portion of our exposure to price fluctuations in oil, natural gas and NGL prices. Results of commodity derivative contracts are reflected in oil, natural gas and NGL revenues and results of interest rate and foreign exchange rate derivative contracts are reflected in interest expense.

One of the primary factors that can have an impact on our results of operations is the method used to value our derivatives. We have established the fair value of our derivative instruments utilizing established index prices, volatility curves and discount factors. These estimates are compared to counterparty valuations for reasonableness. Derivative transactions are also subject 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. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. Additionally, in accordance with accounting guidance for derivatives and hedging, to the extent that a legal right of set-off exists, we net the value of our derivative instruments with the same counterparty in the accompanying consolidated balance sheets.

Another factor that can impact our results of operations each period is our ability to estimate the level of correlation between future changes in the fair value of the derivative instruments and the transactions being hedged, both at inception and on an ongoing basis. This correlation is complicated since energy commodity prices, the primary risk we hedge, have quality and location differences that can be difficult to hedge effectively. The factors underlying our estimates of fair value and our assessment of correlation of our derivative instruments are impacted by actual results and changes in conditions that affect these factors, many of which are beyond our control.

Due to the volatility of oil, natural gas and NGL prices and, to a lesser extent, interest rates and foreign exchange rates, our financial condition and results of operations may be significantly impacted by changes in the market value of our derivative instruments. As of December 31, 2017 and 2016, the fair values of our derivatives were net liabilities of $35 million and net liabilities of $577 million, respectively.

Income Taxes. The amount of income taxes recorded requires interpretations and application of complex rules and regulations pertaining to federal, state and local taxing jurisdictions. Income taxes are accounted for using the asset and liability method as required by GAAP. We recognize deferred tax assets and liabilities for temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements. Deferred tax assets for NOL and tax credit carryforwards have also been recognized. We routinely assess the realizability of our deferred tax assets and reduce such assets by a valuation allowance if it is more-likely-than-not that all or some portion of the deferred tax assets will not be realized. In assessing the need for additional valuation allowances or adjustments to existing valuation allowances, we consider the weight of all available evidence, both positive and negative, concerning the realization of the deferred tax asset. Among the more significant types of evidence that we consider are:

•	taxable income projections in future years;

•	reversal of existing deferred tax liabilities against deferred tax assets and whether the carryforward period is so brief that it would limit realization of the tax benefit;

•	future sales and operating cost projections that will produce more than enough taxable income to realize the deferred tax asset based on existing sales prices and cost structures; and

•	our earnings history exclusive of the loss that created the future deductible amount coupled with evidence indicating that the loss is an aberration rather than a continuing condition.

Our judgments and assumptions in estimating future taxable income include such factors as future operating conditions and commodity prices when determining if deferred tax assets are not more-likely-than-not to be realized. As of December 31, 2017 and 2016, we had deferred tax assets totaling $2.826 billion and $4.690 billion upon which we had a valuation allowance of $2.674 billion and $4.389 billion, respectively.

We also routinely assess potential uncertain tax positions and, if required, establish accruals for such positions. Accounting guidance for recognizing and measuring uncertain tax positions requires that a more-likely-than-not threshold condition be met on a tax position, based solely on its technical merits of being sustained, before any benefit of the uncertain tax position can be recognized in the financial statements. Guidance is also provided regarding de-recognition, classification and disclosure of these uncertain tax positions. If a tax position does not meet or exceed the more-likely-than-not threshold then no benefit can be recorded. We accrue any applicable interest related to uncertain tax positions as a component of interest expense. Penalties, if any, related to uncertain tax positions would be recorded in other expense. Additional information about uncertain tax positions appears in Note 6 of the notes to our consolidated financial statements included in Item 8 of this report.

Disclosures About Effects of Transactions with Related Parties

Our equity method investees are considered related parties. See Note 7 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of transactions with our equity method investees.