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

Overview

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

Although we have taken measures to mitigate liquidity concerns over the next 12 months, as outlined above in Overview, there can be no assurance that these measures will be sufficient for periods beyond the next 12 months. If needed, we may seek to access the capital markets or otherwise refinance a portion of our outstanding indebtedness to improve our liquidity. We 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 facilities. Furthermore, our ability to generate operating cash flow in the current commodity price environment, sell assets, access capital markets or take any other action to improve our liquidity and manage our debt is subject to the risks discussed above and the other risks and uncertainties that exist in our industry, some of which we may not be able to anticipate at this time or control.

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 NGL, 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, 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.

Oil Derivatives(a)
Year		Type of Derivative Instrument		Notional Volume			Average NYMEX Price
				(mmbbls)
2019		Swaps		17			$57.16
2019		Two-way collars		6			$58.00/$67.75
2019		Basis protection swaps		7			$6.01
2019		Puts		2			$53.83
2020		Swaps		7			$58.28
2020		Two-way collars		2			$65.00/$83.25
Natural Gas Derivatives(a)
Year		Type of Derivative Instrument		Notional Volume			Average NYMEX Price
				(bcf)
2019		Swaps		453			$2.87
2019		Two-way collars		55			$2.75/$3.02
2019		Three-way collars		88			$2.50/$2.80/$3.10
2019		Calls		22			$12.00
2019		Basis protection swaps		50			($0.56)
2020		Swaps		217			$2.75
2020		Call swaptions		106			$2.77
2020		Calls		22			$12.00

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(a)	Includes amounts settled in January and February 2019.

See Note 13 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of derivatives and hedging activities.

Debt

We decreased our total principal amount of debt outstanding by approximately $1.8 billion in 2018. We accomplished this primarily by using the net proceeds from the sale of our Utica interests and other assets. We currently plan to use cash flow from operations and availability under our credit facilities to fund our capital expenditures for 2019. We are seeking to reduce cash costs (production, gathering, processing and transportation, general and administrative and interest expenses), improve our production volumes from existing wells, and achieve additional operating and capital efficiencies with a focus on growing our oil volumes.

In 2018, we issued at par $850 million of 7.00% Senior Notes due 2024 (the “2024 notes”) and $400 million of 7.50% Senior Notes due 2026 (the “2026 notes” and, together with the 2024 notes, the “senior notes”) pursuant to a public offering for net proceeds of approximately $1.236 billion. We may redeem some or all of the 2024 notes at any time prior to April 1, 2021 and some or all of the 2026 notes at any time prior to October 1, 2021, in each case at a price equal to 100% of the principal amount of the notes to be redeemed plus a “make-whole” premium.

We used the net proceeds from the senior notes, together with cash on hand and borrowings under the Chesapeake revolving credit facility, to repay in full $1.233 billion of borrowings under our secured term loan due 2021 for $1.285 billion, which included a $52 million make-whole premium. We recorded a loss of approximately $65 million associated with the repayment of the term loan, including the make-whole premium and the write-off of $13 million of associated deferred charges. Also in 2018, we used the proceeds from the sale of our Utica assets in Ohio to redeem all of the $1.416 billion aggregate principal amount outstanding of our 8.00% Senior Secured Second Lien Notes due 2022 which included a $60 million make-whole premium. We recorded a gain of approximately $331 million associated with the redemption, including the realization of the remaining $391 million difference in principal and book value due to troubled debt restructuring accounting in 2015, offset by the make-whole premium of $60 million.

We may continue to use a combination of cash, borrowings and issuances of our common stock or other securities to retire our outstanding debt, including any debt assumed in connection with the completion with the WildHorse acquisition, through privately negotiated transactions, open market repurchases, redemptions, tender offers or otherwise, but we are under no obligation to do so. We expect to generate additional liquidity with proceeds from future sales of assets that do not fit our strategic priorities.

Chesapeake Revolving Credit Facility

The Chesapeake revolving credit facility is currently subject to a $3.0 billion borrowing base that matures in September 2023. As of December 31, 2018, we had $2.474 billion of borrowing capacity available under the Chesapeake revolving credit facility. Our next borrowing base redetermination is scheduled for the second quarter of 2019. As of December 31, 2018, we had outstanding borrowings of $419 million under the Chesapeake revolving credit facility and had used $107 million of the Chesapeake revolving credit facility for various letters of credit. Borrowings under the facility bear interest at a variable rate. Under the Chesapeake revolving credit facility, we borrowed $11.697 billion and repaid $12.059 billion in 2018, we borrowed $7.771 billion and repaid $6.990 billion in 2017 and we borrowed and repaid $5.146 billion in 2016. See Note 3 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of the terms of the Chesapeake revolving credit facility. As of December 31, 2018, we were in compliance with all applicable financial covenants under the credit agreement. Our leverage ratio was approximately 3.31 to 1.00. Our secured leverage ratio and fixed charge coverage ratio were not in effect for the quarter ended December 31, 2018, due to the Utica Shale divestiture taking place during the quarter. Both ratios, in addition to the leverage ratio, will be in effect for the quarter ending March 31, 2019.

WildHorse Revolving Credit Facility

In connection with the acquisition of WildHorse, our subsidiary Brazos Valley Longhorn became the borrower under the WildHorse revolving credit facility. The WildHorse revolving credit facility has a maximum credit amount of $2.0 billion, with current aggregate elected commitments of $1.3 billion and a current borrowing base of $1.3 billion. The WildHorse revolving credit facility matures in December 2021. The borrowing base under the WildHorse revolving credit facility is subject to redetermination, on at least a semi-annual basis, primarily on estimated proved reserves. The next scheduled redetermination is in the second quarter of 2019. As of the WildHorse acquisition date of February 1, 2019, we had $578 million of borrowing capacity available under the WildHorse revolving credit facility, with outstanding borrowings of $675 million and $47 million utilized as a letter of credit. The WildHorse revolving credit facility is guaranteed by certain of Brazos Valley Longhorn’s subsidiaries (the “BVL Guarantors”) and is required to be secured by substantially all of the assets of Brazos Valley Longhorn and BVL Guarantors, including mortgages on not less than 85% of the proved reserves of their oil and gas properties.

The obligations under the WildHorse revolving credit facility are the senior secured obligations of Brazos Valley Longhorn and the BVL Guarantors. The obligations under the WildHorse revolving credit facility will not be obligations of Chesapeake or any of its subsidiaries other than Brazos Valley Longhorn and the BVL Guarantors. The obligations under the WildHorse revolving credit facility will rank equally in right of payment with all other senior secured indebtedness of Brazos Valley Longhorn and the other BVL Guarantors, and will be effectively senior to Brazos Valley Longhorn’s and the BVL Guarantors’ senior unsecured indebtedness, including their obligations under the WildHorse senior notes, to the extent of the value of the collateral securing the WildHorse revolving credit facility.

The Wildhorse revolving credit facility is used for the liquidity and expenses of Brazos Valley Longhorn and its subsidiaries and not Chesapeake or any of its subsidiaries other than Brazos Valley Longhorn, Brazos Valley Longhorn Finance Corp. (“BVL Finance Corp.”) and the other BVL Guarantors. Revolving loans under the WildHorse revolving credit facility bear interest at the alternate base rate, Eurodollar rate or LIBOR market index rate at Brazos Valley Longhorn’s election, plus an applicable margin (ranging from 0.50%-1.50% per annum for alternate base rate loans, 1.50%-2.50% per annum for Eurodollar loans and 1.50%-2.50% per annum for LIBOR market index rate loans), depending on Brazos Valley Longhorn’s total commitment usage. The unused portion of the total commitments are subject to a commitment fee that varies from 0.375% to 0.500%, depending on Brazos Valley Longhorn’s total commitment usage. The terms of the WildHorse revolving credit facility include covenants limiting, among other things, the ability of Brazos Valley Longhorn and its Restricted Subsidiaries (as defined under the WildHorse revolving credit facility) to incur additional indebtedness, make investments or loans, incur liens, consummate mergers or similar fundamental changes, make restricted payments, including dividends to Chesapeake, and enter into transactions with affiliates, including Chesapeake and its other subsidiaries. The WildHorse revolving credit facility also contains financial covenants that require Brazos Valley Longhorn to maintain (i)(x) if there are no loans outstanding thereunder, a ratio of net debt to EBITDAX (as defined under the WildHorse revolving credit facility) of not more than 4.00 to 1.00 as of the last day of each fiscal quarter or (y) if there are such loans outstanding, a ratio of total debt to EBITDAX of not more than 4.00 to 1.00 as of the last day of each fiscal quarter and (ii) a ratio of current assets (including availability under the WildHorse revolving credit facility) to current liabilities of not less than 1.00 to 1.00 as of the last day of each fiscal quarter. As of December 31, 2018, WildHorse was in compliance with all applicable financial covenants under the credit agreement. WildHorse’s ratio of net debt to EBITDAX was 1.81 to 1.00 and our ratio of current assets was 4.30 to 1.00 as of December 31, 2018.

The WildHorse revolving credit facility includes events of default relating to customary matters, including, among other things, nonpayment of principal, interest or other amounts; violation of covenants; incorrectness of representations and warranties in any material respect; defaults with respect to indebtedness in an aggregate principal amount of $25.0 million or more; bankruptcy; judgments involving liability of $15.0 million or more that are not paid; change of control; and ERISA events. Many events of default are subject to customary notice and cure periods.

WildHorse Senior Notes

As a result of the completion of the acquisition of WildHorse, Brazos Valley Longhorn assumed the obligations under WildHorse’s $700 million aggregate principal amount of 6.875% Senior Notes due 2025 (the “WildHorse senior notes”) and BVL Finance Corp., a wholly owned subsidiary of Brazos Valley Longhorn, became a co-issuer of the WildHorse senior notes.

The WildHorse senior notes are the senior unsecured obligations of Brazos Valley Longhorn, BVL Finance Corp. and the other BVL Guarantors. The WildHorse senior notes will not be obligations of Chesapeake or any of its subsidiaries other than Brazos Valley Longhorn, BVL Finance Corp. and the other BVL Guarantors. The WildHorse senior notes will rank equally in right of payment with all other senior unsecured indebtedness of Brazos Valley Longhorn, BVL Finance Corp. and the other BVL Guarantors, and will be effectively subordinated to Brazos Valley Longhorn’s, BVL Finance Corp.’s and the other BVL Guarantors’ senior secured indebtedness, including their obligations under the WildHorse revolving credit facility, to the extent of the value of the collateral securing such indebtedness.

The indenture (the “WildHorse indenture”) governing the WildHorse senior notes contains customary reporting covenants (including furnishing quarterly and annual reports to the holders of the WildHorse senior notes) and restrictive covenants that, among other things, restrict the ability of Brazos Valley Longhorn and its subsidiaries to: (i) pay dividends on, purchase or redeem Brazos Valley Longhorn’s equity interests or purchase or redeem subordinated debt; (ii) make certain investments; (iii) incur or guarantee additional indebtedness or issue certain types of equity securities; (iv) create or incur certain secured debt; (v) sell assets; (vi) consolidate, merge or transfer all or substantially all of Brazos Valley Longhorn’s assets; (vii) enter into agreements that restrict distributions or other payments from Brazos Valley Longhorn’s restricted subsidiaries to Brazos Valley Longhorn; (viii) engage in transactions with affiliates, including Chesapeake and its other subsidiaries; and (ix) create unrestricted subsidiaries. These covenants are subject to a number of important qualifications and limitations. In addition, most of the covenants will be terminated before the WildHorse senior notes mature if at any time no default or event of default exists under the WildHorse indenture and the WildHorse senior notes receive an investment grade rating from both of two specified ratings agencies. The WildHorse indenture also contains customary events of default.

If the WildHorse senior notes are downgraded within 90 days after the consummation of the acquisition of WildHorse (which constitutes a “Change of Control” under the WildHorse indenture), the WildHorse indenture requires Brazos Valley Longhorn (or a third party, in certain circumstances) to make an offer to repurchase the WildHorse senior notes at 101% of their principal amount, plus accrued and unpaid interest, within 30 days of such downgrade. If any holder of WildHorse senior notes accepts such offer, Brazos Valley Longhorn may (subject to the terms and conditions thereof) fund the purchase price with loans under the WildHorse revolving credit facility or Chesapeake may elect to draw under the Chesapeake revolving credit facility, use cash on hand, issue debt securities or use other sources of liquidity to fund such repurchase. If Brazos Valley Longhorn and Chesapeake are not required to make such offer or not all holders of WildHorse senior notes accept such an offer, Chesapeake may seek to amend, engage in liability management transactions with respect to, or redeem or refinance, the WildHorse senior notes at any time.

The WildHorse revolving credit facility and the WildHorse Indenture constrain the ability of WildHorse and its subsidiaries to make distributions or otherwise provide funds to, or guarantee the obligations of, Chesapeake and its other subsidiaries. The provisions of the WildHorse revolving credit facility and the WildHorse Indenture require that all transactions between WildHorse and its subsidiaries, on the one hand, and Chesapeake and its other subsidiaries, on the other hand, be on an arm's-length basis

Contractual Obligations and Off-Balance Sheet Arrangements

From time to time, we enter into arrangements and transactions that can give rise to contractual obligations and off-balance sheet commitments. The table below summarizes our contractual cash obligations for both recorded obligations and certain off-balance sheet arrangements and commitments as of December 31, 2018:

		Payments Due By Period
		Total				2019				2020-2021				2022-2023				2024 and Beyond
		($ in millions)
Long-term debt:(a)
Principal(b)		$	8,168			$	381			$	1,479			$	1,208			$	5,100
Interest		3,058				523				942				793				800
Capital lease obligation(c)		30				10				20				—				—
Operating lease obligations(d)		4				3				1				—				—
Operating commitments(e)		5,786				837				1,467				1,051				2,431
Unrecognized tax benefits(f)		53				—				—				53				—
Standby letters of credit		107				107				—				—				—
Other		18				4				8				6				—
Total contractual cash obligations(g)		$	17,224			$	1,865			$	3,917			$	3,111			$	8,331

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(a)	We assumed $1.4 billion of debt with the completion of the WildHorse acquisition on February 1, 2019 that is not included in the table above.

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

(c)	See Note 6 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our capital lease obligation.

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

(e)	See Note 4 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our gathering, processing and transportation agreements and service contract commitments.

(f)	See Note 8 of the notes to our consolidated financial statements included in Item 8 of this report for a discussion of unrecognized tax benefits.

(g) This table does not include derivative liabilities or the estimated discounted liability for future dismantlement, abandonment and restoration costs of oil and natural gas properties. See Notes 13 and 21, respectively, of the

notes to our consolidated financial statements included in Item 8 of this report for more information on our derivatives and asset retirement obligations. This table also does not include our costs to produce reserves attributable to non-expense-bearing royalty and other interests in our properties, including VPPs, which are discussed in Note 14 of the notes to our consolidated financial statements included in Item 8 of this report.

Capital Expenditures

Our 2019 capital expenditures program is expected to generate greater capital efficiency than the 2018 program as we focus on expanding our margins through disciplined investing in the highest-return projects. 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 2019 capital expenditures, inclusive of Brazos Valley and capitalized interest, are $2.3 – $2.5 billion compared to our 2018 capital spending level of $2.4 billion. Management continues to review operational plans for 2019 and beyond, which could result in changes to projected capital expenditures and projected revenues from sales of oil, natural gas and NGL.

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, 2018, 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 ($976 million as of December 31, 2018) and exploration and production companies that own interests in properties we operate ($211 million as of December 31, 2018). This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in 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 2018, 2017 and 2016, we recognized $6 million, $9 million and $10 million, respectively, of bad debt expense related to potentially uncollectible receivables.

Some of our counterparties have requested or required us to post collateral as financial assurance of our performance under certain contractual arrangements, such as gathering, processing, transportation and hedging agreements. As of February 22, 2019, we have received requests and posted approximately $162 million of collateral related to certain of our marketing and other contracts. We may be requested or required by other counterparties to post additional collateral in an aggregate amount of approximately $355 million, which may be in the form of additional letters of credit, cash or other acceptable collateral. However, we have substantial long-term business relationships with each of these counterparties, and we may be able to mitigate any collateral requests through ongoing business arrangements and by offsetting amounts that the counterparty owes us. Any posting of collateral consisting of cash or letters of credit reduces availability under our revolving credit facility and negatively impacts our liquidity.

Sources of Funds

The following table presents the sources of our cash and cash equivalents for the years ended December 31, 2018, 2017 and 2016. See Note 14 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,
		2018				2017				2016
		($ in millions)
Cash provided by (used in) operating activities		$	2,000			$	745			$	(204	)
Proceeds from issuances of debt, net		1,236				1,585				3,686
Proceeds from revolving credit facility borrowings, net		—				781				—
Proceeds from divestitures of proved and unproved properties, net		2,231				1,249				1,406
Proceeds from sales of other property and equipment, net		147				55				131
Proceeds from sales of investments		74				—				—
Total sources of cash and cash equivalents		$	5,688			$	4,415			$	5,019

Cash Flow from Operating Activities

Cash provided by operating activities was $2.000 billion in 2018 compared to cash provided by operating activities of $745 million in 2017 and cash used in operating activities of $204 million in 2016. The increase in 2018 is primarily the result of higher prices for the oil, natural gas and NGL we sold. 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. Changes in cash flow from operations are largely due to the same factors that affect our net income, excluding various non-cash items, such as depreciation, depletion and amortization, certain impairments, gains or losses on sales of fixed assets, deferred income taxes and mark-to-market changes in our derivative instruments. See further discussion below under Results of Operations.

Debt issuances

The following table reflects the proceeds received from issuances of debt in 2018, 2017 and 2016. 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,
		2018								2017								2016
		Principal Amount of Debt Issued				Net Proceeds				Principal Amount of Debt Issued				Net Proceeds				Principal Amount of Debt Issued				Net Proceeds
		($ in millions)
Senior notes		$	1,250			$	1,236			$	1,600			$	1,585			$	1,000			$	975
Convertible senior notes		—				—				—				—				1,250				1,235
Term loans		—				—				—				—				1,500				1,476
Total		$	1,250			$	1,236			$	1,600			$	1,585			$	3,750			$	3,686

Divestitures of Proved and Unproved Properties

During 2018, we divested $2.231 billion of proved and unproved properties including $1.868 billion for all of our Utica Shale properties in Ohio. During 2017 and 2016, we divested certain non-core assets for approximately $1.249 billion and $1.406 billion, respectively. Proceeds from these transactions were used to repay debt and fund our development program. See Note 14 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion.

Uses of Funds

The following table presents the uses of our cash and cash equivalents for the years ended December 31, 2018, 2017 and 2016:

		Years Ended December 31,
		2018				2017				2016
		($ in millions)
Oil and Natural Gas Expenditures:
Drilling and completion costs		$	1,958			$	2,186			$	1,295
Acquisitions of proved and unproved properties		135				101				552
Interest capitalized on unproved leasehold		153				184				236
Total oil and natural gas expenditures		2,246				2,471				2,083
Other Uses of Cash and Cash Equivalents:
Cash paid to purchase debt		2,813				2,592				2,734
Payments on revolving credit facility borrowings, net		362				—				—
Extinguishment of other financing		122				—				—
Additions to other property and equipment		21				21				37
Cash paid for preferred stock dividends		92				183				—
Distributions to noncontrolling interest owners		6				8				10
Other		27				17				98
Total other uses of cash and cash equivalents		3,443				2,821				2,879
Total uses of cash and cash equivalents		$	5,689			$	5,292			$	4,962

Drilling and Completion Costs

Our drilling and completion costs decreased in 2018 compared to 2017 primarily as a result of decreased completion activity. We completed 351 operated wells in 2018 compared to 401 in 2017.

Cash Paid to Purchase Debt

In 2018, we used $2.813 billion of cash to repurchase $2.701 billion principal amount 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.

Extinguishment of Other Financing

In 2018, we repurchased previously conveyed overriding royalty interests (ORRIs) from the CHK Utica, L.L.C. investors and extinguished our obligation to convey future ORRIs to the investors for combined consideration of $199 million. The cash paid was bifurcated between extinguishment of the obligation and acquisition of the ORRI. See Note 5 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of the transaction.

Dividends

We paid dividends of $92 million on our preferred stock during 2018 and paid dividends of $183 million on our preferred stock in 2017, including $92 million of dividends in arrears that had been suspended throughout 2016. We did not pay dividends on our preferred stock in 2016. We eliminated common stock dividends in the 2015 third quarter and do not intend to resume paying cash dividends on our common stock in the foreseeable future.

Results of Operations

Oil, Natural Gas and NGL Production and Average Sales Prices

		2018
		Oil						Natural Gas						NGL						Total
		mbbl per day			$/bbl			mmcf per day			$/mcf			mbbl per day			$/bbl			mboe per day			%			$/boe
Marcellus		—			—			828			3.06			—			—			138			26			18.38
Haynesville		—			—			789			2.90			—			—			131			25			17.43
Eagle Ford		60			69.01			137			3.46			20			25.57			103			20			49.93
Powder River Basin		11			63.38			64			2.91			4			26.83			25			5			38.20
Mid-Continent		9			63.93			64			2.76			5			26.43			25			5			36.23
Retained assets(a)		80			67.67			1,882			3.01			29			25.88			422			81			27.98
Divested assets(b)		10			63.72			396			2.90			23			27.26			99			19			24.26
Total		90			67.25			2,278			2.99			52			26.50			521			100	%		27.27
		2017
		Oil						Natural Gas						NGL						Total
		mbbl per day			$/bbl			mmcf per day			$/mcf			mbbl per day			$/bbl			mboe per day			%			$/boe
Marcellus		—			—			804			2.45			—			—			134			24			14.67
Haynesville		—			—			784			2.85			—			—			131			24			17.10
Eagle Ford		59			52.34			142			3.30			18			22.95			100			18			39.24
Powder River Basin		6			49.97			37			3.01			3			27.33			15			3			32.57
Mid-Continent		8			49.24			69			2.79			5			22.99			25			5			28.77
Retained assets(a)		73			51.78			1,836			2.71			26			23.37			405			74			23.07
Divested assets(b)		17			47.87			570			2.92			31			23.02			143			26			22.34
Total		90			51.03			2,406			2.76			57			23.18			548			100	%		22.88
		2016
		Oil						Natural Gas						NGL						Total
		mbbl per day			$/bbl			mmcf per day			$/mcf			mbbl per day			$/bbl			mboe per day			%			$/boe
Marcellus		—			—			730			1.56			—			—			121			19			9.31
Haynesville		—			—			681			2.31			—			—			114			18			13.87
Eagle Ford		56			42.19			140			2.61			17			14.85			97			15			30.97
Powder River Basin		6			39.58			37			2.36			3			17.27			15			3			24.78
Mid-Continent		5			42.47			39			2.27			3			16.71			14			2			23.55
Retained assets(a)		67			41.98			1,627			2.00			23			15.26			361			57			17.76
Divested assets(b)		24			36.89			1,240			2.13			44			14.50			274			43			15.13
Total		91			40.65			2,867			2.05			67			14.76			635			100	%		16.63

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(a) Includes assets retained as of December 31, 2018.

(b)	Divested assets include Barnett, Devonian and certain Mid-Continent assets in 2016, certain Haynesville assets in 2017 and Utica assets in Ohio in 2018.

Oil, Natural Gas and NGL Sales

		Years Ended December 31,
		2018				change			2017				change			2016
		($ in millions)
Oil		$	2,201			32	%		$	1,668			23	%		$	1,351
Natural gas		2,486				3	%		2,422				12	%		2,155
NGL		502				4	%		484				34	%		360
Oil, natural gas and NGL sales		$	5,189			13	%		$	4,574			18	%		$	3,866

2018 vs. 2017. The increase in the price received per boe in 2018 resulted in an $836 million increase in revenues, and decreased sales volumes resulted in a $221 million decrease in revenues, for a total net increase in revenues of $615 million.

2017 vs. 2016. The increase in the price received per boe in 2017 resulted in a $1.250 billion increase in revenues, and decreased sales volumes resulted in a $542 million decrease in revenues, for a total net increase in revenues of $708 million.

See Note 7 of the notes to our consolidated financial statements included in Item 8 of this report for a complete discussion of oil, natural gas and NGL sales.

Oil, Natural Gas and NGL Derivatives

		Years Ended December 31,
		2018				2017				2016
		($ in millions)
Oil derivatives – realized gains (losses)		$	(321	)		$	70			$	97
Oil derivatives – unrealized gains (losses)		445				(134		)		(318		)
Total gains (losses) on oil derivatives		124				(64		)		(221		)
Natural gas derivatives – realized gains (losses)		7				(9		)		151
Natural gas derivatives – unrealized gains (losses)		(154		)		489				(500		)
Total gains (losses) on natural gas derivatives		(147		)		480				(349		)
NGL derivatives – realized gains (losses)		(13		)		(4		)		(8		)
NGL derivatives – unrealized gains (losses)		2				(1		)		—
Total gains (losses) on NGL derivatives		(11		)		(5		)		(8		)
Total gains (losses) on oil, natural gas and NGL derivatives		$	(34	)		$	411			$	(578	)

See Note 13 of the notes to our consolidated financial statements included in Item 8 of this report for a complete discussion of our derivative activity.

Marketing Revenues and Expenses

		Years Ended December 31,
		2018				change			2017				change			2016
		($ in millions)
Marketing revenues		$	5,076			13	%		$	4,511			(2	)%		$	4,584
Marketing expenses		5,158				12	%		4,598				(4	)%		4,778
Marketing gross margin		$	(82	)		6	%		$	(87	)		55	%		$	(194	)

2018 vs. 2017. Marketing revenues and expenses increased in 2018 primarily as a result of increased oil, natural gas and NGL prices received in our marketing operations. Gross margin was negatively impacted by downstream pipeline delivery commitments.

2017 vs. 2016. Marketing revenues and expenses decreased in 2017 primarily as a result of decreased oil, natural gas and NGL prices received in our marketing operations. 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.

Oil, Natural Gas and NGL Production Expenses

		Years Ended December 31,
		2018				change			2017				change			2016
		($ in millions)
Oil, natural gas and NGL production expenses
Marcellus		$	34			21	%		$	28			—	%		$	28
Haynesville		57				8	%		53				33	%		40
Eagle Ford		183				(3	)%		188				27	%		148
Powder River Basin		49				63	%		30				36	%		22
Mid-Continent		102				(8	)%		111				21	%		92
Retained Assets(a)		425				4	%		410				24	%		330
Divested Assets		49				(54	)%		107				(67	)%		325
Total		474				(8	)%		517				(21	)%		655
Ad valorem tax		65				44	%		45				(18	)%		55
Total oil, natural gas and NGL production expenses		$	539			(4	)%		$	562			(21	)%		$	710
		($ per boe)
Oil, natural gas and NGL production expenses
Marcellus		$	0.68			17	%		$	0.58			(8	)%		$	0.63
Haynesville		$	1.20			9	%		$	1.10			13	%		$	0.97
Eagle Ford		$	4.88			(5	)%		$	5.15			23	%		$	4.18
Powder River Basin		$	5.36			(3	)%		$	5.53			34	%		$	4.14
Mid-Continent		$	11.26			(7	)%		$	12.12			(30	)%		$	17.31
Retained Assets(a)		$	2.76			(1	)%		$	2.78			11	%		$	2.50
Divested Assets		$	1.34			(34	)%		$	2.04			(37	)%		$	3.23
Total		$	2.50			(3	)%		$	2.59			(8	)%		$	2.81
Ad valorem tax		$	0.34			55	%		$	0.22			(8	)%		$	0.24
Total oil, natural gas and NGL production expenses per boe		$	2.84			1	%		$	2.81			(8	)%		$	3.05

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(a) Includes assets retained as of December 31, 2018.

2018 vs. 2017. The absolute increase for retained properties was the result of increased production volumes related to our retained assets primarily in the Powder River Basin. The total per unit increase was the result of increased ad valorem tax primarily due to higher prices received for our oil, natural gas and NGL production. Production expenses in 2018 included approximately $15 million associated with VPP production volumes.

2017 vs. 2016. The absolute and per unit decrease was the result of the sale of certain oil and natural gas properties in 2016, partially offset by increased workover costs in the Eagle Ford and increased water disposal costs in the Eagle Ford and Mid-Continent. Production expenses in 2017 and 2016 included approximately $19 million and $44 million, respectively, associated with VPP production volumes.

We anticipate a continued decrease in production expenses associated with VPP production volumes as the contractually scheduled volumes under our remaining VPP agreement decrease and operating efficiencies generally improve.

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

		Years Ended December 31,
		2018				2017				2016
		($ in millions, except per unit)
Oil, natural gas and NGL gathering, processing and transportation expenses		$	1,398			$	1,471			$	1,855
Oil ($ per bbl)		$	4.30			$	3.94			$	3.61
Natural gas ($ per mcf)		$	1.32			$	1.34			$	1.47
NGL ($ per bbl)		$	8.37			$	7.88			$	7.83
Total ($ per boe)		$	7.35			$	7.36			$	7.98

2018 vs. 2017. The absolute and per unit decrease for oil and natural gas gathering, processing and transportation expenses was primarily due to lower gathering fees associated with restructured midstream contracts, lower volume commitments on downstream pipelines and certain 2017 and 2018 divestitures.

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

Production Taxes

		Years Ended December 31,
		2018				change			2017				change			2016
		($ in millions, except per unit)
Production taxes		$	124			39	%		$	89			20	%		$	74
Production taxes per boe		$	0.65			48	%		$	0.44			38	%		$	0.32

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

General and Administrative Expenses

		Years Ended December 31,
		2018				change			2017				change			2016
		($ in millions, except per unit)
Gross overhead		$	714			(10	)%		$	791			(12	)%		$	900
Allocated to production expenses		(141		)		(20	)%		(177		)		(15	)%		(209		)
Allocated to marketing		(20		)		(31	)%		(29		)		(47	)%		(55		)
Capitalized general and administrative expenses		(119		)		(13	)%		(137		)		(8	)%		(149		)
Reimbursed from third parties		(154		)		(17	)%		(186		)		(25	)%		(247		)
General and administrative expenses, net		$	280			7	%		$	262			9	%		$	240
General and administrative expenses, net per boe		$	1.47			12	%		$	1.31			27	%		$	1.03

2018 vs. 2017. Gross overhead decreased primarily due to our reduction in workforce. The absolute and per unit net expense increase was primarily due to less overhead allocated to production expenses, marketing expenses and capitalized general and administrative costs, as well as lower producing overhead reimbursements from third party working interest owners, due to certain divestitures in 2017 and 2018.

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

Restructuring and Other Termination Costs. On January 30, 2018, we underwent a reduction in workforce impacting approximately 13% of employees across all functions, primarily on our Oklahoma City campus. In connection with the reduction, we incurred a total charge of approximately $38 million in 2018 for one-time termination benefits. The charge consisted of $33 million in salary and severance expense and $5 million in other termination benefits. In 2016, we recognized $6 million of charges related to a reduction of workforce in connection with the restructuring of our compressor manufacturing subsidiary and the reductions of workforce resulting from the conveyance of our interests in the Barnett Shale and Devonian Shale operating areas. See Note 19 of the notes to our consolidated financial statements included in Item 8 of this report for a discussion of our restructuring and termination costs.

Provision for Legal Contingencies, Net

		Years Ended December 31,
		2018				2017				2016
		($ in millions)
Provision for legal contingencies, net		$	26			$	(38	)		$	123

The 2018 and 2016 amounts consist of accruals for loss contingencies primarily related to royalty claims. The 2017 amount consists of the recovery of a legal settlement, partially offset by accruals for loss contingencies primarily related to royalty claims. See Note 4 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of royalty claims.

Oil, Natural Gas and NGL Depreciation, Depletion and Amortization

		Years Ended December 31,
		2018				change			2017				change			2016
		($ in millions, except per unit)
Oil, natural gas and NGL depreciation, depletion and amortization		$	1,145			15	%		$	995			(10	)%		$	1,107
Oil, natural gas and NGL depreciation, depletion and amortization per boe		$	6.02			21	%		$	4.98			5	%		$	4.76

2018 vs. 2017. The absolute and per unit increase in 2018 is primarily the result of a higher depletion rate per boe. The depletion rate per boe is a function of capitalized costs, future development costs, and the related underlying reserves in the periods presented. The increase in depletion rate per boe primarily reflects a downward revision in proved reserve estimates in the fourth quarter of 2017 due to an updated development plan in the Eagle Ford aligning up-spacing, our activity schedule and well performance.

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

Loss on Sale of Oil and Natural Gas Properties

In 2018, we sold all of our net acres in the Utica Shale operating area located in Ohio along with related property and equipment (collectively, the “Designated Properties”) for net proceeds of $1.868 billion to Encino. The sale of our Designated Properties to Encino involved a significant change in proved reserves under SEC rules for full cost companies and significantly altered the relationship between costs and proved reserves and therefore resulted in the recognition of loss of approximately $578 million. See Note 14 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of the transaction.

Impairments

		Years Ended December 31,
		2018				change			2017				change			2016
		($ in millions)
Impairments		$	53			960	%		$	5			(100	)%		$	3,025

In 2018, we recorded a $45 million impairment related to 890 compressors and $8 million for other property and equipment for the difference between the fair value and carrying value. In 2016, we recognized an impairment in the

carrying value of our oil and natural gas properties of $2.564 billion and impairments totaling $426 million related to other fixed assets sold in our Barnett Shale and Devonian Shale divestitures. See Note 17 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our impairments.

Other Operating Expense

		Years Ended December 31,
		2018				change			2017				change			2016
		($ in millions)
Other operating expense		$	10			(98	)%		$	413			13	%		$	365

The 2017 and 2016 amounts consist of discrete costs incurred to terminate various gathering and transportation agreements, including those associated with oil and natural gas asset divestitures. See Note 18 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our other operating expense.

Interest Expense

		Years Ended December 31,
		2018				2017				2016
		($ in millions)
Interest expense on senior notes		$	591			$	551			$	588
Interest expense on term loan		86				127				46
Amortization of loan discount, issuance costs and other		24				40				33
Amortization of premium		(88		)		(138		)		(165		)
Interest expense on revolving credit facility		37				39				35
Realized gains on interest rate derivatives		(3		)		(3		)		(11		)
Unrealized losses on interest rate derivatives		2				4				21
Capitalized interest		(162		)		(194		)		(251		)
Total interest expense		$	487			$	426			$	296
Interest expense per boe(a)		$	2.55			$	2.11			$	1.18
Average senior notes borrowings		$	8,160			$	7,714			$	8,749
Average credit facilities borrowings		$	505			$	443			$	195
Average term loan borrowings		$	911			$	1,446			$	537

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(a)	Includes the effects of realized (gains) losses from interest rate derivatives, excludes the effects of unrealized (gains) losses from interest rate derivatives and is shown net of amounts capitalized.

The decrease in capitalized interest is a result of lower average balances of unproved oil and natural gas properties, the primary asset on which interest is capitalized. 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.

Gains (Losses) on Investments. In 2018, FTS International, Inc. (NYSE: FTSI) completed an initial public offering. Due to the offering, the ownership percentage of our equity method investment in FTSI decreased from approximately 29% to 24% and resulted in a gain of $78 million. In addition, we sold approximately 4.3 million shares of FTSI in the offering for net proceeds of approximately $74 million and recognized a gain of $61 million decreasing our ownership percentage to approximately 20%. We continue to hold approximately 22.0 million shares in the publicly traded company. In 2016, we recognized an other-than-temporary impairment of our Sundrop Fuels Inc. (Sundrop) investment of $119 million. See Note 16 of the notes to our consolidated financial statements included in Item 8 of this report for a discussion of our investments.

Gains (Losses) on Purchases or Exchanges of Debt. In 2018, we used the net proceeds from the issuance of our 2024 and 2026 senior notes, together with cash on hand and borrowings under the Chesapeake revolving credit facility, to repay in full $1.233 billion of borrowings under our secured term loan due 2021 for $1.285 billion, which included a $52 million make-whole premium. We recorded a loss of approximately $65 million associated with the repayment of the term loan, including the make-whole premium and the write-off of $13 million of associated deferred charges. Also in 2018, we used the proceeds from the sale of our Utica assets in Ohio to redeem all of the $1.416 billion aggregate principal amount outstanding of our 8.00% Senior Secured Second Lien Notes due 2022 which included a $60 million call premium. We recorded a gain of approximately $331 million associated with the redemption, including the realization of the remaining $391 million difference in principal and book value due to troubled debt restructuring accounting in 2015, offset by the make-whole premium of $60 million. Additionally, we recorded a loss of $3 million associated with certain deferred charges related to the Chesapeake revolving credit facility prior to its amendment and restatement.

In 2017, we retired $2.389 billion principal amount of our outstanding senior notes, senior secured second lien 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.

Other Income. In 2018, we extinguished our obligation to convey future ORRIs to the CHK Utica L.L.C. investors and recognized a $61 million gain included in other income on our consolidated statement of operations. See Note 5 of the notes to our consolidated financial statements included in Item 8 of this report for a discussion of this transaction.

Income Tax Expense (Benefit). We recorded an income tax benefit of $10 million in 2018, income tax expense of $2 million in 2017 and an income tax benefit of $190 million in 2016. Our effective tax rate can fluctuate as a result of various items, including the impact of state income taxes, permanent differences, tax law changes and adjustments to the valuation allowance. See Note 8 of the notes to our consolidated financial statements included in Item 8 of this report for a discussion of income tax expense (benefit).

Critical Accounting Policies and Estimates

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

Oil and Natural Gas Properties. We follow the full cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized.

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.

Two primary factors impacting this test are reserve estimates and the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended December 31, 2018. Downward revisions to estimates of oil and natural gas reserves and/or unfavorable 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, future development costs and commodity pricing differentials are the most significant of our estimates. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. These revisions could materially affect our financial statements. The volatility of commodity prices results in increased uncertainty inherent in these estimates and assumptions. Changes in oil, natural gas or NGL prices could result in actual results differing significantly from our estimates. See Supplemental Disclosures About Oil, Natural Gas, and NGL Producing Activities included in Item 8 of this report for further information.

Derivatives. We use commodity 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 derivative contracts are reflected in interest expense.

Due to the volatility of oil, natural gas and NGL prices and, to a lesser extent, interest rates and foreign exchange rates, our financial condition and results of operations may be significantly impacted by changes in the market value of our derivative instruments. As of December 31, 2018 and 2017, the fair values of our derivatives were net assets of $282 million and net liabilities of $35 million, respectively.

One of the primary factors that can have an impact on our results of operations is the method used to value our derivatives. We have established the fair value of our derivative instruments utilizing established index prices, volatility curves and discount factors. These estimates are compared to counterparty valuations for reasonableness. Derivative transactions are also subject 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.

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, 2018 and 2017, we had deferred tax assets totaling $3.252 billion and $2.826 billion upon which we had a valuation allowance of $2.433 billion and $2.674 billion, respectively.

We also routinely assess potential uncertain tax positions and, if required, establish accruals for such positions. Accounting guidance for recognizing and measuring uncertain tax positions requires that a more likely than not threshold condition be met on a tax position, based solely on its technical merits of being sustained, before any benefit of the uncertain tax position can be recognized in the financial statements. Guidance is also provided regarding de-recognition, classification and disclosure of these uncertain tax positions. If a tax position does not meet or exceed the more likely than not threshold then no benefit can be recorded. We accrue any applicable interest related to uncertain tax positions as a component of interest expense. Penalties, if any, related to uncertain tax positions would be recorded in other expense. Additional information about uncertain tax positions appears in Note 8 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 9 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.