filings.toolsItem 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
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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 of this report.
Recent highlights include the following:
| • | acquired WildHorse, an oil and gas company with operations in the Eagle Ford Shale and Austin Chalk formations in southeast Texas, for approximately 717.4 million shares of our common stock and $381 million in cash, and the assumption of WildHorse’s debt of $1.4 billion as of February 1, 2019. We anticipate the acquisition to materially increase our oil production and enhance our oil production mix as well as significantly reduce costs due to operational synergies that we believe the combined company will achieve. We achieved $250 million of cost savings in 2019 and we expect that the WildHorse Merger will provide substantial cost savings with $200 million to $280 million in projected average annual savings, totaling $1 billion to $1.5 billion by 2023, due to operational and capital efficiencies as a result of Chesapeake’s significant expertise with unconventional assets and technical and operational excellence; |
| • | entered into a secured 4.5-year term loan facility for $1.5 billion to finance a tender offer for unsecured notes issued by Brazos Valley Longhorn and Brazos Valley Longhorn Finance Corp., each a wholly owned subsidiary of Chesapeake, and to fund the retirement of Brazos Valley Longhorn’s secured revolving credit facility; |
| • | exchanged new 11.5% Senior Secured Second Lien Notes due 2025 for 8.00% Senior Notes due 2027, 8.00% Senior Notes due 2026, 8.00% Senior Notes due 2025, 7.50% Senior Notes due 2026 and 7.00% Senior Notes due 2024. Also, we issued an additional $120 million of 11.5% Senior Secured Second Lien Notes due 2025 pursuant to a private offering, at 89.75% of par. These transactions resulted in the removal of approximately $900 million principal amount of debt from the company’s balance sheet. |
| • | privately negotiated exchanges of approximately $507 million principal amount of our outstanding senior notes for 235,563,519 shares of common stock and $186 million principal amount of our outstanding convertible senior notes for 73,389,094 shares of common stock, reducing annual interest payments; |
| • | exchanged 40,000 shares of our 5.75% (Series A) Cumulative Convertible Preferred Stock for 10,367,950 shares of common stock, reducing annual preferred stock dividend payments; |
| • | extended our debt maturity profile by privately exchanging approximately $884 million aggregate principal amount of our existing 6.625% Senior Notes due 2020, 6.875% Senior Notes due 2020, 6.125% Senior Notes due 2021 and 5.375% Senior Notes due 2021 for approximately $919 million aggregate principal amount of new 8.00% Senior Notes due 2026; and |
| • | improved our cost structure by reducing combined production, gathering, processing and transportation and general and administrative expenses by approximately $0.79 per boe, or $290 million in 2019 compared to 2018, or 13%. The primary driver in the reduction is lower gathering, processing and transportation expenses due to certain 2018 divestitures and recently renegotiated contracts. |
In 2020 and beyond, our focus remains concentrated on four long-term strategic priorities:
| • | reduce total leverage to achieve long-term net debt/EBITDAX of 2x; |
| • | achieve sustained free cash flow generation; |
| • | improve margins through financial discipline and operating efficiencies; and |
| • | maintain industry leading environmental and safety performance. |
Natural gas prices are at their lowest levels since the first half of 2016. Accordingly, a majority of our 2020 capital will be allocated to our higher margin oil assets with total expected 2020 capital expenditures being approximately 30% lower than 2019 while maintaining flat oil production. We plan to seek the lowest capital program possible to reach and sustain positive cash flow.
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 believe the prolonged lower commodity price environment has fundamentally changed the expectations of capital markets, resulting in new capital being both more difficult and more expensive to access. Currently, capital markets are no longer willing to fund organic growth. We believe our strategic priorities are consistent with these expectations as we look to continue to increase our cash flow and expand our margins by focusing on high-return drilling locations and reduced capital and operating costs using cash generated from operations and asset sales. We look to continue to reduce debt on our balance sheet with asset sales and liability management activities similar to those completed in 2019.
Change in Accounting Principle
During the first quarter of 2019, we changed our method of accounting for our oil and natural gas exploration and development activities from the full cost method to the successful efforts method of accounting. Financial information for all periods presented has been recast to reflect retrospective application of the successful efforts method of accounting. See Notes 1 and 2 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of the change in accounting principle.
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, 2019, we had a cash balance of $6 million compared to $4 million as of December 31, 2018, and a net working capital deficit of $1.141 billion as of December 31, 2019, compared to a net working capital deficit of $1.289 billion as of December 31, 2018. As of December 31, 2019, our working capital deficit includes $385 million of debt due in the next 12 months. Our total principal debt as of December 31, 2019 was $8.916 billion compared to $8.168 billion as of December 31, 2018. As of December 31, 2019, we had $1.351 billion of borrowing capacity available under our revolving credit facility, with outstanding borrowings of $1.590 billion and $59 million utilized for various letters of credit. See Note 5 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.
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 our exposure to adverse market price changes, we enter into various derivative instruments. Our oil, natural gas and NGL derivative activities, when combined with our sales of oil, natural gas and NGL, allow us to better predict the total revenue we expect to receive.
As of February 19, 2020, including January and February derivative contracts that have settled, approximately 70% of our 2020 forecasted oil, natural gas and NGL production revenue was hedged. We had approximately 76% downside oil price protection through swaps and collars at an average price of $59.90 per bbl. We had 39% downside gas price protection through swaps at $2.76 per mcf and 14% under put spread arrangements based on an average bought put NYMEX price of $2.05 per mcf and exposure below an average sold put NYMEX price of $1.80 per mcf.
| Oil Derivatives**(a)** | |||||||
| Year | Type of Derivative Instrument | Notional Volume | Average NYMEX Price | ||||
| (mmbbls) | |||||||
| 2020 | Swaps | 30 | $59.59 | ||||
| 2020 | Two-way collars | 2 | $65.00/$83.25 | ||||
| 2020 | Basis protection swaps | 12 | $2.57 | ||||
| 2021 | Calls | 4 | $61.58 | ||||
| 2022 | Calls | 4 | $61.58 | ||||
| Natural Gas Derivatives**(a)** | |||||||
| Year | Type of Derivative Instrument | Notional Volume | Average NYMEX Price | ||||
| (bcf) | |||||||
| 2020 | Swaps | 265 | $2.76 | ||||
| 2020 | Calls | 22 | $12.00 | ||||
| 2020 | Basis protection swaps | 53 | $0.03 | ||||
| 2020 | Put spread(b) | 94 | $1.80/$2.05 | ||||
| 2021 | Call swaptions | 15 | $2.80 | ||||
| 2021 | Calls | 96 | $2.75 | ||||
| 2022 | Call swaption | 15 | $2.80 |
| (a) | Includes amounts settled in January and February 2020. |
| (b) | Put spread: These instruments contain a fixed floor price (bought put) and sub floor price (sold put). If the market price exceeds the bought put strike, we receive the market price. If the market price is between the bought put and sold put strike prices, we receive the bought put price. If the market price falls below the subfloor, we receive the market price plus the difference between the sold put and bought put. |
See Note 14 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 are committed to reducing total leverage to achieve long-term net debt/EBITDAX of 2x. To accomplish this goal, we intend to allocate our capital expenditures to projects we believe offer the highest return and value regardless of the commodity price environment, to deploy leading drilling and completion technology throughout our portfolio, and to take advantage of acquisition and divestiture opportunities to strengthen our cost structure and our portfolio. Increasing our margins means not only increasing our absolute level of cash flows from operations, but also increasing our cash flows from operations generated per barrel of oil equivalent production. We continue to seek opportunities to reduce cash costs (production, gathering, processing and transportation and general and administrative), improve our production volumes from existing wells, and achieve additional operating and capital efficiencies with a focus on growing our oil volumes.
We may continue to use a combination of cash, borrowings and issuances of our common stock or other securities and the proceeds from asset sales to retire our outstanding debt or preferred stock through privately negotiated transactions, open market repurchases, redemptions, exchanges, tender offers or otherwise, but we are under no obligation to do so.
Revolving Credit Facility
Our revolving credit facility matures in September 2023 and the current aggregate commitment of the lenders and borrowing base under the facility is $3.0 billion. The revolving credit facility provides for an accordion feature, pursuant to which the aggregate commitments thereunder may be increased to up to $4.0 billion from time to time, subject to agreement of the participating lenders and certain other customary conditions. Scheduled borrowing base redeterminations will continue to occur semiannually. Our next borrowing base redetermination is scheduled for the second quarter of 2020. Borrowings under the facility bear interest at a variable rate. As of December 31, 2019, we had outstanding borrowings of $1.590 billion under our revolving credit facility and had used $59 million for various letters of credit. See Note 5 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of the terms of our revolving credit facility. As of December 31, 2019, we were in compliance with all applicable financial covenants under the credit agreement. As of December 31, 2019, our leverage ratio was approximately 3.43 to 1, our first lien leverage ratio was approximately 1.21 to 1 and our fixed charge coverage ratio was approximately 3.64 to 1.
Term Loan
In December 2019, we entered into a secured 4.5-year term loan facility in an aggregate principal amount of $1.5 billion for net proceeds of approximately $1.455 billion. Our obligations under the new facility are unconditionally guaranteed on a joint and several basis by the same subsidiaries that guarantee our revolving credit facility and second lien notes (including BVL and its subsidiaries) and are secured by first-priority liens on the same collateral securing our revolving credit facility (with a position in the collateral proceeds waterfall junior to the revolving credit facility). The term loan bears interest at a rate of London Interbank Offered Rate (LIBOR) plus 8.00% per annum, subject to a 1.00% LIBOR floor, or the Alternative Base Rate (ABR) plus 7.00% per annum, subject to a 2.00% ABR floor, at our option. The loan was made at 98% of par. We used the net proceeds to finance tender offers for our unsecured BVL senior notes and to fund the retirement of BVL’s secured revolving credit facility. The term loan matures in June 2024 and voluntary prepayments are subject to a make-whole premium prior to the 18-month anniversary of the closing of the term loan, a premium to par of 5.00% from the 18-month anniversary until but excluding the 30-month anniversary, a premium to par of 2.5% from the 30-month anniversary until but excluding the 42-month anniversary and at par beginning on the 42-month anniversary. The term loan may be subject to mandatory prepayments and offers to prepay with net cash proceeds of certain issuances of debt, certain asset sales and other dispositions of collateral and upon a change of control. See Note 5 of the notes to our consolidated financial statements included in Item 8 for further discussion of the term loan facility.
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, 2019:
| Payments Due By Period | ||||||||||||||||||||
| Total | 2020 | 2021-2022 | 2023-2024 | 2025 and Beyond | ||||||||||||||||
| ($ in millions) | ||||||||||||||||||||
| Long-term debt: | ||||||||||||||||||||
| Principal(a) | $ | 8,916 | $ | 385 | $ | 583 | $ | 3,888 | $ | 4,060 | ||||||||||
| Interest | 3,314 | 705 | 1,338 | 1,101 | 170 | |||||||||||||||
| Finance lease obligation(b) | 20 | 10 | 10 | — | — | |||||||||||||||
| Operating lease obligations(c) | 28 | 10 | 9 | 4 | 5 | |||||||||||||||
| Operating commitments(d) | 8,056 | 1,143 | 1,955 | 1,479 | 3,479 | |||||||||||||||
| Standby letters of credit | 59 | 59 | — | — | — | |||||||||||||||
| VPP obligation(e) | 64 | 55 | 9 | — | — | |||||||||||||||
| Other | 13 | 3 | 8 | 2 | — | |||||||||||||||
| Total contractual cash obligations(f) | $ | 20,470 | $ | 2,370 | $ | 3,912 | $ | 6,474 | $ | 7,714 |
| (a) | See Note 5 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our long-term debt. |
| (b) | See Note 8 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our finance lease obligation. |
| (c) | See Note 8 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our operating lease obligations. |
| (d) | See Note 6 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our gathering, processing and transportation agreements and service contract commitments. |
| (e) | See Note 7 of the notes to our consolidated financial statements included in Item 8 of this report for a discussion of our VPP obligation. |
(f) 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 14 and 22, 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.
Capital Expenditures
Our 2020 capital expenditures program is expected to generate greater capital efficiency than the 2019 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 2020 capital expenditures are $1.3 – $1.6 billion compared to our 2019 capital spending level of $2.2 billion. We reduced the midpoint of our 2020 range by approximately 30% from 2019 spending to improve our cash flow profile. Management continues to review operational plans for 2020 and beyond, which could result in changes to projected capital expenditures and projected revenues from sales of oil, natural gas and NGL.
Credit Risk
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 24, 2020, we have posted approximately $60 million of collateral related to certain of our marketing and other contracts. We may be requested or required by other counterparties to post additional collateral in an aggregate amount of approximately $220 million, which may be in the form of additional letters of credit, cash or other acceptable collateral. However, we have substantial long-term business relationships with each of these counterparties, and we may be able to mitigate any collateral requests through ongoing business arrangements and by offsetting amounts that the counterparty owes us. Any posting of collateral consisting of cash or letters of credit reduces availability under our revolving credit facility and negatively impacts our liquidity.
Sources of Funds
The following table presents the sources of our cash and cash equivalents for the years ended December 31, 2019, 2018 and 2017. See Note 3 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of divestitures of oil and natural gas assets.
| Years Ended December 31, | ||||||||||||
| 2019 | 2018 | 2017 | ||||||||||
| ($ in millions) | ||||||||||||
| Cash provided by operating activities | $ | 1,623 | $ | 1,730 | $ | 475 | ||||||
| Proceeds from issuances of debt, net | 1,563 | 1,236 | 1,585 | |||||||||
| Proceeds from revolving credit facility borrowings, net | 496 | — | 781 | |||||||||
| Proceeds from divestitures of proved and unproved properties, net | 130 | 2,231 | 1,249 | |||||||||
| Proceeds from sales of other property and equipment, net | 6 | 147 | 55 | |||||||||
| Proceeds from sales of investments | — | 74 | — | |||||||||
| Total sources of cash and cash equivalents | $ | 3,818 | $ | 5,418 | $ | 4,145 |
Cash Flow from Operating Activities
Cash provided by operating activities was $1.623 billion, $1.730 billion and $475 million in 2019, 2018 and 2017, respectively. The decrease in 2019 is primarily the result of lower prices for the oil, natural gas and NGL we sold as well as certain cash expenditures related to our WildHorse acquisition. The increase in 2018 is primarily the result of higher prices for the oil, natural gas and NGL we sold. Changes in cash flow from operations are largely due to the same factors that affect our net income, excluding various non-cash items, such as depreciation, depletion and amortization, certain impairments, gains or losses on sales of fixed assets, deferred income taxes and mark-to-market changes in our derivative instruments. See further discussion below under Results of Operations.
Debt issuances
The following table reflects the proceeds received from issuances of debt in 2019, 2018 and 2017. See Note 5 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion.
| Years Ended December 31, | ||||||||||||||||||||||||
| 2019 | 2018 | 2017 | ||||||||||||||||||||||
| Principal Amount of Debt Issued | Net Proceeds | Principal Amount of Debt Issued | Net Proceeds | Principal Amount of Debt Issued | Net Proceeds | |||||||||||||||||||
| ($ in millions) | ||||||||||||||||||||||||
| Term loan | $ | 1,500 | $ | 1,455 | $ | — | $ | — | $ | — | $ | — | ||||||||||||
| Senior secured second lien notes | 120 | 108 | — | — | — | — | ||||||||||||||||||
| Senior notes | — | — | 1,250 | 1,236 | 1,600 | 1,585 | ||||||||||||||||||
| Total | $ | 1,620 | $ | 1,563 | $ | 1,250 | $ | 1,236 | $ | 1,600 | $ | 1,585 |
Divestitures of Proved and Unproved Properties
During 2019, we divested certain non-core assets for approximately $130 million. 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, we divested certain non-core assets for approximately $1.249 billion. Proceeds from these transactions were used to repay debt and fund our development program. See Note 3 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion.
Uses of Funds
The following table presents the uses of our cash and cash equivalents for the years ended December 31, 2019, 2018 and 2017:
| Years Ended December 31, | ||||||||||||
| 2019 | 2018 | 2017 | ||||||||||
| ($ in millions) | ||||||||||||
| Oil and Natural Gas Expenditures: | ||||||||||||
| Drilling and completion costs | $ | 2,180 | $ | 1,848 | $ | 2,113 | ||||||
| Acquisitions of proved and unproved properties | 35 | 128 | 88 | |||||||||
| Total oil and natural gas expenditures | 2,215 | 1,976 | 2,201 | |||||||||
| Other Uses of Cash and Cash Equivalents: | ||||||||||||
| Cash paid to purchase debt | 1,073 | 2,813 | 2,592 | |||||||||
| Business combination, net | 353 | — | — | |||||||||
| Payments on revolving credit facility borrowings, net | — | 362 | — | |||||||||
| Extinguishment of other financing | — | 122 | — | |||||||||
| Additions to other property and equipment | 48 | 21 | 21 | |||||||||
| Cash paid for preferred stock dividends | 91 | 92 | 183 | |||||||||
| Distributions to noncontrolling interest owners | 4 | 6 | 8 | |||||||||
| Other | 32 | 27 | 17 | |||||||||
| Total other uses of cash and cash equivalents | 1,601 | 3,443 | 2,821 | |||||||||
| Total uses of cash and cash equivalents | $ | 3,816 | $ | 5,419 | $ | 5,022 |
Drilling and Completion Costs
Our drilling and completion costs increased in 2019 compared to 2018 primarily as a result of increased completion activity in our oil plays. We spud, completed, and connected wells at a higher average working interest in 2019 compared to 2018 due to the divestiture of the Utica asset and the acquisition of the Brazos Valley asset. Our average operated rig count was 18 rigs and spud wells were 333 in 2019 compared to an average operated rig count of 17 rigs and 322 spud wells in 2018 and 17 rigs and 341 spud wells in 2017. We completed 370 operated wells in 2019 compared to 351 in 2018 and 401 in 2017.
Business Combination - Acquisition of WildHorse
In 2019, we acquired WildHorse for approximately 717.4 million shares of our common stock and $381 million less $28 million of cash held by WildHorse as of the acquisition date. See Note 3 of the notes to our consolidated financial statements included in Item 1 of Part I of this report for further discussion of the acquisition.
Cash Paid to Purchase Debt
In 2019, we repurchased $698 million principal amount of our BVL Senior Notes for $693 million and retired our BVL revolving credit facility for $1.028 billion. We also repaid upon maturity $380 million principal amount of our Floating Rate Senior Notes due April 2019. In 2018, we used $2.813 billion of cash to repurchase $2.701 billion principal amount of debt. In 2017, we used $2.592 billion of cash to repurchase $2.389 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.
Dividends
We paid dividends of $91 million and $92 million on our preferred stock during 2019 and 2018, respectively, and 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 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
| 2019 | |||||||||||||||||||||||||||
| Oil | Natural Gas | NGL | Total | ||||||||||||||||||||||||
| mbbl per day | $/bbl | mmcf per day | $/mcf | mbbl per day | $/bbl | mboe per day | % | $/boe | |||||||||||||||||||
| Marcellus | — | — | 946 | 2.48 | — | — | 158 | 33 | 14.88 | ||||||||||||||||||
| Haynesville | — | — | 702 | 2.42 | — | — | 117 | 24 | 14.50 | ||||||||||||||||||
| Eagle Ford | 58 | 61.22 | 153 | 2.73 | 19 | 17.04 | 102 | 21 | 41.72 | ||||||||||||||||||
| Brazos Valley | 33 | 59.29 | 49 | 1.79 | 5 | 8.04 | 47 | 10 | 44.96 | ||||||||||||||||||
| Powder River Basin | 19 | 54.28 | 86 | 2.47 | 5 | 16.63 | 38 | 8 | 34.31 | ||||||||||||||||||
| Mid-Continent | 8 | 55.69 | 57 | 2.13 | 4 | 18.02 | 21 | 4 | 29.91 | ||||||||||||||||||
| Retained assets(a) | 118 | 59.16 | 1,993 | 2.45 | 33 | 15.62 | 483 | 100 | 25.57 | ||||||||||||||||||
| Divested assets(b) | — | — | 2 | 0.40 | — | — | 1 | — | 17.55 | ||||||||||||||||||
| Total | 118 | 59.16 | 1,995 | 2.45 | 33 | 15.62 | 484 | 100 | % | 25.57 | |||||||||||||||||
| 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 | — | — | 788 | 2.90 | — | — | 131 | 25 | 17.42 | ||||||||||||||||||
| Eagle Ford | 60 | 69.02 | 136 | 3.46 | 20 | 25.59 | 102 | 20 | 50.01 | ||||||||||||||||||
| Powder River Basin | 11 | 63.36 | 64 | 2.90 | 4 | 26.83 | 25 | 5 | 38.12 | ||||||||||||||||||
| Mid-Continent | 9 | 64.17 | 60 | 2.77 | 4 | 26.50 | 24 | 5 | 36.61 | ||||||||||||||||||
| Retained assets(a) | 80 | 67.72 | 1,876 | 3.01 | 28 | 25.90 | 420 | 81 | 27.97 | ||||||||||||||||||
| Divested assets(b) | 10 | 63.54 | 402 | 2.90 | 24 | 27.21 | 101 | 19 | 24.37 | ||||||||||||||||||
| 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 | % | $/boe | |||||||||||||||||||
| Marcellus | — | — | 804 | 2.45 | — | — | 134 | 25 | 14.67 | ||||||||||||||||||
| Haynesville | — | — | 784 | 2.85 | — | — | 131 | 24 | 17.10 | ||||||||||||||||||
| Eagle Ford | 58 | 52.37 | 141 | 3.31 | 18 | 22.98 | 100 | 18 | 39.33 | ||||||||||||||||||
| Powder River Basin | 6 | 50.06 | 37 | 3.01 | 3 | 27.37 | 15 | 3 | 32.52 | ||||||||||||||||||
| Mid-Continent | 8 | 49.26 | 66 | 2.79 | 5 | 23.10 | 23 | 4 | 28.92 | ||||||||||||||||||
| Retained assets(a) | 72 | 51.82 | 1,832 | 2.71 | 26 | 23.42 | 403 | 74 | 23.05 | ||||||||||||||||||
| Divested assets(b) | 18 | 47.83 | 574 | 2.92 | 31 | 22.98 | 145 | 26 | 22.41 | ||||||||||||||||||
| Total | 90 | 51.03 | 2,406 | 2.76 | 57 | 23.18 | 548 | 100 | % | 22.88 |
(a) Includes assets retained as of December 31, 2019.
| (b) | Divested assets include certain Utica assets in Ohio in 2018 and Haynesville assets in 2017 as well as certain Mid-Continent assets in both 2018 and 2017. |
Oil, Natural Gas and NGL Sales
| Years Ended December 31, | ||||||||||||||||||
| 2019 | change | 2018 | change | 2017 | ||||||||||||||
| ($ in millions) | ||||||||||||||||||
| Oil | $ | 2,543 | 16 | % | $ | 2,201 | 32 | % | $ | 1,668 | ||||||||
| Natural gas | 1,782 | (28 | )% | 2,486 | 3 | % | 2,422 | |||||||||||
| NGL | 192 | (62 | )% | 502 | 4 | % | 484 | |||||||||||
| Oil, natural gas and NGL sales | $ | 4,517 | (13 | )% | $ | 5,189 | 13 | % | $ | 4,574 |
2019 vs. 2018. Oil revenues increase of $342 million is primarily attributable to increased production volumes through the acquisition of WildHorse offset by a decrease in prices. Increased oil volumes resulted in a $605 million increase offset by a decrease in prices resulting in a $263 million decrease in revenues. Natural gas and NGL revenues decrease of $1.014 billion is primarily attributable to a decrease in natural gas and NGL prices and a decrease in production volumes primarily due to divestiture activity. Decreased natural gas and NGL prices and production volumes resulted in a $650 million and $364 million decrease to revenues, respectively.
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 $615 million.
See Note 9 of the notes to our consolidated financial statements included in Item 8 of this report for a complete discussion of oil, natural gas and NGL sales.
Oil, Natural Gas and NGL Derivatives
| Years Ended December 31, | ||||||||||||
| 2019 | 2018 | 2017 | ||||||||||
| ($ in millions) | ||||||||||||
| Oil derivatives – realized gains (losses) | $ | 36 | $ | (321 | ) | $ | 70 | |||||
| Oil derivatives – unrealized gains (losses) | (248 | ) | 445 | (134 | ) | |||||||
| Total gains (losses) on oil derivatives | (212 | ) | 124 | (64 | ) | |||||||
| Natural gas derivatives – realized gains (losses) | 114 | 7 | (9 | ) | ||||||||
| Natural gas derivatives – unrealized gains (losses) | 103 | (154 | ) | 489 | ||||||||
| Total gains (losses) on natural gas derivatives | 217 | (147 | ) | 480 | ||||||||
| NGL derivatives – realized gains (losses) | — | (13 | ) | (4 | ) | |||||||
| NGL derivatives – unrealized gains (losses) | — | 2 | (1 | ) | ||||||||
| Total gains (losses) on NGL derivatives | — | (11 | ) | (5 | ) | |||||||
| Total gains (losses) on oil, natural gas and NGL derivatives | $ | 5 | $ | (34 | ) | $ | 411 |
See Note 14 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, | ||||||||||||||||||
| 2019 | change | 2018 | change | 2017 | ||||||||||||||
| ($ in millions) | ||||||||||||||||||
| Marketing revenues | $ | 3,967 | (22 | )% | $ | 5,076 | 13 | % | $ | 4,511 | ||||||||
| Marketing expenses | 4,003 | (22 | )% | 5,158 | 12 | % | 4,598 | |||||||||||
| Marketing margin | $ | (36 | ) | 56 | % | $ | (82 | ) | 6 | % | $ | (87 | ) |
2019 vs. 2018. Marketing revenues and expenses decreased in 2019 primarily as a result of decreased oil, natural gas and NGL prices received in our marketing operations. Marketing margin improved as a result of improved pricing on oil inventory and better margins on non-equity gas and oil transactions offset by an increase in pipeline deficiency fees.
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. Marketing margin was negatively impacted by downstream pipeline delivery commitments.
Other Revenue
| Years Ended December 31, | ||||||||||||
| 2019 | 2018 | 2017 | ||||||||||
| ($ in millions) | ||||||||||||
| Other revenue | $ | 63 | $ | 63 | $ | 67 |
Other revenue primarily relates to the amortization of deferred VPP revenue. Our remaining deferred revenue balance of $64 million will be amortized on a straight-line basis through February 2021. See Note 7 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our VPPs.
Gains (Losses) on Sales of Assets
| Years Ended December 31, | ||||||||||||
| 2019 | 2018 | 2017 | ||||||||||
| ($ in millions) | ||||||||||||
| Gains (losses) on sales of assets | $ | 43 | $ | (264 | ) | $ | 476 |
In 2019, we received proceeds of approximately $136 million, net of post-closing adjustments, and recognized a net gain of approximately $43 million, primarily for the sale of non-core 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 for net proceeds of $1.868 billion to Encino and recognized a loss of $273 million associated with the transaction. Also in 2018, we sold portions of our acreage, producing properties and other related property and equipment in the Mid-Continent, including our Mississippian Lime assets, for approximately $491 million, subject to certain customary closing adjustments, and we recognized a gain of approximately $12 million associated with the transactions.
In 2017, we sold portions of our acreage and producing properties in our Haynesville Shale operating area in northern Louisiana for approximately $915 million, subject to certain customary closing adjustments, and recognized a gain of approximately $326 million.
See Note 3 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of these transactions.
Oil, Natural Gas and NGL Production Expenses
| Years Ended December 31, | ||||||||||||||||||
| 2019 | change | 2018 | change | 2017 | ||||||||||||||
| ($ in millions) | ||||||||||||||||||
| Oil, natural gas and NGL production expenses | ||||||||||||||||||
| Marcellus | $ | 32 | (6 | )% | $ | 34 | 21 | % | $ | 28 | ||||||||
| Haynesville | 47 | (18 | )% | 57 | 8 | % | 53 | |||||||||||
| Eagle Ford | 180 | (1 | )% | 181 | (3 | )% | 187 | |||||||||||
| Brazos Valley | 96 | n/a | — | n/a | — | |||||||||||||
| Powder River Basin | 71 | 45 | % | 49 | 69 | % | 29 | |||||||||||
| Mid-Continent | 94 | (4 | )% | 98 | (8 | )% | 107 | |||||||||||
| Retained Assets(a) | 520 | 24 | % | 419 | 4 | % | 404 | |||||||||||
| Divested Assets(b) | — | (100 | )% | 55 | (51 | )% | 113 | |||||||||||
| Total oil, natural gas and NGL production expenses | $ | 520 | 10 | % | $ | 474 | (8 | )% | $ | 517 | ||||||||
| ($ per boe) | ||||||||||||||||||
| Oil, natural gas and NGL production expenses | ||||||||||||||||||
| Marcellus | $ | 0.56 | (16 | )% | $ | 0.67 | 16 | % | $ | 0.58 | ||||||||
| Haynesville | $ | 1.10 | (8 | )% | $ | 1.20 | 9 | % | $ | 1.10 | ||||||||
| Eagle Ford | $ | 4.79 | (2 | )% | $ | 4.87 | (5 | )% | $ | 5.13 | ||||||||
| Brazos Valley | $ | 5.62 | n/a | $ | — | n/a | $ | — | ||||||||||
| Powder River Basin | $ | 5.13 | (4 | )% | $ | 5.34 | (3 | )% | $ | 5.51 | ||||||||
| Mid-Continent | $ | 12.22 | 8 | % | $ | 11.31 | (8 | )% | $ | 12.31 | ||||||||
| Retained Assets(a) | $ | 2.94 | 8 | % | $ | 2.73 | (1 | )% | $ | 2.75 | ||||||||
| Divested Assets(b) | $ | — | (100 | )% | $ | 1.49 | (30 | )% | $ | 2.14 | ||||||||
| Total oil, natural gas and NGL production expenses per boe | $ | 2.94 | 18 | % | $ | 2.50 | (3 | )% | $ | 2.59 |
(a) Includes assets retained as of December 31, 2019.
| (b) | Divested assets include certain Utica assets in Ohio in 2018 and Haynesville assets in 2017 as well as certain Mid-Continent assets in both 2018 and 2017. |
2019 vs. 2018. The absolute and per unit increase was the result of the acquisition of WildHorse in 2019 and increased production volumes in the Powder River Basin, partially offset by the sale of certain oil and natural gas properties in 2018 and 2019. Production expenses in 2019 included approximately $11 million associated with VPP production volumes.
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. Production expenses in 2018 included approximately $15 million associated with VPP production volumes.
We anticipate a continued decrease in production expenses associated with VPP production volumes as the contractually scheduled volumes under our remaining VPP agreement decrease and operating efficiencies generally improve.
Oil, Natural Gas, and NGL Gathering, Processing and Transportation Expenses
| Years Ended December 31, | ||||||||||||
| 2019 | 2018 | 2017 | ||||||||||
| ($ in millions, except per unit) | ||||||||||||
| Oil, natural gas and NGL gathering, processing and transportation expenses | $ | 1,082 | $ | 1,398 | $ | 1,471 | ||||||
| Oil ($ per bbl) | $ | 3.20 | $ | 4.30 | $ | 3.94 | ||||||
| Natural gas ($ per mcf) | $ | 1.21 | $ | 1.32 | $ | 1.34 | ||||||
| NGL ($ per bbl) | $ | 5.32 | $ | 8.37 | $ | 7.88 | ||||||
| Total ($ per boe) | $ | 6.13 | $ | 7.35 | $ | 7.36 |
2019 vs. 2018. The absolute and per unit decrease for oil and natural gas gathering, processing and transportation expenses was primarily due to the divestiture of our Utica Shale properties in 2018.
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.
Severance and Ad Valorem Taxes
| Years Ended December 31, | ||||||||||||||||||
| 2019 | change | 2018 | change | 2017 | ||||||||||||||
| ($ in millions, except per unit) | ||||||||||||||||||
| Severance taxes | $ | 144 | 16 | % | $ | 124 | 39 | % | $ | 89 | ||||||||
| Ad valorem taxes | 80 | 23 | % | 65 | 44 | % | 45 | |||||||||||
| Severance and ad valorem taxes | $ | 224 | 19 | % | $ | 189 | 41 | % | $ | 134 | ||||||||
| Severance taxes per boe | $ | 0.81 | 25 | % | $ | 0.65 | 48 | % | $ | 0.44 | ||||||||
| Ad valorem taxes per boe | 0.46 | 35 | % | 0.34 | 55 | % | 0.22 | |||||||||||
| Severance and ad valorem taxes per boe | $ | 1.27 | 28 | % | $ | 0.99 | 50 | % | $ | 0.66 |
2019 vs. 2018. The absolute and per unit increase in severance taxes was primarily due to the addition of Texas assets through our acquisition of WildHorse, expiring tax exemptions in Haynesville and the divestiture of Ohio assets that were taxed at a lower rate. The absolute and per unit increase in ad valorem taxes was primarily due to a change in the mix of taxable oil and natural gas reserves by state. The addition of Texas assets through our acquisition of WildHorse increased the amount of oil and natural gas reserves subject to ad valorem tax whereas the divestiture of Ohio assets decreased the amount of oil and gas reserves not subject to ad valorem tax.
2018 vs. 2017. The absolute and per unit increase in severance taxes was primarily due to higher prices received for our oil, natural gas and NGL production, offset by lower production volumes. The total per unit increase in ad valorem taxes was the result of increased ad valorem tax primarily due to higher prices received for our oil, natural gas and NGL production.
Exploration Expenses
| Years Ended December 31, | ||||||||||||||||||
| 2019 | change | 2018 | change | 2017 | ||||||||||||||
| ($ in millions, except per unit) | ||||||||||||||||||
| Impairments of unproved properties | $ | 32 | (46 | )% | $ | 59 | (72 | )% | $ | 214 | ||||||||
| Dry hole expense | 25 | (32 | )% | 37 | n/a | — | ||||||||||||
| Geological and geophysical expense and other | 27 | (59 | )% | 66 | 214 | % | 21 | |||||||||||
| Exploration expense | $ | 84 | (48 | )% | $ | 162 | (31 | )% | $ | 235 |
2019 vs. 2018. The decrease in exploration expense was primarily due to fewer impairments of unproved properties and fewer exploratory geological and geophysical projects. In addition, we recognized a reduction in delay rental expense primarily due to the divested Utica operating area in 2018.
2018 vs. 2017. The decrease in exploration expense was primarily due to fewer impairments of unproved properties, partially offset by an increase in dry hole expense and exploratory geological and geophysical projects.
General and Administrative Expenses
| Years Ended December 31, | ||||||||||||||||||
| 2019 | change | 2018 | change | 2017 | ||||||||||||||
| ($ in millions, except per unit) | ||||||||||||||||||
| Gross overhead | $ | 682 | (4 | )% | $ | 714 | (10 | )% | $ | 791 | ||||||||
| Allocated to production expenses | (132 | ) | (6 | )% | (141 | ) | (20 | )% | (177 | ) | ||||||||
| Allocated to marketing expenses | (14 | ) | (30 | )% | (20 | ) | (31 | )% | (29 | ) | ||||||||
| Allocated to exploration expenses | (11 | ) | 10 | % | (10 | ) | 67 | % | (6 | ) | ||||||||
| Allocated to sand mine expense | (7 | ) | — | % | — | — | % | — | ||||||||||
| Capitalized general and administrative expenses | (56 | ) | 4 | % | (54 | ) | (10 | )% | (60 | ) | ||||||||
| Reimbursed from third parties | (147 | ) | (5 | )% | (154 | ) | (17 | )% | (186 | ) | ||||||||
| General and administrative expenses, net | $ | 315 | (6 | )% | $ | 335 | 1 | % | $ | 333 | ||||||||
| General and administrative expenses, net per boe | $ | 1.78 | 1 | % | $ | 1.76 | 5 | % | $ | 1.67 |
2019 vs. 2018. The decrease in gross overhead expense is primarily due to compensation reductions in our long-term incentives that are tied to the Company’s equity performance.
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.
Restructuring and Other Termination Costs. In 2019, we incurred a charge of $12 million related to one-time termination benefits for certain employees. In January 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 $5 million in other termination benefits. See Note 21 of the notes to our consolidated financial statements included in Item 8 of this report for a discussion of our restructuring and termination costs.
Provision for Legal Contingencies, Net
| Years Ended December 31, | ||||||||||||
| 2019 | 2018 | 2017 | ||||||||||
| ($ in millions) | ||||||||||||
| Provision for legal contingencies, net | $ | 19 | $ | 26 | $ | (38 | ) |
The 2019 and the 2018 amounts consist of accruals for loss contingencies 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 6 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of royalty claims.
Depreciation, Depletion and Amortization
| Years Ended December 31, | ||||||||||||||||||
| 2019 | change | 2018 | change | 2017 | ||||||||||||||
| ($ in millions, except per unit) | ||||||||||||||||||
| Depreciation, depletion and amortization | $ | 2,264 | 30 | % | $ | 1,737 | 2 | % | $ | 1,697 | ||||||||
| Depreciation, depletion and amortization per boe | $ | 12.82 | 40 | % | $ | 9.13 | 8 | % | $ | 8.49 |
The absolute and per unit increases in 2018 and 2019 are primarily the result of a higher depletion rate. The depletion rate increases are driven by a higher concentration of our production mix and capital deployment in liquids-rich operating areas, which generally involve higher finding costs per boe relative to gas-rich operating areas. The depletion rate in 2019 also reflects our acquisition of WildHorse assets, located in a liquids-rich operating area.
Impairments
| Years Ended December 31, | ||||||||||||
| 2019 | 2018 | 2017 | ||||||||||
| ($ in millions) | ||||||||||||
| Impairments due to lower forecasted commodity prices | $ | 8 | $ | 23 | $ | 27 | ||||||
| Impairments due to reduction in future development(a) | — | — | 560 | |||||||||
| Impairments due to anticipated sale | — | 55 | 222 | |||||||||
| Total impairments of oil and natural gas properties | 8 | 78 | 809 | |||||||||
| Impairments of other fixed assets | 3 | 53 | 5 | |||||||||
| Total impairments | $ | 11 | $ | 131 | $ | 814 |
| (a) | The impairment was the result of an updated development plan in 2017, which included a removal of PUDs from properties in the process of being divested in the Mid-Continent operating area. |
Other fixed assets. In 2018, we recorded a $45 million impairment related to 890 compressors and $8 million for other property and equipment for the difference between the fair value and carrying value. See Note 19 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our impairments.
Other Operating Expense
| Years Ended December 31, | |||||||||||||||||
| 2019 | change | 2018 | change | 2017 | |||||||||||||
| ($ in millions) | |||||||||||||||||
| Other operating expense | $ | 92 | n/a | $ | — | (100 | )% | $ | 416 |
In 2019, we recorded approximately $37 million of costs related to our acquisition of WildHorse which consisted of consulting fees, financial advisory fees, legal fees and travel and lodging expenses. In addition, we recorded approximately $38 million of severance expense as a result of the acquisition of WildHorse. A majority of the WildHorse executives and employees were terminated at the time of acquisition. These executives and employees were entitled to severance benefits in accordance with existing employment agreements.
The 2017 amount consists of discrete costs incurred to terminate various gathering and transportation agreements, including those associated with oil and natural gas asset divestitures. See Note 20 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our other operating expense.
Interest Expense
| Years Ended December 31, | ||||||||||||
| 2019 | 2018 | 2017 | ||||||||||
| ($ in millions) | ||||||||||||
| Interest expense on senior notes | $ | 578 | $ | 591 | $ | 551 | ||||||
| Interest expense on term loan | 4 | 86 | 127 | |||||||||
| Amortization of loan discount, issuance costs and other | 3 | 24 | 40 | |||||||||
| Amortization of premium | (5 | ) | (88 | ) | (138 | ) | ||||||
| Interest expense on revolving credit facility | 96 | 37 | 39 | |||||||||
| Realized gains on interest rate derivatives | (5 | ) | (3 | ) | (3 | ) | ||||||
| Unrealized losses on interest rate derivatives | 4 | 2 | 4 | |||||||||
| Capitalized interest | (24 | ) | (16 | ) | (19 | ) | ||||||
| Total interest expense | $ | 651 | $ | 633 | $ | 601 | ||||||
| Interest expense per boe | $ | 3.68 | $ | 3.33 | $ | 2.99 | ||||||
| Average senior notes borrowings | $ | 7,857 | $ | 8,160 | $ | 7,714 | ||||||
| Average credit facility borrowings | $ | 1,934 | $ | 505 | $ | 443 | ||||||
| Average term loan borrowings | $ | 37 | $ | 911 | $ | 1,446 |
See Note 5 of the notes to our consolidated financial statements included in Item 8 of this report for a discussion of our debt instruments.
Gains (Losses) on Investments.
FTS International Inc. (NYSE: FTSI). In 2018, FTS International, Inc. 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 2019, the hydraulic fracturing industry experienced challenging operating conditions resulting in the current fair value of our investment in FTSI falling below book value of $65 million and remaining below that value as of the end of the year. Based on FTSI’s 2019 operating results and FTSI’s share price of $1.04 per share as of December 31, 2019, we determined that the reduction in fair value is other-than-temporary, and recognized an impairment of our investment in FTSI of approximately $43 million. We will continue to monitor the hydraulic fracturing industry, FTSI operating results and FTSI share price for indicators that the reduction in fair value is other-than-temporary, which could result in an additional impairment of our investment in FTSI. See Note 18 of the notes to our consolidated financial statements included in Item 8 of this report for a discussion of our investments.
JWH Midstream LLC (JWH). In 2019, in connection with the acquisition of WildHorse, we obtained a 50% membership interest in JWH Midstream LLC (JWH). The carrying value of our investment in JWH, which was being accounted for as an equity method investment, was approximately $17 million. In 2019, we paid approximately $7 million to terminate our involvement in the partnership. This removed us from any future obligations related to this joint venture and, therefore, we impaired the full value of the investment and recognized approximately $24 million of impairment expense in 2019.
Gains (Losses) on Purchases or Exchanges of Debt. In 2019, we privately negotiated exchanges of approximately $507 million principal amount of our outstanding senior notes for 235,563,519 shares of common stock and $186 million principal amount of our outstanding convertible senior notes for 73,389,094 shares of common stock. We recorded an aggregate net gain of approximately $64 million associated with the exchanges. Additionally, in various transactions throughout 2019, we repurchased approximately $698 million principal amount of the BVL Senior Notes, recognizing a net $10 million gain on the transactions.
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.
Other Income. In 2019, we recognized $9 million of other income from the sale of seismic data licenses to third parties. The remaining amount in 2019 was from other non-operating miscellaneous income. 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.
Income Tax Expense (Benefit). We recorded an income tax benefit of $331 million in 2019, an income tax benefit of $10 million in 2018 and income tax expense of $2 million in 2017. The income tax benefit for 2019 consists mainly of a partial release of the valuation allowance maintained against our net deferred tax asset position. The partial release was a consequence of recording a net deferred tax liability of $314 million resulting from the business combination accounting for WildHorse. Other material items included in the 2019 income tax benefit include a benefit for the reversal of a liability for unrecognized tax benefits of $32 million partially offset by an expense of $10 million associated with Texas no longer being in a net deferred tax asset position, and a current state income tax expense of $6 million. See Note 10 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 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.
Impairments. Long-lived assets used in operations, including proved oil and gas properties, are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows expected to be generated by an asset group. Individual assets are grouped for impairment purposes based on
a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. If there is an indication the carrying amount of an asset may not be recovered, the asset is assessed by management through an established process in which changes to significant assumptions such as prices, volumes, and future development plans are reviewed. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value by discounting using a weighted average cost of capital. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is assessed by management using the income approach. Level 3 inputs associated with the calculation of discounted cash flows used in the impairment analysis include our estimate of future crude oil and natural gas prices, production costs, development expenditures, anticipated production of proved reserves and other relevant data. Additionally, we utilize a combination of NYMEX strip pricing and consensus pricing, adjusted for differentials, to value the reserves.
Income Taxes. The amount of income taxes recorded requires interpretations and application of complex rules and regulations pertaining to federal, state and local taxing jurisdictions. Income taxes are accounted for using the asset and liability method as required by GAAP. We recognize deferred tax assets and liabilities for temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements. Deferred tax assets for NOL carryforwards and disallowed business interest carryforwards have also been recognized. We routinely assess the realizability of our deferred tax assets and reduce such assets by a valuation allowance if it is more likely than not that all or some portion of the deferred tax assets will not be realized. In assessing the need for additional valuation allowances or adjustments to existing valuation allowances, we consider the weight of all available evidence, both positive and negative, concerning the realization of the deferred tax asset. Among the more significant types of evidence that we consider are:
| • | taxable income projections in future years; |
| • | reversal of existing deferred tax liabilities against deferred tax assets and whether the carryforward period is so brief that it would limit realization of the tax benefit; |
| • | future sales and operating cost projections that will produce more than enough taxable income to realize the deferred tax asset based on existing sales prices and cost structures; and |
| • | our earnings history exclusive of any loss that creates a future deductible amount coupled with evidence indicating that the loss is an aberration rather than a continuing condition. |
Our judgments and assumptions in estimating future taxable income include such factors as future operating conditions and commodity prices when determining if deferred tax assets are not more likely than not to be realized. As of December 31, 2019, and 2018, we had deferred tax assets totaling $2.449 billion and $3.231 billion upon which we had a valuation allowance of $1.805 billion and $2.011 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 10 of the notes to our consolidated financial statements included in Item 8 of this report.
Contingencies. We are subject to various legal proceedings, claims, and liabilities that arise in the ordinary course of business. Except for contingencies acquired in a business combination, which are recorded at fair value at the time of acquisition, we accrue losses when such losses are probable and reasonably estimable. If we determine that a loss is probable and cannot estimate a specific amount for that loss, but can estimate a range of loss, the best estimate within the range is accrued. If no amount within the range is a better estimate than any other, the minimum amount of the range is accrued. Our in-house legal personnel regularly assess contingent liabilities and, in certain circumstances, consult with third-party legal counsel or consultants to assist in the evaluation of our liability for these contingencies.
We make judgments and estimates when we establish liabilities for litigation and other contingent matters. Estimates of litigation-related liabilities are based on the facts and circumstances of the individual case and on information currently available to us. The extent of information available varies based on the status of the litigation and our evaluation of the claim and legal arguments. In future periods, a number of factors could significantly change our estimate of litigation-related liabilities, including discovery activities; briefings filed with the relevant court; rulings from
the court made pre-trial, during trial, or at the conclusion of any trial; and similar cases involving other plaintiffs and defendants that may set or change legal precedent. As events unfold throughout the litigation process, we evaluate the available information and may consult with third-party legal counsel to determine whether liability accruals should be established or adjusted.
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, 2019, and 2018, the fair values of our derivatives were net assets of $130 million and $282 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.
Disclosures About Effects of Transactions with Related Parties
Our equity method investees are considered related parties. See Note 24 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.
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