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
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.
Introduction
We are an independent exploration and production company engaged in the acquisition, exploration and development of properties to produce oil, natural gas and NGLs from underground reservoirs. We own a large and geographically diverse portfolio of onshore U.S. unconventional natural gas and liquids assets, including interests in approximately 7,400 oil and natural gas wells. Our natural gas resource plays are the Marcellus Shale in the northern Appalachian Basin in Pennsylvania and the Haynesville/Bossier Shales in northwestern Louisiana. Our liquids-rich resource plays are the Eagle Ford Shale in South Texas and the stacked pay in the Powder River Basin in Wyoming.
Recent Developments
Voluntary Reorganization Under Chapter 11
On June 28, 2020, the Debtors filed voluntary petitions for relief under the Bankruptcy Code in the Bankruptcy Court. On June 29, 2020, the Bankruptcy Court entered an order authorizing the joint administration of the Chapter 11 Cases under the caption In re Chesapeake Energy Corporation, Case No. 20-33233 (DRJ). Subsidiaries with noncontrolling interests, consolidated variable interest entities and certain de minimis subsidiaries (collectively, the “Non-Filing Entities”) were not part of the Chapter 11 Cases. The Debtors and the Non-Filing Entities continued to operate in the ordinary course of business during the Chapter 11 Cases.
During the Chapter 11 Cases, the Debtors operated as debtors-in-possession in accordance with the applicable provisions of the Bankruptcy Code. The Bankruptcy Court granted first day motions filed by us that were designed primarily to mitigate the impact of the Chapter 11 Cases on our operations, customers and employees. As a result, we were able to conduct normal business activities and pay all associated obligations for the period following the Bankruptcy filing and were authorized to pay owner royalties, employee wages and benefits, and certain vendors and suppliers in the ordinary course for goods and services provided. During the pendency of the Chapter 11 Cases, all transactions outside the ordinary course of business required the prior approval of the Bankruptcy Court.
For the duration of the Chapter 11 Cases, our operations and ability to develop and execute our business plan were subject to the risks and uncertainties associated with the Chapter 11 process as described in Item 1A. “Risk Factors.” As a result of these risks and uncertainties, the number of our shares of common stock and stockholders, assets, liabilities, officers and/or directors could be significantly different following the outcome of the Chapter 11 Cases, and the description of our operations, properties and capital plans included in this Form 10-Q may not accurately reflect our operations, properties and capital plans following the Chapter 11 Cases.
During the Chapter 11 Cases, we expected our financial results to continue to be volatile as Restructuring activities and expenses, contract terminations and rejections, and claims assessments significantly impact our consolidated financial statements. As a result, our historical financial performance is likely not indicative of our financial performance after the date of the Petition Date. In addition, we incurred significant professional fees and other costs in connection with preparation for the Chapter 11 Cases.
On October 13, 2020, we filed a notice with the Bankruptcy Court that we reached an agreement with Tapstone Energy, LLC (“Tapstone Energy”) as the “Stalking Horse” bidder to sell our Mid-Continent asset for $85 million in a Section 363 transaction under the Bankruptcy Code. An auction supervised by the Bankruptcy Court was held on November 10, 2020, in which other pre-qualified buyers submitted bids for the asset. We presented the results of the auction process to the Bankruptcy Court and the sale was approved on November 13, 2020. On December 11, 2020, we closed the transaction with Tapstone Energy for $130 million, subject to post-closing adjustments which resulted in the recognition of a gain of approximately $27 million.
On November 22, 2020, we filed notice with the Bankruptcy Court that we had reached an agreement with The Williams Companies, Inc. (“Williams”) to transfer certain Haynesville assets, including interests in 144 producing wells and approximately 50,000 net acres, in exchange for improved midstream contract terms with respect to assets we retained. On December 15, 2020, the Court approved the transaction with Williams and the exchange resulted in the recognition of loss of approximately $128 million based on the difference between the carrying value of the assets and the fair value of the assets surrendered. The exchange was executed to obtain sufficient savings on midstream obligations as required by the Plan. Therefore, the loss was recorded to reorganization items, net in our consolidated statements of operations.
See Item 1. Business, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 2 of the notes to our consolidated financial statements included in Item 8 of this report for a discussion of our Chapter 11 proceedings.
COVID-19 Pandemic and Impact on Global Demand for Oil and Natural Gas
The global spread of COVID-19 created significant volatility, uncertainty, and economic disruption during 2020. The pandemic has reached more than 200 countries and territories and has resulted in widespread adverse impacts on the global economy and on our customers and other parties with whom we have business relations. There remains considerable uncertainty regarding how long the pandemic and related market conditions will persist. In certain cases, states that had begun taking steps to reopen their economies experienced a subsequent surge in cases of COVID-19, causing these states to cease such reopening measures in some cases and reinstitute restrictions in others. To date, we have experienced limited operational impacts as a result of COVID-19 or the related governmental restrictions.
As an essential business under the guidelines issued by each of the states in which we operate, we have been allowed to continue operations. As a result, in mid-March of 2020, we restricted access to all of our offices and for a period of time directed employees to work remotely to the extent possible. We began to re-open our offices in phases beginning in mid-May of 2020, and we have implemented special precautions to minimize the risk to our employees of exposure. These actions have allowed us to maintain the engagement and connectivity of our personnel. However, due to severe impacts from the COVID-19 pandemic on the global demand for oil and natural gas, financial results may not necessarily be indicative of operating results for the 2020 fiscal year or for any other future period. Moreover, future operations could be negatively affected if a significant number of our employees are quarantined as a result of exposure to the virus.
Our first priority in our response to this crisis has been the health and safety of our employees and those of our other business counterparties. We have implemented preventative measures and developed corporate and regional response plans to minimize unnecessary risk of exposure and prevent infection, while supporting our employees, contractors and vendors to the best of our ability. We have a business continuity team tasked with responding to health, safety and environmental matters and personnel issues, and we have activated this business continuity team to address the impacts of the pandemic on our business as they develop. We also have modified certain business practices (including those related to employee travel, employee work locations, and cancellation of physical participation in meetings, events and conferences) to protect the health and safety of our employees and contractors and the communities in which we operate by conforming to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention, the World Health Organization and other governmental and regulatory authorities.
There is considerable uncertainty regarding how long the pandemic and related market conditions will persist and the extent and duration of governmental and other measures implemented to try to slow the spread of the virus, such as large-scale travel bans and restrictions, border closures, quarantines, shelter-in-place orders and business and government shutdowns. One of the largest impacts of the pandemic has been a significant reduction in global demand for oil and, to a lesser extent, natural gas. In addition, in the first half of 2020, oil prices declined significantly due to an increase in supply emanating from a disagreement on production cuts among members of OPEC+ and certain non-OPEC oil-producing countries. The resulting oversupply and the reduced demand in response to COVID-19 have together caused prices in the oil and gas market to remain depressed. Oil and natural gas prices are expected to continue to be volatile as a result of the near-term production instability and the ongoing COVID-19 pandemic and as changes in oil and natural gas inventories, industry demand and global and national economic performance are reported. The supply and demand imbalance has disrupted the oil and natural gas exploration and production industry and other industries that serve exploration and production companies. We
expect to see continued volatility in oil and natural gas prices for the foreseeable future, and such volatility has adversely impacted and is expected to continue to adversely impact our business, cash flows, liquidity, financial condition and results of operations.
As of the date of this Form 10-K, our efforts to respond to the challenges presented by the conditions described above and minimize the impacts to our business have yielded positive results. We have moved quickly to implement strategies to reduce costs, increase operational efficiencies and lower our capital spending. In 2020, we reduced our workforce by 25%. In connection with this reduction, we recorded non-recurring charges of approximately $44 million for the year ended December 31, 2020, and we anticipate an estimated annualized savings of approximately $70 million. In February 2021, we reduced our workforce by an additional 15%. In addition, due to the significant drop in oil prices and midstream constraints in 2020, we shut in wells and delayed 38 turn-in-lines, which reduced our oil production by approximately 50%, 25% and 10% in May, June and July, respectively. In response to recent improvements in market conditions, we have returned most wells to production and intend to complete most of our drilled but uncompleted wells by the second quarter of 2021. We anticipate our capital expenditures for the remainder of the year will be focused primarily on our natural gas assets. We have not received any funding under the CARES Act or other federal programs to support our operations and do not anticipate that we will. We are continuing to address concerns to protect the health and safety of our employees and those of our customers and other business counterparties, and this includes changes to comply with health-related guidelines as they are modified and supplemented.
We cannot predict the full impact that COVID-19 or the current significant disruption and volatility in the oil and natural gas markets will have on our business, cash flows, liquidity, financial condition and results of operations. The ultimate impact of the pandemic will depend on future developments that cannot be anticipated, including, among others, the ultimate severity of the virus, the consequences of governmental and other measures designed to mitigate the spread of the virus, the development and availability of treatments and vaccines and the extent to which these treatments and vaccines may remain effective as potential new strains of the virus emerge, the duration of the pandemic, any actions taken by members of Organization of Petroleum Exporting Countries (OPEC+) and other foreign, oil-exporting countries, actions taken by governmental authorities, customers and other thirds parties, workforce availability, and the timing and extent of any return to normal economic and operating conditions. For additional discussion regarding risks associated with the COVID-19 pandemic, see Item 1A “Risk Factors” in this report.
Cancellation of Rights Plan
On April 23, 2020, our Board of Directors declared a dividend of one Right payable on May 4, 2020 for each share of our common stock outstanding on May 4, 2020 to the shareholders of record on that date (the “Rights”). In connection with the distribution of the Rights, we entered into a Rights Agreement with Computershare Trust Company, N.A., as rights agent (the “Rights Agreement”). Each Right entitles the registered holder to purchase from us Preferred Shares.
The Rights Agreement was intended to protect value by preserving our ability to use our tax attributes to offset potential future income taxes for federal income tax purposes. Our ability to use our tax attributes would have been substantially limited if we had experienced an ownership change under Section 382 of the Code prior to emergence from bankruptcy on February 9, 2021. The Rights Agreement reduced the likelihood of an ownership change by deterring any person or group of affiliated or associated persons from acquiring beneficial ownership of 4.9% or more of the outstanding shares of our common stock.
In connection with the adoption of the Rights Agreement the Company filed a Certificate of Designations of Series B Preferred Stock with the Secretary of State of the State of Oklahoma setting forth the rights, powers, and preferences of the Series B Preferred Stock issuable upon exercise of the Rights (the “Preferred Shares”). On the Plan Effective Date, the Company filed a Certificate of Elimination with the Secretary of State of the State of Oklahoma eliminating the Preferred Shares and returning them to authorized but undesignated shares of the Company’s preferred stock. The foregoing is a summary of the terms of the Certificate of Elimination. The summary does not purport to be complete and is qualified in its entirety by reference to the Certificate of Elimination.
Liquidity and Capital Resources
Liquidity Overview
Our primary sources of capital resources and liquidity have historically consisted of internally generated cash flows from operations, borrowings under certain credit agreements, dispositions of non-core assets and the capital markets when conditions are favorable. Our ability to issue additional indebtedness, dispose of assets or access the capital markets was substantially limited during the Chapter 11 Cases and required court approval in most instances. Accordingly, our liquidity depended mainly on cash generated from operating activities and available funds under the DIP Credit Facility discussed below.
The Bankruptcy Filing constituted an event of default under certain of our secured and unsecured debt obligations. As a result of the Bankruptcy Filing, the principal and interest due under these debt instruments became immediately due and payable. However, pursuant to Section 362 of the Bankruptcy Code, the creditors were stayed from taking any action as a result of such defaults.
Recent Events Affecting Liquidity
On June 28, 2020, prior to the commencement of the Chapter 11 Cases, the Company entered into a commitment letter (the “Commitment Letter”) with certain of the lenders under our pre-petition revolving credit facility and/or their affiliates (collectively, the “Commitment Parties”), pursuant to which, and subject to the satisfaction of certain customary conditions, including the approval of the Bankruptcy Court, the Commitment Parties agreed to provide the Debtors with a post-petition senior secured super-priority debtor-in-possession revolving credit facility in an aggregate principal amount of up to approximately $2.104 billion (the “DIP Credit Facility”), consisting of a revolving loan facility of new money in an aggregate principal amount of up to $925 million, which includes a sub-facility of up to $200 million for the issuance of letters of credit, and an up to approximately $1.179 billion term loan that reflects the roll-up of a portion of our outstanding borrowings under the pre-petition revolving credit facility. Pursuant to the Commitment Letter, the Commitment Parties also committed to provide, subject to certain conditions, an up to $2.5 billion exit credit facility, consisting of an up to $1.75 billion revolving credit facility (the “Exit Revolving Facility”) and an up to $750 million senior secured term loan facility (the “Exit Term Loan Facility” and, together with the Exit Revolving Facility, the “Exit Credit Facilities”). The terms and conditions of the DIP Credit Facility are set forth in the senior secured super-priority debtor-in-possession credit agreement (the “DIP Credit Agreement”) attached to the Commitment Letter. The DIP Credit Facility provided us the capital necessary to fund our operations during the Chapter 11 reorganization proceedings. The proceeds of the DIP Credit Facility were used for, among other things, post-petition working capital, permitted capital investments, general corporate purposes, letters of credit, administrative costs, premiums, expenses and fees for the transactions contemplated by the Chapter 11 Cases, payment of court approved adequate protection obligations, and other such purposes consistent with the DIP Credit Facility. On July 1, 2020, the Company, as borrower, entered into the DIP Credit Agreement along with the Debtor guarantors party thereto, MUFG Union Bank, N.A., as agent, and the other lender, issuer, and agent parties thereto. On September 15, 2020, we entered into the first amendment to the DIP Credit Agreement. The amendment, among other things, amended the maximum hedging covenant to allow the Debtors to enter into additional non-speculative hedge agreements based on forecasted production. See Note 2 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our DIP Credit Facility.
As of December 31, 2020, we had a cash balance of $279 million, as compared to $6 million as of December 31, 2019, and a net working capital deficit of $1.986 billion as of December 31, 2020, as compared to a net working capital deficit of $1.141 billion as of December 31, 2019. Additionally, our DIP Credit Facility was approved by the Bankruptcy Court on July 31, 2020 which allowed us up to $925 million of borrowing capacity. As of December 31, 2020, we had no outstanding borrowings under our DIP Credit Facility. 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.
Post-Emergence Debt
The Bankruptcy Court confirmed the Plan in a bench ruling on January 13, 2021 and entered the Confirmation Order on January 16, 2021. The Debtors emerged from bankruptcy on February 9, 2021. Upon emergence, all existing equity was canceled and new common stock was issued to the previous holders of our term loan, second lien notes, senior notes and certain general unsecured creditors.
On the Effective Date, pursuant to the terms of the Plan, the Company, as borrower, entered into a reserve-based credit agreement (the “Credit Agreement”) providing for a reserve-based credit facility (the “Exit Credit Facility”) with an initial borrowing base of $2.5 billion. The borrowing base will be redetermined semiannually on or around May 1 and November 1 of each year and the next scheduled redetermination will be on or about October 1, 2021. The aggregate initial elected commitments of the lenders under the Exit Credit Facility will be $1.75 billion of revolving Tranche A Loans (the “Tranche A Loans”) and $220 million of fully funded Tranche B Loans (the “Tranche B Loans”).
The Exit Credit Facility provides for a $200.0 million sublimit of the aggregate commitments that are available for the issuance of letters of credit. The Exit Credit Facility bears interest at the ABR (alternate base rate) or LIBOR, at our election, plus an applicable margin (ranging from 2.25–3.25% per annum for ABR loans and 3.25–4.25% per annum for LIBOR loans, subject to a 1.00% LIBOR floor), depending on the percentage of the borrowing base then being utilized. The Tranche A Loans mature 3 years after the Effective Date and the Tranche B Loans mature 4 years after the Effective Date. The Tranche B Loans can be repaid if no Tranche A Loans are outstanding
On February 2, 2021, the Company, issued $500 million aggregate principal amount of its 5.5% Senior Notes due 2026 (the “2026 Notes”) and $500 million aggregate principal amount of its 5.875% Senior Notes due 2029 (the “2029 Notes” and, together with the 2026 Notes, the “Notes”). The offering of the Notes was part of a series of exit financing transactions being undertaken in connection with the Debtors’ Chapter 11 Cases and meant to provide the exit financing originally intended to be provided by the Exit Term Loan Facility pursuant to the Commitment Letter.
Based upon the business plan approved by the Court and our hedging activities we expect to generate adequate cash flows from operating activities to fully fund all investing activities without incremental borrowings under our Exit Credit Facility.
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 25, 2021, we had downside oil price protection on approximately 19 mmbbls through swaps at $42.69 per bbl. We had downside natural gas price protection on 548 bcf through swaps and collars at an average price of $2.67 per mcf.
| Oil Derivatives**(a)** | ||||||||||||||||||||
| Year | Type of Derivative Instrument | Notional Volume | Average NYMEX/Basis Price | |||||||||||||||||
| (mmbbls) | ||||||||||||||||||||
| 2021 | Fixed-price swaps | 19 | $42.69 | |||||||||||||||||
| 2021 | Basis protection swaps(b) | 5 | $0.61 | |||||||||||||||||
| 2022 | Fixed-price swaps | 11 | $44.30 | |||||||||||||||||
| 2022 | Basis protection swaps(b) | 2 | $0.09 | |||||||||||||||||
| 2023 | Fixed-price swaps | 2 | $47.17 | |||||||||||||||||
| Natural Gas Derivatives**(a)** | ||||||||||||||||||||
| Year | Type of Derivative Instrument | Notional Volume | Average NYMEX/Basis Price | |||||||||||||||||
| (bcf) | ||||||||||||||||||||
| 2021 | Fixed-price swaps(c) | 518 | $2.67 | |||||||||||||||||
| 2021 | Two-way collars | 30 | $2.80/$3.29 | |||||||||||||||||
| 2021 | Basis protection swaps | 119 | ($0.57) | |||||||||||||||||
| 2022 | Fixed-price swaps | 249 | $2.55 | |||||||||||||||||
| 2022 | Two-way collars | 23 | $2.30/$2.94 | |||||||||||||||||
| 2022 | Basis protection swaps | 30 | $0.18 | |||||||||||||||||
| 2023 | Fixed-price swaps | 45 | $2.75 | |||||||||||||||||
| 2023 | Basis protection swaps | 4 | $0.75 |
(a) Includes amounts settled in January and February 2021.
(b) Includes CMA WTI Roll swaps.
(c) Includes non-NYMEX fixed-price swaps.
See Note 14 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of derivatives and hedging activities.
Contractual Obligations and Off-Balance Sheet Arrangements
From time to time, we enter into arrangements and transactions that can give rise to contractual obligations and off-balance sheet commitments. The table below summarizes our contractual cash obligations for both recorded obligations and certain off-balance sheet arrangements and commitments as of December 31, 2020:
| Payments Due By Period | ||||||||||||||||||||||||||||||||
| Total | 2021 | 2022-2023 | 2024-2025 | 2026 and Beyond | ||||||||||||||||||||||||||||
| ($ in millions) | ||||||||||||||||||||||||||||||||
| Long-term debt: | ||||||||||||||||||||||||||||||||
| Principal(a) | $ | 9,096 | $ | 2,472 | $ | 440 | $ | 4,702 | $ | 1,482 | ||||||||||||||||||||||
| Interest(a) | 2,375 | 607 | 1,130 | 560 | 78 | |||||||||||||||||||||||||||
| Finance lease obligation(b) | 10 | 10 | — | — | — | |||||||||||||||||||||||||||
| Operating lease obligations(c) | 30 | 28 | 2 | — | — | |||||||||||||||||||||||||||
| Operating commitments(d) | 5,102 | 872 | 1,326 | 992 | 1,912 | |||||||||||||||||||||||||||
| Standby letters of credit | 54 | 54 | — | — | — | |||||||||||||||||||||||||||
| Other | 12 | 6 | 6 | — | — | |||||||||||||||||||||||||||
| Total contractual cash obligations(e) | $ | 16,679 | $ | 4,049 | $ | 2,904 | $ | 6,254 | $ | 3,472 |
(a) The maturities of our debt obligations and associated interest reflect their original expiration dates and do not reflect any acceleration due to any events of default pertaining to these obligations. 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) 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
For the year ending December 31, 2021, we currently expect to bring or have online approximately 110 to 125 gross wells across five to six rigs and plan to invest between approximately $670 – $740 million in capital expenditures. We expect that approximately 80% of our 2021 capital expenditures will be directed toward our natural gas assets. We currently plan to fund our 2021 capital program through cash on hand, expected cash flow from our operations and borrowings under our Exit Revolver. We may alter or change our plans with respect to our capital program and expected capital expenditures based on developments in our business, our financial position, our industry or any of the markets in which we operate.
Credit Risk
Our customers and counterparties are experiencing uncertain economic conditions which may impact their ability to make payments to us, which could adversely affect our business, cash flows, liquidity, financial condition and results of operations. We monitor the creditworthiness of all our customers and counterparties and we generally require letters of credit or parent guarantees for receivables from parties deemed to have sub-standard credit, unless the credit risk can otherwise be mitigated.
Sources of Funds
The following table presents the sources of our cash and cash equivalents for the years ended December 31, 2020, 2019 and 2018. See Note 3 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of divestitures of oil and natural gas assets.
| Years Ended December 31, | ||||||||||||||||||||
| 2020 | 2019 | 2018 | ||||||||||||||||||
| ($ in millions) | ||||||||||||||||||||
| Cash provided by operating activities | $ | 1,164 | $ | 1,623 | $ | 1,730 | ||||||||||||||
| Proceeds from issuances of debt, net | — | 1,563 | 1,236 | |||||||||||||||||
| Proceeds from revolving credit facility borrowings, net | 339 | 496 | — | |||||||||||||||||
| Proceeds from divestitures of proved and unproved properties, net | 136 | 130 | 2,231 | |||||||||||||||||
| Proceeds from sales of other property and equipment, net | 14 | 6 | 147 | |||||||||||||||||
| Proceeds from sales of investments | — | — | 74 | |||||||||||||||||
| Total sources of cash and cash equivalents | $ | 1,653 | $ | 3,818 | $ | 5,418 |
Cash Flow from Operating Activities
Cash provided by operating activities was $1.164 billion, $1.623 billion and $1.730 billion in 2020, 2019 and 2018, respectively. The decrease in 2020 is primarily the result of lower prices for the oil, natural gas and NGL we sold. The decrease in 2019 is primarily the result of lower prices for the oil, natural gas and NGL we sold as well as certain cash expenditures related to our WildHorse acquisition. Changes in cash flow from operations are largely due to the same factors that affect our net income, excluding various non-cash items, such as depreciation, depletion and amortization, certain impairments, gains or losses on sales of fixed assets, deferred income taxes and mark-to-market changes in our derivative instruments. See further discussion below under Results of Operations.
Debt issuances
The following table reflects the proceeds received from issuances of debt in 2020, 2019 and 2018. See Note 5 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion.
| Years Ended December 31, | ||||||||||||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | ||||||||||||||||||||||||||||||||||||
| Principal Amount of Debt Issued | Net Proceeds | Principal Amount of Debt Issued | Net Proceeds | Principal Amount of Debt Issued | Net Proceeds | |||||||||||||||||||||||||||||||||
| ($ in millions) | ||||||||||||||||||||||||||||||||||||||
| Term loan | $ | — | $ | — | $ | 1,500 | $ | 1,455 | $ | — | $ | — | ||||||||||||||||||||||||||
| Senior secured second lien notes | — | — | 120 | 108 | — | — | ||||||||||||||||||||||||||||||||
| Senior notes | — | — | — | — | 1,250 | 1,236 | ||||||||||||||||||||||||||||||||
| Total | $ | — | $ | — | $ | 1,620 | $ | 1,563 | $ | 1,250 | $ | 1,236 |
Divestitures of Proved and Unproved Properties
In 2020, we divested our Mid-Continent asset for $130 million and certain non-core assets for approximately $6 million. In 2019, we divested certain non-core assets for approximately $130 million. In 2018, we divested $2.231 billion of proved and unproved properties including $1.868 billion for our Utica Shale properties in Ohio. Proceeds from these transactions were used to repay debt and fund our development program. See Note 3 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion.
Uses of Funds
The following table presents the uses of our cash and cash equivalents for the years ended December 31, 2020, 2019 and 2018:
| Years Ended December 31, | ||||||||||||||||||||
| 2020 | 2019 | 2018 | ||||||||||||||||||
| ($ in millions) | ||||||||||||||||||||
| Oil and Natural Gas Expenditures: | ||||||||||||||||||||
| Drilling and completion costs | $ | 1,111 | $ | 2,180 | $ | 1,848 | ||||||||||||||
| Acquisitions of proved and unproved properties | 9 | 35 | 128 | |||||||||||||||||
| Total oil and natural gas expenditures | 1,120 | 2,215 | 1,976 | |||||||||||||||||
| Other Uses of Cash and Cash Equivalents: | ||||||||||||||||||||
| Cash paid to purchase debt | 94 | 1,073 | 2,813 | |||||||||||||||||
| DIP credit facility and exit facilities financing costs | 109 | — | — | |||||||||||||||||
| Business combination, net | — | 353 | — | |||||||||||||||||
| Payments on revolving credit facility borrowings, net | — | — | 362 | |||||||||||||||||
| Extinguishment of other financing | — | — | 122 | |||||||||||||||||
| Additions to other property and equipment | 22 | 48 | 21 | |||||||||||||||||
| Cash paid for preferred stock dividends | 22 | 91 | 92 | |||||||||||||||||
| Other | 13 | 36 | 27 | |||||||||||||||||
| Total other uses of cash and cash equivalents | 260 | 1,601 | 3,437 | |||||||||||||||||
| Total uses of cash and cash equivalents | $ | 1,380 | $ | 3,816 | $ | 5,413 |
Drilling and Completion Costs
Our drilling and completion costs decreased in 2020 compared to 2019 primarily as a result of decreased drilling and completion activity mainly in our liquids-rich 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 8 rigs and spud wells were 167 in 2020 compared to an average operated rig count of 18 rigs and 333 spud wells in 2019 and 17 rigs and 322 spud wells in 2018. We completed 188 operated wells in 2020 compared to 370 in 2019 and 351 in 2018.
Business Combination - Acquisition of WildHorse
In 2019, we acquired WildHorse for approximately 3.6 million reverse stock split adjusted 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 8 of this report for further discussion of the acquisition.
Cash Paid to Purchase Debt
In 2020, we repurchased approximately $160 million aggregate principal amount of our senior notes for $94 million. 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.
DIP Credit Facility Financing Costs
In 2020, we paid $109 million of one-time fees to lenders to establish our DIP Credit Facility and Exit Credit Facility.
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 $22 million, $91 million and $92 million on our preferred stock during 2020, 2019 and 2018, respectively. On April 17, 2020, we announced that we were suspending payment of dividends on each series of our outstanding convertible preferred stock. Pursuant to the restructuring support agreement associated with our Chapter 11 Cases (the “Restructuring Support Agreement”), each holder of an equity interest in Chesapeake had such interest canceled, released, and extinguished without any distribution. See Note 2 of the notes to our consolidated financial statements included in Item 8 of this report for additional information about the Chapter 11 Cases.
Results of Operations
Year ended December 31, 2020 compared to the year ended December 31, 2019
Below is a discussion of changes in our results of operations for 2020 compared to 2019. A discussion of changes in our results of operations for 2019 compared to 2018 has been omitted from this Form 10-K, but may be found in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of our Form 10-K for the year ended December 31, 2019 as filed with the SEC on February 27, 2020.
Oil, Natural Gas and NGL Production and Average Sales Prices
| 2020 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Oil | Natural Gas | NGL | Total | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| mbbl per day | $/bbl | mmcf per day | $/mcf | mbbl per day | $/bbl | mboe per day | % | $/boe | ||||||||||||||||||||||||||||||||||||||||||||||||
| Marcellus | — | — | 1,052 | 1.64 | — | — | 175 | 39 | 9.82 | |||||||||||||||||||||||||||||||||||||||||||||||
| Haynesville | — | — | 521 | 1.83 | — | — | 87 | 20 | 10.99 | |||||||||||||||||||||||||||||||||||||||||||||||
| Eagle Ford | 50 | 39.12 | 135 | 2.28 | 18 | 12.56 | 91 | 20 | 27.47 | |||||||||||||||||||||||||||||||||||||||||||||||
| Brazos Valley | 36 | 37.30 | 50 | 0.86 | 6 | 6.02 | 50 | 11 | 28.13 | |||||||||||||||||||||||||||||||||||||||||||||||
| Powder River Basin | 13 | 36.64 | 58 | 1.92 | 4 | 14.94 | 26 | 6 | 24.22 | |||||||||||||||||||||||||||||||||||||||||||||||
| Retained assets(a) | 99 | 38.14 | 1,816 | 1.73 | 28 | 11.46 | 429 | 96 | 16.80 | |||||||||||||||||||||||||||||||||||||||||||||||
| Divested assets(b) | 4 | 37.92 | 56 | 1.87 | 3 | 12.36 | 16 | 4 | 17.85 | |||||||||||||||||||||||||||||||||||||||||||||||
| Total | 103 | 38.16 | 1,872 | 1.73 | 31 | 11.55 | 445 | 100 | % | 16.84 | ||||||||||||||||||||||||||||||||||||||||||||||
| 2019 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Oil | Natural Gas | NGL | Total | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| mbbl per day | $/bbl | mmcf per day | $/mcf | mbbl per day | $/bbl | mboe per day | % | $/boe | ||||||||||||||||||||||||||||||||||||||||||||||||
| Marcellus | — | — | 946 | 2.48 | — | — | 158 | 32 | 14.88 | |||||||||||||||||||||||||||||||||||||||||||||||
| Haynesville | — | — | 672 | 2.42 | — | — | 112 | 23 | 14.53 | |||||||||||||||||||||||||||||||||||||||||||||||
| Eagle Ford | 58 | 61.22 | 153 | 2.73 | 19 | 17.04 | 102 | 21 | 41.72 | |||||||||||||||||||||||||||||||||||||||||||||||
| Brazos Valley | 33 | 59.29 | 49 | 1.79 | 5 | 8.04 | 47 | 10 | 44.96 | |||||||||||||||||||||||||||||||||||||||||||||||
| Powder River Basin | 19 | 54.28 | 86 | 2.47 | 5 | 16.63 | 38 | 8 | 34.31 | |||||||||||||||||||||||||||||||||||||||||||||||
| Retained assets(a) | 110 | 59.47 | 1,906 | 2.46 | 29 | 15.37 | 457 | 94 | 25.51 | |||||||||||||||||||||||||||||||||||||||||||||||
| Divested assets(b) | 8 | 55.30 | 89 | 2.09 | 5 | 17.66 | 27 | 6 | 26.65 | |||||||||||||||||||||||||||||||||||||||||||||||
| Total | 118 | 59.20 | 1,995 | 2.45 | 34 | 15.62 | 484 | 100 | % | 25.58 |
(a) Includes assets retained as of December 31, 2020.
(b) Divested assets include Mid-Continent assets in 2020.
Oil, Natural Gas and NGL Sales
| Years Ended December 31, | ||||||||||||||||||||
| 2020 | change | 2019 | ||||||||||||||||||
| ($ in millions) | ||||||||||||||||||||
| Oil | $ | 1,427 | (44) | % | $ | 2,543 | ||||||||||||||
| Natural gas | 1,188 | (33) | % | 1,782 | ||||||||||||||||
| NGL | 130 | (32) | % | 192 | ||||||||||||||||
| Oil, natural gas and NGL sales | $ | 2,745 | (39) | % | $ | 4,517 |
The decrease in the price received per boe in 2020 resulted in a $1.423 billion decrease in revenues, and decreased sales volumes resulted in a $349 million decrease in revenues, for a total net decrease in revenues of $1.772 billion. See Note 9 of the notes to our consolidated financial statements included in Item 8 of this report for a complete discussion of oil, natural gas and NGL sales.
Oil, Natural Gas and NGL Derivatives
| Years Ended December 31, | ||||||||||||||
| 2020 | 2019 | |||||||||||||
| ($ in millions) | ||||||||||||||
| Oil derivatives – realized gains (losses) | $ | 694 | $ | 36 | ||||||||||
| Oil derivatives – unrealized gains (losses) | (140) | (248) | ||||||||||||
| Total gains (losses) on oil derivatives | 554 | (212) | ||||||||||||
| Natural gas derivatives – realized gains (losses) | 161 | 114 | ||||||||||||
| Natural gas derivatives – unrealized gains (losses) | (119) | 103 | ||||||||||||
| Total gains (losses) on natural gas derivatives | 42 | 217 | ||||||||||||
| Total gains (losses) on oil, natural gas and NGL derivatives | $ | 596 | $ | 5 |
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, | ||||||||||||||||||||
| 2020 | change | 2019 | ||||||||||||||||||
| ($ in millions) | ||||||||||||||||||||
| Marketing revenues | $ | 1,869 | (53) | % | $ | 3,967 | ||||||||||||||
| Marketing expenses | 1,889 | (53) | % | 4,003 | ||||||||||||||||
| Marketing margin | $ | (20) | 44 | % | $ | (36) |
Marketing revenues and expenses decreased in 2020 primarily as a result of decreased oil, natural gas and NGL prices received in our marketing operations and less volumes being marketed. Marketing margin increased primarily due to improved margins related to non-equity transactions.
Other Revenue
| Years Ended December 31, | ||||||||||||||
| 2020 | 2019 | |||||||||||||
| ($ in millions) | ||||||||||||||
| Other revenue | $ | 56 | $ | 63 |
Other revenue primarily relates to the amortization of deferred VPP revenue. In 2020, we sold the assets related to our remaining VPP and extinguished the liability related to the production volume delivery obligation. 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 on Sales of Assets
| Years Ended December 31, | ||||||||||||||
| 2020 | 2019 | |||||||||||||
| ($ in millions) | ||||||||||||||
| Gains on sales of assets | $ | 30 | $ | 43 |
In 2020, we filed a notice with the Bankruptcy Court that we reached an agreement with Tapstone Energy to sell our Mid-Continent asset in a transaction under Section 363 the Bankruptcy Code. An auction supervised by the Bankruptcy Court was held on November 10, 2020 in which other pre-qualified buyers submitted bids for the asset. We presented the results of the auction process to the Bankruptcy Court and the sale was approved on November 13, 2020. On December 11, 2020, we closed the transaction with Tapstone Energy for $130 million, subject to post-closing adjustments, which resulted in the recognition of a gain of approximately $27 million.
In 2019, we received proceeds of approximately $136 million, net of post-closing adjustments, and recognized a net gain of approximately $43 million, primarily for the sale of non-core oil and natural gas properties.
See Note 3 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of these transactions.
Oil, Natural Gas and NGL Production Expenses
| Years Ended December 31, | ||||||||||||||||||||
| 2020 | change | 2019 | ||||||||||||||||||
| ($ in millions) | ||||||||||||||||||||
| Oil, natural gas and NGL production expenses | ||||||||||||||||||||
| Marcellus | $ | 32 | — | % | $ | 32 | ||||||||||||||
| Haynesville | 36 | (12) | % | 41 | ||||||||||||||||
| Eagle Ford | 112 | (38) | % | 180 | ||||||||||||||||
| Brazos Valley | 89 | (8) | % | 97 | ||||||||||||||||
| Powder River Basin | 42 | (42) | % | 72 | ||||||||||||||||
| Retained Assets(a) | 311 | (26) | % | 422 | ||||||||||||||||
| Divested Assets(b) | 62 | (37) | % | 98 | ||||||||||||||||
| Total oil, natural gas and NGL production expenses | $ | 373 | (28) | % | $ | 520 | ||||||||||||||
| ($ per boe) | ||||||||||||||||||||
| Oil, natural gas and NGL production expenses | ||||||||||||||||||||
| Marcellus | $ | 0.50 | (11) | % | $ | 0.56 | ||||||||||||||
| Haynesville | $ | 1.14 | 14 | % | $ | 1.00 | ||||||||||||||
| Eagle Ford | $ | 3.37 | (30) | % | $ | 4.83 | ||||||||||||||
| Brazos Valley | $ | 4.86 | (14) | % | $ | 5.66 | ||||||||||||||
| Powder River Basin | $ | 4.41 | (15) | % | $ | 5.17 | ||||||||||||||
| Retained Assets(a) | $ | 1.98 | (22) | % | $ | 2.53 | ||||||||||||||
| Divested Assets(b) | $ | 10.52 | 5 | % | $ | 9.99 | ||||||||||||||
| Total oil, natural gas and NGL production expenses per boe | $ | 2.29 | (22) | % | $ | 2.94 |
(a) Includes assets retained as of December 31, 2020.
(b) Divested assets include our Mid-Continent assets in 2020.
The absolute and per unit decrease was primarily the result of production curtailments and reduced workover activity in our liquids-rich operating areas due to lower commodity prices.
Oil, Natural Gas, and NGL Gathering, Processing and Transportation Expenses
| Years Ended December 31, | ||||||||||||||
| 2020 | 2019 | |||||||||||||
| ($ in millions, except per unit) | ||||||||||||||
| Oil, natural gas and NGL gathering, processing and transportation expenses | $ | 1,082 | $ | 1,082 | ||||||||||
| Oil ($ per bbl) | $ | 4.00 | $ | 3.20 | ||||||||||
| Natural gas ($ per mcf) | $ | 1.28 | $ | 1.21 | ||||||||||
| NGL ($ per bbl) | $ | 4.90 | $ | 5.32 | ||||||||||
| Total ($ per boe) | $ | 6.64 | $ | 6.13 |
The per unit increase for oil and natural gas gathering, processing and transportation expenses was primarily due to the increase in transportation expense related to oil deficiency fees for our Eagle Ford operating area and production curtailments.
Severance and Ad Valorem Taxes
| Years Ended December 31, | ||||||||||||||||||||
| 2020 | change | 2019 | ||||||||||||||||||
| ($ in millions, except per unit) | ||||||||||||||||||||
| Severance taxes | $ | 87 | (40) | % | $ | 144 | ||||||||||||||
| Ad valorem taxes | 62 | (23) | % | 80 | ||||||||||||||||
| Severance and ad valorem taxes | $ | 149 | (33) | % | $ | 224 | ||||||||||||||
| Severance taxes per boe | $ | 0.53 | (35) | % | $ | 0.81 | ||||||||||||||
| Ad valorem taxes per boe | 0.38 | (17) | % | 0.46 | ||||||||||||||||
| Severance and ad valorem taxes per boe | $ | 0.91 | (28) | % | $ | 1.27 |
The decrease in severance taxes was primarily due to the reduction in value as a result of decreased prices in areas where tax is calculated on net revenue instead of production. The decrease in ad valorem taxes is primarily due to lower assessed property values for 2020 compared to 2019.
Exploration Expense
| Years Ended December 31, | ||||||||||||||||||||
| 2020 | change | 2019 | ||||||||||||||||||
| ($ in millions) | ||||||||||||||||||||
| Impairments of unproved properties | $ | 411 | 1,184 | % | $ | 32 | ||||||||||||||
| Dry hole expense | 7 | (72) | % | 25 | ||||||||||||||||
| Geological and geophysical expense and other | 9 | (67) | % | 27 | ||||||||||||||||
| Exploration expense | $ | 427 | 408 | % | $ | 84 |
The increase in exploration expense was the result of non-cash impairment charges of $411 million in unproved properties, primarily in our liquids-rich operating areas of $266 million. Our development plans contained significant reductions in future capital assigned to the liquids-rich plays resulting in a lack of intent and ability to develop unproved properties in the next five years. Additionally, a non-cash impairment charge of $144 million with respect to our Haynesville assets was recorded due to unfavorable economic conditions and capital constraints.
General and Administrative Expenses
| Years Ended December 31, | ||||||||||||||||||||
| 2020 | change | 2019 | ||||||||||||||||||
| ($ in millions, except per unit) | ||||||||||||||||||||
| Gross overhead | $ | 578 | (15) | % | $ | 682 | ||||||||||||||
| Allocated to production expenses | (186) | (12) | % | (212) | ||||||||||||||||
| Allocated to marketing expenses | (11) | (21) | % | (14) | ||||||||||||||||
| Allocated to exploration expenses | — | (100) | % | (11) | ||||||||||||||||
| Allocated to sand mine expense | (3) | (57) | % | (7) | ||||||||||||||||
| Capitalized general and administrative expenses | (71) | (3) | % | (73) | ||||||||||||||||
| Reimbursed from third parties | (40) | (20) | % | (50) | ||||||||||||||||
| General and administrative expenses, net | $ | 267 | (15) | % | $ | 315 | ||||||||||||||
| General and administrative expenses, net per boe | $ | 1.63 | (8) | % | $ | 1.78 |
Gross overhead decreased primarily due to our reduction in workforce in 2020.
Separation and Other Termination Costs
In 2020 and 2019, we incurred charges of approximately $44 million and $12 million, respectively, related to one-time termination benefits for certain employees.
Provision for Legal Contingencies
| Years Ended December 31, | ||||||||||||||
| 2020 | 2019 | |||||||||||||
| ($ in millions) | ||||||||||||||
| Provision for legal contingencies | $ | 27 | $ | 19 |
The 2020 and 2019 amounts consist of accruals for loss contingencies related to royalty claims.
Depreciation, Depletion and Amortization
| Years Ended December 31, | ||||||||||||||||||||
| 2020 | change | 2019 | ||||||||||||||||||
| ($ in millions, except per unit) | ||||||||||||||||||||
| Depreciation, depletion and amortization | $ | 1,097 | (52) | % | $ | 2,264 | ||||||||||||||
| Depreciation, depletion and amortization per boe | $ | 6.72 | (48) | % | $ | 12.82 |
The absolute and per unit decreases in 2020 are primarily the result of an $8.446 billion impairment recognized in 2020 on our proved oil and natural gas properties due to lower forecasted commodity prices, which reduced the depletable carrying value.
Impairments
| Years Ended December 31, | ||||||||||||||
| 2020 | 2019 | |||||||||||||
| ($ in millions) | ||||||||||||||
| Impairments of oil and gas properties | $ | 8,446 | $ | 8 | ||||||||||
| Impairments of other fixed assets | 89 | 3 | ||||||||||||
| Total impairments | $ | 8,535 | $ | 11 |
Oil and natural gas properties. In 2020, we recorded impairments of proved oil and natural gas properties related to Eagle Ford, Brazos Valley, Powder River Basin, Mid-Continent and other non-core assets, all of which were due to lower forecasted commodity prices.
Other fixed assets. In 2020, we recorded a $76 million impairment of our sand mine assets that support our Brazos Valley operating area for the difference between the fair value and carrying value of the assets as well as a $13 million impairment of compressor inventory due to a lack of a current market for compressors.
See Note 18 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our impairments.
Other Operating Expense
| Years Ended December 31, | ||||||||||||||||||||
| 2020 | change | 2019 | ||||||||||||||||||
| ($ in millions) | ||||||||||||||||||||
| Other operating expense | $ | 109 | 18 | % | $ | 92 |
In 2020, we terminated certain gathering, processing and transportation contracts and recognized a non-recurring $80 million expense related to the contract terminations. The contract terminations removed approximately $169 million of future commitments related to gathering, processing and transportation agreements.
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 $38 million of severance expense as a result of the acquisition of WildHorse. A majority of the WildHorse executives and employees were terminated at the time of acquisition. These executives and employees were entitled to severance benefits in accordance with existing employment agreements.
Interest Expense
| Years Ended December 31, | ||||||||||||||
| 2020 | 2019 | |||||||||||||
| ($ in millions, except per unit) | ||||||||||||||
| Interest expense on DIP credit facility | $ | 3 | $ | — | ||||||||||
| Interest expense on senior notes | 239 | 578 | ||||||||||||
| Interest expense on term loan | 71 | 4 | ||||||||||||
| Interest expense on pre-petition revolving credit facility | 89 | 96 | ||||||||||||
| Amortization of discount, issuance costs and other | 31 | 3 | ||||||||||||
| Amortization of premium | (87) | (5) | ||||||||||||
| Realized gains on interest rate derivatives | — | (5) | ||||||||||||
| Unrealized losses on interest rate derivatives | — | 4 | ||||||||||||
| Capitalized interest | (15) | (24) | ||||||||||||
| Total interest expense | $ | 331 | $ | 651 | ||||||||||
| Interest expense per boe | $ | 2.03 | $ | 3.68 | ||||||||||
| Average pre-petition revolving credit facility | $ | 1,887 | $ | 1,934 | ||||||||||
| Average DIP credit facility | $ | 1 | $ | — | ||||||||||
| Average senior notes borrowings | n/a | $ | 7,857 | |||||||||||
| Average term loan borrowings | n/a | $ | 37 |
The decrease in interest expense on senior notes is due to our Chapter 11 proceedings. We have not paid or recognized interest expense on any outstanding debt that was reclassified to liabilities subject to compromise.
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. (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%.
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 was other-than-temporary and recognized an impairment of our investment in FTSI of approximately $43 million.
In 2020, the hydraulic fracturing industry experienced challenging operating conditions resulting in FTSI filing for Chapter 11 bankruptcy, and we recognized an impairment of our entire investment of $23 million. FTSI emerged from bankruptcy on November 19, 2020 and this restructuring resulted in a reduction of the common stock we owned in FTSI from 20% to less than 2%. The decreased ownership percentage and the loss of significant influence required us to measure the investment at fair value.
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.
See Note 17 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 2020, we repurchased approximately $160 million aggregate principal amount of senior notes for $95 million and recorded an aggregate gain of approximately $65 million. 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.
Other Income. In 2019, we recognized $9 million of other income from the sale of seismic data licenses to third parties. The remaining amount in 2019 was from other non-operating miscellaneous income.
Reorganization Items, Net
| Years Ended December 31, 2020 | ||||||||
| ($ in millions) | ||||||||
| Provision for allowed claims | $ | (879) | ||||||
| Write off of unamortized debt premiums (discounts) | 518 | |||||||
| Write off of unamortized debt issuance costs | (61) | |||||||
| Debt and equity financing fees | (145) | |||||||
| Loss on divested assets | (128) | |||||||
| Legal and professional fees | (113) | |||||||
| Gain on settlement of pre-petition accounts payable | 15 | |||||||
| Loss on settlement of pre-petition revenues payable | (3) | |||||||
| Reorganization items, net | $ | (796) |
We have incurred and will continue to incur significant expenses, gains and losses associated with our reorganization, primarily the write-off of unamortized debt issuance costs and related unamortized premiums and discounts, debt and equity financing fees, provision for allowed claims and legal and professional fees incurred subsequent to the Chapter 11 Filings for the reorganization process.
Income Tax Expense (Benefit). We recorded an income tax benefit of $19 million and $331 million in 2020 and 2019, respectively. The income tax benefit for 2020 consists of a reversal of the income tax expense recorded in 2019 of $10 million relating to Texas no longer being in a net deferred tax asset position for the period ended December 31, 2019. Texas reverted back to being in a net deferred tax asset position which was offset by a valuation allowance for the period ended December 31, 2020 which resulted in the reversal. The $19 million also includes a current state income tax benefit of $6 million and a $3 million benefit for amounts which were previously sequestered or anticipated to be sequestered by the Internal Revenue Service (IRS) against certain refunds of alternative minimum tax (AMT) credits. The IRS announced on January 16, 2020, that refunds of AMT credits should not have been subject to sequestration. All previously sequestered funds have been received. The income tax benefit for 2019 consists mainly of a $314 million 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 the aforementioned deferred tax position in Texas 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.
Bankruptcy Proceedings. We have applied Accounting Standards Codification (ASC) 852, Reorganizations (“ASC 852”) in preparing our consolidated financial statements. ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 Cases, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain revenues, expenses, realized gains and losses and provisions for losses that are realized or incurred in the bankruptcy proceedings, including losses related to executory contracts that were approved for rejection by the Bankruptcy Court, and unamortized deferred financing costs, premiums and discount associated with debt classified as liabilities subject to compromise, are recorded in reorganization items, net on our accompanying consolidated statements of operations. In addition, pre-petition obligations that may be impacted by the bankruptcy reorganization process have been classified on our consolidated balance sheets as of December 31, 2020 as liabilities subject to compromise. These liabilities are reported at the amounts we anticipate will be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts. See Note 2 of the notes to our consolidated financial statements included in Item 8 of this report for more information.
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 NYMEX strip 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:
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taxable income projections in future years;
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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;
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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 more likely than not to be realized.
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.
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