filings.toolsItem 8. Financial Statements and Supplementary Data
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Item 8. Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
To the Shareholders and the Board of Directors of EQT Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of EQT Corporation and subsidiaries (the Company) as of December 31, 2020 and 2019, the related statements of consolidated operations, comprehensive income, cash flows and equity for each of the three years in the period ended December 31, 2020, and the related notes and the financial statement schedule listed in the Index at Item 15 (a) (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company at December 31, 2020 and 2019, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 17, 2021 expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Depreciation, depletion and amortization ('DD&A') of proved oil and natural gas properties
| Description of the Matter | At December 31, 2020, the net book value of the Company's proved oil and natural gas properties was $13,613 million, and depreciation, depletion and amortization (DD&A) expense was $1,393 million for the year then ended. As described in Note 1, under the successful efforts method of accounting, DD&A is recorded on a cost center basis using the units-of-production method. Proved developed reserves, as estimated by the Company’s internal engineers, are used to calculate depreciation of wells and related equipment and facilities and amortization of intangible drilling costs. Total proved reserves, also estimated by the Company’s engineers, are used to calculate depletion on property acquisitions. Proved natural gas, natural gas liquids (NGLs) and oil reserve estimates are based on geological and engineering evaluations of in-place hydrocarbon volumes. Significant judgment is required by the Company’s engineers in evaluating geological and engineering data when estimating proved natural gas, NGLs and oil reserves. Estimating reserves also requires the selection of inputs, including natural gas, NGLs and oil price assumptions, future operating and capital costs assumptions and tax rates by jurisdiction, among others. Because of the complexity involved in estimating natural gas, NGLs and oil reserves, management used independent engineers to audit the estimates prepared by the Company’s internal engineers as of December 31, 2020. Auditing the Company’s DD&A calculation is especially complex because of the use of the work of the internal engineers and the independent engineers and the evaluation of management’s determination of the inputs described above used by the specialists in estimating proved natural gas, NGLs and oil reserves. | ||||
| How We Addressed the Matter in Our Audit | We obtained an understanding, evaluated the design and tested the operating effectiveness of the Company’s controls over its process to calculate DD&A, including management’s controls over the completeness and accuracy of the financial data provided to the specialists for use in estimating the proved natural gas, NGLs and oil reserves. Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the Company engineer primarily responsible for overseeing the preparation of the reserve estimates by the internal engineering staff and the independent engineers used to audit the estimates. In addition, we evaluated the completeness and accuracy of the financial data and inputs described above used by the specialists in estimating proved natural gas, NGLs and oil reserves by agreeing them to source documentation and we identified and evaluated corroborative and contrary evidence. For proved undeveloped reserves, we evaluated management’s development plan for compliance with the SEC rule that undrilled locations are scheduled to be drilled within five years, unless specific circumstances justify a longer time, by assessing consistency of the development projections with the Company’s drill plan and the availability of capital relative to the drill plan. We also tested the mathematical accuracy of the DD&A calculations, including comparing the proved natural gas, NGLs and oil reserves amounts used to the Company’s reserve report. |
Accounting for the Equitrans gas gathering agreement
| Description of the Matter | As more fully described in Note 5 to the consolidated financial statements, on February 26, 2020, the Company entered into the Share Purchase Agreements and the Consolidated Gas Gathering Agreement (the Consolidated GGA) pursuant to which, among other things, the Company sold to Equitrans Midstream 50% of its ownership of Equitrans Midstream's common stock in exchange for approximately $52 million in cash and rate relief under certain of the Company's gathering contracts with EQM, an affiliate of Equitrans Midstream. The Consolidated GGA provides for additional cash bonus payments (the Henry Hub Cash Bonus) payable by the Company to EQM conditioned upon the quarterly average of the NYMEX Henry Hub natural gas settlement price exceeding certain price thresholds during a specified period. The Company’s initial entry to record this transaction included recognition of a contract asset representing the estimated fair value of the rate relief provided by the Consolidated GGA of $410 million and a derivative liability related to the Henry Hub Cash Bonus of approximately $117 million. The determination of fair value of these components included significant judgment and assumptions by management, including an estimated production volume forecast, future commodity prices and price volatility, and a market-based discount rate. Auditing the Company's initial accounting for the Consolidated GGA contract asset and Henry Hub Cash Bonus derivative liability involved a high degree of subjectivity as the determination of fair values was based on assumptions as described above about future market and economic conditions. Additionally, a detailed analysis of the terms of the relevant agreements was required to determine the existence of any derivatives that may require separate accounting under applicable accounting guidance. | ||||
| How We Addressed the Matter in Our Audit | We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s accounting for the Consolidated GGA. For example, we tested controls over management's assessment of the appropriateness of the significant assumptions outlined above that are inputs to the fair value calculations. We also tested management’s evaluation of the Consolidated GGA and the identification and evaluation of specific features and the related accounting. To test the initial accounting for the Consolidated GGA, our audit procedures included, among others, inspection of the underlying agreement and testing management’s application of the relevant accounting guidance, including the determination of the balance sheet classification of each transaction component and the identification of any derivatives included in the arrangements. We involved professionals with specialized skill and knowledge to assist in evaluating the appropriateness of the accounting for the Consolidated GGA, including conclusions reached with respect to identification and bifurcation of embedded features. Our testing of the Company’s estimate of fair value of the contract asset and derivative liability related to the Henry Hub option included, among other procedures, evaluating the significant assumptions used and testing the completeness and accuracy of the underlying data. The audit effort involved the use of our valuation specialists to assist in evaluating the appropriateness of the methodology used in the cash flow models, as well as testing the significant market-related assumptions, such as future commodity prices and the market-based discount rate, used to develop the fair value estimates. |
Convertible Notes Issuance
| Description of the Matter | As described in Note 10 to the consolidated financial statements, in April 2020, the Company issued $500 million of aggregate principal of 1.75% convertible senior notes due May 2026 in a private offering to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended. Additionally, the Company entered into separate capped call transactions to reduce potential dilution to the Company’s common stock upon any conversion of the Convertible Notes. These transactions are collectively referred to as the Convertible Notes Transactions. To account for the Convertible Notes, the Company was required to separate the Convertible Notes into liability and equity components. The carrying amount of the liability component was calculated by measuring the fair value of similar debt instruments that do not have an associated conversion feature. The carrying amount of the equity component was determined by deducting the fair value of the liability component from the principal value of the Convertible Notes. Auditing the Company’s accounting for the Convertible Notes Transactions was complex due to the judgment that was required in determining the balance sheet classification of the elements of the Convertible Notes. Additionally, a detailed analysis of the terms of the Convertible Notes Transactions was required to determine the existence of any derivatives that may require separate accounting under applicable accounting guidance. | ||||
| How We Addressed the Matter in Our Audit | We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Convertible Notes Transactions. For example, we tested the Company's controls over the initial recognition and measurement of the Convertible Notes Transactions, including the recording of the associated liability and equity components. We also tested the evaluation of the Convertible Notes and the identification and evaluation of specific features and the related accounting. To test the initial accounting for the Convertible Notes Transactions, our audit procedures included, among others, inspection of the agreements underlying the Convertible Notes Transactions and testing management’s application of the relevant accounting guidance, including the determination of the balance sheet classification of each transaction and the identification of any derivatives included in the arrangements. We involved professionals with specialized skill and knowledge to assist in evaluating the appropriateness of the accounting for the convertible notes, including conclusions reached with respect to identification and bifurcation of embedded features. |
Valuation of Acquired Proved Reserves
| Description of the Matter | As described in Note 6 to the consolidated financial statements, the Company completed the acquisition of the Appalachian assets of Chevron U.S.A. during the year ended December 31, 2020. The Company’s accounting for the acquisition included determining the fair value of the acquired proved reserves. The determination of fair value of the acquired proved reserves included significant judgment and assumptions by management, including future commodity prices, anticipated production volumes, future operating costs, and a weighted average cost of capital (WACC). Auditing the Company's valuation of acquired proved reserves involved a high degree of subjectivity as the determination of fair value was based on assumptions as described above about future market and economic conditions. In addition, the certain of the assumptions developed by the Company’s engineering staff in conjunction with the reserve estimates described in the preceding critical audit matter, are used as inputs in the cash flow model. | ||||
| How We Addressed the Matter in Our Audit | We obtained an understanding, evaluated the design, and tested the operating effectiveness of controls over the Company's process to estimate fair value for the acquired proved reserves. For example, we tested controls over management's assessment of the appropriateness of the significant assumptions that are inputs to the fair value calculation and management’s review of the valuation model. Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the Company engineer primarily responsible for overseeing the preparation of the reserve estimates by the internal engineering staff, the independent engineers used to audit the estimates, and the external valuation specialist used to assist with the determination of the fair value of certain acquired assets. Our testing of the Company’s estimate of fair value of the acquired proved reserves included, among other procedures, evaluating the significant assumptions used and testing the completeness and accuracy of the underlying data. The audit effort involved the use of our valuation specialists to assist in evaluating the appropriateness of the methodology used in the cash flow model, as well as testing the significant market-related assumptions described above used to develop the fair value estimate. We evaluated the reasonableness of management's assumptions by comparing the key market-related assumptions (including future natural gas prices and WACC rates) used in the cash flow model to external market and third-party data and anticipated production volumes to the reserve estimates audited by the independent engineers. |
/s/ Ernst & Young LLP
We have served as the Company's auditor since 1950.
Pittsburgh, Pennsylvania
February 17, 2021
Report of Independent Registered Public Accounting Firm
To the Shareholders and the Board of Directors of EQT Corporation
Opinion on Internal Control over Financial Reporting
We have audited EQT Corporation and subsidiaries' internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, EQT Corporation and subsidiaries (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on the COSO criteria.
As indicated in the accompanying Management’s Report on Internal Control over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of the assets acquired in the Chevron Acquisition, which are included in the 2020 consolidated financial statements of the Company and constituted 5% of total assets, as of December 31, 2020, and less than 1% of consolidated total operating revenues, for the year ended December 31, 2020. Our audit of internal control over financial reporting of the Company also did not include an evaluation of the internal control over financial reporting of assets acquired in the Chevron Acquisition.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2020 and 2019, and the related statements of consolidated operations, comprehensive income, cash flows and equity for each of the three years in the period ended December 31, 2020 and the related notes and the financial statement schedule listed in the Index at Item 15 (a) of the Company and our report dated February 17, 2021 expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ernst & Young LLP
Pittsburgh, Pennsylvania
February 17, 2021
EQT CORPORATION AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED OPERATIONS
YEARS ENDED DECEMBER 31,
| 2020 | 2019 | 2018 | |||||||||||||||
| (Thousands, except per share amounts) | |||||||||||||||||
| Operating revenues: | |||||||||||||||||
| Sales of natural gas, natural gas liquids and oil | $ | 2,650,299 | $ | 3,791,414 | $ | 4,695,519 | |||||||||||
| Gain (loss) on derivatives not designated as hedges | 400,214 | 616,634 | (178,591) | ||||||||||||||
| Net marketing services and other | 8,330 | 8,436 | 40,940 | ||||||||||||||
| Total operating revenues | 3,058,843 | 4,416,484 | 4,557,868 | ||||||||||||||
| Operating expenses: | |||||||||||||||||
| Transportation and processing | 1,710,734 | 1,752,752 | 1,697,001 | ||||||||||||||
| Production | 155,403 | 153,785 | 195,775 | ||||||||||||||
| Exploration | 5,484 | 7,223 | 6,765 | ||||||||||||||
| Selling, general and administrative | 174,769 | 170,611 | 232,543 | ||||||||||||||
| Depreciation and depletion | 1,393,465 | 1,538,745 | 1,569,038 | ||||||||||||||
| Amortization of intangible assets | 26,006 | 35,916 | 41,367 | ||||||||||||||
| Impairment/loss on sale/exchange of long-lived assets | 100,729 | 1,138,287 | 2,709,976 | ||||||||||||||
| Impairment of intangible and other assets | 34,694 | 15,411 | — | ||||||||||||||
| Impairment of goodwill | — | — | 530,811 | ||||||||||||||
| Impairment and expiration of leases | 306,688 | 556,424 | 279,708 | ||||||||||||||
| Other operating expenses | 28,537 | 199,440 | 78,008 | ||||||||||||||
| Total operating expenses | 3,936,509 | 5,568,594 | 7,340,992 | ||||||||||||||
| Operating loss | (877,666) | (1,152,110) | (2,783,124) | ||||||||||||||
| Gain on Equitrans Share Exchange (see Note 5) | (187,223) | — | — | ||||||||||||||
| Loss on investment in Equitrans Midstream Corporation | 314,468 | 336,993 | 72,366 | ||||||||||||||
| Dividend and other income | (35,512) | (91,483) | (7,017) | ||||||||||||||
| Loss on debt extinguishment | 25,435 | — | — | ||||||||||||||
| Interest expense | 271,200 | 199,851 | 228,958 | ||||||||||||||
| Loss from continuing operations before income taxes | (1,266,034) | (1,597,471) | (3,077,431) | ||||||||||||||
| Income tax benefit | (298,858) | (375,776) | (696,511) | ||||||||||||||
| Loss from continuing operations | (967,176) | (1,221,695) | (2,380,920) | ||||||||||||||
| Income from discontinued operations, net of tax | — | — | 373,762 | ||||||||||||||
| Net loss | (967,176) | (1,221,695) | (2,007,158) | ||||||||||||||
| Less: Net loss attributable to noncontrolling interest | (10) | — | — | ||||||||||||||
| Less: Net income from discontinued operations attributable to noncontrolling interests | — | — | 237,410 | ||||||||||||||
| Net loss attributable to EQT Corporation | $ | (967,166) | $ | (1,221,695) | $ | (2,244,568) | |||||||||||
| Amounts attributable to EQT Corporation: | |||||||||||||||||
| Loss from continuing operations | $ | (967,166) | $ | (1,221,695) | $ | (2,380,920) | |||||||||||
| Income from discontinued operations, net of tax | — | — | 136,352 | ||||||||||||||
| Net loss | $ | (967,166) | $ | (1,221,695) | $ | (2,244,568) | |||||||||||
| Loss per share of common stock attributable to EQT Corporation: | |||||||||||||||||
| Basic and diluted: | |||||||||||||||||
| Weighted average common stock outstanding | 260,613 | 255,141 | 260,932 | ||||||||||||||
| Loss from continuing operations | $ | (3.71) | $ | (4.79) | $ | (9.12) | |||||||||||
| Income from discontinued operations | — | — | 0.52 | ||||||||||||||
| Net loss | $ | (3.71) | $ | (4.79) | $ | (8.60) | |||||||||||
The accompanying notes are an integral part of these Consolidated Financial Statements.
EQT CORPORATION AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
YEARS ENDED DECEMBER 31,
| 2020 | 2019 | 2018 | |||||||||||||||
| (Thousands) | |||||||||||||||||
| Net loss | $ | (967,176) | $ | (1,221,695) | $ | (2,007,158) | |||||||||||
| Other comprehensive (loss) income, net of tax: | |||||||||||||||||
| Net change in cash flow hedges: | |||||||||||||||||
| Natural gas, net of tax expense: $2,584 in 2018 | — | — | (4,625) | ||||||||||||||
| Interest rate, net of tax expense: $210 in 2019 and $80 in 2018 | — | 387 | 168 | ||||||||||||||
| Other postretirement benefits liability adjustment, net of tax (benefit) expense: $(36), $150 and $510 | (156) | 316 | 606 | ||||||||||||||
| Change in accounting principle | — | (496) | — | ||||||||||||||
| Other comprehensive (loss) income | (156) | 207 | (3,851) | ||||||||||||||
| Comprehensive loss | (967,332) | (1,221,488) | (2,011,009) | ||||||||||||||
| Less: Comprehensive loss attributable to noncontrolling interest | (10) | — | — | ||||||||||||||
| Less: Comprehensive income from discontinued operations attributable to noncontrolling interests | — | — | 237,410 | ||||||||||||||
| Comprehensive loss attributable to EQT Corporation | $ | (967,322) | $ | (1,221,488) | $ | (2,248,419) |
The accompanying notes are an integral part of these Consolidated Financial Statements.
EQT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
| 2020 | 2019 | ||||||||||
| (Thousands) | |||||||||||
| ASSETS | |||||||||||
| Current assets: | |||||||||||
| Cash and cash equivalents | $ | 18,210 | $ | 4,596 | |||||||
| Accounts receivable (less provision for doubtful accounts: $6,239 and $6,861) | 566,552 | 610,088 | |||||||||
| Derivative instruments, at fair value | 527,073 | 812,664 | |||||||||
| Income tax receivable | — | 298,854 | |||||||||
| Prepaid expenses and other | 103,615 | 28,653 | |||||||||
| Total current assets | 1,215,450 | 1,754,855 | |||||||||
| Property, plant and equipment | 21,995,249 | 21,655,351 | |||||||||
| Less: Accumulated depreciation and depletion | 5,940,984 | 5,499,861 | |||||||||
| Net property, plant and equipment | 16,054,265 | 16,155,490 | |||||||||
| Contract asset | 410,000 | — | |||||||||
| Investment in Equitrans Midstream Corporation | 203,380 | 676,009 | |||||||||
| Other assets | 230,374 | 222,873 | |||||||||
| Total assets | $ | 18,113,469 | $ | 18,809,227 | |||||||
| LIABILITIES AND SHAREHOLDERS' EQUITY | |||||||||||
| Current liabilities: | |||||||||||
| Current portion of debt | $ | 154,161 | $ | 16,204 | |||||||
| Accounts payable | 705,461 | 796,438 | |||||||||
| Derivative instruments, at fair value | 600,877 | 312,696 | |||||||||
| Other current liabilities | 301,911 | 220,564 | |||||||||
| Total current liabilities | 1,762,410 | 1,345,902 | |||||||||
| Credit facility borrowings | 300,000 | 294,000 | |||||||||
| Term Loan Facility borrowings | — | 999,353 | |||||||||
| Senior notes | 4,371,467 | 3,878,366 | |||||||||
| Note payable to EQM Midstream Partners, LP | 99,838 | 105,056 | |||||||||
| Deferred income taxes | 1,371,967 | 1,485,814 | |||||||||
| Other liabilities and credits | 945,057 | 897,148 | |||||||||
| Total liabilities | 8,850,739 | 9,005,639 | |||||||||
| Shareholders' equity: | |||||||||||
| Common stock, no par value, shares authorized: 640,000 and 320,000, shares issued: 280,003 and 257,003 | 8,241,684 | 7,818,205 | |||||||||
| Treasury stock, shares at cost: 1,658 and 1,832 | (29,348) | (32,507) | |||||||||
| Retained earnings | 1,048,259 | 2,023,089 | |||||||||
| Accumulated other comprehensive loss | (5,355) | (5,199) | |||||||||
| Total common shareholders' equity | 9,255,240 | 9,803,588 | |||||||||
| Noncontrolling interests in consolidated subsidiaries | 7,490 | — | |||||||||
| Total equity | 9,262,730 | 9,803,588 | |||||||||
| Total liabilities and shareholders' equity | $ | 18,113,469 | $ | 18,809,227 |
The accompanying notes are an integral part of these Consolidated Financial Statements.
EQT CORPORATION AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
YEARS ENDED DECEMBER 31,
| 2020 | 2019 | 2018 | |||||||||||||||
| (Thousands) | |||||||||||||||||
| Cash flows from operating activities: | |||||||||||||||||
| Net loss | $ | (967,176) | $ | (1,221,695) | $ | (2,007,158) | |||||||||||
| Adjustments to reconcile net loss to net cash provided by operating activities: | |||||||||||||||||
| Deferred income tax expense (benefit) | (155,840) | (275,063) | (510,405) | ||||||||||||||
| Depreciation and depletion | 1,393,465 | 1,538,745 | 1,729,739 | ||||||||||||||
| Amortization of intangible assets | 26,006 | 35,916 | 77,374 | ||||||||||||||
| Impairment/loss on sale/exchange of long-lived assets and leases | 442,111 | 1,710,122 | 2,989,684 | ||||||||||||||
| Gain on Equitrans Share Exchange | (187,223) | — | — | ||||||||||||||
| Impairment of goodwill | — | — | 798,689 | ||||||||||||||
| Loss on investment in Equitrans Midstream Corporation | 314,468 | 336,993 | 72,366 | ||||||||||||||
| Loss on debt extinguishment | 25,435 | — | — | ||||||||||||||
| Share-based compensation expense | 19,552 | 31,233 | 25,189 | ||||||||||||||
| Amortization, accretion and other | 37,414 | 23,296 | (33,039) | ||||||||||||||
| (Gain) loss on derivatives not designated as hedges | (400,214) | (616,634) | 178,591 | ||||||||||||||
| Cash settlements received (paid) on derivatives not designated as hedges | 897,190 | 246,639 | (225,279) | ||||||||||||||
| Net premiums (paid) received on derivative instruments | (46,665) | 22,616 | — | ||||||||||||||
| Changes in other assets and liabilities: | |||||||||||||||||
| Accounts receivable | (36,296) | 432,323 | (439,062) | ||||||||||||||
| Accounts payable | (29,193) | (238,674) | 457,113 | ||||||||||||||
| Income tax receivable and payable | 322,763 | (167,281) | (117,188) | ||||||||||||||
| Other current assets | (68,628) | 54,776 | (28,256) | ||||||||||||||
| Other items, net | (49,468) | (61,608) | 7,898 | ||||||||||||||
| Net cash provided by operating activities | 1,537,701 | 1,851,704 | 2,976,256 | ||||||||||||||
| Cash flows from investing activities: | |||||||||||||||||
| Capital expenditures | (1,042,231) | (1,602,454) | (2,999,037) | ||||||||||||||
| Cash paid for acquisitions (see Note 6) | (691,942) | — | — | ||||||||||||||
| Capital expenditures for discontinued operations | — | — | (732,727) | ||||||||||||||
| Capital contributions to Mountain Valley Pipeline, LLC | — | — | (820,943) | ||||||||||||||
| Proceeds from sale of assets | 126,080 | — | 583,381 | ||||||||||||||
| Cash received for Equitrans Share Exchange | 52,323 | — | — | ||||||||||||||
| Other investing activities | (30) | 1,312 | (9,778) | ||||||||||||||
| Net cash used in investing activities | (1,555,800) | (1,601,142) | (3,979,104) | ||||||||||||||
| Cash flows from financing activities: | |||||||||||||||||
| Net proceeds from issuance of common stock | 340,923 | — | — | ||||||||||||||
| Proceeds from borrowings on credit facility | 3,118,250 | 2,978,750 | 8,637,500 | ||||||||||||||
| Repayment of borrowings on credit facility | (3,112,250) | (3,484,750) | (8,953,500) | ||||||||||||||
| Proceeds from issuance of debt | 2,600,000 | 1,000,000 | 2,500,000 | ||||||||||||||
| Debt issuance costs and Capped Call Transactions (See Note 10) | (71,056) | (913) | (40,966) | ||||||||||||||
| Repayments and retirements of debt | (2,822,262) | (704,661) | (8,376) | ||||||||||||||
| Premiums paid on debt extinguishment | (21,132) | — | — | ||||||||||||||
| Dividends paid | (7,664) | (30,655) | (31,375) | ||||||||||||||
| Proceeds and excess tax benefits from awards under employee compensation plans | — | — | 1,946 | ||||||||||||||
| Cash paid for taxes related to net settlement of share-based incentive awards | (596) | (7,224) | (22,647) | ||||||||||||||
| Repurchase and retirement of common stock | — | — | (538,876) | ||||||||||||||
| Repurchase of common stock | — | — | (27) | ||||||||||||||
| Contributions from (distributions to) noncontrolling interests | 7,500 | — | (380,651) | ||||||||||||||
| Acquisition of 25% of Strike Force Midstream LLC | — | — | (175,000) | ||||||||||||||
| Net cash transferred at Separation and Distribution | — | — | (129,008) | ||||||||||||||
| Net cash provided by (used in) financing activities | 31,713 | (249,453) | 859,020 | ||||||||||||||
| Net change in cash and cash equivalents | 13,614 | 1,109 | (143,828) | ||||||||||||||
| Cash and cash equivalents at beginning of year | 4,596 | 3,487 | 147,315 | ||||||||||||||
| Cash and cash equivalents at end of year | $ | 18,210 | $ | 4,596 | $ | 3,487 |
The accompanying notes are an integral part of these Consolidated Financial Statements.
See Note 1 for supplemental cash flow information. See Note 8 for discontinued operations cash flow information.
EQT CORPORATION AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED EQUITY
YEARS ENDED DECEMBER 31, 2020, 2019 and 2018
| Common Stock | Accumulated Other Comprehensive (Loss) Income | Noncontrolling Interests in Consolidated Subsidiaries | |||||||||||||||||||||||||||||||||||||||
| Shares | No Par Value | Treasury Stock | Retained Earnings | Total Equity | |||||||||||||||||||||||||||||||||||||
| (Thousands, except per share or unit amounts) | |||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2017 | 264,320 | $ | 9,388,903 | $ | (63,602) | $ | 3,996,775 | $ | (2,458) | $ | 5,094,995 | $ | 18,414,613 | ||||||||||||||||||||||||||||
| Comprehensive (loss) income, net of tax: | |||||||||||||||||||||||||||||||||||||||||
| Net (loss) income | (2,244,568) | 237,410 | (2,007,158) | ||||||||||||||||||||||||||||||||||||||
| Net change in cash flow hedges: | |||||||||||||||||||||||||||||||||||||||||
| Natural gas, net of tax: $2,584 | (4,625) | (4,625) | |||||||||||||||||||||||||||||||||||||||
| Interest rate, net of tax: $80 | 168 | 168 | |||||||||||||||||||||||||||||||||||||||
| Other postretirement benefits liability adjustment, net of tax: $510 | 606 | 606 | |||||||||||||||||||||||||||||||||||||||
| Dividends ($0.12 per share) | (31,375) | (31,375) | |||||||||||||||||||||||||||||||||||||||
| Share-based compensation plans, net | 798 | (6,976) | 14,408 | 953 | 8,385 | ||||||||||||||||||||||||||||||||||||
| Distributions to noncontrolling interests in discontinued operations (a) | (380,651) | (380,651) | |||||||||||||||||||||||||||||||||||||||
| Change in accounting principle | 4,113 | 4,113 | |||||||||||||||||||||||||||||||||||||||
| Repurchase and retirement of common stock | (10,646) | (538,876) | (538,876) | ||||||||||||||||||||||||||||||||||||||
| Purchase of Strike Force Midstream LLC noncontrolling interests | 1,818 | (176,818) | (175,000) | ||||||||||||||||||||||||||||||||||||||
| Changes in ownership of consolidated subsidiaries | (158,560) | 214,930 | 56,370 | ||||||||||||||||||||||||||||||||||||||
| Distribution of Equitrans Midstream Corporation | (857,755) | 1,459,330 | 903 | (4,990,819) | (4,388,341) | ||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2018 | 254,472 | $ | 7,828,554 | $ | (49,194) | $ | 3,184,275 | $ | (5,406) | $ | — | $ | 10,958,229 | ||||||||||||||||||||||||||||
| Comprehensive (loss) income, net of tax: | |||||||||||||||||||||||||||||||||||||||||
| Net loss | (1,221,695) | (1,221,695) | |||||||||||||||||||||||||||||||||||||||
| Net change in interest rate cash flow hedges, net of tax: $210 | 387 | 387 | |||||||||||||||||||||||||||||||||||||||
| Other postretirement benefits liability adjustment, net of tax: $150 | 316 | 316 | |||||||||||||||||||||||||||||||||||||||
| Dividends ($0.12 per share) | (30,655) | (30,655) | |||||||||||||||||||||||||||||||||||||||
| Share-based compensation plans | 921 | 6,355 | 16,687 | 23,042 | |||||||||||||||||||||||||||||||||||||
| Change in accounting principle | 496 | (496) | — | ||||||||||||||||||||||||||||||||||||||
| Distribution of Equitrans Midstream Corporation (see Note 9) | (2,234) | 93,123 | 90,889 | ||||||||||||||||||||||||||||||||||||||
| Other | (222) | (14,470) | (2,455) | (16,925) | |||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2019 | 255,171 | $ | 7,818,205 | $ | (32,507) | $ | 2,023,089 | $ | (5,199) | $ | — | $ | 9,803,588 | ||||||||||||||||||||||||||||
| Comprehensive loss, net of tax: | |||||||||||||||||||||||||||||||||||||||||
| Net loss | (967,166) | (10) | (967,176) | ||||||||||||||||||||||||||||||||||||||
| Other postretirement benefits liability adjustment, net of tax: $(36) | (156) | (156) | |||||||||||||||||||||||||||||||||||||||
| Dividends ($0.03 per share) | (7,664) | (7,664) | |||||||||||||||||||||||||||||||||||||||
| Share-based compensation plans | 174 | 18,911 | 3,159 | 22,070 | |||||||||||||||||||||||||||||||||||||
| Equity component of convertible senior notes (see Note 10) | 63,645 | 63,645 | |||||||||||||||||||||||||||||||||||||||
| Issuance of common shares | 23,000 | 340,923 | 340,923 | ||||||||||||||||||||||||||||||||||||||
| Contributions from noncontrolling interests | 7,500 | 7,500 | |||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2020 | 278,345 | $ | 8,241,684 | $ | (29,348) | $ | 1,048,259 | $ | (5,355) | $ | 7,490 | $ | 9,262,730 |
Common shares authorized: 320,000 at December 31, 2018 and 2019 and 640,000 at December 31, 2020.
Preferred shares authorized: 3,000. There were no preferred shares issued or outstanding.
(a)For the year ended December 31, 2018, distributions to noncontrolling interests were $4.295, $1.123 and $0.5966 per common unit for EQM Midstream Partners, LP, EQGP Holdings, LP and RM Partners LP, respectively.
The accompanying notes are an integral part of these Consolidated Financial Statements.
EQT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2020
1. Summary of Significant Accounting Policies
Principles of Consolidation. The Consolidated Financial Statements include the accounts of EQT Corporation and all subsidiaries, ventures and partnerships in which EQT holds a controlling interest (collectively, EQT or the Company). Intercompany accounts and transactions have been eliminated in consolidation. The Company records noncontrolling interest in its Consolidated Financial Statements for any non-wholly-owned consolidated subsidiary.
Investment in Consolidated Partnership. In the fourth quarter of 2020, the Company entered into a partnership with a third-party investor (the Partnership). Because the Company has the power to direct the activities that most significantly affect the Partnership's economic performance, the Company consolidates the Partnership. The Company presents noncontrolling interest in the Partnership as a component of equity in the Consolidated Balance Sheet and an allocation of earnings attributable to the noncontrolling interest in the Statement of Consolidated Operations.
Segments. The Company's operations consist of one reportable segment. The Company has a single, company-wide management team that administers all properties as a whole rather than by discrete operating segments. The Company measures financial performance as a single enterprise and not on an area-by-area basis. Substantially all of the Company's operating revenues, income from operations and assets are generated and located in the United States.
Reclassification. Certain previously reported amounts have been reclassified to conform to the current year presentation.
Discontinued Operations. For businesses classified as discontinued operations, balance sheet amounts and results of operations are reclassified from their historical presentation to assets and liabilities of discontinued operations in the Consolidated Balance Sheet and discontinued operations on the Statement of Consolidated Operations, respectively. The Statement of Consolidated Cash Flows was not reclassified for discontinued operations. See Note 8.
Use of Estimates. The preparation of financial statements in conformity with United States generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and accompanying notes. Actual results could differ from those estimates.
Cash and Cash Equivalents. The Company considers all highly-liquid investments with an original maturity of three months or less when purchased to be cash equivalents and accounts for such investments at cost. Interest earned on cash equivalents is included as a reduction of interest expense.
Accounts Receivable. The Company's accounts receivable relates primarily to the sales of natural gas, natural gas liquids (NGLs) and oil and amounts due from joint interest partners. See Note 2 for a discussion of amounts due from contracts with customers.
Derivative Instruments. See Note 3 for a discussion of the Company's derivative instruments and Note 4 for a discussion of the Company's fair value hierarchy and fair value measurements.
Prepaid Expenses and Other. The following table summarizes the Company's prepaid expenses and other current assets.
| December 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| (Thousands) | |||||||||||
| Margin requirements with counterparties (See Note 3) | $ | 82,552 | $ | 12,606 | |||||||
| Prepaid expenses and other current assets | 21,063 | 16,047 | |||||||||
| Total prepaid expenses and other | $ | 103,615 | $ | 28,653 |
Property, Plant and Equipment. The following table summarizes the Company's property, plant and equipment.
| December 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| (Thousands) | |||||||||||
| Oil and gas producing properties, successful efforts method | $ | 21,771,025 | $ | 21,316,834 | |||||||
| Less: Accumulated depreciation and depletion | 5,866,418 | 5,402,515 | |||||||||
| Net oil and gas producing properties | 15,904,607 | 15,914,319 | |||||||||
| Other properties, at cost less accumulated depreciation | 149,658 | 241,171 | |||||||||
| Net property, plant and equipment | $ | 16,054,265 | $ | 16,155,490 |
The Company uses the successful efforts method of accounting for gas, NGL and oil producing activities. Under this method, the cost of productive wells and related equipment, development dry holes and productive acreage, including productive mineral interests, are capitalized and depleted using the unit-of-production method. These costs include salaries, benefits and other internal costs directly attributable to production activities. The Company capitalized internal costs of approximately $51 million, $77 million and $130 million in 2020, 2019 and 2018, respectively. The Company also capitalized interest expense related to well development of approximately $17 million, $24 million and $29 million in 2020, 2019 and 2018, respectively. Depletion expense is calculated based on actual produced sales volumes multiplied by the applicable depletion rate per unit. Depletion rates for leases and wells are each calculated by dividing net capitalized costs by the number of units expected to be produced over the life of the reserves separately. Costs for exploratory dry holes, exploratory geological and geophysical activities and delay rentals as well as other property carrying costs are charged to exploration expense. The Company's producing oil and gas properties had an overall average depletion rate of $0.92, $1.01 and $1.04 per Mcfe for the years ended December 31, 2020, 2019 and 2018, respectively.
There were no exploratory wells drilled during 2020, 2019 and 2018, and there were no capitalized exploratory well costs for the years ended December 31, 2020, 2019 and 2018.
Impairment of Long-lived Assets. The carrying values of the Company's proved oil and gas properties are reviewed for impairment when events or circumstances indicate that the remaining carrying value may not be recoverable. To determine whether impairment of the Company's oil and gas properties has occurred, the Company compares the estimated expected undiscounted future cash flows to the carrying values of those properties. Estimated future cash flows are based on proved and, if determined reasonable by management, risk-adjusted probable reserves and assumptions generally consistent with the assumptions used by the Company for internal planning and budgeting purposes, including, among other things, the intended use of the asset, anticipated production from reserves, future market prices for natural gas, NGLs and oil adjusted for basis differentials, future operating costs and inflation. Proved oil and gas properties that have carrying amounts in excess of estimated future undiscounted cash flows are written down to fair value, which is estimated by discounting the estimated future cash flows using discount rates and other assumptions that marketplace participants would use in their fair value estimates.
There were no indicators of impairment identified in 2020.
During the fourth quarter of 2019, there were indicators that the carrying values of certain of the Company's properties may be impaired due to depressed natural gas prices and changes in the Company's development strategy, including the Company's contemplation of a potential asset divestiture of certain of its non-strategic exploration and production assets. As a result of the 2019 impairment evaluation, the Company recorded total impairment of $1,124.4 million, of which $1,035.7 million was associated with the Company's non-strategic assets located in the Ohio Utica and $88.7 million was associated with the Company's Pennsylvania and West Virginia Utica assets. The impairment was recorded as a reduction to the assets' carrying values to their estimated fair values of approximately $839.4 million with respect to the Company's Ohio Utica assets and approximately $26.8 million with respect to the Company's Pennsylvania and West Virginia Utica assets. The fair value of the impaired assets, as determined at December 31, 2019, was based on significant inputs that are not observable in the market and, as such, are considered a Level 3 fair value measurement. See Note 4 for a description of the fair value hierarchy. Key assumptions included in the calculation of the fair value included the following: (i) reserves, including risk adjustments for probable reserves; (ii) future commodity prices; (iii) to the extent available, market-based indicators of fair value, including estimated proceeds that could be realized upon a potential disposition; (iv) production rates based on the Company's experience with similar properties; (v) future operating and development costs; (vi) inflation and (vii) a market-based weighted average cost of capital.
During 2018, there were indicators that the carrying values of certain of the Company's oil and gas producing properties may be impaired due to the Company's intention to sell its Huron and Permian assets before the end of their useful lives. As a result of
the 2018 impairment evaluation, the Company recorded impairment of $2.4 billion associated with the Company's Huron and Permian assets. See Note 7 for discussion of the Huron and Permian assets divestitures.
Impairment and Expiration of Leases. Capitalized costs of unproved oil and gas properties are evaluated for recoverability on a prospective basis at least annually. Indicators of potential impairment include changes due to economic factors, potential shifts in business strategy and historical experience. The likelihood of an impairment of unproved oil and gas properties increases as the expiration of a lease term approaches and drilling activity has not commenced. If the Company does not intend to drill on the property prior to expiration of the lease or does not have the intent and ability to extend, renew, trade or sell the lease prior to expiration, impairment expense is recorded. Expense for lease expirations where the lease was not previously impaired is recorded as the lease expires. For the years ended December 31, 2020, 2019 and 2018, the Company recorded $306.7 million, $556.4 million and $279.7 million, respectively, for lease impairments and expirations. The Company's unproved properties had a net book value of approximately $2,292 million and $3,322 million at December 31, 2020 and 2019, respectively.
Goodwill. Goodwill is the cost of an acquisition less the fair value of the identifiable net assets of the acquired business. Goodwill is tested for impairment at the Company's single reporting unit level on at least an annual basis or if events or circumstances indicate that it is more likely than not that the fair value of its reporting unit is below its carrying value. The Company considers market capitalization and other valuation techniques, as applicable, when estimating fair value for goodwill impairment testing purposes.
In connection with the 2018 annual goodwill impairment test, the Company identified several qualitative factors that are generally considered when assessing goodwill for impairment, including the steep decline in the Company's stock price through the quarter ended December 31, 2018, the weak market performance of the Company's peers for the same period, the Company's excess capital spend compared to the capital budget announced in October 2018, the recent operational volume curtailments and the Company's strategy to slow the cadence of its future drilling operations.
The Company performed the first step of the goodwill impairment test for its single reporting unit as of November 30, 2018. The Company used its market capitalization plus a control premium to estimate fair value for its single reporting unit. Estimated market capitalization was calculated by multiplying the Company's 30-day weighted average stock price and the number of outstanding common stock of the Company (EQT common stock) as of November 30, 2018. The reporting unit's estimated fair value was significantly less than its carrying value and, as such, all of the goodwill was impaired. This impairment charge was classified as a component of operating expenses.
Contract Asset. See Note 5 for discussion of the Company's contract asset.
The carrying value of the Company's contract asset is reviewed for impairment when events or circumstances indicate that the remaining carrying value may not be recoverable. To determine whether impairment of the Company's contract asset has occurred, the Company compares the estimated undiscounted future cash flows to the carrying value. Estimated future cash flows are based on the estimated volumes and the in-service date of the Mountain Valley Pipeline. If the contract asset's carrying amount exceeds the estimated future undiscounted cash flows, it is written down to fair value, which is estimated by discounting the estimated future cash flows using discount rates and other assumptions that marketplace participants would use in their fair value estimates.
During 2020, the Company identified indicators that the carrying value of the contract asset may not be fully recoverable due to further delays of the timing of completion of the Mountain Valley Pipeline as well as changes to the regulatory landscape. The Company performed the first step of the impairment test and determined the estimated expected undiscounted future cash flows exceeded the carrying value of the contract asset, indicating the contract asset was not impaired. The estimated undiscounted future cash flows were based on significant inputs that are not observable in the market and, as such, are considered a Level 3 fair value measurement. See Note 4 for a description of the fair value hierarchy. Key assumptions in the calculation of estimated undiscounted future cash flows included estimated production volumes subject to the Consolidated GGA (defined in Note 5 to the Consolidated Financial Statements) and a probability-weighted estimate of the in-service date of the Mountain Valley Pipeline.
Investment in Equitrans Midstream Corporation. As of December 31, 2020, the Company owned approximately 25 million shares of common stock of Equitrans Midstream Corporation (Equitrans Midstream). The Company does not have the ability to exercise significant influence and does not have a controlling financial interest in Equitrans Midstream or any of its subsidiaries. As such, its investment in Equitrans Midstream is accounted for as an investment in equity securities and recorded at fair value in the Consolidated Balance Sheets. The fair value is calculated by multiplying the closing stock price of Equitrans Midstream's common stock by the number of shares of Equitrans Midstream's common stock owned by the Company. Changes
in fair value are recorded in loss on investment in Equitrans Midstream Corporation in the Statements of Consolidated Operations. See Note 4 for a description of the fair value hierarchy. Dividends received on the investment in Equitrans Midstream are recorded in dividend and other income in the Statements of Consolidated Operations. See Note 5 and Note 8.
Intangible Assets. The Company's intangible assets were recorded under the acquisition method of accounting at their estimated fair values at the acquisition date of Rice Energy Inc. (Rice Energy). The Company's intangible assets were composed of non-compete agreements with former Rice Energy executives. The non-compete agreements had a useful life of 3 years. The Company calculates amortization on a straight-line basis over the estimated useful life of the intangible assets. The Company's intangible assets were fully amortized as of December 31, 2020.
The following table summarizes the Company's intangible assets.
| December 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| (Thousands) | |||||||||||
| Non-compete agreements | $ | 108,689 | $ | 124,100 | |||||||
| Less: Accumulated amortization | 108,689 | 82,683 | |||||||||
| Less: Impairment of intangible assets (a) | — | 15,411 | |||||||||
| Intangible assets, net | $ | — | $ | 26,006 |
(a)In 2019 the Company recognized impairment of its intangible assets associated with non-compete agreements for former Rice Energy executives who are now employees of the Company.
Other Current Liabilities. The following table summarizes the Company's other current liabilities.
| December 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| (Thousands) | |||||||||||
| Accrued interest payable | $ | 91,953 | $ | 36,590 | |||||||
| Current portion of long-term capacity contracts | 50,504 | 34,000 | |||||||||
| Taxes other than income | 44,619 | 57,850 | |||||||||
| Incentive compensation | 33,601 | 18,573 | |||||||||
| Current portion of operating lease liabilities | 25,004 | 29,036 | |||||||||
| Income tax payable | 23,909 | — | |||||||||
| Severance accrual | 2,536 | 11,769 | |||||||||
| Other accrued liabilities | 29,785 | 32,746 | |||||||||
| Total other current liabilities | $ | 301,911 | $ | 220,564 |
Unamortized Debt Discount and Issuance Expense. Discounts and expenses incurred with the issuance of debt are amortized over the life of the debt. These amounts are presented as a reduction of senior notes in the Consolidated Balance Sheets. See Note 10.
Income Taxes. The Company files a consolidated U.S. federal income tax return and uses the asset and liability method to account for income taxes. The provision for income taxes represents amounts paid or estimated to be payable net of amounts refunded or estimated to be refunded for the current year and the change in deferred taxes exclusive of amounts recorded in other comprehensive income (OCI). Any refinements to prior year taxes made in the current year due to new information are reflected as adjustments in the current period. Separate income taxes are calculated for income from continuing operations, income from discontinued operations and items charged or credited directly to shareholders' equity.
Deferred income tax assets and liabilities arise from temporary differences between the financial reporting and tax bases of the Company's assets and liabilities and are recognized using enacted tax rates for the effect of such temporary differences. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that a portion or all of the deferred tax asset will not be realized.
In accounting for uncertainty of a tax position taken or expected to be taken in a tax return, the Company uses a recognition threshold and measurement attribute for the financial statement recognition and measurement. The recognition threshold requires the Company to determine whether it is more likely than not that a tax position will be sustained upon examination,
including resolution of any related appeals or litigation processes, based on the technical merits of the position. If it is more likely than not that a tax position will be sustained, the Company measures and recognizes the tax position at the largest amount of benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. The Company recognizes accrued interest and penalties related to unrecognized tax benefits in income tax expense. See Note 9.
Insurance. The Company maintains insurance to cover traditional insurable risks such as general liability, workers compensation, auto liability, environmental liability, property damage, business interruption and other risks. These policies may be subject to deductible or retention amounts, coverage limitations and exclusions. The Company was previously self-insured for certain material losses related to general liability and certain other casualty coverages, such as workers compensation, auto liability and environmental liability. However, the Company is no longer self-insured with respect to any material losses related to general liability, workers compensation or environmental liability arising on or after November 12, 2020, or for losses related to auto liability arising on or after November 12, 2019. The recorded reserves represent estimates of the ultimate cost of claims incurred as of the balance sheet date. Reserves are estimated based on analyses of historical data and actuarial estimates and are not discounted. The liabilities are reviewed by the Company quarterly and by independent actuaries annually to ensure appropriateness. While the Company believes these estimates are reasonable based on the information available, financial results could be impacted if actual trends, including the severity or frequency of claims, differ from estimates.
Asset Retirement Obligations. The Company accrues a liability for asset retirement obligations based on an estimate of the amount and timing of settlement. For oil and gas wells, the fair value of the Company's plugging and abandonment obligations is recorded at the time the obligation is incurred, which is typically at the time the well is spud. Upon initial recognition of an asset retirement obligation, the Company increases the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in their present value through charges to depreciation and depletion expense. The initial capitalized costs are depleted over the useful lives of the related assets.
The Company's asset retirement obligations related to the abandonment of oil and gas producing facilities include reclaiming drilling sites, plugging wells and dismantling related structures. Estimates are based on historical experience of plugging and abandoning wells and reclaiming or disposing other assets and estimated remaining lives of the wells and assets.
The following table presents a reconciliation of the beginning and ending carrying amounts of the Company's asset retirement obligations included in other liabilities and credits in the Consolidated Balance Sheets.
| December 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| (Thousands) | |||||||||||
| Balance at January 1 | $ | 461,821 | $ | 287,805 | |||||||
| Accretion expense | 22,506 | 13,733 | |||||||||
| Liabilities incurred | 10,293 | 8,985 | |||||||||
| Liabilities settled | (4,030) | (3,569) | |||||||||
| Liabilities assumed in acquisitions | 45,825 | — | |||||||||
| Liabilities removed due to divestitures | (54,836) | (5,535) | |||||||||
| Change in estimates | 41,978 | 160,402 | |||||||||
| Balance at December 31 | $ | 523,557 | $ | 461,821 |
The Company does not have any assets that are legally restricted for purposes of settling these obligations. During 2020 and 2019, the Company had changes in estimates for the plugging of horizontal and conventional wells that were related primarily to pad reclamation and increased cost assumptions for the Company's compliance with existing regulatory requirements that were derived, in part, from recent plugging experience and actual costs incurred. The Company operates in several states that have implemented expanded requirements that resulted in the Company's use of additional materials during the plugging process, which has increased the estimated cost for plugging horizontal and conventional wells.
Revenue Recognition. For information on revenue recognition from contracts with customers and gains and losses on derivative commodity instruments see Notes 2 and 3, respectively.
Transportation and Processing. Costs incurred to gather, process and transport gas produced by the Company to market sales points are recorded as transportation and processing costs in the Statements of Consolidated Operations. The Company markets some transportation for resale. These costs, which are not incurred to transport gas produced by the Company, are reflected as a deduction from net marketing services and other revenues.
Share-based Compensation. See Note 13 for a discussion of the Company's share-based compensation plans.
Provision for Doubtful Accounts. Reserves for uncollectible accounts are recorded in selling, general and administrative expense in the Statements of Consolidated Operations. Judgment is required to assess the ultimate realization of the Company's accounts receivable. Reserves are based on historical experience, current and expected economic trends and specific information about customer accounts, such as the customer's creditworthiness.
Other Operating Expenses. The following table summarizes the Company's other operating expenses.
| Years Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (Thousands) | |||||||||||||||||
| Changes in legal reserves, including settlements | $ | 11,350 | $ | 82,395 | $ | 51,677 | |||||||||||
| Transactions | 11,739 | — | 26,331 | ||||||||||||||
| Reorganization, including severance and contract terminations | 5,448 | 97,702 | — | ||||||||||||||
| Proxy | — | 19,343 | — | ||||||||||||||
| Total other operating expenses | $ | 28,537 | $ | 199,440 | $ | 78,008 |
Other Postretirement Benefits Plan. The Company sponsors a plan for postretirement benefits plan. The Company recognized expense related to its defined contribution plan of $6.5 million, $8.9 million and $17.3 million for the years ended December 31, 2020, 2019 and 2018, respectively.
Earnings Per Share (EPS). Basic EPS is computed by dividing net income attributable to EQT by the weighted average number of common shares outstanding during the period. Diluted EPS is computed by dividing net income attributable to EQT by the weighted average number of common shares and potentially dilutive securities, net of shares assumed to be repurchased using the treasury stock method. Potentially dilutive securities arise from the assumed conversion of outstanding stock options and other share-based awards as well as the conversion premium on the Convertible Notes. Purchases of treasury shares are calculated using the average share price of EQT common stock during the period.
In periods when the Company reports a net loss, all options, restricted stock, performance awards and stock appreciation rights are excluded from the calculation of diluted weighted average shares outstanding because of their anti-dilutive effect on loss per share. As a result, for the years ended December 31, 2020, 2019 and 2018, all securities, totaling 6,778,383, 3,035,247 and 2,211,122, respectively, were excluded from potentially dilutive securities because of their anti-dilutive effect on EPS.
As discussed in Note 10, the Company issued the Convertible Notes during the second quarter of 2020 and, upon conversion of the Convertible Notes, intends to use a combined settlement approach to satisfy its settlement obligation under the Convertible Notes. As such, there is no adjustment to the diluted EPS numerator for the cash-settled portion of the instrument. For the year ended December 31, 2020, the conversion premium of 6,666,670 shares was excluded from potentially dilutive securities because of its anti-dilutive effect on loss per share.
Supplemental Cash Flow Information. The following table summarizes net cash paid (received) for interest and income taxes and non-cash activity included in the Consolidated Statements of Cash Flows.
| Years Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (Thousands) | |||||||||||||||||
| Cash paid (received) during the year for: | |||||||||||||||||
| Interest, net of amount capitalized | $ | 195,681 | $ | 198,562 | $ | 260,959 | |||||||||||
| Income taxes, net | (448,906) | (1,710) | (3,675) | ||||||||||||||
| Non-cash activity during the period for: | |||||||||||||||||
| Increase in asset retirement costs and obligations | $ | 52,271 | $ | 169,387 | $ | 34,602 | |||||||||||
| Increase in right-of-use assets and lease liabilities, net | 18,877 | 113,350 | — | ||||||||||||||
| Capitalization of non-cash equity share-based compensation | 3,142 | — | 4,314 | ||||||||||||||
| Measurement period adjustments for prior period acquisitions | — | — | 14,377 |
Recently Issued Accounting Standards
In June 2016, the Financial Accounting Standards Board (FASB) issued ASU 2016-13, Financial Instruments – Credit Losses: Measurement of Credit Losses on Financial Instruments. This ASU amends guidance on reporting credit losses for assets held at amortized cost basis and available for sale debt securities. For assets held at amortized cost basis, this ASU eliminates the probable initial recognition threshold and requires entities to reflect their current estimate of all expected credit losses. The amendment affects loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables and any other financial assets not excluded from its scope that have a contractual right to receive cash. This ASU is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. The Company adopted this ASU on January 1, 2020 with no changes to its methodology, financial statements or disclosures.
In July 2018, the FASB issued ASU 2018-07, Improvements to Nonemployee Share-Based Payment Accounting. This ASU expands the scope of Topic 718, Compensation – Share Compensation, to include share-based payment transactions where a grantor acquires goods or services from a nonemployee. This ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, and early adoption is permitted. The Company adopted this ASU on January 1, 2020 with no changes to its methodology, financial statements or disclosures.
In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement, Changes to the Disclosure Requirements for Fair Value Measurement. This ASU modifies the hierarchy associated with Level 1, 2 and 3 fair value measurements and the related disclosure requirements. This ASU is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, and early adoption is permitted. The Company adopted this ASU on January 1, 2020 with no changes to its methodology, financial statements or disclosures.
In August 2018, the FASB issued ASU 2018-15, Intangibles – Goodwill and Other – Internal-Use Software: Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract. This ASU provides guidance on accounting for implementation costs incurred by a customer in a cloud computing arrangement that is a service contract. This ASU is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, and early adoption is permitted. The Company adopted this ASU prospectively on January 1, 2020, at which point onward applicable costs were capitalized to the Consolidated Balance Sheet rather than expensed to selling, general and administrative expense in the Statement of Consolidated Operations. For the year ended December 31, 2020, such capitalized costs were approximately $9 million.
In December 2019, the FASB issued ASU 2019-12, Income Taxes: Simplifying the Accounting for Income Taxes. This ASU simplifies accounting for income taxes by eliminating certain exceptions to ASC 740, Income Taxes, related to the general approach for intraperiod tax allocation, methodology for calculating income taxes in an interim period and recognition of deferred taxes when there are investment ownership changes. In addition, this ASU simplifies aspects of accounting for franchise taxes and interim period effects of enacted changes in tax laws or rates and provides clarification on accounting for transactions that result in a step up in the tax basis of goodwill and allocation of consolidated income tax expense to separate financial statements of entities not subject to income tax. This ASU is effective for fiscal years beginning after December 15, 2020, including interim periods within those fiscal years, and early adoption is permitted. The Company plans to adopt this ASU in the first quarter of 2021 and does not expect this adoption to have a material impact on its financial statements and related disclosures.
In August 2020, the FASB issued ASU 2020-06, Debt with Conversion and Other Options and Derivatives and Hedging: Accounting for Convertible Instruments and Contracts in an Entity's Own Equity. This ASU simplifies accounting for convertible instruments by removing certain separation models for convertible instruments. For convertible instruments with conversion features that are not accounted for as derivatives under ASC 815 or do not result in substantial premiums accounted for as paid-in capital, the convertible instrument's embedded conversion features are no longer separated from the host contract. Consequently, and as long as no other feature requires bifurcation and recognition as a derivative, the convertible instrument is accounted for as a single liability measured at its amortized cost. This ASU also amends the impact of convertible instruments on the calculation of diluted EPS and adds several new disclosure requirements. This ASU is effective for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. The Company plans to adopt this ASU on January 1, 2022 using the full retrospective method of adoption. The Company is evaluating the impact this standard will have on its financial statements and related disclosures.
Subsequent Events. The Company has evaluated subsequent events through the date of the financial statement issuance.
2. Revenue from Contracts with Customers
Under the Company's natural gas, natural gas liquids (NGLs) and oil sales contracts, the Company generally considers the delivery of each unit (MMBtu or Bbl) to be a separate performance obligation that is satisfied upon delivery. These contracts typically require payment within 25 days of the end of the calendar month in which the commodity is delivered. A significant number of these contracts contain variable consideration because the payment terms refer to market prices at future delivery dates. In these situations, the Company has not identified a standalone selling price because the terms of the variable payments relate specifically to the Company's efforts to satisfy the performance obligations. Other contracts, such as fixed price contracts or contracts with a fixed differential to New York Mercantile Exchange (NYMEX) or index prices, contain fixed consideration. The fixed consideration is allocated to each performance obligation on a relative standalone selling price basis, which requires judgment from management. For these contracts, the Company generally concludes that the fixed price or fixed differentials in the contracts are representative of the standalone selling price.
Based on management's judgment, the performance obligations for the sale of natural gas, NGLs and oil are satisfied at a point in time because the customer obtains control and legal title of the asset when the natural gas, NGLs or oil is delivered to the designated sales point.
The sales of natural gas, NGLs and oil presented in the Statements of Consolidated Operations represent the Company's share of revenues net of royalties and exclude revenue interests owned by others. When selling natural gas, NGLs and oil on behalf of royalty or working interest owners, the Company is acting as an agent and, thus, reports the revenue on a net basis.
For contracts with customers where the Company's performance obligations had been satisfied and an unconditional right to consideration existed as of the balance sheet date, the Company recorded amounts due from contracts with customers of $394.1 million and $384.0 million in accounts receivable in the Consolidated Balance Sheets as of December 31, 2020 and 2019, respectively.
The table below provides disaggregated information on the Company's revenues. Certain contracts that provide for the release of capacity that is not used to transport the Company's produced volumes are outside the scope of ASU 2014-09, Revenue from Contracts with Customers. The costs of, and recoveries on, such capacity are reported in net marketing services and other in the Statements of Consolidated Operations. Derivative contracts are also outside the scope of ASU 2014-09.
| Years Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (Thousands) | |||||||||||||||||
| Revenues from contracts with customers: | |||||||||||||||||
| Natural gas sales | $ | 2,459,854 | $ | 3,559,809 | $ | 4,217,684 | |||||||||||
| NGLs sales | 169,871 | 197,985 | 442,010 | ||||||||||||||
| Oil sales | 20,574 | 33,620 | 35,825 | ||||||||||||||
| Net marketing services and other | — | — | 13,865 | ||||||||||||||
| Total revenues from contracts with customers | 2,650,299 | 3,791,414 | 4,709,384 | ||||||||||||||
| Other sources of revenue: | |||||||||||||||||
| Net marketing services and other | 8,330 | 8,436 | 27,075 | ||||||||||||||
| Gain (loss) on derivatives not designated as hedges | 400,214 | 616,634 | (178,591) | ||||||||||||||
| Total operating revenues | $ | 3,058,843 | $ | 4,416,484 | $ | 4,557,868 |
The following table summarizes the transaction price allocated to the Company's remaining performance obligations on all contracts with fixed consideration as of December 31, 2020. Amounts shown exclude contracts that qualified for the exception to the relative standalone selling price method as of December 31, 2020.
| 2021 | 2022 | 2023 | Total | ||||||||||||||||||||||||||
| (Thousands) | |||||||||||||||||||||||||||||
| Natural gas sales | $ | 178,100 | $ | 8,158 | $ | 6,794 | $ | 193,052 |
3. Derivative Instruments
The Company's primary market risk exposure is the volatility of future prices for natural gas and NGLs, which can affect the Company's operating results. The Company uses derivative commodity instruments to hedge its cash flows from sales of produced natural gas and NGLs. The overall objective of the Company's hedging program is to protect cash flows from undue exposure to the risk of changing commodity prices.
The derivative commodity instruments used by the Company are primarily swap, collar and option agreements. These agreements may require payments to, or receipt of payments from, counterparties based on the differential between two prices for the commodity. The Company uses these agreements to hedge its NYMEX and basis exposure. The Company may also use other contractual agreements when executing its commodity hedging strategy. The Company typically enters into over the counter (OTC) derivative commodity instruments with financial institutions, and the creditworthiness of all counterparties is regularly monitored.
The Company does not designate any of its derivative instruments as cash flow hedges; therefore, all changes in fair value of the Company's derivative instruments are recognized in operating revenues in the Statements of Consolidated Operations. The Company recognizes all derivative instruments as either assets or liabilities at fair value on a gross basis. These derivative instruments are reported as either current assets or current liabilities due to their highly liquid nature. The Company can net settle its derivative instruments at any time.
Contracts that result in physical delivery of a commodity expected to be sold by the Company in the normal course of business are generally designated as normal sales and are exempt from derivative accounting. Contracts that result in the physical receipt or delivery of a commodity but are not designated or do not meet all of the criteria to qualify for the normal purchase and normal sale scope exception are subject to derivative accounting.
The Company's OTC derivative instruments generally require settlement in cash. The Company also enters into exchange traded derivative commodity instruments that are generally settled with offsetting positions. Settlements of derivative commodity instruments are reported as a component of cash flows from operating activities in the Statements of Consolidated Cash Flows.
With respect to the derivative commodity instruments held by the Company, the Company hedged portions of expected sales of production and portions of its basis exposure covering approximately 1,955 billion cubic feet (Bcf) of natural gas and 3,462 thousand barrels (Mbbl) of NGLs as of December 31, 2020 and 1,644 Bcf of natural gas as of December 31, 2019. The open positions at both December 31, 2020 and 2019 had maturities extending through December 2024.
Certain of the Company's OTC derivative instrument contracts provide that, if the Company's credit rating assigned by Moody's Investors Service, Inc. (Moody's) or S&P Global Ratings (S&P) is below the agreed-upon credit rating threshold (typically, below investment grade), and if the associated derivative liability exceeds the agreed-upon dollar threshold for such credit rating, the counterparty to such contract can require the Company to deposit collateral. Similarly, if such counterparty's credit rating assigned by Moody's or S&P is below the agreed-upon credit rating threshold, and if the associated derivative liability exceeds the agreed-upon dollar threshold for such credit rating, the Company can require the counterparty to deposit collateral with the Company. Such collateral can be up to 100% of the derivative liability. Investment grade refers to the quality of a company's credit as assessed by one or more credit rating agencies. To be considered investment grade, a company must be rated "Baa3" or higher by Moody's, "BBB–" or higher by S&P and "BBB–" or higher by Fitch Rating Service (Fitch). Anything below these ratings is considered non-investment grade. As of December 31, 2020, the Company's senior notes were rated "Ba3" by Moody's and "BB" by S&P.
When the net fair value of any of the Company's OTC derivative instrument contracts represents a liability to the Company that is in excess of the agreed-upon dollar threshold for the Company's then-applicable credit rating, the counterparty has the right to require the Company to remit funds as a margin deposit in an amount equal to the portion of the derivative liability that is in excess of the dollar threshold amount. The Company records these deposits as a current asset in the Consolidated Balance Sheets. As of December 31, 2020, the aggregate fair value of all OTC derivative instruments with credit rating risk-related contingent features that were in a net liability position was $137.7 million, for which the Company deposited and recorded $21.1 million as a current asset. As of December 31, 2019, there were no such deposits recorded in the Consolidated Balance Sheet.
When the net fair value of any of the Company's OTC derivative instrument contracts represents an asset to the Company that is in excess of the agreed-upon dollar threshold for the counterparty's then-applicable credit rating, the Company has the right to require the counterparty to remit funds as a margin deposit in an amount equal to the portion of the derivative asset that is in excess of the dollar threshold amount. The Company records these deposits as a current liability in the Consolidated Balance Sheets. As of December 31, 2020 and 2019, there were no such deposits recorded in the Consolidated Balance Sheets.
When the Company enters into exchange traded natural gas contracts, exchanges may require the Company to remit funds to the corresponding broker as good faith deposits to guard against the risks associated with changing market conditions. The Company is required to make such deposits based on an established initial margin requirement and the net liability position, if any, of the fair value of the associated contracts. The Company records these deposits as a current asset in the Consolidated Balance Sheets. When the fair value of such contracts is in a net asset position, the broker may remit funds to the Company. The Company records these deposits as a current liability in the Consolidated Balance Sheets. The initial margin requirements are established by the exchanges based on the price, volatility and the time to expiration of the contract. The margin requirements are subject to change at the exchanges' discretion. As of December 31, 2020 and 2019, the Company recorded $61.5 million and $12.6 million, respectively, of such deposits as a current asset in the Consolidated Balance Sheets.
Refer to Note 5 for a discussion of the derivative liability recorded in connection with the Equitrans Share Exchange (defined in Note 5).
The Company has netting agreements with financial institutions and its brokers that permit net settlement of gross commodity derivative assets against gross commodity derivative liabilities. The table below summarizes the impact of netting agreements and margin deposits on gross derivative assets and liabilities.
| Gross derivative instruments recorded in the Consolidated Balance Sheet | Derivative instruments subject to master netting agreements | Margin requirements with counterparties | Net derivative instruments | ||||||||||||||||||||
| December 31, 2020 | (Thousands) | ||||||||||||||||||||||
| Asset derivative instruments at fair value | $ | 527,073 | $ | (328,809) | $ | — | $ | 198,264 | |||||||||||||||
| Liability derivative instruments at fair value | 600,877 | (328,809) | (82,552) | 189,516 | |||||||||||||||||||
| December 31, 2019 | |||||||||||||||||||||||
| Asset derivative instruments at fair value | $ | 812,664 | $ | (226,116) | $ | — | $ | 586,548 | |||||||||||||||
| Liability derivative instruments at fair value | 312,696 | (226,116) | (12,606) | 73,974 |
The Company has not executed any interest rate swaps since 2011. As of December 31, 2019, amounts related to historical interest rate swaps that had been previously recorded in accumulated OCI were fully reclassified into interest expense. See Note 12.
4. Fair Value Measurements
The Company records its financial instruments, which are principally derivative instruments, at fair value in the Consolidated Balance Sheets. The Company estimates the fair value of its financial instruments using quoted market prices when available. If quoted market prices are not available, the fair value is based on models that use market-based parameters, including forward curves, discount rates, volatilities and nonperformance risk, as inputs. Nonperformance risk considers the effect of the Company's credit standing on the fair value of liabilities and the effect of the counterparty's credit standing on the fair value of assets. The Company estimates nonperformance risk by analyzing publicly available market information, including a comparison of the yield on debt instruments with credit ratings similar to the Company's or counterparty's credit rating and the yield on a risk-free instrument.
The Company has categorized its assets and liabilities recorded at fair value into a three-level fair value hierarchy based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Assets and liabilities that use Level 2 inputs primarily include the Company's swap, collar and option agreements.
Exchange traded commodity swaps have Level 1 inputs. The fair value of the commodity swaps with Level 2 inputs is based on standard industry income approach models that use significant observable inputs, including, but not limited to, NYMEX natural gas forward curves, LIBOR-based discount rates, basis forward curves and natural gas liquids forward curves. The Company's
collars and options are valued using standard industry income approach option models. The significant observable inputs used by the option pricing models include NYMEX forward curves, natural gas volatilities and LIBOR-based discount rates.
The table below summarizes assets and liabilities measured at fair value on a recurring basis.
| Fair value measurements at reporting date using: | |||||||||||||||||||||||
| Gross derivative instruments recorded in the Consolidated Balance Sheets | Quoted prices in active markets for identical assets (Level 1) | Significant other observable inputs (Level 2) | Significant unobservable inputs (Level 3) | ||||||||||||||||||||
| December 31, 2020 | (Thousands) | ||||||||||||||||||||||
| Asset derivative instruments at fair value | $ | 527,073 | $ | 70,603 | $ | 456,470 | $ | — | |||||||||||||||
| Liability derivative instruments at fair value | 600,877 | 93,361 | 507,516 | — | |||||||||||||||||||
| December 31, 2019 | |||||||||||||||||||||||
| Asset derivative instruments at fair value | $ | 812,664 | $ | 95,041 | $ | 717,623 | $ | — | |||||||||||||||
| Liability derivative instruments at fair value | 312,696 | 71,107 | 241,589 | — |
The carrying values of cash equivalents, accounts receivable and accounts payable approximate fair value due to their short-term maturities. The carrying value of the Company's investment in Equitrans Midstream approximates fair value as Equitrans Midstream is a publicly traded company. The carrying values of borrowings on the Company's credit facility and Term Loan Facility (which was fully repaid in the second quarter of 2020) approximate fair value as the interest rates are based on prevailing market rates. The Company considered all of these fair values to be Level 1 fair value measurements.
The Company has an immaterial investment in a fund that invests in companies developing technology and operating solutions for exploration and production companies. The Company recognized a cumulative effect of accounting change related to this investment in the first quarter of 2018. The investment is valued using, as a practical expedient, the net asset value provided in the financial statements received from fund managers and is recorded in other assets in the Consolidated Balance Sheets.
The Company estimates the fair value of its senior notes using established fair value methodology. Because not all of the Company's senior notes are actively traded, their fair value is a Level 2 fair value measurement. As of December 31, 2020 and 2019, the Company's senior notes had a fair value of approximately $5.2 billion and $3.9 billion, respectively, and a carrying value of approximately $4.5 billion and $3.9 billion, respectively, inclusive of any current portion. The fair value of the Company's note payable to EQM Midstream Partners, LP (EQM) is estimated using an income approach model with a market-based discount rate and is a Level 3 fair value measurement. As of December 31, 2020 and 2019, the Company's note payable to EQM had a fair value of approximately $130 million and $128 million, respectively, and a carrying value of approximately $105 million and $110 million, respectively, inclusive of any current portion. See Note 10 for further discussion of the Company's debt.
The Company recognizes transfers between Levels as of the actual date of the event or change in circumstances that caused the transfer. There were no transfers between Levels 1, 2 and 3 during the periods presented.
For information on the fair values, and impairments thereof, of proved and unproved oil and gas properties and other long-lived assets, see Note 1. For a discussion of other fair value measurements, see Note 5 for the Equitrans Share Exchange, Note 6 for the Chevron Acquisition and Asset Exchange Transactions (each defined in Note 6) and Note 7 for divestitures.
5. The Equitrans Share Exchange
On February 26, 2020, the Company entered into two share purchase agreements (the Share Purchase Agreements) with Equitrans Midstream, pursuant to which, among other things, the Company sold to Equitrans Midstream a total of 25,299,752 shares, or 50% of its ownership, of Equitrans Midstream's common stock in exchange for approximately $52 million in cash and rate relief under certain of the Company's gathering contracts with EQM, an affiliate of Equitrans Midstream (the Equitrans Share Exchange). The transactions contemplated by the Share Purchase Agreements closed on March 5, 2020 (the Share Purchase Closing Date). The rate relief was effected through the execution of the Consolidated GGA (defined herein).
On February 26, 2020, the Company entered into a gas gathering and compression agreement (the Consolidated GGA) with an affiliate of EQM, pursuant to which, among other things, EQM agreed to provide to the Company gas gathering services in the
Marcellus and Utica Shales of Pennsylvania and West Virginia, and the Company committed to an initial annual minimum volume commitment of 3.0 Bcf per day and an acreage dedication in Pennsylvania and West Virginia. The Consolidated GGA is effective through December 31, 2035 and will renew annually thereafter unless terminated by the Company or EQM. The Consolidated GGA provides for additional cash bonus payments (the Henry Hub Cash Bonus) payable by the Company to EQM during the period beginning on the first day of the quarter in which the Mountain Valley Pipeline is placed in service and ending on the earlier of 36 months thereafter or December 31, 2024. Such payments are conditioned upon the quarterly average of the NYMEX Henry Hub natural gas settlement price exceeding certain price thresholds. In addition, the Consolidated GGA provides a cash payment option that grants the Company the right to receive payments from EQM in the event that the Mountain Valley Pipeline in-service date has not occurred prior to January 1, 2022.
On the Share Purchase Closing Date, the Company recorded in the Consolidated Balance Sheet a contract asset representing the estimated fair value of the rate relief provided by the Consolidated GGA of $410 million, a derivative liability related to the Henry Hub Cash Bonus of approximately $117 million and a decrease in the Company's investment in Equitrans Midstream of approximately $158 million. The resulting gain of approximately $187 million was recorded in the Statement of Consolidated Operations. Beginning with the Mountain Valley Pipeline in-service date, the Company expects to recognize amortization of the contract asset over a period of approximately four years in a manner consistent with the expected timing of the Company's realization of the economic benefits of the rate relief provided by the Consolidated GGA. As of December 31, 2020, the derivative liability related to the Henry Hub Cash Bonus was approximately $107 million.
The fair value of the contract asset was based on significant inputs that are not observable in the market and, as such, is a Level 3 fair value measurement. Key assumptions used in the fair value calculation included an estimated production volume forecast, a market-based discount rate and a probability-weighted estimate of the in-service date of the Mountain Valley Pipeline. The fair value of the derivative liability related to the Henry Hub Cash Bonus was based on significant inputs that were interpolated from observable market data and, as such, is a Level 2 fair value measurement. See Note 4 for a description of the fair value hierarchy.
6. Acquisition and Exchange Transactions
Chevron Acquisition. In the fourth quarter of 2020, the Company acquired upstream assets and an investment in midstream gathering assets located in the Appalachian Basin from Chevron U.S.A. Inc. (Chevron) for an aggregate purchase price of $735 million, subject to certain purchase price adjustments (the Chevron Acquisition). The transaction closed on November 30, 2020 and had an effective date of July 1, 2020.
The Chevron Acquisition included approximately 335,000 net Marcellus acres, approximately 400,000 net Utica acres, approximately 550 gross wells, which are producing approximately 450 net MMcfe per day, and approximately 100 work-in-process wells at various stages in the development cycle. The Chevron Acquisition also included a 31% investment in the Laurel Mountain Midstream (LMM) gathering assets, which are operated by The Williams Companies, Inc., and two water systems that provide both fresh and produced water handling capabilities.
The Company does not have the power to direct the activities that most significantly impact LMM's economic performance; therefore, the Company is not the primary beneficiary and accounts for its investment in LMM as an equity method investment. The Company's pro-rata share of earnings in LMM is recorded as equity income which is included in dividend and other income on the Statements of Consolidated Operations.
The Chevron Acquisition was accounted for as a business combination, using the acquisition method. The following table summarizes the preliminary purchase price and the preliminary estimated fair values of assets acquired and liabilities assumed as of November 30, 2020. Certain data necessary to complete the purchase price allocation is not yet available, including, but not limited to, a final title defect analysis and final appraisals of assets acquired and liabilities assumed. The Company expects to complete the purchase price allocation during the second quarter of 2021, at which time the value of the assets acquired and liabilities assumed will be revised, if necessary.
| Preliminary Purchase Price Allocation | ||||||||
| (Thousands) | ||||||||
| Cash consideration (a) | $ | 691,942 | ||||||
| Fair value of liabilities assumed: | ||||||||
| Accounts payable | $ | 3,347 | ||||||
| Other current liabilities | 16,566 | |||||||
| Deferred tax liability | 939 | |||||||
| Other liabilities and credits (b) | 109,876 | |||||||
| Amount attributable to liabilities assumed | $ | 130,728 | ||||||
| Fair value of assets acquired: | ||||||||
| Other current assets | $ | 5,609 | ||||||
| Net property, plant and equipment | 720,315 | |||||||
| Other assets | 96,746 | |||||||
| Amount attributable to assets acquired | $ | 822,670 |
(a)The difference between cash consideration and the aggregate purchase price of $735 million represents the results of operating activities between the effective date of July 1, 2020 and the closing date of November 30, 2020 as well as amounts related to customary post-closing matters.
(b)Other liabilities and credits included liabilities due to minimum volume commitment (MVC) contracts as well as liabilities for asset retirement obligations and environmental obligations.
The fair values of the acquired natural gas and oil properties were measured using discounted cash flow valuation techniques based on inputs that are not observable in the market and, as such, are considered Level 3 fair value measurements. Significant inputs include future commodity prices, projections of estimated quantities of reserves, estimated future rates of production, projected reserve recovery factors, timing and amount of future development and operating costs and a weighted average cost of capital. The fair value of the undeveloped properties were measured using the guideline transaction method based on inputs that are not observable in the market and, as such, are considered Level 3 fair value measurements. Significant inputs include future development plans from a market participant perspective and value per undeveloped acre.
The fair value of the acquired investment in LMM, which is included in other assets on the Consolidated Balance Sheet, was primarily measured using discounted cash flow valuation techniques. A majority of the inputs are not observable in the market and, as such, are considered Level 3 fair value measurements. Significant inputs include projected revenues, expenses and capital expenditures.
The fair value of the acquired MVC liabilities were measured using expected throughput and annual MVCs per associated contract calculated on a discounted basis. A majority of the inputs are not observable in the market and, as such, are considered Level 3 fair value measurements. Significant inputs include estimated future volumes and market participant cost of debt.
2020 Asset Exchange Transactions. During 2020, the Company closed on various acreage trade agreements (collectively, the 2020 Asset Exchange Transactions), pursuant to which the Company exchanged approximately 24,400 aggregate net revenue interest acres across Greene, Allegheny, Armstrong, Westmoreland and Washington Counties, Pennsylvania; Wetzel and Marshall Counties, West Virginia; and Belmont County, Ohio for approximately 19,400 aggregate net revenue interest acres across Greene and Washington Counties, Pennsylvania; Marshall, Wetzel and Marion Counties, West Virginia; and Belmont County, Ohio. As a result of the 2020 Asset Exchange Transactions, the Company recognized a net loss of $61.6 million in impairment/loss on sale/exchange of long-lived assets in the Statement of Consolidated Operations for the year ended December 31, 2020.
2019 Asset Exchange Transaction. During the third quarter of 2019, the Company closed on an acreage trade agreement and purchase and sale agreement with a third party (the 2019 Asset Exchange Transaction), pursuant to which the Company exchanged approximately 16,000 net revenue interest acres primarily in Wetzel and Marion Counties, West Virginia. Under the terms of the purchase and sale agreement, the Company assigned to the third party a gas gathering agreement that covers a portion of Tyler County, West Virginia and provides a firm gathering commitment, and the Company was released from its remaining obligations under that gas gathering agreement. As consideration for the third party's assumption of the Tyler County gas gathering agreement, the Company agreed to reimburse the third party for certain firm gathering costs under the gas
gathering agreement through December 2022 and assign the third party an additional approximately 3,000 net revenue interest acres in Tyler and Wetzel Counties, West Virginia.
As a result of the 2019 Asset Exchange Transaction, the Company recognized a net loss of $13.9 million in impairment/loss on sale/exchange of long-lived assets in the Statement of Consolidated Operations for the year ended December 31, 2019. As of December 31, 2020 and 2019, the liability for the reimbursement of those certain firm gathering costs was $25.8 million and $36.8 million, respectively, and was recorded in other current and noncurrent liabilities in the Consolidated Balance Sheets.
The fair value of leases acquired and, for the 2019 Asset Exchange Transaction, the fair value of the liability for the reimbursement of certain firm gathering costs were based on inputs that are not observable in the market and, as such, are a Level 3 fair value measurement. See Note 4 for a description of the fair value hierarchy. Key assumptions used in the fair value calculations included market-based prices for comparable acreage and the net present value of expected payments due for reimbursement.
7. Divestitures
2020 Divestitures. On May 11, 2020, the Company closed a transaction to sell certain non-strategic assets located in Pennsylvania and West Virginia (the 2020 Divestiture) for an aggregate purchase price of approximately $125 million in cash, subject to customary purchase price adjustments and the Contingent Consideration defined and discussed below. The Pennsylvania assets sold included 80 Marcellus wells and approximately 33 miles of gathering lines; the West Virginia assets sold included 809 conventional wells and approximately 154 miles of gathering lines. In addition, the 2020 Divestiture relieved the Company of approximately $49 million in asset retirement obligations and other liabilities associated with the sold assets. Proceeds from the sale were used to pay down the Company's Term Loan Facility. See Note 10.
The purchase and sale agreement for the 2020 Divestiture provides for additional cash bonus payments (the Contingent Consideration) payable to the Company of up to $20 million. Such Contingent Consideration is conditioned upon the three-month average of the NYMEX Henry Hub natural gas settlement price relative to stated floor and target price thresholds beginning on August 31, 2020 and ending on November 30, 2022. The Contingent Consideration represents an embedded derivative that is recorded at fair value in the Consolidated Balance Sheets. The Contingent Consideration had no fair value as of May 11, 2020 and a fair value of $1.9 million as of December 31, 2020. During the year ended December 31, 2020, the Company received contingent consideration cash of $0.9 million. Changes in fair value are recorded in impairment/loss on sale/exchange of long-lived assets in the Statements of Consolidated Operations. The fair value of the Contingent Consideration is based on significant inputs that are interpolated from observable market data and, as such, is a Level 2 fair value measurement. See Note 4 for a description of the fair value hierarchy.
As a result of the 2020 Divestiture, the Company recognized a net loss of $39.1 million, including the impact of the change in fair value of the Contingent Consideration, in impairment/loss on sale/exchange of long-lived assets in the Statement of Consolidated Operations during the year ended December 31, 2020.
2018 Divestiture. In 2018, the Company sold its non-core production and related midstream assets located in the Huron play and Permian Basin (the 2018 Divestitures). For the year ended December 31, 2018, as a result of the 2018 Divestitures, the Company recorded an impairment/loss on sale of long-lived assets of $2.4 billion due to the carrying value of the properties and related pipeline assets exceeding the amounts received for the 2018 Divestitures.
The fair value of the impaired assets was based on significant inputs that are not observable in the market and, as such, are considered to be Level 3 fair value measurements. See Note 4 for a description of the fair value hierarchy and Note 1 for the Company's policy on impairment of proved and unproved properties. Key assumptions included in the calculation of the fair value of the impaired assets included the following: reserves, including risk adjustments for probable and possible reserves; future commodity prices; to the extent available, market-based indicators of fair value including estimated proceeds that could be realized upon a potential disposition; production rates based on the Company's experience with similar properties it operates; estimated future operating and development costs; and a market-based weighted average cost of capital.
In connection with the closing of the 2018 Divestitures, the Company recorded a loss of $259.3 million during the third quarter of 2018 related to certain capacity contracts that the Company no longer has existing production to satisfy and does not plan to use in the future. The loss was recorded in impairment/loss on sale/exchange of long-lived assets in the Statement of Consolidated Operations. The fair value of the loss for the initial measurement was based on significant inputs that are not observable in the market and, as such, is considered a Level 3 fair value measurement. The key unobservable input in the
calculation is the amount of potential future economic benefit from the contracts. See Note 4 for a description of the fair value hierarchy.
8. Separation and Distribution and Discontinued Operations
On November 12, 2018, the Company completed the separation of its midstream business, which was composed of the separately operated natural gas gathering, transmission and storage and water services businesses of the Company, from its upstream business, which is composed of the natural gas, NGLs and oil development, production and sales and commercial operations of the Company (the Separation). The Separation was effected by the transfer of the midstream business from the Company to Equitrans Midstream and the distribution of 80.1% of the outstanding shares of Equitrans Midstream's common stock to the Company's shareholders (the Distribution). The Company's shareholders received 0.80 shares of Equitrans Midstream's common stock for every one share of EQT common stock held as the close of business on November 1, 2018. The Company retained 19.9% of the outstanding shares of Equitrans Midstream's common stock. See Note 1 for a discussion of the Company's accounting for the investment in Equitrans Midstream and Note 5 for a discussion of the Company's sale of a portion of its shares of Equitrans Midstream's common stock in 2020.
In connection with the Separation and Distribution, the Company entered into several agreements with Equitrans Midstream to implement the legal and structural separation between the two companies, govern the relationship between the Company and Equitrans Midstream and allocate between the Company and Equitrans Midstream various assets, liabilities and obligations, including, among other things, employee benefits, litigation, contracts, equipment, real property, intellectual property and tax-related assets and liabilities.
In the ordinary course of business, the Company engages in transactions with Equitrans Midstream and its affiliates including, but not limited to, gas gathering agreements, transportation service and precedent agreements, storage agreements and water services agreements. These agreements have terms ranging from month-to-month up to 20 years.
Equitrans Midstream comprised the Company's former EQM Gathering, EQM Transmission and EQM Water segments. For all periods prior to the Separation and Distribution, the results of operations of Equitrans Midstream are reflected as discontinued operations. The Statement of Consolidated Operations for the year ended December 31, 2018 has been recast to reflect discontinued operations presentation and include certain transportation and processing expenses in continuing operations that had previously been eliminated in consolidation. Cash flows related to Equitrans Midstream are included in the Statement of Consolidated Cash Flows for the period prior to the Separation and Distribution. The results of operations of Equitrans Midstream are summarized below. The Company allocated transaction costs associated with the Separation and Distribution and a portion of transaction costs associated with the 2017 acquisition of Rice Energy Inc. (the Rice Merger) to discontinued operations.
| January 1, 2018 to November 12, 2018 | |||||
| (Thousands) | |||||
| Operating revenues | $ | 388,854 | |||
| Transportation and processing | (803,858) | ||||
| Operation and maintenance | 99,671 | ||||
| Selling, general and administrative | 62,702 | ||||
| Depreciation | 160,701 | ||||
| Impairment of goodwill (a) | 267,878 | ||||
| Transaction costs | 93,062 | ||||
| Amortization of intangible assets | 36,007 | ||||
| Other income | 51,014 | ||||
| Interest expense | 88,300 | ||||
| Income from discontinued operations before income taxes | 435,405 | ||||
| Income tax expense | 61,643 | ||||
| Income from discontinued operations after income taxes | 373,762 | ||||
| Less: Net income from discontinued operations attributable to noncontrolling interests | 237,410 | ||||
| Net income from discontinued operations | $ | 136,352 |
(a)Following the third quarter of 2018, and prior to the Separation and Distribution, indicators of goodwill impairment were identified in the form of announced production curtailments, which could reduce the volumetric-based fee revenues of two reporting units to which the Company's goodwill was recorded. The two reporting units, Rice Retained Midstream and RMP PA Gas Gathering, were allocated to discontinued operations as a result of the Separation and Distribution. Both of these reporting units earned a substantial portion of their revenues from volumetric-based fees, which are sensitive to changes in development plans. In estimating the fair value of these reporting units, a combination of the income approach and the market approach was used. The discounted cash flow method income approach applies significant inputs that are not observable in the public market (Level 3), including estimates and assumptions related to future throughput volumes, operating costs, capital spending and changes in working capital. The comparable company method market approach evaluates the value of a company using metrics of other businesses of similar size and industry. The reference transaction method evaluates the value of a company based on pricing multiples derived from similar transactions entered into by similar companies.
For the year ended December 31, 2018, the fair value of the Rice Retained Midstream reporting unit was greater than its carrying value, but the carrying value of the RMP PA Gas Gathering reporting unit exceeded its fair value. As a result, impairment of goodwill of $267.9 million was recorded with a corresponding decrease to goodwill in the Consolidated Balance Sheet and allocated to discontinued operations.
The following table presents cash flows from or used in discontinued operations related to Equitrans Midstream that are included, and not separately stated, in the Statement of Consolidated Cash Flows for the year ended December 31, 2018.
| January 1, 2018 to November 12, 2018 | |||||
| (Thousands) | |||||
| Cash flows from operating activities: | |||||
| Deferred income tax benefit | $ | (373,405) | |||
| Depreciation | 160,701 | ||||
| Amortization of intangibles | 36,007 | ||||
| Impairment of goodwill | 267,878 | ||||
| Other income | (51,450) | ||||
| Share-based compensation expense | 1,841 | ||||
| Cash flows from investing activities: | |||||
| Capital expenditures | $ | (732,727) | |||
| Capital contributions to Mountain Valley Pipeline, LLC (a) | (820,943) | ||||
| Cash flows from financing activities: | |||||
| Proceeds from issuance of debt | $ | 2,500,000 | |||
| Proceeds in borrowings on credit facility | 3,378,500 | ||||
| Repayment of borrowings on credit facility | (3,219,500) | ||||
| Debt issuance costs | (40,966) | ||||
| Distributions to noncontrolling interests | (380,651) | ||||
| Acquisition of 25% of Strike Force Midstream LLC | (175,000) |
(a)Mountain Valley Pipeline, LLC is a joint venture that is constructing the Mountain Valley Pipeline. EQM owns an interest in the joint venture and makes capital contributions to the joint venture.
9. Income Taxes
The following table summarizes income tax (benefit) expense.
| Years Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (Thousands) | |||||||||||||||||
| Current: | |||||||||||||||||
| Federal | $ | (132,625) | $ | (106,487) | $ | (513,293) | |||||||||||
| State | (10,393) | 5,774 | (46,218) | ||||||||||||||
| Subtotal | (143,018) | (100,713) | (559,511) | ||||||||||||||
| Deferred: | |||||||||||||||||
| Federal | (131,355) | (213,397) | 20,496 | ||||||||||||||
| State | (24,485) | (61,666) | (157,496) | ||||||||||||||
| Subtotal | (155,840) | (275,063) | (137,000) | ||||||||||||||
| Total income tax benefit | $ | (298,858) | $ | (375,776) | $ | (696,511) |
For the year ended December 31, 2020, the current federal and state income tax benefit consisted primarily of refunds of $117 million, including interest, related to the Company's alternative minimum tax (AMT) credit carryforward, the Tax Cuts and Jobs Act of 2017 (the Tax Cuts and Jobs Act) and the acceleration of the receipt of such refunds with the Coronavirus Aid, Relief and Economic Security Act (CARES Act). The remainder of the tax benefit of $26 million, including interest, is related to federal and state audits that were settled in 2020. For the year ended December 31, 2019, the current U.S. federal income tax benefit consisted primarily of expected refunds of $120 million related to the Company's AMT credit carryforward and the Tax Cuts and Jobs Act. For the year ended December 31, 2018, the current U.S. federal income tax benefit consisted primarily of an expected refund of $141 million related to the Company's AMT credit carryforward, partly offset by $16 million of current state tax expense. The remaining current tax benefit of $435 million for the year ended December 31, 2018, was offset by current expense related to discontinued operations and will not result in additional refunds to the Company.
On December 22, 2017, the U.S. Congress enacted the Tax Cuts and Jobs Act, which made significant changes to U.S. federal income tax law, including lowering the federal corporate tax rate to 21% from 35% beginning January 1, 2018. The Tax Cuts and Jobs Act also preserved deductibility of intangible drilling costs (IDCs) for U.S. federal income tax purposes, which allows the Company to deduct a portion of drilling costs in the year incurred and minimizes current taxes payable. Prior to 2018, IDCs were limited for AMT purposes, which resulted in the Company paying AMT in periods when no other federal taxes were currently payable. The Tax Cuts and Jobs Act also repealed the AMT for tax years beginning January 1, 2018 and provided that existing AMT credit carryforwards can be used to offset current federal taxes owed with 50% of any remaining balance being refunded in tax years 2018 through 2020. With the passing of the CARES Act, the Company was able to accelerate these refunds to 2020. As a result of an IRS announcement in January 2019 that reversed its position that AMT refunds were subject to sequestration by the federal government at a rate equal to 6.2% of the refund, the Company reversed the related valuation allowance of $13 million in the first quarter of 2019.
The Tax Cuts and Jobs Act limited the deductibility of interest expense, and, as a result, the Company recorded a valuation allowance in 2019 for a portion of the interest expense limit imposed for separate company state income tax purposes. During 2020, final regulations were issued that provided clarity on several issues that were beneficial to the Company including (i) the exclusion of commitment fees and debt issuance costs from the definition of interest and (ii) the inclusion of the adding back depreciation, depletion and amortization associated with cost of goods sold to arrive at adjusted taxable income. These changes eliminated the interest expense limitation for the Company and the related valuation allowance was reversed in 2020.
The Company has federal net operating loss (NOLs) carryforwards related to the Rice Merger and NOLs generated in 2017 in excess of amounts carried back to prior years. The Company also has NOLs acquired in the Company's 2016 acquisition of Trans Energy, Inc., of which a nominal amount is available for use annually over the next 20 years. The Tax Cuts and Jobs Act limited the utilization of NOLs generated after December 31, 2017 that have been carried forward into future years to 80% of taxable income and eliminated the ability to carry NOLs back to earlier tax years for refunds of taxes paid. NOLs generated in 2018 and in future periods can be carried forward indefinitely. As a result of the CARES Act, NOLs generated in 2018, 2019 and 2020 can be carried back five years and are allowed to fully offset taxable income ignoring the 80% limitation if utilized prior to 2021.
Income tax benefit from continuing operations differed from amounts computed at the federal statutory rate of 21% on pre-tax income for reasons summarized below.
| Years Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (Thousands) | |||||||||||||||||
| Tax at statutory rate | $ | (265,867) | $ | (335,469) | $ | (646,261) | |||||||||||
| State income taxes | (75,035) | (119,659) | (251,780) | ||||||||||||||
| Valuation allowance | 106,548 | 81,522 | 88,785 | ||||||||||||||
| Tax settlements | (33,384) | — | — | ||||||||||||||
| Federal and state tax credits | (11,628) | (7,908) | (2,400) | ||||||||||||||
| Goodwill impairment | — | — | 111,470 | ||||||||||||||
| Other | (19,492) | 5,738 | 3,675 | ||||||||||||||
| Income tax benefit | $ | (298,858) | $ | (375,776) | $ | (696,511) | |||||||||||
| Effective tax rate | 23.6 | % | 23.5 | % | 22.6 | % |
The Company's effective tax rate for the year ended December 31, 2020 was higher compared to the U.S. federal statutory rate due primarily to state income taxes and federal and state income tax settlements, partly offset by valuation allowances that limit certain federal and state tax benefits. The Company's effective tax rate for the year ended December 31, 2019 was higher compared to the U.S. federal statutory rate due primarily to state income taxes and the release of the valuation allowance related to AMT sequestration, partly offset by valuation allowances that limit certain state tax benefits. The Company's effective tax rate for the year ended December 31, 2018 was higher compared to the U.S. federal statutory rate due primarily to state income taxes. The Company recognized additional state tax benefit as a result of the 2018 Divestitures and the resulting shift in the Company's state apportionment in state taxing jurisdictions for natural gas and liquids sales as these sales shifted more heavily to lower taxed jurisdictions. The Company had no tax basis in the goodwill allocated to continuing operations that had been impaired in 2018.
The Company believes that it is more likely than not that the benefit from certain state NOL carryforwards and certain federal NOLs acquired in recent acquisitions will not be realized. A valuation allowance is required when it is more likely than not that all or a portion of a deferred tax asset will not be realized. All available evidence, both positive and negative, must be considered in determining the need for a valuation allowance. At December 31, 2020, 2019 and 2018, positive evidence considered included the reversals of financial-to-tax temporary differences, the implementation of and/or ability to employ various tax planning strategies and the estimation of future taxable income. Negative evidence considered included historical pre-tax book losses of the Company's former EQT Production business segment. A review of positive and negative evidence regarding these tax benefits resulted in the conclusion that valuation allowances for certain NOLs were warranted as it was more likely than not that the Company would not use them prior to expiration. Uncertainties such as future commodity prices can affect the Company's calculations and its ability to use these NOLs prior to expiration. Further, because of the Tax Cuts and Jobs Act, the Company recorded a write-off of deferred tax assets related to certain executive incentive-based awards to be paid in a future year that will not be deductible.
During 2020 and 2019, the Company recorded a partial valuation allowance against a deferred tax asset related to the unrealized loss recorded on its investment in Equitrans Midstream that it does not believe it will be able to utilize due to limitations imposed on capital losses. The Company has capital loss carryback capacity and provided a valuation allowance on the portion in excess of the carryback. Management will continue to assess the potential for realizing deferred tax assets based on the feasibility of future tax planning strategies and may record adjustments to the related valuation allowances in future periods that could materially impact net income.
The following table reconciles the beginning and ending amount of reserve for uncertain tax positions, excluding interest and penalties.
| 2020 | 2019 | 2018 | |||||||||||||||
| (Thousands) | |||||||||||||||||
| Balance at January 1 | $ | 259,588 | $ | 315,279 | $ | 301,558 | |||||||||||
| Additions for tax positions taken in current year | 5,470 | 19,431 | 8,459 | ||||||||||||||
| Additions for tax positions taken in prior years | 7,250 | 8,929 | 14,396 | ||||||||||||||
| Reductions for tax positions taken in prior years | (38,859) | (84,051) | (9,134) | ||||||||||||||
| Reductions for tax positions settled with tax authorities | (58,236) | — | — | ||||||||||||||
| Balance at December 31 | $ | 175,213 | $ | 259,588 | $ | 315,279 |
Included in the balances above are unrecognized tax benefits of $91.0 million, $150.9 million and $124.6 million that, if recognized, would affect the effective tax rates as of December 31, 2020, 2019 and 2018, respectively. Also included in the balances above are uncertain tax positions of $90.3 million, $113.7 million, and $88.2 million for the years ended December 31, 2020, 2019 and 2018, respectively, that were recorded in the Consolidated Balance Sheets as a reduction of the related deferred tax asset for general business credit carryforwards and NOLs. During 2020, the Company adjusted its tax reserves as a result of settling its 2010 – 2012 amended return refund claim with the IRS by (i) reducing the uncertain tax positions and increasing the amount of the deferred tax asset for AMT credits by $14.9 million, (ii) reducing the uncertain tax position offset to the deferred tax asset for Research and Experimentation credits by $35.3 million and (iii) writing down the deferred tax asset by $22.6 million to the settlement amount. In addition, in 2020, the Company settled a dispute related to its 2013 Pennsylvania returns and reduced the uncertain tax positions by $46.9 million and agreed to remit $33.5 million to the Commonwealth of Pennsylvania. During 2019, the Company released $84.0 million of reserves and reinstated the related deferred tax asset for AMT due to settlement of the 2013 amended return refund claim with the IRS.
Included in the balances above are $0.0 million, $0.7 million and $0.7 million, as of December 31, 2020, 2019 and 2018, respectively, for tax positions for which the ultimate deductibility is highly certain but there is uncertainty about the timing of tax deductions. Any disallowance of the shorter deductibility period would accelerate the payment of cash taxes to an earlier period but would not affect the Company's annual effective tax rate.
The Company recognizes interest and penalties related to unrecognized tax benefits in income tax expense. The Company recorded interest and penalties (income) expense of approximately $(3.8) million, $3.3 million and $3.4 million for the years ended December 31, 2020, 2019 and 2018, respectively. Interest and penalties of $11.4 million and $15.2 million were included in the Consolidated Balance Sheets at December 31, 2020 and 2019, respectively.
As of December 31, 2020, 2019 and 2018, the Company believed that, as a result of potential settlements with, or legal or administrative guidance by, relevant taxing authorities or the lapse of applicable statutes of limitation, it is reasonably possible that a decrease of $125.9 million, $80.2 million and $33.3 million, respectively, in unrecognized tax benefits related to federal tax positions may be necessary within twelve months.
The Company's consolidated U.S. federal income tax liability has been settled with the IRS through 2013. The Company is also the subject of various state income tax examinations. As of December 31, 2020, with few exceptions, the Company is no longer subject to state examinations by tax authorities for years before 2015.
There were no material changes to the Company's methodology for accounting for unrecognized tax benefits during 2020.
The following table summarizes the source and tax effects of temporary differences between financial reporting and tax bases of assets and liabilities.
| December 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| (Thousands) | |||||||||||
| Deferred income taxes: | |||||||||||
| Total deferred income tax assets | $ | (610,821) | $ | (643,227) | |||||||
| Total deferred income tax liabilities | 1,982,788 | 2,129,041 | |||||||||
| Total net deferred income tax liabilities | 1,371,967 | 1,485,814 | |||||||||
| Total deferred income tax liabilities (assets): | |||||||||||
| Drilling and development costs expensed for income tax reporting | 918,120 | 1,100,061 | |||||||||
| Tax depreciation in excess of book depreciation | 1,027,179 | 974,520 | |||||||||
| Investment in Equitrans Midstream | (94,689) | (109,883) | |||||||||
| Incentive compensation and deferred compensation plans | (22,419) | (16,923) | |||||||||
| NOL carryforwards | (789,544) | (635,446) | |||||||||
| Alternative minimum tax credit carryforward | (81,237) | (190,992) | |||||||||
| Federal tax credits | (79,846) | (59,854) | |||||||||
| State capital loss carryforward | (28,317) | — | |||||||||
| Unrealized (losses) gains | (43,475) | 54,460 | |||||||||
| Interest disallowance limitation | (160) | (46,776) | |||||||||
| Convertible debt | 37,489 | — | |||||||||
| Other | (1,126) | (6,797) | |||||||||
| Total excluding valuation allowances | 841,975 | 1,062,370 | |||||||||
| Valuation allowances | 529,992 | 423,444 | |||||||||
| Total net deferred income tax liabilities | $ | 1,371,967 | $ | 1,485,814 |
During 2020, net deferred tax liability decreased by $113.8 million compared to 2019 due primarily to book impairments, which are included in drilling and development costs expensed for income tax reporting but are not currently deductible for tax purposes, and the Company's investment in Equitrans Midstream, partly offset by increased tax depreciation in excess of book depreciation.
As of December 31, 2020, the Company had a deferred tax asset of $233.2 million, net of valuation allowances of $22.8 million, related to tax benefits from federal NOL carryforwards generated prior to 2018 and expiring between 2035 to 2037. Federal NOLs generated in 2018 and thereafter are represented by a deferred tax asset of $75.6 million and will carryforward indefinitely but will be limited to offset 80% of taxable income in each year. As of December 31, 2020, the Company had a deferred tax asset of $480.8 million, net of valuation allowances of $387.7 million, related to tax benefits from state NOL carryforwards with expiration dates ranging from 2021 to 2040. Due to a decrease in state apportionment rates and impairment of assets, the Company will have less realizable NOLs in future years on a separate company basis and, as such, in 2020 recorded a valuation allowance on its property, plant and equipment state deferred tax asset of $0.6 million. In 2020, the Company incurred an unrealized loss on its investment in Equitrans Midstream. This investment is a capital asset for tax purposes and capital losses can only be utilized to offset a capital gain and are limited to being carried back three years and forward five years for potential utilization. Due to these limitations, the Company also recorded a valuation allowance on the deferred tax asset for its retained equity stake of Equitrans Midstream of $62.4 million for separate company state income tax reporting purposes and $56.4 million for federal.
As of December 31, 2019, the Company had a deferred tax asset of $218.8 million, net of valuation allowances of $22.8 million, related to tax benefits from federal NOL carryforwards expiring in 2037. Federal NOLs generated in 2018 and forward will carryforward indefinitely but will be limited to offset 80% of taxable income in each year. As of December 31, 2019, the Company had a deferred tax asset of $416.7 million, net of valuation allowances of $324.1 million, related to tax benefits from state NOL carryforwards with various expiration dates ranging from 2020 to 2039. Due to a decrease in state apportionment rates and impairment of assets, the Company will have less realizable NOLs in future years and, as such, had to record a valuation allowance on its property, plant and equipment state deferred tax asset of $4.5 million in 2019. Additionally, for separate company state income tax reporting purposes, the Tax Cuts and Jobs Act interest deduction limitation resulted in a valuation allowance of $21.3 million recorded in 2019. In 2019, the Company incurred an unrealized loss on its investment in
Equitrans Midstream. This investment is a capital asset for tax purposes and capital losses can only be utilized to offset a capital gain and are limited to being carried back three years and forward five years for potential utilization. Due to these limitations, the Company also recorded a valuation allowance on the deferred tax asset recorded for its retained equity stake of Equitrans Midstream of $42.4 million for separate company state income tax reporting purposes and $8.3 million for federal.
For the year ended December 31, 2019, the Company recorded a $90.9 million adjustment to retained earnings and additional paid-in-capital related to the Separation and Distribution. The Separation and Distribution resulted in the recognition of a tax gain related to a pre-Separation transaction. Recognition occurred as a result of Equitrans Midstream exiting the Company's consolidated federal filing group. The gain amount reported in the tax return was different than the amount estimated in the 2018 financial statements; therefore, the Company recorded a return-to-provision adjustment in 2019. This adjustment impacts the amount of deferred taxes transferred to Equitrans Midstream as of the Separation and Distribution date of November 12, 2018.
10. Debt
| December 31, 2020 | December 31, 2019 | ||||||||||||||||||||||||||||||||||
| Principal Value | Carrying Value (a) | Fair Value (b) | Principal Value | Carrying Value (a) | Fair Value (b) | ||||||||||||||||||||||||||||||
| (Thousands) | |||||||||||||||||||||||||||||||||||
| Credit Facility expires July 2022 | $ | 300,000 | $ | 300,000 | $ | 300,000 | $ | 294,000 | $ | 294,000 | $ | 294,000 | |||||||||||||||||||||||
| Term Loan Facility due May 31, 2021 | — | — | — | 1,000,000 | 999,353 | 999,353 | |||||||||||||||||||||||||||||
| Senior notes: | |||||||||||||||||||||||||||||||||||
| Floating rate notes due October 1, 2020 | — | — | — | 500,000 | 499,238 | 500,290 | |||||||||||||||||||||||||||||
| 2.50% notes due October 1, 2020 | — | — | — | 500,000 | 499,228 | 500,950 | |||||||||||||||||||||||||||||
| 8.81% to 9.00% series A notes due 2020 – 2021 | 24,000 | 24,000 | 25,232 | 35,200 | 35,200 | 37,380 | |||||||||||||||||||||||||||||
| 4.875% notes due November 15, 2021 | 125,118 | 124,943 | 128,231 | 750,000 | 747,571 | 774,173 | |||||||||||||||||||||||||||||
| 3.00% notes due October 1, 2022 | 568,823 | 566,689 | 578,055 | 750,000 | 745,579 | 737,025 | |||||||||||||||||||||||||||||
| 7.42% series B notes due 2023 | 10,000 | 10,000 | 10,038 | 10,000 | 10,000 | 10,788 | |||||||||||||||||||||||||||||
| 7.875% notes due February 1, 2025 (c) | 1,000,000 | 992,905 | 1,146,250 | — | — | — | |||||||||||||||||||||||||||||
| 1.75% convertible notes due May 1, 2026 | 500,000 | 359,635 | 587,385 | — | — | — | |||||||||||||||||||||||||||||
| 7.75% debentures due July 15, 2026 | 115,000 | 112,224 | 137,025 | 115,000 | 111,727 | 129,466 | |||||||||||||||||||||||||||||
| 3.90% notes due October 1, 2027 | 1,250,000 | 1,242,182 | 1,249,400 | 1,250,000 | 1,241,024 | 1,167,763 | |||||||||||||||||||||||||||||
| 5.00% notes due January 15, 2029 | 350,000 | 344,106 | 371,469 | — | — | — | |||||||||||||||||||||||||||||
| 8.750% notes due February 1, 2030 (c) | 750,000 | 743,726 | 924,510 | — | — | — | |||||||||||||||||||||||||||||
| Note payable to EQM | 105,056 | 105,056 | 130,464 | 110,059 | 110,059 | 128,241 | |||||||||||||||||||||||||||||
| Total debt | 5,097,997 | 4,925,466 | 5,588,059 | 5,314,259 | 5,292,979 | 5,279,429 | |||||||||||||||||||||||||||||
| Less: Current portion of debt | 154,336 | 154,161 | 159,943 | 16,204 | 16,204 | 17,436 | |||||||||||||||||||||||||||||
| Long-term debt | $ | 4,943,661 | $ | 4,771,305 | $ | 5,428,116 | $ | 5,298,055 | $ | 5,276,775 | $ | 5,261,993 |
(a)For the note payable to EQM, the principal value represents the carrying value. For all other debt, the principal value less the unamortized debt issuance costs and debt discounts represents the carrying value.
(b)The carrying value of borrowings under the Company's credit facility and Term Loan Facility approximate fair value as the interest rates are based on prevailing market rates; therefore, they are a Level 1 fair value measurement. For the note payable to EQM, fair value is measured using Level 3 inputs. For all other debt, fair value is measured using Level 2 inputs. See Note 4 for a description of the fair value hierarchy.
(c)See discussion below of the interest rate on these notes under "Adjustable Rate Notes."
As of December 31, 2020, aggregate maturities for the Company's senior notes were $149 million in 2021, $569 million in 2022, $10 million in 2023, $0 million in 2024, $1,000 million in 2025 and $2,965 million thereafter. The indentures governing the Company's long-term indebtedness contain certain restrictive financial and operating covenants, including covenants that restrict, among other things, the Company's ability to incur, as applicable, indebtedness, incur liens, enter into sale and leaseback transactions, complete acquisitions, merge, sell assets and perform certain other corporate actions.
$2.5 Billion Credit Facility. The Company has a $2.5 billion credit facility that expires in July 2022. The Company may request two one-year extensions of the expiration date, the approval of which is subject to satisfaction of certain conditions. The
Company may, on a one-time basis, request that the lenders' commitments be increased to an aggregate of up to $3.0 billion, subject to certain terms and conditions. Each lender in the facility may decide if it will increase its commitment. The credit facility may be used for working capital, capital expenditures, share repurchases and any other lawful corporate purposes. The credit facility is underwritten by a syndicate of 20 financial institutions, each of which is obligated to fund its pro-rata portion of any borrowings by the Company.
Under the terms of the credit facility, the Company may obtain base rate loans or Eurodollar rate loans denominated in U.S. dollars. Base rate loans bear interest at a base rate plus a margin based on the Company's credit ratings. Eurodollar rate loans bear interest at a Eurodollar rate plus a margin based on the Company's credit ratings. Based on the Company's senior notes credit rating as of December 31, 2020, the margin on base rate loans was 1.00% and the margin on Eurodollar rate loans was 2.00%.
The Company is not required to maintain compensating bank balances. The Company's debt issuer credit ratings, as determined by Moody's, S&P or Fitch on its non-credit-enhanced, senior unsecured long-term debt, determine the level of fees associated with the credit facility in addition to the interest rate charged by the counterparties on any amounts borrowed against the credit facility; the lower the Company's debt credit rating, the higher the level of fees and borrowing rate.
The Company's credit facility contains various provisions that, if not complied with, could result in termination of the credit facility, require early payment of amounts outstanding or similar actions. The most significant covenants and events of default under the credit facility are the maintenance of a debt-to-total capitalization ratio and limitations on transactions with affiliates. The credit facility contains financial covenants that require a total debt-to-total capitalization ratio no greater than 65%, the calculation of which excludes the effects of accumulated OCI. As of December 31, 2020, the Company was in compliance with all debt provisions and covenants.
The Company had $0.8 billion of letters of credit outstanding under its credit facility as of December 31, 2020 and no letters of credit outstanding under its credit facility as of December 31, 2019. For each of the years ended December 31, 2020, 2019 and 2018, the Company incurred commitment fees of approximately 28, 20 and 20 basis points, respectively, on the undrawn portion of its credit facility to maintain credit availability.
Under the Company's credit facility, for the years ended December 31, 2020, 2019 and 2018, the maximum amounts of outstanding borrowings were $0.7 billion, $1.1 billion and $1.6 billion, respectively, the average daily balances were approximately $148 million, $340 million and $854 million, respectively, and interest was incurred at weighted average annual interest rates of 2.3%, 3.8% and 3.4%, respectively.
Term Loan Facility. The Company had a $1.0 billion unsecured term loan facility (the Term Loan Facility) that was scheduled to mature in May 2021. In 2019, the Company used the proceeds from borrowings of $1.0 billion under the Term Loan Facility to repay $700 million aggregate principal amount of 8.125% senior notes, repay outstanding borrowings under the Company's $2.5 billion credit facility and pay accrued interest and fees and expenses related to the term loan agreement. Borrowings under the Term Loan Facility that are repaid may not be reborrowed.
The Company used proceeds from the offering of its Convertible Notes (see below), income tax refunds received during 2020 (see Note 9) and proceeds from the 2020 Divestiture (see Note 7) to fully repay its Term Loan Facility on June 30, 2020. Under the Company's Term Loan Facility, from January 1, 2020 through June 30, 2020, the average daily balance was approximately $692 million and interest was incurred at a weighted average annual interest rate of 2.6%. For the period May 31, 2019 through December 31, 2019, the average daily balance was $1.0 billion and interest was incurred at a weighted average annual interest rate of 3.1%.
Adjustable Rate Notes. On January 21, 2020, the Company issued $1.0 billion aggregate principal amount of 6.125% senior notes due February 1, 2025 and $750 million aggregate principal amount of 7.000% senior notes due February 1, 2030 (together, the Adjustable Rate Notes). The Company used the net proceeds from the Adjustable Rate Notes to repay $500 million aggregate principal amount of the Company's floating rate notes, $500 million aggregate principal amount of the Company's 2.50% senior notes, $500 million aggregate principal amount of the Company's 4.875% senior notes and $200 million of the Company's Term Loan Facility borrowings.
The covenants of the Adjustable Rate Notes are consistent with the Company's existing senior unsecured notes, with an additional interest rate adjustment provision that provides for adjustments to the interest rates on the Adjustable Rate Notes based on credit ratings assigned by Moody's, S&P and Fitch to the Company's senior notes. As a result of changes to the Company's senior notes credit rating, the interest rate on the 6.125% senior notes and the 7.000% senior notes was 7.875% and
8.750%, respectively, as of December 31, 2020. The adjusted interest rate under the Adjustable Rate Notes cannot exceed 2% of the original interest rate first set forth on the face of the Adjustable Rate Notes; however, if the Company's credit ratings improve, the interest rate under the Adjustable Rate Notes could be reduced to as low as the original interest rate set forth on the face of the Adjustable Rate Notes.
Convertible Notes. On April 28, 2020, the Company issued $500 million aggregate principal amount of 1.75% convertible senior notes (the Convertible Notes) due May 1, 2026 unless earlier redeemed, repurchased or converted. The Convertible Notes were issued in a private offering to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended. After deducting offering costs of $16.9 million and Capped Call Transactions (defined and discussed below) costs of $32.5 million, the net proceeds from the offering of $450.6 million were used to repay $450 million of the Company's Term Loan Facility borrowings as well as for general corporate purposes.
Holders of the Convertible Notes may convert their Convertible Notes, at their option, at any time prior to the close of business on January 30, 2026 under the following circumstances:
-
during any quarter commencing after the quarter ended June 30, 2020 as long as the last reported price of EQT common stock for at least 20 trading days (consecutive or otherwise) during the period of 30 consecutive trading days ending on the last trading day of the immediately preceding quarter is greater than or equal to 130% of the conversion price on each such trading day;
-
during the five-business-day period after any five-consecutive-trading-day period (the measurement period) in which the trading price per $1,000 principal amount of the Convertible Notes for each trading day of the measurement period is less than 98% of the product of the last reported price of EQT common stock and the conversion rate for the Convertible Notes on each such trading day;
-
if the Company calls any or all of the Convertible Notes for redemption, at any time prior to the close of business on the second scheduled trading day immediately preceding such redemption date; and
-
upon the occurrence of certain corporate events set forth in the Convertible Notes indenture.
On or after February 1, 2026, holders of the Convertible Notes may convert their Convertible Notes, at their option, at any time until the close of business on the second scheduled trading date immediately preceding May 1, 2026.
Upon conversion of the Convertible Notes, the Company intends to use a combined settlement approach to satisfy its settlement obligation by paying or delivering to holders of the Convertible Notes cash equal to the principal amount of the obligation and EQT common stock for amounts that exceed the principal amount of the obligation.
The Company may not redeem the Convertible Notes prior to May 5, 2023. On or after May 5, 2023 and prior to February 1, 2026, the Company may redeem for cash all or any portion of the Convertible Notes, at its option, at a redemption price equal to 100% of the principal amount of the Convertible Notes to be redeemed plus accrued and unpaid interest up to the redemption date as long as the last reported price per share of EQT common stock has been at least 130% of the conversion price in effect for at least 20 trading days (consecutive or otherwise) during any 30-consecutive-trading-day period ending on the trading day immediately preceding the date on which the Company delivers notice of redemption. A sinking fund is not provided for the Convertible Notes.
The initial conversion rate for the Convertible Notes is 66.6667 shares of EQT common stock per $1,000 principal amount of the Convertible Notes, which is equivalent to an initial conversion price of $15.00 per share of EQT common stock. The initial conversion price represents a premium of 20% to the $12.50 per share closing price of EQT common stock on April 23, 2020. The conversion rate is subject to adjustment under certain circumstances. In addition, following certain corporate events that occur prior to May 1, 2026 or if the Company delivers notice of redemption, the Company will, in certain circumstances, increase the conversion rate for a holder who elects to convert its Convertible Notes in connection with such corporate event or notice of redemption.
In connection with the Convertible Notes offering, the Company entered into privately negotiated capped call transactions (the Capped Call Transactions), the purpose of which is to reduce the potential dilution to EQT common stock upon conversion of the Convertible Notes and/or offset any cash payments the Company is required to make in excess of the principal amount of such obligation, with such reduction and offset subject to a cap. The Capped Call Transactions have an initial strike price of $15.00 per share of EQT common stock and an initial capped price of $18.75 per share of EQT common stock, each of which are subject to certain customary adjustments.
For accounting purposes, the Company separated the Convertible Notes into liability and equity components. The carrying amount of the liability component was calculated by measuring the fair value of similar debt instruments that do not have
associated convertible features. The carrying amount of the equity component, representing the conversion option, was determined by deducting the fair value of the liability component from the principal value of the Convertible Notes. The equity component is not remeasured as long as it continues to meet the condition for equity classification. The excess of the principal amount of the liability component over its carrying amount (the debt discount) will be amortized to interest expense over the term of the Convertible Notes, which is approximately 6 years, at an effective interest rate of 8.4%. At inception, the Company recorded the Convertible Notes at fair value of approximately $358.1 million, a net deferred tax liability of $41.0 million and an equity component of $100.9 million.
Issuance costs were allocated to the liability and equity components of the Convertible Notes based on their relative fair values. Issuance costs attributable to the liability component of $12.1 million were recorded as a reduction to the liability component of the Convertible Notes and will be amortized to interest expense over the term of the Convertible Notes at an effective interest rate of 8.4%. Issuance costs attributable to the equity component of $4.8 million, representing the conversion option, were netted with the equity component.
The Capped Call Transactions are separate from the Convertible Notes. The Capped Call Transactions were recorded in shareholders' equity and were not accounted for as derivatives. The cost to purchase the Capped Call Transactions was recorded as a reduction to equity and will not be remeasured.
For the year ended December 31, 2020, the Convertible Notes had a net shareholders' equity impact of $63.6 million, which consisted of the conversion option equity component of $100.9 million less the Capped Call Transactions costs of $32.5 million and issuance costs attributable to the equity component of $4.8 million.
As of December 31, 2020, the net carrying amount of the Convertible Notes liability component consisted of principal of $500 million less the unamortized debt discount of $129.1 million and unamortized issuance costs of $11.3 million. The table below summarizes the components of interest expense related to the Convertible Notes.
| Year Ended December 31, 2020 | |||||
| (Thousands) | |||||
| Contractual interest expense | $ | 5,906 | |||
| Amortization of debt discount | 12,856 | ||||
| Amortization of issuance costs | 853 | ||||
| Total Convertible Notes interest expense | $ | 19,615 |
5.00% Senior Notes. On November 16, 2020, the Company issued $350 million aggregate principal amount of 5.00% senior notes due January 15, 2029. After deducting offering costs of $6.0 million, the net proceeds from the offering of $344.0 million were used to fund a portion of the purchase price of the Chevron Acquisition described in Note 6. The covenants of the 5.00% senior notes are consistent with the Company's existing senior unsecured notes; provided, however, that the 5.00% senior notes include an additional offer to repurchase provision applicable upon the occurrence of certain change of control events specified in the related indenture.
2020 Debt Repayments. In February 2020, the Company fully redeemed its floating rate notes and 2.50% senior notes at a price of 100% and 100.446% (inclusive of a make whole premium), respectively, of each note's principal amount plus accrued but unpaid interest of $1.2 million and $4.2 million, respectively. This resulted in the payment of make whole call premiums of $2.2 million related to the 2.50% senior notes.
Throughout 2020, the Company repurchased $624.9 million aggregate principal amount of the Company's 4.875% senior notes at a total cost of $647.3 million, inclusive of tender premiums of $13.7 million and accrued but unpaid interest of $8.7 million.
In November 2020, the Company repurchased $181.2 million aggregate principal amount of the Company's 3.00% senior notes at a total cost of $182.8 million, inclusive of a tender premium of $0.9 million and accrued but unpaid interest of $0.7 million.
Note Payable to EQM. EQM owns a preferred interest in EQT Energy Supply, LLC (EES), a subsidiary of the Company, that is accounted for as a note payable due to the terms of the operating agreement of EES. The fair value of the note payable to EQM is a Level 3 fair value measurement and is estimated using an income approach model using a market-based discount rate. Principal amounts due for the note payable to EQM are $5.2 million in 2021, $5.5 million in 2022, $5.8 million in 2023, $6.3 million in 2024, $6.5 million in 2025 and $75.8 million thereafter.
Surety Bonds. During the year ended December 31, 2020, the Company issued approximately $93 million in surety bonds in response to its credit downgrades by Moody's, S&P and Fitch.
Subsequent Events. On February 1, 2021, the Company redeemed the remaining $125.1 million aggregate principal amount of the Company's 4.875% senior notes at a total cost of $130.7 million, inclusive of redemption premiums of $4.3 million and accrued but unpaid interest of $1.3 million.
11. Common Stock
As of December 31, 2020, the Company reserved 13.7 million shares of authorized and unissued EQT common stock for stock compensation plans and 40 million shares of authorized and unissued EQT common stock for settlement of the Convertible Notes.
In October 2020, the Company entered into an underwriting agreement under which the Company sold 20,000,000 shares of common stock at a price to the public of $15.50 per share. In November 2020, the option to purchase 3,000,000 additional shares was exercised by the underwriters on the same terms. After deducting offering costs of $15.6 million, the net proceeds of $340.9 million were used to fund a portion of the purchase price of the Chevron Acquisition described in Note 6**.**
The Company made no share repurchases in 2020 or 2019. During 2018, the Company repurchased 10,646,382 shares of EQT common stock at an average price of $50.62, which included $0.02 for commission, pursuant to the Company's previously announced share repurchase programs. This exhausted the Company's share repurchase authorization under such programs.
12. Changes in Accumulated OCI (Loss) by Component
The following table explains the changes in accumulated OCI (loss) by component.
| Natural gas cash flow hedges, net of tax | Interest rate cash flow hedges, net of tax | Other postretirement benefits liability adjustment, net of tax | Accumulated OCI (loss), net of tax | ||||||||||||||||||||
| (Thousands) | |||||||||||||||||||||||
| December 31, 2017 | $ | 4,625 | $ | (555) | $ | (6,528) | $ | (2,458) | |||||||||||||||
| (Gains) losses reclassified from accumulated OCI, net of tax | (4,625) | (a) | 168 | (b) | 606 | (c) | (3,851) | ||||||||||||||||
| Distribution to Equitrans Midstream Corporation | — | — | 903 | 903 | |||||||||||||||||||
| December 31, 2018 | — | (387) | (5,019) | (5,406) | |||||||||||||||||||
| Losses reclassified from accumulated OCI, net of tax | — | 387 | (b) | 316 | (c) | 703 | |||||||||||||||||
| Change in accounting principle | — | — | (496) | (496) | |||||||||||||||||||
| December 31, 2019 | — | — | (5,199) | (5,199) | |||||||||||||||||||
| Losses reclassified from accumulated OCI, net of tax | — | — | (156) | (c) | (156) | ||||||||||||||||||
| December 31, 2020 | $ | — | $ | — | $ | (5,355) | $ | (5,355) |
(a)Gains, net of tax, related to natural gas cash flow hedges were reclassified from accumulated OCI into operating revenues.
(b)Losses, net of tax, related to interest rate cash flow hedges were reclassified from accumulated OCI into interest expense.
(c)Losses, net of tax, related to other postretirement benefits liability adjustments were attributable to net actuarial losses and net prior service costs.
13. Share-Based Compensation Plans
The following table summarizes the Company's share-based compensation expense.
| Years Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (Thousands) | |||||||||||||||||
| Incentive Performance Share Unit Programs | $ | 10,457 | $ | 13,306 | $ | 14,072 | |||||||||||
| Value Driver Performance Share Unit Award Programs | 885 | 3,376 | 8,808 | ||||||||||||||
| Restricted stock awards | 10,480 | 14,430 | 14,503 | ||||||||||||||
| Non-qualified stock options | 848 | 4,774 | 2,757 | ||||||||||||||
| Stock appreciation rights | 2,724 | — | — | ||||||||||||||
| Other programs, including non-employee director awards | 2,155 | 2,257 | 3,014 | ||||||||||||||
| Less: Discontinued operations | — | — | (18,250) | ||||||||||||||
| Total share-based compensation expense (a) | $ | 27,549 | $ | 38,143 | $ | 24,904 |
(a)For the years ended December 31, 2020 and 2019, share-based compensation expense of $2.1 million and $28.6 million, respectively, was included in other operating expenses related primarily to reorganization costs.
In connection with the Separation in 2018, the Company transferred obligations related to then-outstanding share-based compensation awards to Equitrans Midstream. To preserve the aggregate fair value of awards held prior to the Separation, as measured immediately before and immediately after the Separation, each holder of share-based compensation awards generally received an adjusted award consisting of both a stock-based compensation award denominated in Company equity and a stock-based compensation award denominated in Equitrans Midstream equity. These awards were adjusted in accordance with the basket method, which resulted in participants retaining one unit of the existing Company incentive award and receiving an additional 0.80 units of an Equitrans Midstream-based award.
The Company recognizes compensation cost related to unvested awards held by its employees, regardless of who settles the obligation. Upon vesting the Company is obligated to settle all outstanding share-based compensation awards denominated in the Company's equity, regardless of whether the holders are employees of the Company or Equitrans Midstream. Likewise, upon vesting, Equitrans Midstream is obligated to settle all of the outstanding share-based compensation awards denominated in its equity, regardless of whether the holders are employees of Equitrans Midstream or the Company. Changes in performance and number of outstanding awards can impact the ultimate amount of these obligations. Share counts for awards discussed herein represent outstanding shares to be remitted by the Company to its employees and employees of Equitrans Midstream. When an award has graduated vesting, the Company records expense equal to the vesting percentage on the vesting date.
The Company typically uses treasury stock to fund awards paid in stock, but the Company can elect to fund such awards by stock acquired by the Company in the open market or from any other person, issued directly by the Company or any combination of the foregoing.
There was no cash received from exercises under all share-based payment arrangements for employees and directors for the years ended December 31, 2020 and 2019. Cash received from exercises under all share-based payment arrangements for employees and directors for the year ended December 31, 2018 was $1.9 million. During the years ended December 31, 2020, 2019 and 2018, share-based payment arrangements paid in stock generated tax benefits of $1.0 million, $2.4 million and $13.4 million, respectively.
Incentive Performance Share Unit Programs – Equity & Liability
The Management Development and Compensation Committee of the Company's Board of Directors (the Compensation Committee) has adopted the:
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2016 Incentive Performance Share Unit Program (2016 Incentive PSU Program) under the 2014 Long-Term Incentive Plan (LTIP);
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2017 Incentive Performance Share Unit Program (2017 Incentive PSU Program) under the 2014 LTIP;
-
2018 Incentive Performance Share Unit Program (2018 Incentive PSU Program) under the 2014 LTIP;
-
2019 Incentive Performance Share Unit Program (2019 Incentive PSU Program) under the 2014 LTIP; and
-
2020 Incentive Performance Share Unit Program (2020 Incentive PSU Program) under the 2019 LTIP.
The programs noted above are collectively referred to as the Incentive PSU Programs. The 2016 Incentive PSU Program and 2020 Incentive PSU Program granted equity awards. The 2017 Incentive PSU Program, 2018 Incentive PSU Program and 2019 Incentive PSU Program granted both equity and liability awards.
The Incentive PSU Programs were established to provide long-term incentive opportunities to executives and key employees to further align their interests with those of the Company's shareholders and with the strategic objectives of the Company. The performance period for each of the awards under the Incentive PSU Programs is 36 months, with vesting occurring upon payment following the expiration of the performance period.
Executive performance incentive program awards granted in years 2016 and 2017 were earned based on:
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the level of total shareholder return relative to a predefined peer group; and
-
the cumulative total sales volume growth, in each case, over the performance period.
Executive performance incentive program awards granted in years 2018 and 2019 were earned based on:
-
the level of total shareholder return relative to a predefined peer group;
-
the level of operating and development cost improvement; and
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return on capital employed.
Beginning in 2020, executive performance incentive program awards granted are earned based on:
-
adjusted well costs;
-
adjusted free cash flow; and
-
the level of total shareholder return relative to a predefined peer group.
Prior to 2020, the payout factor varies between zero and 300% of the number of outstanding units contingent upon the performance metrics listed above. The 2020 Incentive PSU Program has a payout factor that ranges from zero to 150%. The Company recorded the 2016 Incentive PSU Program, 2020 Incentive PSU Program and the portion of the 2017 Incentive PSU Program, 2018 Incentive PSU Program and 2019 Incentive PSU Program to be settled in stock as equity awards using a grant date fair value determined through a Monte Carlo simulation, which projected the share price for the Company and its peers at the end point of the performance period. The 2017 Incentive PSU Program, 2018 Incentive PSU Program and 2019 Incentive PSU Program also included awards to be settled in cash, which are recorded at fair value as of the measurement date determined through a Monte Carlo simulation, which projected the share price for the Company and its peers at the end point of the performance period. The expected share prices were generated using each company's annual volatility for the expected term and the commensurate three-year risk-free rate shown in the chart below. As the Incentive PSU Programs include a performance condition that affects the number of shares that will ultimately vest, the Monte Carlo simulation computed either the grant date fair value for equity awards or the measurement date fair value for liability awards for each possible performance condition outcome on the grant date for equity awards or the measurement date for liability awards. The Company reevaluates the then-probable outcome at the end of each reporting period to record expense at the probable outcome grant date fair value or measurement date fair value, as applicable. Vesting of the units under each Incentive PSU Program occurs upon payment after the end of the performance period.
The following table summarizes Incentive PSU Programs to be settled in stock and classified as equity awards:
| Incentive PSU Programs - Equity Settled | Nonvested Shares (a) | Weighted Average Fair Value | Aggregate Fair Value | |||||||||||||||||
| Outstanding at January 1, 2018 | 832,622 | $ | 115.10 | $ | 95,832,997 | |||||||||||||||
| Granted | 172,350 | 76.53 | 13,189,946 | |||||||||||||||||
| Vested | (306,407) | 141.11 | (43,237,092) | |||||||||||||||||
| Forfeited | (162,551) | 93.55 | (15,206,691) | |||||||||||||||||
| Outstanding at December 31, 2018 | 536,014 | 94.36 | 50,579,160 | |||||||||||||||||
| Granted | 463,380 | 29.45 | 13,646,541 | |||||||||||||||||
| Vested | (384,101) | 96.30 | (36,988,926) | |||||||||||||||||
| Outstanding at December 31, 2019 | 615,293 | 44.27 | 27,236,775 | |||||||||||||||||
| Granted | 1,376,198 | 6.62 | 9,107,846 | |||||||||||||||||
| Vested | (44,573) | 120.60 | (5,375,504) | |||||||||||||||||
| Forfeited | (7,190) | 13.28 | (95,483) | |||||||||||||||||
| Outstanding at December 31, 2020 | 1,939,728 | $ | 15.92 | $ | 30,873,634 |
(a)For the years ended December 31, 2020 and 2019, the Company settled total shares of 7,020 and 130,393, respectively, for Equitrans Midstream employees.
The following table summarizes Incentive PSU Programs to be settled in cash and classified as liability awards:
| Incentive PSU Programs - Cash Settled | Nonvested Shares (b) | Weighted Average Fair Value | Aggregate Fair Value | |||||||||||||||||
| Outstanding at January 1, 2018 | 117,530 | $ | 120.60 | $ | 14,174,118 | |||||||||||||||
| Granted | 142,890 | 76.53 | 10,935,371 | |||||||||||||||||
| Forfeited | (30,582) | 94.56 | (2,891,844) | |||||||||||||||||
| Outstanding at December 31, 2018 | 229,838 | 96.67 | 22,217,645 | |||||||||||||||||
| Granted | 255,920 | 29.45 | 7,536,844 | |||||||||||||||||
| Forfeited | (33,348) | 75.65 | (2,522,819) | |||||||||||||||||
| Outstanding at December 31, 2019 | 452,410 | 60.19 | 27,231,670 | |||||||||||||||||
| Vested | (93,359) | 120.60 | (11,259,095) | |||||||||||||||||
| Forfeited | (19,356) | 61.43 | (1,189,050) | |||||||||||||||||
| Outstanding at December 31, 2020 | 339,695 | $ | 43.52 | $ | 14,783,525 |
(b)For the year ended December 31, 2020, the Company settled total shares paid in cash of 40,018 for Equitrans Midstream employees.
Total capitalized compensation costs related to the Incentive PSU Programs for the years ended December 31, 2020, 2019, and 2018 were $0.9 million, $(0.8) million, and $3.7 million. As of December 31, 2020, $0.1 million, $0.8 million and $6.2 million of unrecognized compensation cost (assuming no changes to the performance condition achievement level) related to the 2019 Incentive PSU Program – Equity, 2019 Incentive PSU Program – Liability and 2020 Incentive PSU Program, respectively, was expected to be recognized over the remainder of the performance periods.
Fair value is estimated using a Monte Carlo simulation valuation method with the following weighted average assumptions at grant date:
| Incentive PSU Programs Issued During the Years Ended December 31, | |||||||||||||||||||||||||||||
| 2020 (a) | 2019 | 2018 | 2017 | 2016 | |||||||||||||||||||||||||
| Risk-free rate | 1.22% | 2.44% | 1.97% | 1.47% | 1.31% | ||||||||||||||||||||||||
| Volatility factor | 45.41% | 54.60% | 32.60% | 32.30% | 28.43% | ||||||||||||||||||||||||
| Expected term | 3 years | 3 years | 3 years | 3 years | 3 years |
Dividends paid from the beginning of the performance period will be cumulatively added as additional shares of common stock; therefore, dividend yield is not applicable.
(a)There were three grant dates for the 2020 Incentive PSU Program. Amounts shown represent weighted average.
Value Driver Performance Share Unit Award Programs
Historically, the Compensation Committee adopted the following programs, collectively referred to as the VDPSU Programs:
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2017 Value Driver Performance Share Unit Award Program (2017 EQT VDPSU Program) under the 2014 LTIP;
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2018 Value Driver Performance Share Unit Award Program (2018 EQT VDPSU Program) under the 2014 LTIP; and
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2019 Value Driver Performance Share Unit Award Program (2019 EQT VDPSU Program) under the 2014 LTIP.
The programs noted above are collectively referred to as the VDPSU Programs. The VDPSU Programs were established to align the interests of key employees with the interests of shareholders and customers and the strategic objectives of the Company. Under each VDPSU Program, 50% of the confirmed awards vested upon payment following the first anniversary of the grant date; the remaining 50% of the confirmed awards vested upon payment following the second anniversary of the grant date, subject to continued service through such date. Due to the graded vesting of each award under the VDPSU Programs, the Company recognized compensation cost over the requisite service period for each separately vesting tranche of the award as though each award was, in substance, multiple awards. The payments were contingent upon adjusted earnings before interest, income taxes, depreciation and amortization performance as compared to the Company's annual business plan and individual,
business unit and Company value driver performance over the respective one-year periods. The following table provides additional detailed information on each historical award.
| VDPSU Program | Accounting Treatment | Weighted Average Fair Value | Cash paid (Millions) | Awards Outstanding (including accrued dividends) as of December 31, 2020 (a) | ||||||||||
| 2017 | Liability | $ | 65.40 | $ | 14.0 | N/A | ||||||||
| $ | 65.40 | $ | 4.0 | N/A | ||||||||||
| 2018 | Liability | $ | 56.92 | $ | 4.9 | N/A | ||||||||
| $ | 56.92 | $ | 1.2 | N/A | ||||||||||
| 2019 (b) | Liability | $ | 18.89 | $ | 1.7 | N/A | ||||||||
| $ | 18.89 | N/A | 144,116 |
(a)The 2017 EQT VDPSU Program and 2018 EQT VDPSU Program included 95,452 and 130,355 awards, respectively, for Equitrans Midstream employees that were settled by the Company.
(b)The total liability recorded for the 2019 EQT VDPSU Program was $1.7 million as of December 31, 2020. The second tranche of the 2019 EQT VDPSU Program will be paid during the first quarter of 2021.
Total capitalized compensation costs related to the VDPSU Programs for the years ended December 31, 2020, 2019 and 2018 were $0.4 million, $2.5 million and $3.4 million, respectively.
Restricted Stock Unit Awards – Equity
The Company granted 1,767,960, 613,440 and 145,540 restricted stock unit equity awards to key employees of the Company during the years ended December 31, 2020, 2019 and 2018, respectively. Awards granted in 2019 and 2018 will fully vest at the end of the three-year period commencing with the date of grant, assuming continued service through such date, while the 2020 awards are subject to a three-year graded vesting schedule, also assuming continued service through such date. For the years ended December 31, 2020, 2019 and 2018, the weighted average fair value of these restricted stock grants, based on the grant date fair value of EQT common stock, was approximately $10.02, $17.42 and $54.33, respectively.
The total fair value of restricted stock awards vested during the years ended December 31, 2020, 2019 and 2018 was $3.2 million, $11.9 million and $39.8 million, respectively. Total capitalized compensation costs related to the restricted stock unit equity awards was $3.0 million for the year ended December 31, 2020.
As of December 31, 2020, $9.3 million of unrecognized compensation cost related to nonvested restricted stock equity awards was expected to be recognized over a remaining weighted average vesting term of approximately 1.1 years.
The following table summarizes restricted stock equity award activity as of December 31, 2020.
| Restricted Stock - Equity Settled | Nonvested Shares (a) | Weighted Average Fair Value | Aggregate Fair Value | |||||||||||||||||
| Outstanding at January 1, 2020 | 310,997 | $ | 25.47 | $ | 7,921,313 | |||||||||||||||
| Granted | 1,767,960 | 10.02 | 17,711,033 | |||||||||||||||||
| Vested | (130,487) | 24.26 | (3,165,269) | |||||||||||||||||
| Forfeited | (80,070) | 10.90 | (872,763) | |||||||||||||||||
| Outstanding at December 31, 2020 | 1,868,400 | $ | 11.56 | $ | 21,594,314 |
(a)Nonvested shares outstanding at December 31, 2020 includes 59,340 shares for an Equitrans Midstream employee that will be settled by the Company.
Restricted Stock Unit Awards – Liability
During the years ended December 31, 2019 and 2018, the Company granted 686,350 and 373,750 restricted stock unit liability awards, respectively, to key employees of the Company that will be paid in cash. The Company did not grant restricted stock unit awards to be paid in cash during 2020.
Adjusted for forfeitures, there were 554,306 awards outstanding as of December 31, 2020. Because these awards are liability awards, the Company records compensation expense based on the fair value of the awards as remeasured at the end of each reporting period. The restricted units granted will be fully vested at the end of the three-year period commencing with the date
of grant, assuming continued service through such date. The total liability recorded for these restricted units was $4.5 million, $4.4 million and $6.9 million as of December 31, 2020, 2019 and 2018, respectively.
Non-Qualified Stock Options
The fair value of the Company's option grants was estimated at the grant date using a Black-Scholes option-pricing model with the assumptions indicated in the table below for the years ended December 31, 2020, 2019 and 2018. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the date of grant. The dividend yield is based on the dividend yield of EQT common stock at the time of grant. Expected volatilities are based on historical volatility of EQT common stock. The expected term represents the period of time that options granted are expected to be outstanding based on historical option exercise experience.
| Years Ended December 31, | |||||||||||||||||
| 2020 | 2019 (a) | 2018 | |||||||||||||||
| Risk-free interest rate | 1.10 | % | 2.48 | % | 2.25 | % | |||||||||||
| Dividend yield | — | % | 0.46 | % | 0.20 | % | |||||||||||
| Volatility factor | 60.00 | % | 27.97 | % | 26.46 | % | |||||||||||
| Expected term | 4 years | 5 years | 5 years | ||||||||||||||
| Number of Options Granted | 1,000,000 | 779,300 | 287,800 | ||||||||||||||
| Weighted Average Grant Date Fair Value | $ | 1.61 | $ | 5.31 | $ | 15.39 | |||||||||||
| Total Intrinsic Value of Options Exercised (Millions) | $ | — | $ | — | $ | — |
(a)There were two grant dates for the 2019 options. Amount shown represents weighted average.
As of December 31, 2020, $0.8 million of unrecognized compensation cost related to outstanding nonvested stock options was expected to be recognized by December 31, 2023.
The following table summarizes option activity as of December 31, 2020.
| Non-Qualified Stock Options | Shares | Weighted Average Exercise Price | Weighted Average Remaining Contractual Term | Aggregate Intrinsic Value | ||||||||||||||||||||||
| Outstanding at January 1, 2020 | 2,554,729 | $ | 28.37 | |||||||||||||||||||||||
| Granted | 1,000,000 | 10.00 | ||||||||||||||||||||||||
| Outstanding at December 31, 2020 | 3,554,729 | 23.20 | 5.3 years | $ | 2,710,000 | |||||||||||||||||||||
| Exercisable at December 31, 2020 | 2,543,829 | $ | 28.41 | 4.9 years | $ | — |
Stock Appreciation Rights
During 2020, the Company granted stock appreciation rights subject to certain performance conditions, such as adjusted well costs and adjusted free cash flow. Once vested, the participant is entitled to receive, upon exercise, a number of shares of EQT’s common stock, cash or a combination of the two, based upon the excess of the fair market value as of the date of exercise over a base price of $10.00.
The awards are accounted for as liability awards and, as such, compensation expense is recorded based on the fair value of the awards as remeasured at the end of each reporting period using a Black-Scholes option-pricing model with the assumptions indicated in the table below. The risk-free rate is based on the U.S. Treasury yield curve in effect at the reporting date. The dividend yield is based on the dividend yield of EQT common stock at the reporting date, which is set at zero for the stock appreciation rights as the Company suspended future dividends during 2020. Expected volatilities are based on a 50-50 blend of the expected term-matched historical volatility as of the valuation date and the weighted-average implied volatility from thirty
days prior to the valuation date. The expected term represents the period of time between the valuation date and the midpoint of the exercise window.
| 2020 Stock Appreciation Rights | |||||
| Risk-free interest rate | 0.30 | % | |||
| Dividend yield | — | % | |||
| Volatility factor | 67.50 | % | |||
| Expected term | 3.28 years | ||||
| Number of Stock Appreciation Rights Granted | 1,240,000 | ||||
| Weighted Average Grant Date Fair Value | $ | 2.61 | |||
| Total Intrinsic Value of Exercises (Millions) | $ | — |
As of December 31, 2020, $4.7 million of unrecognized compensation cost related to outstanding stock appreciation rights was expected to be recognized by December 31, 2022.
The following table summarizes stock appreciation rights activity as of December 31, 2020.
| Stock Appreciation Rights | Shares | Weighted Average Exercise Price | Weighted Average Remaining Contractual Term | Aggregate Intrinsic Value | ||||||||||||||||||||||
| Outstanding at January 1, 2020 | — | $ | — | |||||||||||||||||||||||
| Granted | 1,240,000 | 10.00 | ||||||||||||||||||||||||
| Outstanding at December 31, 2020 | 1,240,000 | 10.00 | 9.0 years | $ | 3,360,400 | |||||||||||||||||||||
| Exercisable at December 31, 2020 | — | $ | — | — | $ | — |
Non-employee Directors' Share-Based Awards
Prior to 2020, the Company granted share-based awards that vested upon grant to non-employee directors. The share-based awards were historically paid in cash or EQT common stock following a directors' termination of service on the Company's Board of Directors. Beginning in 2020, the Company grants to non-employee directors restricted stock unit awards that vest on the date of the Company's annual meeting of shareholders immediately following the grant of such awards. The restricted stock unit awards are settled in EQT common stock on the vesting date or, if elected by the director, following a director's termination of service on the Company's Board of Directors.
Awards to be paid in cash are accounted for as liability awards and, as such, compensation expense is recorded based on the fair value of the awards as remeasured at the end of each reporting period. Awards to be settled in EQT common stock are accounted for as equity awards and, as such, compensation expense is recorded based on the fair value of the awards at the grant date fair value. A total of 398,456 non-employee director share-based awards, including accrued dividends, were outstanding as of December 31, 2020. A total of 201,300, 146,790 and 50,979 share-based awards were granted to non-employee directors during the years ended December 31, 2020, 2019 and 2018, respectively. The weighted average fair value of these grants, based on the closing EQT common stock price on the business day prior to the grant date, was $13.46, $18.11 and $52.65 for the years ended December 31, 2020, 2019 and 2018, respectively.
Subsequent Events - 2021 Awards
Effective in 2021, the Compensation Committee adopted the 2021 Incentive Performance Share Unit Program (2021 Incentive PSU Program) under the 2020 LTIP. The 2021 Incentive PSU Program was established to align the interests of executives and key employees with the interests of shareholders and the strategic objectives of the Company. A total of 922,260 units were granted under the 2021 Incentive PSU Program. The payout of the stock units will vary between zero and 200% of the number of outstanding units contingent upon a combination of the Company's absolute total shareholder return and total shareholder return relative to a predefined peer group over the period January 1, 2021 through December 31, 2023.
Effective in 2021, the Compensation Committee granted 1,889,510 restricted stock equity awards that will follow a three-year graded vesting schedule commencing with the date of grant, assuming continued employment. The share total includes the newly instituted "equity-for-all" program, which granted equity awards to all permanent full-time employees beginning in 2021.
14. Concentrations of Credit Risk
Revenues and related accounts receivable from the Company's operations are generated primarily from the sale of produced natural gas, NGLs and oil to marketers, utilities and industrial customers located in the Appalachian Basin and in markets that are accessible through the Company's transportation portfolio, which includes markets in the Gulf Coast, Midwest and Northeast United States and Canada. The Company also contracts with certain processors to market a portion of NGLs on behalf of the Company. We do not depend on any single customer and believe that the loss of any one customer would not have an adverse effect on our ability to sell our natural gas, NGLs and oil.
Approximately 86% and 62% of the Company's accounts receivable balances as of December 31, 2020 and 2019, respectively, represent amounts due from non-end users. The Company manages the credit risk of sales to non-end users by limiting its dealings with only non-end users that meet the Company's criteria for credit and liquidity strength and by regularly monitoring these accounts. The Company may require letters of credit, guarantees, performance bonds or other credit enhancements from a non-end user for that non-end user to meet the Company's credit criteria. The Company did not experience any significant defaults on sales of natural gas to non-end users during the years ended December 31, 2020, 2019 or 2018.
The Company is exposed to credit loss in the event of nonperformance by counterparties to its derivative contracts. This credit exposure is limited to derivative contracts with a positive fair value, which may change as market prices change. The Company's OTC derivative instruments are primarily with financial institutions and, thus, are subject to events that would impact those companies individually as well as the financial industry as a whole. The Company uses various processes and analyses to monitor and evaluate its credit risk exposures, including monitoring current market conditions and counterparty credit fundamentals. Credit exposure is controlled through credit approvals and limits based on counterparty credit fundamentals. To manage the level of credit risk, the Company enters into transactions primarily with financial counterparties that are of investment grade, enters into netting agreements whenever possible and may obtain collateral or other security.
As of December 31, 2020, the Company was not in default under any derivative contracts and had no knowledge of default by any counterparty to its derivative contracts. During the year ended December 31, 2020, the Company made no adjustments to the fair value of its derivative contracts due to credit related concerns outside of the normal non-performance risk adjustment included in the Company's established fair value procedure. The Company monitors market conditions that may impact the fair value of its derivative contracts.
15. Leases
The Company primarily leases drilling rigs, other drilling equipment and facilities.
On January 1, 2019, in connection with the Company's adoption of ASU 2016-02, Leases, the Company recorded in its Consolidated Balance Sheet $89.0 million of right-of-use assets and lease liabilities representing the present value of the Company's right to use its leased assets and obligation to make lease payments on those leased assets, respectively.
To determine the present value of its right-of-use assets and lease liabilities at adoption and thereafter, the Company calculates a discount rate per lease contract based on an estimate of the rate of interest that the Company would pay to borrow (on a collateralized-basis over a similar term) an amount equal to the lease payment obligation.
Upon adoption of ASU 2016-02, the Company elected a practical expedient to forgo application of the recognition requirements under the standard to short-term leases; as such, short-term leases are not recorded in the Consolidated Balance Sheets. In addition, the Company elected a practical expedient to account for lease and nonlease components together as a lease.
Certain of the Company's lease contracts include variable lease payments, such as property taxes, other operating and maintenance expenses and payments based on asset use, which are not included in operating lease cost or the present value of the right-of-use asset or lease liability. Certain of the Company's lease contracts provide renewal periods at the Company's option; if a renewal period option is reasonably assured to be exercised, the associated lease payment obligations are included in the present value of the right-of-use asset and lease liability. As of December 31, 2020 and 2019, the Company was not a lessor.
The following table summarizes the Company's lease costs.
| Years Ended December 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| (Thousands) | |||||||||||
| Operating lease costs | $ | 28,286 | $ | 57,517 | |||||||
| Variable lease costs (a) | 15,922 | 17,143 | |||||||||
| Total lease costs (b) | $ | 44,208 | $ | 74,660 |
(a)Includes short-term lease costs.
(b)For the years ended December 31, 2020 and 2019, includes drilling rig lease costs capitalized to property, plant and equipment of $29.9 million and $58.5 million, respectively, of which $19.9 million and $48.1 million, respectively, were operating lease costs.
During the fourth quarter of 2020, the Company recognized $22.8 million of right-of-use asset impairment in impairment of intangible and other assets in the Statement of Consolidated Operations as a result of the Company's assessment that the fair values of certain of the Company's right-of-use assets were less than their carrying values.
For the years ended December 31, 2020 and 2019, cash paid for lease liabilities and reported in cash flows provided by operating activities in the Statements of Consolidated Cash Flows was $10.4 million and $10.8 million, respectively. During the years ended December 31, 2020 and 2019, the Company recorded $18.9 million and $24.3 million, respectively, of right-of-use assets in exchange for new lease liabilities.
The Company records its right-of-use assets in other assets and the current and noncurrent portions of its lease liabilities in other current liabilities and other liabilities and credits, respectively, in the Consolidated Balance Sheets. As of December 31, 2020 and 2019, right-of-use assets were $21.6 million and $52.2 million, respectively, and lease liabilities were $49.9 million and $59.0 million, respectively, of which $25.0 million and $29.0 million, respectively, were classified as current. As of December 31, 2020 and 2019, the weighted average remaining lease term was 2.8 years and 3.3 years, respectively. As of both December 31, 2020 and 2019, the weighted average discount rate was 3.3%.
The following table summarizes the Company's lease payment obligations as of December 31, 2020.
| December 31, 2020 | |||||
| (Thousands) | |||||
| 2021 | $ | 26,197 | |||
| 2022 | 9,841 | ||||
| 2023 | 9,764 | ||||
| 2024 | 6,456 | ||||
| 2025 | 150 | ||||
| Total lease payment obligations | 52,408 | ||||
| Less: Interest | 2,495 | ||||
| Present value of lease liabilities | $ | 49,913 |
16. Commitments and Contingencies
The Company has commitments for demand charges under existing long-term contracts and binding precedent agreements with various pipelines as well as commitments for processing capacity. Aggregate future payments for these items as of December 31, 2020 were $24.8 billion, composed of $1.3 billion in 2021, $1.7 billion in 2022, $1.8 billion in 2023, $1.9 billion in 2024, $1.8 billion in 2025 and $16.3 billion thereafter. The Company also has commitments to purchase equipment, materials, frac sand for use as a proppant in its hydraulic fracturing operations and minimum volume commitments associated with certain water agreements. As of December 31, 2020, future commitments under these contracts were $96.5 million in 2021 and $14.3 million in 2022.
See Note 15 for a summary of undiscounted future cash flows owed by the Company as lessee to lessors pursuant to contractual agreements in effect as of December 31, 2020.
Conditioned upon the credit ratings assigned by Moody's, S&P and Fitch to the Company's senior notes, counterparties to the Company's derivative and midstream services contracts may request additional assurances of the Company, including collateral. See Note 3 for a discussion of what is deemed investment grade and other factors affecting margin deposit requirements on the
Company's derivative contracts as well as collateral posted as of December 31, 2020. See Note 10 for a discussion of letters of credit outstanding and surety bonds posted as of December 31, 2020.
In the ordinary course of business, various legal and regulatory claims and proceedings are pending or threatened against the Company. While the amounts claimed may be substantial, the Company is unable to predict with certainty the ultimate outcome of such claims and proceedings. The Company accrues legal and other direct costs related to loss contingencies when actually incurred. The Company has established reserves it believes to be appropriate for pending matters and, after consultation with counsel and giving appropriate consideration to available insurance, the Company believes that the ultimate outcome of any matter currently pending against the Company will not materially affect the financial position, results of operations or liquidity of the Company.
The Company is subject to various federal, state and local environmental and environmentally-related laws and regulations. These laws and regulations, which are constantly changing, can require expenditures for remediation and may result in the assessment of fines. The Company has established procedures for ongoing evaluation of its operations to identify potential environmental exposures and to assure compliance with regulatory policies and procedures. The estimated costs associated with identified situations that require remedial action are accrued. Ongoing expenditures for compliance with environmental laws and regulations, including investments in plant and facilities to meet environmental requirements, have not been material. Management believes that any such required expenditures will not be significantly different in either their nature or amount in the future and does not know of any environmental liabilities that will have a material effect on the Company's financial position, results of operations or liquidity. The Company has identified situations that require remedial action for which approximately $18.9 million was recorded in other liabilities and credits in the Consolidated Balance Sheet as of December 31, 2020.
17. Guarantees
In connection with the sale of its NORESCO domestic operations in 2005, the Company agreed to maintain in-place guarantees of certain warranty obligations of NORESCO. The savings guarantees provided that, once an energy-efficiency construction project was completed by NORESCO, the customer would experience a certain dollar amount of energy savings over a number of years. The undiscounted maximum aggregate payments that may be due related to these guarantees were approximately $44 million as of December 31, 2020, extending at a decreasing amount for approximately 8 years.
This guarantee is exempt from ASC Topic 460, Guarantees. The Company considers the likelihood that it will be required to perform on these arrangements to be remote and expects any potential payments to be immaterial to the Company's financial position, results of operations and liquidity. As such, the Company has not recorded any liabilities related to this guarantee in its Consolidated Balance Sheets.
18. Natural Gas Producing Activities (Unaudited)
The following supplementary information summarized presents the results of natural gas and oil activities in accordance with the successful efforts method of accounting for production activities.
Production Costs
The following tables present total aggregate capitalized costs and costs incurred related to natural gas, NGLs and oil production activities.
| Years Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (Thousands) | |||||||||||||||||
| Capitalized costs | |||||||||||||||||
| Proved properties | $ | 19,479,211 | $ | 17,994,820 | $ | 17,648,731 | |||||||||||
| Unproved properties | 2,291,814 | 3,322,014 | 4,166,048 | ||||||||||||||
| Total capitalized costs | 21,771,025 | 21,316,834 | 21,814,779 | ||||||||||||||
| Less: Accumulated depreciation and depletion | 5,866,418 | 5,402,515 | 4,666,212 | ||||||||||||||
| Net capitalized costs | $ | 15,904,607 | $ | 15,914,319 | $ | 17,148,567 |
| Years Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (Thousands) | |||||||||||||||||
| Costs incurred (a) | |||||||||||||||||
| Property acquisition: | |||||||||||||||||
| Proved properties (b) | $ | 761,940 | $ | 40,316 | $ | 77,099 | |||||||||||
| Unproved properties (c) | 78,404 | 154,128 | 198,854 | ||||||||||||||
| Exploration | 5,484 | 7,223 | 1,708 | ||||||||||||||
| Development | 947,233 | 1,560,346 | 2,443,980 | ||||||||||||||
(a)Amounts exclude capital expenditures for facilities, information technology and other corporate items.
(b)Amounts in 2020 include $674.0 million and $6.5 million for the purchase of Marcellus and Utica wells, respectively, associated with the Chevron Acquisition. Amounts in 2018 include $5.2 million and $9.2 million for the purchase of Marcellus and Utica wells, respectively, including the impact of measurement period adjustments for 2017 acquisitions.
(c)Amounts in 2020 include $38.9 million for the purchase of unproved properties associated with the Chevron Acquisition.
Results of Operations for Producing Activities
The following table presents the results of operations related to natural gas, NGLs and oil production.
| Years Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (Thousands) | |||||||||||||||||
| Sales of natural gas, NGLs and oil | $ | 2,650,299 | $ | 3,791,414 | $ | 4,695,519 | |||||||||||
| Transportation and processing | 1,710,734 | 1,752,752 | 1,697,001 | ||||||||||||||
| Production | 155,403 | 153,785 | 195,775 | ||||||||||||||
| Exploration | 5,484 | 7,223 | 6,765 | ||||||||||||||
| Depreciation and depletion | 1,393,465 | 1,538,745 | 1,569,038 | ||||||||||||||
| Impairment/loss on sale/exchange of long-lived assets | 100,729 | 1,138,287 | 2,709,976 | ||||||||||||||
| Impairment and expiration of leases | 306,688 | 556,424 | 279,708 | ||||||||||||||
| Income tax benefit | (254,671) | (340,843) | (454,009) | ||||||||||||||
| Results of operations from producing activities, excluding corporate overhead | $ | (767,533) | $ | (1,014,959) | $ | (1,308,735) |
Reserve Information
Proved developed reserves represent only those reserves expected to be recovered from existing wells and support equipment. Proved undeveloped reserves represent proved reserves expected to be recovered from new wells after substantial development costs are incurred.
The Company's estimate of proved natural gas, NGLs and crude oil reserves was prepared by Company engineers. The engineer primarily responsible for overseeing the preparation of the reserves estimate holds a bachelor's degree in chemical engineering from Michigan Technological University, a master's degree in chemical engineering from Colorado State University and an executive master of business administration in energy from the University of Oklahoma and has 20 years of experience in the oil and gas industry. To support the accurate and timely preparation and disclosure of its reserve estimates, the Company established internal controls over its reserve estimation processes and procedures, including the following: the price, heat content conversion rate and cost assumptions used in the economic model to determine the reserves are reviewed by management; division of interest and production volumes are reconciled between the system used to calculate the reserves and other accounting/measurement systems; the reserves reconciliation between prior year reserves and current year reserves is reviewed by senior management; and the estimates of proved natural gas, NGLs and crude oil reserves are audited by Netherland, Sewell & Associates, Inc. (NSAI), an independent consulting firm hired by management. Since 1961, NSAI has evaluated oil and gas properties and independently certified petroleum reserves quantities in the United States and internationally.
In the course of its audit, NSAI conducted a detailed review of 100% of the total net natural gas, NGLs and oil proved reserves attributable to the Company's interests as of December 31, 2020. NSAI conducted a detailed, well-by-well audit of all the
Company's properties. The estimates prepared by the Company and audited by NSAI were within the recommended 10% tolerance threshold set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). Standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, analogy and material balance were utilized in the evaluation of reserves. All of the Company's proved reserves are located in the United States.
For all tables presented, NGLs and oil were converted at a rate of one Mbbl to approximately six million cubic feet (MMcf).
| Years Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (MMcf) | |||||||||||||||||
| Natural gas, NGLs and oil | |||||||||||||||||
| Proved developed and undeveloped reserves: | |||||||||||||||||
| Balance at January 1 | 17,469,394 | 21,816,776 | 21,445,667 | ||||||||||||||
| Revision of previous estimates | (739,213) | (4,907,239) | (1,124,904) | ||||||||||||||
| Purchase of hydrocarbons in place | 1,380,564 | — | — | ||||||||||||||
| Sale of hydrocarbons in place | (256,663) | — | (1,748,557) | ||||||||||||||
| Extensions, discoveries and other additions | 3,445,802 | 2,067,753 | 4,739,233 | ||||||||||||||
| Production | (1,497,792) | (1,507,896) | (1,494,663) | ||||||||||||||
| Balance at December 31 | 19,802,092 | 17,469,394 | 21,816,776 | ||||||||||||||
| Proved developed reserves: | |||||||||||||||||
| Balance at January 1 | 12,443,987 | 11,550,161 | 11,297,956 | ||||||||||||||
| Balance at December 31 | 13,641,345 | 12,443,987 | 11,550,161 | ||||||||||||||
| Proved undeveloped reserves: | |||||||||||||||||
| Balance at January 1 | 5,025,407 | 10,266,615 | 10,147,711 | ||||||||||||||
| Balance at December 31 | 6,160,747 | 5,025,407 | 10,266,615 |
| Years Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (MMcf) | |||||||||||||||||
| Natural gas | |||||||||||||||||
| Proved developed and undeveloped reserves: | |||||||||||||||||
| Balance at January 1 | 16,677,202 | 20,805,452 | 19,830,236 | ||||||||||||||
| Revision of previous estimates | (781,668) | (4,722,799) | (960,285) | ||||||||||||||
| Purchase of natural gas in place | 1,209,326 | — | — | ||||||||||||||
| Sale of natural gas in place | (254,930) | — | (1,331,391) | ||||||||||||||
| Extensions, discoveries and other additions | 3,433,857 | 2,029,683 | 4,659,835 | ||||||||||||||
| Production | (1,418,774) | (1,435,134) | (1,392,943) | ||||||||||||||
| Balance at December 31 | 18,865,013 | 16,677,202 | 20,805,452 | ||||||||||||||
| Proved developed reserves: | |||||||||||||||||
| Balance at January 1 | 11,811,521 | 10,887,953 | 10,152,543 | ||||||||||||||
| Balance at December 31 | 12,750,312 | 11,811,521 | 10,887,953 | ||||||||||||||
| Proved undeveloped reserves: | |||||||||||||||||
| Balance at January 1 | 4,865,681 | 9,917,499 | 9,677,693 | ||||||||||||||
| Balance at December 31 | 6,114,701 | 4,865,681 | 9,917,499 |
| Years Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (Mbbl) | |||||||||||||||||
| NGLs | |||||||||||||||||
| Proved developed and undeveloped reserves: | |||||||||||||||||
| Balance at January 1 | 126,955 | 162,395 | 258,507 | ||||||||||||||
| Revision of previous estimates | 6,825 | (30,312) | (33,653) | ||||||||||||||
| Purchase of NGLs in place | 25,879 | — | — | ||||||||||||||
| Sale of NGLs in place | (289) | — | (59,080) | ||||||||||||||
| Extensions, discoveries and other additions | 1,757 | 6,177 | 12,895 | ||||||||||||||
| Production | (12,365) | (11,305) | (16,274) | ||||||||||||||
| Balance at December 31 | 148,762 | 126,955 | 162,395 | ||||||||||||||
| Proved developed reserves: | |||||||||||||||||
| Balance at January 1 | 100,945 | 106,879 | 180,170 | ||||||||||||||
| Balance at December 31 | 141,489 | 100,945 | 106,879 | ||||||||||||||
| Proved undeveloped reserves: | |||||||||||||||||
| Balance at January 1 | 26,010 | 55,516 | 78,337 | ||||||||||||||
| Balance at December 31 | 7,273 | 26,010 | 55,516 |
| Years Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (Mbbl) | |||||||||||||||||
| Oil | |||||||||||||||||
| Proved developed and undeveloped reserves: | |||||||||||||||||
| Balance at January 1 | 5,077 | 6,159 | 10,731 | ||||||||||||||
| Revision of previous estimates | 250 | (428) | 6,217 | ||||||||||||||
| Purchase of oil in place | 2,660 | — | — | ||||||||||||||
| Sale of oil in place | — | — | (10,447) | ||||||||||||||
| Extensions, discoveries and other additions | 234 | 168 | 338 | ||||||||||||||
| Production | (804) | (822) | (680) | ||||||||||||||
| Balance at December 31 | 7,417 | 5,077 | 6,159 | ||||||||||||||
| Proved developed reserves: | |||||||||||||||||
| Balance at January 1 | 4,466 | 3,489 | 10,731 | ||||||||||||||
| Balance at December 31 | 7,016 | 4,466 | 3,489 | ||||||||||||||
| Proved undeveloped reserves: | |||||||||||||||||
| Balance at January 1 | 611 | 2,670 | — | ||||||||||||||
| Balance at December 31 | 401 | 611 | 2,670 |
The change in reserves during the year ended December 31, 2020 resulted from the following:
-
Conversions of 2,102 Bcfe of proved undeveloped reserves to proved developed reserves.
-
Extensions, discoveries and other additions of 3,446 Bcfe, which exceeded 2020 production of 1,498 Bcfe. Extensions, discoveries and other additions included an increase of 2,096 Bcfe of proved undeveloped additions associated with acreage that was previously unproved but became proved using reliable technologies which expanded the number of our technically proven locations, 1,295 Bcfe due to additions associated with directly offsetting development, 31 Bcfe from extension of proved undeveloped reserves lateral lengths and 24 Bcfe from converting unproved reserves to proved developed reserves.
-
Negative revisions of 510 Bcfe from proved undeveloped locations that are no longer expected to be developed within five years of initial booking as proved reserves as a result of revisions to the Company’s five-year drilling plan allowing for continued alignment with the Company’s combo-development strategy. This includes 245 Bcfe from lower pricing that impacted well economics, shifting capital from the Ohio Utica, to Pennsylvania and West Virginia Marcellus, and 265 Bcfe as a result of continued implementation of the Company’s combo-development strategy.
-
Negative revisions of 384 Bcfe primarily from proved developed locations as a result of negative curve revisions in Ohio Utica.
-
Positive revisions to proved undeveloped locations of 155 Bcfe due primarily to changes in working interests and net revenue interests as well as type curve updates.
-
Purchase of hydrocarbons in place of 1,381 Bcfe due to the Chevron Acquisition described in Note 6**.**
-
Sale of hydrocarbons in place of 257 Bcfe due to the 2020 Divestitures described in Note 7.
The change in reserves during the year ended December 31, 2019 resulted from the following:
-
Conversions of 2,646 Bcfe of proved undeveloped reserves to proved developed reserves.
-
Extensions, discoveries and other additions of 2,068 Bcfe, which exceeded 2019 production of 1,508 Bcfe. Extensions, discoveries and other additions included an increase of 1,796 Bcfe from proved undeveloped additions associated with acreage that was previously unproved, but became proved due to 2019 reserve development that expanded the number of the Company's technically proven locations, implementation of, and alignment with, the Company's combo-development strategy and revisions to the Company's five-year drilling plan; 156 Bcfe from converting unproved reserves to proved developed reserves; and 116 Bcfe from extension of proved undeveloped reserves lateral lengths.
-
Negative revisions of 4,508 Bcfe from proved undeveloped locations that are no longer expected to be developed within five years of initial booking as proved reserves as a result of implementation of the Company's combo-development strategy, which has refocused operations in the Company's core assets and driven execution of new development sequencing processes that emphasize productivity. While these efforts are expected to result in decreased well costs, they negatively impact proved undeveloped reserves as a result of (i) derecognizing previously-recorded proved undeveloped reserves that are now outside the Company's substantially revised five-year capital allocation program for purposes of the Company's reserves calculations and (ii) executing new development sequencing processes that will result in increased probable-to-proved developed conversion.
The change in reserves during the year ended December 31, 2018 resulted from the following:
-
Conversions of 2,722 Bcfe of proved undeveloped reserves to proved developed reserves.
-
Extensions, discoveries and other additions of 4,739 Bcfe, which exceeded 2018 production of 1,495 Bcfe. Extensions, discoveries and other additions included an increase of 315 Bcfe from proved developed reserves extensions from reservoirs underlying acreage not previously booked as proved in the Company's Ohio, Pennsylvania and West Virginia Marcellus fields; 886 Bcfe from proved undeveloped reserves extensions from acreage proved by drilling activity in the Company's Ohio, Pennsylvania and West Virginia Marcellus fields; and 3,538 Bcfe from other proved undeveloped additions associated with acreage that was excluded from prior year proved reserves bookings, but subsequently became proved due to inclusion within the Company's five-year drilling plan.
-
Negative revisions of 1,273 Bcfe from proved undeveloped locations that are no longer expected to be developed within five years of initial booking as proved reserves as a result of changes in the Company's future development plans to focus more heavily on developing the Company's core Pennsylvania assets.
-
Upward revisions of 148 Bcfe from proved developed locations, due primarily to increased reserves from producing wells and improved commodity prices.
-
Sale of hydrocarbons in place of 1,749 Bcfe due to the 2018 Divestitures described in Note 7.
Standard Measure of Discounted Future Cash Flow
Management cautions that the standard measure of discounted future cash flows should not be viewed as an indication of the fair market value of natural gas and oil producing properties, nor of the future cash flows expected to be generated therefrom. The information presented does not give recognition to future changes in estimated reserves, selling prices or costs and has been discounted at a rate of 10%.
The following table summarizes estimated future net cash flows from natural gas and crude oil reserves.
| December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (Thousands) | |||||||||||||||||
| Future cash inflows (a) | $ | 27,976,557 | $ | 42,499,686 | $ | 60,603,624 | |||||||||||
| Future production costs (b) | (16,344,965) | (19,114,076) | (20,463,567) | ||||||||||||||
| Future development costs | (2,268,109) | (2,617,731) | (5,854,503) | ||||||||||||||
| Future income tax expenses | (1,820,341) | (3,013,667) | (6,823,621) | ||||||||||||||
| Future net cash flow | 7,543,142 | 17,754,212 | 27,461,933 | ||||||||||||||
| 10% annual discount for estimated timing of cash flows | (4,176,684) | (9,261,539) | (15,850,035) | ||||||||||||||
| Standardized measure of discounted future net cash flows | $ | 3,366,458 | $ | 8,492,673 | $ | 11,611,898 |
(a)The majority of the Company's production is sold through liquid trading points on interstate pipelines.
For 2020, reserves were computed using average first-day-of-the-month closing prices for the prior twelve months of $39.54 per Bbl for West Texas Intermediate (WTI) less regional adjustments of $18.60 per Bbl, or $20.94 per Bbl, and $1.985 per MMBtu for NYMEX less regional adjustments of $0.68 per MMBtu, or $1.38 per Mcf. Regional adjustments were calculated using historical average realized prices received by the Company in the Appalachian Basin. For 2020, NGL pricing using average first-day-of-the-month closing prices for the prior twelve months for NGL components, adjusted using the regional component makeup of proved NGLs, resulted in a price of $11.97 per Bbl.
For 2019, reserves were computed using average first-day-of-the-month closing prices for the prior twelve months of $55.69 per Bbl for WTI less regional adjustments of $14.26 per Bbl, or $41.43 per Bbl, and $2.58 per MMBtu for NYMEX less regional adjustments of $0.29 per MMBtu, or $2.41 per Mcf. Regional adjustments were calculated using historical average realized prices received by the Company in the Appalachian Basin. For 2019, NGL pricing using average first-day-of-the-month closing prices for the prior twelve months for NGL components, adjusted using the regional component makeup of proved NGLs, resulted in a price of $16.81 per Bbl.
For 2018, reserves were computed using average first-day-of-the-month closing prices for the prior twelve months of $65.56 per Bbl for WTI less regional adjustments, $2.888 per Dth for Columbia Gas Transmission Corp., $2.568 per Dth for Dominion Transmission, Inc., $2.587 per Dth for Texas Eastern Transmission Corp., $2.320 per Dth for the Tennessee, zone 4-300 Leg of Tennessee Gas Pipeline Company and $2.939 per Dth for the Rockies Express Pipeline Zone 3. For 2018, NGL pricing using average first-day-of-the-month closing prices for the prior twelve months for NGL components, adjusted using the regional component makeup of produced NGLs, resulted in prices of $21.93 per Bbl from certain West Virginia Marcellus reserves and $33.89 per Bbl from Ohio Utica reserves.
(b)Includes approximately $1,554 million, $1,186 million and $883 million for future plugging and abandonment costs as of December 31, 2020, 2019 and 2018, respectively.
Holding production and development costs constant, an increase in price of $0.10 per Dth for natural gas, $10 per barrel for NGLs and $10 per barrel for oil would result in a change in the December 31, 2020 discounted future net cash flows before income taxes of the Company's proved reserves of approximately $929 million, $241 million and $630 million, respectively.
The following table summarizes the changes in the standardized measure of discounted future net cash flows.
| Years Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (Thousands) | |||||||||||||||||
| Net sales and transfers of natural gas and oil produced | $ | (784,163) | $ | (1,884,877) | $ | (2,802,742) | |||||||||||
| Net changes in prices, production and development costs | (6,761,447) | (3,502,434) | 2,949,606 | ||||||||||||||
| Extensions, discoveries and improved recovery, net of related costs | 714,808 | 870,504 | 1,616,653 | ||||||||||||||
| Development costs incurred | 797,796 | 1,002,389 | 1,630,506 | ||||||||||||||
| Net purchase of minerals in place | 350,075 | — | — | ||||||||||||||
| Net sale of minerals in place | (226,497) | — | (849,162) | ||||||||||||||
| Revisions of previous quantity estimates | (324,415) | (2,080,040) | (811,576) | ||||||||||||||
| Accretion of discount | 849,267 | 900,004 | 834,026 | ||||||||||||||
| Net change in income taxes | 152,978 | 1,444,368 | (289,549) | ||||||||||||||
| Timing and other | 105,383 | 130,861 | 332,202 | ||||||||||||||
| Net (decrease) increase | (5,126,215) | (3,119,225) | 2,609,964 | ||||||||||||||
| Balance at January 1 | 8,492,673 | 11,611,898 | 9,001,934 | ||||||||||||||
| Balance at December 31 | $ | 3,366,458 | $ | 8,492,673 | $ | 11,611,898 |
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