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, 2019 and 2018, the related statements of consolidated operations, comprehensive income, cash flows and equity for each of the three years in the period ended December 31, 2019, 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, 2019 and 2018, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, 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, 2019, 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 27, 2020 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, 2019, the net book value of the Company's proved oil and natural gas properties was $12,592 million, and depreciation, depletion and amortization (DD&A) expense was $1,539 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, 2019. 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, in assessing whether we can use the work of the specialists 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. |
Ohio Utica Long-Lived Assets Impairment
| Description of the Matter | As more fully described in Note 1 to the consolidated financial statements, the Company recorded an impairment charge of $1,036 million associated with its Ohio Utica long-lived asset grouping for the year ended December 31, 2019. The write-down to fair value was estimated based on the discounted future expected cash flows related to these assets and estimated proceeds from potentially selling the assets to a third-party. The determination of fair value included significant judgment and assumptions by management, including risk adjustments for probable reserves, future commodity prices, anticipated production volumes, future operating and development costs, inflation, a weighted average cost of capital (WACC) and estimated proceeds that could be realized upon a potential disposition. Auditing the Company's impairment calculation 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 identification of proved properties and anticipated production volumes 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 calculating the impairment charge. 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 calculation. Our testing of the Company's estimate of fair value of its Ohio Utica long-lived assets 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 proved locations and anticipated production volumes to the reserve estimates audited by the independent engineers in conjunction with the reserves estimation process. We also performed sensitivity analyses and a retrospective comparison of forecasted cash flows to actual historical data. Additionally, we assessed the likelihood of a potential market transaction and if such a transaction were to occur the estimated potential proceeds from such a transaction. |
/s/ Ernst & Young LLP
We have served as the Company's auditor since 1950.
Pittsburgh, Pennsylvania
February 27, 2020
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, 2019, 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, 2019, based on the COSO criteria.
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, 2019 and 2018, 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, 2018 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 27, 2020 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 27, 2020
EQT CORPORATION AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED OPERATIONS
YEARS ENDED DECEMBER 31,
| 2019 | 2018 | 2017 | |||||||||
| (Thousands, except per share amounts) | |||||||||||
| Operating revenues: | |||||||||||
| Sales of natural gas, natural gas liquids and oil | $ | 3,791,414 | $ | 4,695,519 | $ | 2,651,318 | |||||
| Gain (loss) on derivatives not designated as hedges | 616,634 | (178,591 | ) | 390,021 | |||||||
| Net marketing services and other | 8,436 | 40,940 | 49,681 | ||||||||
| Total operating revenues | 4,416,484 | 4,557,868 | 3,091,020 | ||||||||
| Operating expenses: | |||||||||||
| Transportation and processing | 1,752,752 | 1,697,001 | 1,164,783 | ||||||||
| Production | 153,785 | 195,775 | 181,349 | ||||||||
| Exploration | 7,223 | 6,765 | 17,565 | ||||||||
| Selling, general and administrative | 253,006 | 284,220 | 208,986 | ||||||||
| Depreciation and depletion | 1,538,745 | 1,569,038 | 970,985 | ||||||||
| Amortization of intangible assets | 35,916 | 41,367 | 5,400 | ||||||||
| Impairment/loss on sale/exchange of long-lived assets | 1,138,287 | 2,709,976 | — | ||||||||
| Impairment of intangible assets | 15,411 | — | — | ||||||||
| Impairment of goodwill | — | 530,811 | — | ||||||||
| Impairment and expiration of leases | 556,424 | 279,708 | 7,552 | ||||||||
| Proxy, transaction and reorganization | 117,045 | 26,331 | 152,188 | ||||||||
| Total operating expenses | 5,568,594 | 7,340,992 | 2,708,808 | ||||||||
| Operating (loss) income | (1,152,110 | ) | (2,783,124 | ) | 382,212 | ||||||
| Unrealized loss on investment in Equitrans Midstream Corporation | 336,993 | 72,366 | — | ||||||||
| Dividend and other (income) expense | (91,483 | ) | (7,017 | ) | 2,987 | ||||||
| Loss on debt extinguishment | — | — | 12,641 | ||||||||
| Interest expense | 199,851 | 228,958 | 167,971 | ||||||||
| (Loss) income from continuing operations before income taxes | (1,597,471 | ) | (3,077,431 | ) | 198,613 | ||||||
| Income tax benefit | (375,776 | ) | (696,511 | ) | (1,188,416 | ) | |||||
| (Loss) income from continuing operations | (1,221,695 | ) | (2,380,920 | ) | 1,387,029 | ||||||
| Income from discontinued operations, net of tax | — | 373,762 | 471,113 | ||||||||
| Net (loss) income | (1,221,695 | ) | (2,007,158 | ) | 1,858,142 | ||||||
| Less: Net income from discontinued operations attributable to noncontrolling interests | — | 237,410 | 349,613 | ||||||||
| Net (loss) income attributable to EQT Corporation | $ | (1,221,695 | ) | $ | (2,244,568 | ) | $ | 1,508,529 | |||
| Amounts attributable to EQT Corporation: | |||||||||||
| (Loss) income from continuing operations | $ | (1,221,695 | ) | $ | (2,380,920 | ) | $ | 1,387,029 | |||
| Income from discontinued operations, net of tax | — | 136,352 | 121,500 | ||||||||
| Net (loss) income | $ | (1,221,695 | ) | $ | (2,244,568 | ) | $ | 1,508,529 | |||
| Earnings per share of common stock attributable to EQT Corporation: | |||||||||||
| Basic: | |||||||||||
| Weighted average common stock outstanding | 255,141 | 260,932 | 187,380 | ||||||||
| (Loss) income from continuing operations | $ | (4.79 | ) | $ | (9.12 | ) | $ | 7.40 | |||
| Income from discontinued operations | — | 0.52 | 0.65 | ||||||||
| Net (loss) income | $ | (4.79 | ) | $ | (8.60 | ) | $ | 8.05 | |||
| Diluted: | |||||||||||
| Weighted average common stock outstanding | 255,141 | 260,932 | 187,727 | ||||||||
| (Loss) income from continuing operations | $ | (4.79 | ) | $ | (9.12 | ) | $ | 7.39 | |||
| Income from discontinued operations | — | 0.52 | 0.65 | ||||||||
| Net (loss) income | $ | (4.79 | ) | $ | (8.60 | ) | $ | 8.04 |
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,
| 2019 | 2018 | 2017 | |||||||||
| (Thousands) | |||||||||||
| Net (loss) income | $ | (1,221,695 | ) | $ | (2,007,158 | ) | $ | 1,858,142 | |||
| Other comprehensive income (loss), net of tax: | |||||||||||
| Net change in cash flow hedges: | |||||||||||
| Natural gas, net of tax expense (benefit): $2,584 in 2018 and ($3,191) in 2017 | — | (4,625 | ) | (4,982 | ) | ||||||
| Interest rate, net of tax expense: $210, $80 and $105 | 387 | 168 | 144 | ||||||||
| Other postretirement benefits liability adjustment, net of tax expense: $150, $510 and $193 | 316 | 606 | 338 | ||||||||
| Change in accounting principle (a) | (496 | ) | — | — | |||||||
| Other comprehensive income (loss) | 207 | (3,851 | ) | (4,500 | ) | ||||||
| Comprehensive (loss) income | (1,221,488 | ) | (2,011,009 | ) | 1,853,642 | ||||||
| Less: Comprehensive income from discontinued operations attributable to noncontrolling interests | — | 237,410 | 349,613 | ||||||||
| Comprehensive (loss) income attributable to EQT Corporation | $ | (1,221,488 | ) | $ | (2,248,419 | ) | $ | 1,504,029 |
| (a) | Related to adoption of Accounting Standards Update (ASU) 2018-02. See Note 1. |
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,
| 2019 | 2018 | 2017 | |||||||||
| (Thousands) | |||||||||||
| Cash flows from operating activities: | |||||||||||
| Net (loss) income | $ | (1,221,695 | ) | $ | (2,007,158 | ) | $ | 1,858,142 | |||
| Adjustments to reconcile net (loss) income to net cash provided by operating activities: | |||||||||||
| Deferred income tax benefit | (275,063 | ) | (510,405 | ) | (1,050,612 | ) | |||||
| Depreciation and depletion | 1,538,745 | 1,729,739 | 1,077,559 | ||||||||
| Amortization of intangible assets | 35,916 | 77,374 | 10,940 | ||||||||
| Impairment of long-lived assets and leases and exploratory well costs | 1,710,122 | 2,989,684 | 20,327 | ||||||||
| Impairment of goodwill | — | 798,689 | — | ||||||||
| Unrealized loss on investment in Equitrans Midstream Corporation | 336,993 | 72,366 | — | ||||||||
| Loss on debt extinguishment | — | — | 12,641 | ||||||||
| Amortization, accretion and other | 23,296 | (33,039 | ) | (25,934 | ) | ||||||
| Share-based compensation expense | 31,233 | 25,189 | 94,592 | ||||||||
| (Gain) loss on derivatives not designated as hedges | (616,634 | ) | 178,591 | (390,021 | ) | ||||||
| Cash settlements received (paid) on derivatives not designated as hedges | 246,639 | (225,279 | ) | 40,728 | |||||||
| Net premiums received on derivative instruments | 22,616 | — | — | ||||||||
| Changes in other assets and liabilities: | |||||||||||
| Accounts receivable | 432,323 | (439,062 | ) | (8,979 | ) | ||||||
| Accounts payable | (238,674 | ) | 457,113 | (16,680 | ) | ||||||
| Tax receivable | (167,281 | ) | (117,188 | ) | (12,285 | ) | |||||
| Other items, net | (6,832 | ) | (20,358 | ) | 27,280 | ||||||
| Net cash provided by operating activities | 1,851,704 | 2,976,256 | 1,637,698 | ||||||||
| Cash flows from investing activities: | |||||||||||
| Capital expenditures | (1,602,454 | ) | (2,999,037 | ) | (1,559,051 | ) | |||||
| Cash paid for Rice Merger and other acquisitions (see Note 8), net of cash acquired | — | — | (2,379,229 | ) | |||||||
| Capital expenditures for discontinued operations | — | (732,727 | ) | (380,151 | ) | ||||||
| Net sales of trading securities | — | — | 283,758 | ||||||||
| Exploratory dry hole costs | — | — | (11,420 | ) | |||||||
| Capital contributions to Mountain Valley Pipeline, LLC | — | (820,943 | ) | (159,550 | ) | ||||||
| Proceeds from sale of assets | — | 583,381 | 3,573 | ||||||||
| Other investing activities | 1,312 | (9,778 | ) | — | |||||||
| Net cash used in investing activities | (1,601,142 | ) | (3,979,104 | ) | (4,202,070 | ) | |||||
| Cash flows from financing activities: | |||||||||||
| Proceeds from borrowings on credit facility | 2,978,750 | 8,637,500 | 2,063,000 | ||||||||
| Repayment of borrowings on credit facility | (3,484,750 | ) | (8,953,500 | ) | (1,076,500 | ) | |||||
| Proceeds from borrowings on term loan facility | 1,000,000 | — | — | ||||||||
| Debt issuance costs and credit facility origination fees | (913 | ) | (40,966 | ) | (41,876 | ) | |||||
| Proceeds from issuance of debt | — | 2,500,000 | 3,000,000 | ||||||||
| Repayments and retirements of debt | (704,661 | ) | (8,376 | ) | (2,000,000 | ) | |||||
| Premiums paid on debt extinguishment | — | — | (89,363 | ) | |||||||
| Dividends paid | (30,655 | ) | (31,375 | ) | (20,827 | ) | |||||
| Proceeds and excess tax benefits from awards under employee compensation plans | — | 1,946 | 244 | ||||||||
| Cash paid for taxes related to net settlement of share-based incentive awards | (7,224 | ) | (22,647 | ) | (72,116 | ) | |||||
| Repurchase and retirement of common stock | — | (538,876 | ) | — | |||||||
| Repurchase of common stock | — | (27 | ) | (30 | ) | ||||||
| Distributions to noncontrolling interests | — | (380,651 | ) | (236,123 | ) | ||||||
| Contribution to Strike Force Midstream LLC by minority owner, net of distribution | — | — | 6,738 | ||||||||
| Acquisition of 25% of Strike Force Midstream LLC | — | (175,000 | ) | — | |||||||
| Net cash transferred at Separation and Distribution | — | (129,008 | ) | — | |||||||
| Net cash (used in) provided by financing activities | (249,453 | ) | 859,020 | 1,533,147 | |||||||
| Net change in cash and cash equivalents | 1,109 | (143,828 | ) | (1,031,225 | ) | ||||||
| Cash and cash equivalents at beginning of year | 3,487 | 147,315 | 1,178,540 | ||||||||
| Cash and cash equivalents at end of year | $ | 4,596 | $ | 3,487 | $ | 147,315 |
The accompanying notes are an integral part of these Consolidated Financial Statements. See Note 1 for supplemental cash flow information. See Note 2 for discontinued operations cash flow information.
EQT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
| 2019 | 2018 | ||||||
| (Thousands) | |||||||
| ASSETS | |||||||
| Current assets: | |||||||
| Cash and cash equivalents | $ | 4,596 | $ | 3,487 | |||
| Accounts receivable (less provision for doubtful accounts: $6,861 and $8,648) | 610,088 | 1,241,843 | |||||
| Derivative instruments, at fair value | 812,664 | 481,654 | |||||
| Tax receivable | 298,854 | 131,573 | |||||
| Prepaid expenses and other | 28,653 | 111,107 | |||||
| Total current assets | 1,754,855 | 1,969,664 | |||||
| Property, plant and equipment | 21,655,351 | 22,148,012 | |||||
| Less: Accumulated depreciation and depletion | 5,499,861 | 4,755,505 | |||||
| Net property, plant and equipment | 16,155,490 | 17,392,507 | |||||
| Intangible assets, net | 26,006 | 77,333 | |||||
| Investment in Equitrans Midstream Corporation | 676,009 | 1,013,002 | |||||
| Other assets | 196,867 | 268,838 | |||||
| Total assets | $ | 18,809,227 | $ | 20,721,344 | |||
| LIABILITIES AND SHAREHOLDERS' EQUITY | |||||||
| Current liabilities: | |||||||
| Current portion of debt | $ | 16,204 | $ | 704,390 | |||
| Accounts payable | 796,438 | 1,059,873 | |||||
| Derivative instruments, at fair value | 312,696 | 336,051 | |||||
| Other current liabilities | 220,564 | 254,687 | |||||
| Total current liabilities | 1,345,902 | 2,355,001 | |||||
| Credit facility borrowings | 294,000 | 800,000 | |||||
| Term loan facility borrowings | 999,353 | — | |||||
| Senior notes | 3,878,366 | 3,882,932 | |||||
| Note payable to EQM Midstream Partners, LP | 105,056 | 110,059 | |||||
| Deferred income taxes | 1,485,814 | 1,823,381 | |||||
| Other liabilities and credits | 897,148 | 791,742 | |||||
| Total liabilities | 9,005,639 | 9,763,115 | |||||
| Shareholders' Equity: | |||||||
| Common stock, no par value, shares authorized: 320,000, shares issued: 257,003 and 257,225 | 7,818,205 | 7,828,554 | |||||
| Treasury stock, shares at cost: 1,832 and 2,753 | (32,507 | ) | (49,194 | ) | |||
| Retained earnings | 2,023,089 | 3,184,275 | |||||
| Accumulated other comprehensive loss | (5,199 | ) | (5,406 | ) | |||
| Total shareholders' equity | 9,803,588 | 10,958,229 | |||||
| Total liabilities and shareholders' equity | $ | 18,809,227 | $ | 20,721,344 |
The accompanying notes are an integral part of these Consolidated Financial Statements.
EQT CORPORATION AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED EQUITY
YEARS ENDED DECEMBER 31, 2019**,** 2018 and 2017
| Common Stock | Accumulated Other Comprehensive (Loss) Income | Noncontrolling Interests in Discontinued Operations | ||||||||||||||||||||||||
| Shares | No Par Value | Treasury Stock | Retained Earnings | Total Equity | ||||||||||||||||||||||
| (Thousands, except per share or unit amounts) | ||||||||||||||||||||||||||
| Balance at December 31, 2016 | 172,827 | $ | 3,440,185 | $ | (91,019 | ) | $ | 2,509,073 | $ | 2,042 | $ | 3,258,966 | $ | 9,119,247 | ||||||||||||
| Comprehensive income, net of tax: | ||||||||||||||||||||||||||
| Net income | 1,508,529 | 349,613 | 1,858,142 | |||||||||||||||||||||||
| Net change in cash flow hedges: | ||||||||||||||||||||||||||
| Natural gas, net of tax: ($3,191) | (4,982 | ) | (4,982 | ) | ||||||||||||||||||||||
| Interest rate, net of tax: $105 | 144 | 144 | ||||||||||||||||||||||||
| Other postretirement benefits liability adjustment, net of tax: $193 | 338 | 338 | ||||||||||||||||||||||||
| Dividends ($0.12 per share) | (20,827 | ) | (20,827 | ) | ||||||||||||||||||||||
| Share-based compensation plans, net | 580 | (981 | ) | 27,417 | 190 | 26,626 | ||||||||||||||||||||
| Distributions to noncontrolling interests in discontinued operations (a) | (236,123 | ) | (236,123 | ) | ||||||||||||||||||||||
| Rice Merger, net of withholdings | 90,914 | 5,949,729 | 1,715,611 | 7,665,340 | ||||||||||||||||||||||
| Contribution from noncontrolling interest, net of distribution | 6,738 | 6,738 | ||||||||||||||||||||||||
| Repurchase of common stock | (1 | ) | (30 | ) | (30 | ) | ||||||||||||||||||||
| Balance at December 31, 2017 | 264,320 | $ | 9,388,903 | $ | (63,602 | ) | $ | 3,996,775 | $ | (2,458 | ) | $ | 5,094,995 | $ | 18,414,613 | |||||||||||
| Comprehensive 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 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 (b) | 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 |
Common shares authorized: 320,000. Preferred shares authorized: 3,000. There are no preferred shares issued or outstanding.
| (a) | For the year ended December 31, 2017, distributions to noncontrolling interests were $3.655 and $0.806 per common unit for EQM Midstream Partners, LP and EQGP Holdings, LP, respectively. 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 (formerly known as Rice Midstream Partners LP), respectively. |
| (b) | Related to adoption of ASU 2018-02. See Note 1. |
The accompanying notes are an integral part of these Consolidated Financial Statements.
EQT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2019
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). All significant intercompany accounts and transactions have been eliminated in consolidation.
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.
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 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 3 for a discussion of amounts due from contracts with customers.
Investment in Equitrans Midstream Corporation. As of December 31, 2019, the Company owned approximately 19.9% of the outstanding shares of common stock of Equitrans Midstream Corporation (Equitrans Midstream). See Note 18 for a discussion of events occurring subsequent to December 31, 2019 that will, among other things, affect the Company's ownership of 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 unrealized loss on investment in Equitrans Midstream Corporation in the Statements of Consolidated Operations. See Note 5 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 2.
Property, Plant and Equipment. The following table summarizes the Company's property, plant and equipment.
| December 31, | |||||||
| 2019 | 2018 | ||||||
| (Thousands) | |||||||
| Oil and gas producing properties, successful efforts method | $ | 21,316,834 | $ | 21,814,779 | |||
| Less: Accumulated depreciation and depletion | 5,402,515 | 4,666,212 | |||||
| Net oil and gas producing properties | 15,914,319 | 17,148,567 | |||||
| Other properties, at cost less accumulated depreciation | 241,171 | 243,940 | |||||
| Net property, plant and equipment | $ | 16,155,490 | $ | 17,392,507 |
The Company uses the successful efforts method of accounting for oil and gas 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 $77 million, $130 million and $115 million in 2019, 2018 and 2017, respectively. The Company also capitalized interest expense related to well development of approximately $24 million, $29 million and $21 million in 2019, 2018 and 2017, 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 $1.01, $1.04 and $1.04 per Mcfe for the years ended December 31, 2019, 2018 and 2017, respectively.
There were no exploratory wells drilled during 2019 and 2018, and there were no capitalized exploratory well costs for the years ended December 31, 2019, 2018 and 2017. During 2017, the Company drilled one exploratory dry hole within its non-core acreage, and the related expenditures were included in exploration expense in the Statement of Consolidated Operations for the year ended December 31, 2017.
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 has occurred, the Company compares estimated expected undiscounted future cash flows from its oil and gas properties to the carrying values of those properties. The estimated future cash flows used in the recoverability test 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.
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 5 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. There were no indicators of impairment identified in 2017.
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, 2019, 2018 and 2017, the Company recorded $556.4 million, $279.7 million and $7.6 million, respectively, for lease impairments and expirations. The Company's unproved properties had a net book value of approximately $3,322 million and $4,166 million at December 31, 2019 and 2018, respectively.
Goodwill. Goodwill is the cost of an acquisition less the fair value of the identifiable net assets of the acquired business. At December 31, 2018, the Company had no goodwill. At November 30, 2018, prior to the completion of the 2018 annual goodwill impairment test, the Company's goodwill balance was $530.8 million.
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 to generate near-term free cash flow.
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.
Intangible Assets. The Company's intangible assets were recorded under the acquisition method of accounting at their estimated fair values at the Rice Merger (defined in Note 8) acquisition date. The Company's intangible assets are composed of non-compete agreements with former Rice Energy Inc. (Rice Energy) executives. The non-compete agreements have 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 estimated annual amortization expense for 2020 is $26.0 million.
The following table summarizes the Company's intangible assets.
| December 31, | |||||||
| 2019 | 2018 | ||||||
| (Thousands) | |||||||
| Non-compete agreements | $ | 124,100 | $ | 124,100 | |||
| Less: Accumulated amortization | 82,683 | 46,767 | |||||
| Less: Impairment of intangible assets (a) | 15,411 | — | |||||
| Intangible assets, net | $ | 26,006 | $ | 77,333 |
| (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. |
Derivative Instruments. See Note 4 for further discussion of the Company's derivative instruments.
Other Current Liabilities. The following table summarizes the Company's other current liabilities.
| December 31, | |||||||
| 2019 | 2018 | ||||||
| (Thousands) | |||||||
| Taxes other than income | $ | 57,850 | $ | 75,978 | |||
| Accrued interest payable | 36,590 | 42,998 | |||||
| Current portion of operating lease liability | 29,036 | — | |||||
| Incentive compensation | 18,573 | 46,937 | |||||
| Severance accrual | 11,769 | 8,893 | |||||
| Legal reserve | 3,000 | 53,500 | |||||
| Other accrued liabilities | 63,746 | 26,381 | |||||
| Total other current liabilities | $ | 220,564 | $ | 254,687 |
Revenue Recognition. For information on revenue recognition from contracts with customers and gains and losses on derivative commodity instruments see Notes 3 and 4, respectively.
Unamortized Debt Discount and Issuance Expense. Discounts and expenses incurred with the issuance of debt are amortized on a straight-line basis over the term of the debt. These amounts are presented as a reduction of senior notes in the Consolidated Balance Sheets. See Note 10.
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.
Income Taxes. The Company files a consolidated 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.
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.
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. Purchases of treasury shares are calculated using the average share price of EQT common stock during the period.
The Company reported a net loss for the years ended December 31, 2019 and 2018; therefore, all options and restricted stock were excluded from the calculation of diluted weighted average shares outstanding because of their anti-dilutive effect on EPS. Restricted stock and performance awards excluded from the calculation due to their anti-dilutive effect on EPS totaled 184,075 and 234,149 for the years ended December 31, 2019 and 2018, respectively. Options to purchase common stock that were excluded from potentially dilutive securities because they were anti-dilutive were 2,554,729 and 1,775,249 for the years ended December 31, 2019 and 2018, respectively. Potentially dilutive securities (options and restricted stock) included in the calculation of diluted EPS totaled 346,528 shares for the year ended December 31, 2017. Options to purchase common stock excluded from potentially dilutive securities because they were anti-dilutive totaled 429,785 shares for the year ended December 31, 2017.
Asset Retirement Obligations. The Company accrues a liability for asset retirement obligations based on an estimate of the timing and amount of settlement. For oil and gas wells, the fair value of the Company's plugging and abandonment obligations is recorded at the time the obligations are incurred, which is typically at the time the wells are 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, | |||||||
| 2019 | 2018 | ||||||
| (Thousands) | |||||||
| Balance at January 1 | $ | 287,805 | $ | 443,349 | |||
| Accretion expense | 13,733 | 17,513 | |||||
| Liabilities incurred | 8,985 | 7,785 | |||||
| Liabilities settled | (3,569 | ) | (3,722 | ) | |||
| Liabilities assumed in the Rice Merger | — | 27,999 | |||||
| Liabilities removed due to divestitures | (5,535 | ) | (231,936 | ) | |||
| Change in estimates | 160,402 | 26,817 | |||||
| Balance at December 31 | $ | 461,821 | $ | 287,805 |
The Company does not have any assets that are legally restricted for purposes of settling these obligations. During 2019 and 2018, the Company had changes in estimates for the plugging of horizontal and conventional wells that were related primarily to 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.
Self-Insurance. The Company is self-insured for certain losses related to workers' compensation and maintains a self-insured retention for general liability, automobile liability, environmental liability and other casualty coverage. The Company maintains stop loss coverage with third-party insurers to limit the total exposure for general liability, automobile liability, environmental liability and workers' compensation. 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.
Other Postretirement Benefits Plan. The Company sponsors a plan for postretirement benefits plan. The Company recognized expense related to its defined contribution plan of $8.9 million, $17.3 million and $16.6 million for the years ended December 31, 2019, 2018 and 2017, respectively.
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 2.
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, | |||||||||||
| 2019 | 2018 | 2017 | |||||||||
| (Thousands) | |||||||||||
| Cash paid (received) during the year for: | |||||||||||
| Interest, net of amount capitalized | $ | 198,562 | $ | 260,959 | $ | 189,371 | |||||
| Income taxes, net | (1,710 | ) | (3,675 | ) | 3,637 | ||||||
| Non-cash activity during the period for: | |||||||||||
| Changes in property, plant and equipment accruals | $ | 170,848 | $ | (274,219 | ) | $ | 4,439 | ||||
| Increase in asset retirement costs and obligations | 169,387 | 34,602 | 143,578 | ||||||||
| Increase in right-of-use lease assets and liabilities | 113,350 | — | — | ||||||||
| Capitalization of non-cash equity share-based compensation | — | 4,314 | 8,993 | ||||||||
| Assumption of net liabilities from current period acquisitions | — | — | 10,004 | ||||||||
| Measurement period adjustments for prior period acquisitions | — | 14,377 | (14,315 | ) | |||||||
| Increase in capital contributions payable to Mountain Valley Pipeline, LLC | — | 176,551 | 94,263 |
Recently Issued Accounting Standards
In February 2016, the Financial Accounting Standards Board (FASB) issued ASU 2016-02, Leases. The standard requires entities to record assets and liabilities that arise from operating leases. In July 2018, the FASB issued ASU 2018-11, Leases: Targeted Improvements, which provided an optional transition method of adoption that permitted entities to recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Under the optional transition method, comparative financial information and disclosures are not required. The update also provided transition practical expedients. The standard requires disclosure of the nature, maturity and value of an entity's lease liabilities and elections made by the entity. In March 2019, the FASB issued ASU 2019-01, Leases: Codification Improvements, which, among other things, clarified interim disclosure requirements in the year of ASU 2016-02 adoption.
The Company adopted ASU 2016-02, ASU 2018-11 and ASU 2019-01 on January 1, 2019 using the optional transition method of adoption. The Company implemented a new lease accounting system to monitor its population of lease contracts. The Company also implemented processes and controls to review both new contracts and modifications to existing contracts that contain or are leases for appropriate accounting treatment and generate disclosures required under the standards. For the disclosures required by the standards, see Note 15.
In June 2016, the 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 will be effective for annual reporting periods beginning after December 15, 2019, including interim periods within that reporting period. The Company plans to adopt this ASU in the first quarter of 2020 and expects this adoption to have no impact on its financial statements. The Company is evaluating the impact this standard will have on its related disclosures.
In February 2018, the FASB issued ASU 2018-02, Income Statement – Reporting Comprehensive Income: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. This ASU allows entities to reclassify stranded tax effects resulting from the Tax Cuts and Jobs Act of 2017 (the Tax Cuts and Jobs Act) from accumulated OCI to retained earnings. This ASU is effective for fiscal years beginning after December 15, 2018 and early adoption is permitted. The reclassification permitted under this ASU should be applied either in the period of adoption or retrospectively to each period or periods in which the effect of the change in the U.S. federal corporate income tax rate from the Tax Cuts and Jobs Act is recognized. The Company adopted this ASU on January 1, 2019 and reclassified the income tax effects of the Tax Cuts and Jobs Act of $0.5 million from accumulated OCI to retained earnings.
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 guidance is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, and early adoption is permitted. The Company plans to adopt this ASU in the first quarter of 2020 and does not expect this adoption to have a material impact on its financial statements and related disclosures.
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 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. The new guidance also simplifies aspects of accounting for franchise taxes and interim period effects of enacted changes in tax laws or rates. The new guidance 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 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**.** 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 18 for a discussion of events occurring subsequent to December 31, 2019 that will, among other things, affect the Company's ownership of Equitrans Midstream.
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 EQM Midstream Partners, LP (EQM) 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 Statements of Consolidated Operations for the years ended December 31, 2018 and 2017 have 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 Statements of Consolidated Cash Flows for all periods 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 Rice Merger (see Note 8) to discontinued operations.
| January 1, 2018 to November 12, 2018 | Year Ended December 31, 2017 | ||||||
| (Thousands) | |||||||
| Operating revenues | $ | 388,854 | $ | 279,422 | |||
| Transportation and processing | (803,858 | ) | (604,025 | ) | |||
| Operation and maintenance | 99,671 | 80,833 | |||||
| Selling, general and administrative | 62,702 | 53,275 | |||||
| Depreciation | 160,701 | 106,574 | |||||
| Impairment of goodwill (a) | 267,878 | — | |||||
| Transaction costs | 93,062 | 85,124 | |||||
| Amortization of intangible assets | 36,007 | 5,540 | |||||
| Other income | 51,014 | 26,610 | |||||
| Interest expense | 88,300 | 34,801 | |||||
| Income from discontinued operations before income taxes | 435,405 | 543,910 | |||||
| Income tax expense | 61,643 | 72,797 | |||||
| Income from discontinued operations after income taxes | 373,762 | 471,113 | |||||
| Less: Net income from discontinued operations attributable to noncontrolling interests | 237,410 | 349,613 | |||||
| Net income from discontinued operations | $ | 136,352 | $ | 121,500 |
| (a) | Following the third quarter of 2018, and prior to the Separation and Distribution, indicators of goodwill impairment were identified in the form of the 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 Statements of Consolidated Cash Flows for the years ended December 31, 2018 and 2017.
| January 1, 2018 to November 12, 2018 | Year Ended December 31, 2017 | ||||||
| (Thousands) | |||||||
| Cash flows from operating activities: | |||||||
| Deferred income tax (benefit) expense | $ | (373,405 | ) | $ | 43,471 | ||
| Depreciation | 160,701 | 106,574 | |||||
| Amortization of intangibles | 36,007 | 5,540 | |||||
| Impairment of goodwill | 267,878 | — | |||||
| Other income | (51,450 | ) | (27,281 | ) | |||
| Share-based compensation expense | 1,841 | 468 | |||||
| Cash flows from investing activities: | |||||||
| Capital expenditures | (732,727 | ) | (380,151 | ) | |||
| Capital contributions to Mountain Valley Pipeline, LLC (a) | (820,943 | ) | (159,550 | ) | |||
| Cash flows from financing activities: | |||||||
| Proceeds from issuance of debt | 2,500,000 | — | |||||
| Increase in borrowings on credit facilities | 3,378,500 | 544,084 | |||||
| Repayment of borrowings on credit facilities | (3,219,500 | ) | (344,000 | ) | |||
| Debt issuance costs and credit facility origination fees | (40,966 | ) | (2,257 | ) | |||
| Distributions to noncontrolling interests | (380,651 | ) | (236,123 | ) | |||
| Contribution to Strike Force Midstream LLC by minority owner, net of distribution | — | 6,738 | |||||
| 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. |
3**.** Revenue from Contracts with Customers
Under the Company's natural gas, 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 are 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 excluding revenue interests owned by others. When selling natural gas, NGLs and oil on behalf of royalty owners 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 recognized amounts due from contracts with customers of $384.0 million and $783.0 million in accounts receivable in the Consolidated Balance Sheets as of December 31, 2019 and 2018,
respectively. Accounts receivable also includes amounts due from joint interest partners of $127.9 million and $324.2 million at December 31, 2019 and 2018, respectively, and amounts due for settled derivative instruments.
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, | |||||||
| 2019 | 2018 | ||||||
| (Thousands) | |||||||
| Revenues from contracts with customers: | |||||||
| Natural gas sales | $ | 3,559,809 | $ | 4,217,684 | |||
| NGLs sales | 197,985 | 442,010 | |||||
| Oil sales | 33,620 | 35,825 | |||||
| Net marketing services and other | — | 13,865 | |||||
| Total revenues from contracts with customers | 3,791,414 | 4,709,384 | |||||
| Other sources of revenue: | |||||||
| Net marketing services and other | 8,436 | 27,075 | |||||
| Gain (loss) on derivatives not designated as hedges | 616,634 | (178,591 | ) | ||||
| Total operating revenues | $ | 4,416,484 | $ | 4,557,868 |
The following table includes the transaction price allocated to the Company's remaining performance obligations on all contracts with fixed consideration as of December 31, 2019 and excludes all contracts that qualify for the exception to the relative standalone selling price method.
| 2020 | 2021 | Total | |||||||||
| (Thousands) | |||||||||||
| Natural gas sales | $ | 57,741 | $ | 21,387 | $ | 79,128 |
4**.** 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 Company's overall objective in its hedging program is to protect cash flows from undue exposure to the risk of changing commodity prices.
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 implementing 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 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, which are generally settled with offsetting positions. Settlements of derivative commodity instruments are reported as a component of cash flows from operations 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 1,644 billion cubic feet (Bcf) of natural gas as of December 31, 2019 and 3,128 Bcf of natural gas and 1,505 thousand barrels (Mbbl) of NGLs as of December 31, 2018. The open positions at both December 31, 2019 and 2018 had maturities extending through December 2024.
When the net fair value of any of the Company's swap agreements represents a liability to the Company that is in excess of the agreed-upon threshold between the Company and the counterparty, 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 threshold amount. The Company records these deposits as a current asset. When the net fair value of any of the Company's swap agreements represents an asset to the Company that is in excess of the agreed-upon threshold between the Company and the counterparty, 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 threshold amount. The Company records a current liability for such amounts received. The Company had no such deposits in its Consolidated Balance Sheets at both December 31, 2019 and 2018.
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 must 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. When the fair value of such contracts is in a net asset position, the broker may remit funds to the Company. The Company records a current liability for any such amounts received. 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. The Company recorded current assets of $12.6 million and $40.3 million in its Consolidated Balance Sheets as of December 31, 2019 and 2018, respectively, for such deposits.
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 reflects 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 deposits remitted to counterparties | Net derivative instruments | ||||||||||||
| December 31, 2019 | (Thousands) | ||||||||||||||
| 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 | |||||||||
| December 31, 2018 | |||||||||||||||
| Asset derivative instruments at fair value | $ | 481,654 | $ | (256,087 | ) | $ | — | $ | 225,567 | ||||||
| Liability derivative instruments at fair value | 336,051 | (256,087 | ) | (40,283 | ) | 39,681 |
Certain of the Company's OTC derivative instrument contracts provide that, if the Company's credit ratings assigned by Moody's Investors Service, Inc. (Moody's) or S&P Global Ratings (S&P) is below investment grade, additional collateral must be deposited with the counterparty if the associated derivative liability exceeds certain thresholds. The additional 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, 2019, the Company's senior notes were rated "Baa3" by Moody's and "BBB–" by S&P. Margin deposits on the Company's derivative instruments are also subject to factors other than credit rating, such as natural gas prices and credit thresholds set forth in the agreements between hedging counterparties and the Company. As of December 31, 2019, the aggregate fair value of all OTC derivative instruments with credit risk-related contingent features that were in a net liability position was $76.7 million, for which the Company had no collateral posted. If the Company's credit rating assigned by Moody's or S&P had been downgraded
as of December 31, 2019, the Company would not have been required to post any additional collateral under its OTC derivative instrument contracts.
In January 2020, Moody's downgraded the Company's senior notes credit rating to "Ba1," and, in February 2020, S&P downgraded the Company's senior notes credit rating to "BB+"; however, as of February 26, 2020, the changes in Moody's and S&P's credit rating of the Company's senior notes had no effect on margin deposits on the Company's derivative instruments. See Note 10 for a discussion of the effects of the Moody's and S&P downgrades on the Company's collateral requirements under its midstream service contracts.
The Company has not executed any interest rate swaps since 2011. Amounts related to historical interest rate swaps were recorded to accumulated OCI and have been fully reclassified into interest expense as of December 31, 2019. See Note 12.
5**.** Fair Value Measurements
The Company records its financial instruments, principally derivative instruments, at fair value in its Consolidated Balance Sheets. The Company estimates the fair value of its financial instruments using quoted market prices, where available. If quoted market prices are not available, fair value is based on models that use market-based parameters as inputs, including forward curves, discount rates, volatilities and nonperformance risk. 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 in Level 2 primarily include the Company's swap, collar and option agreements.
Exchange traded commodity swaps are included in Level 1. The fair value of the commodity swaps included in Level 2 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, 2019 | (Thousands) | ||||||||||||||
| Asset derivative instruments at fair value | $ | 812,664 | $ | 95,041 | $ | 717,623 | $ | — | |||||||
| Liability derivative instruments at fair value | 312,696 | 71,107 | 241,589 | — | |||||||||||
| December 31, 2018 | |||||||||||||||
| Asset derivative instruments at fair value | $ | 481,654 | $ | 112,107 | $ | 369,547 | $ | — | |||||||
| Liability derivative instruments at fair value | 336,051 | 126,582 | 209,469 | — |
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 under the Company's credit facility and Term Loan Facility 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 for which the Company recognized a cumulative effect of accounting change 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.
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, the fair value of the senior notes is a Level 2 fair value measurement. As of December 31, 2019 and 2018, the Company's senior notes had a fair value of approximately $3.9 billion and $4.4 billion, respectively, and a carrying value, as presented in the Consolidated Balance Sheets, of approximately $3.9 billion and $4.6 billion, respectively, inclusive of any current portion. The fair value of the Company's note payable to 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, 2019 and 2018, the Company's note payable to EQM had a fair value of $128.2 million and $121.8 million, respectively, and a carrying value, as presented in the Consolidated Balance Sheets of $110.1 million and $114.7 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 for 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 information on the fair values related to the Asset Exchange Transaction (defined in Note 6), see Note 6. For information on the fair values of assets acquired in the Rice Merger (defined in Note 8) and in other acquisition transactions, see Note 8.
6**.** 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 (Asset Exchange Transaction), pursuant to which the Company exchanged approximately 16,000 net revenue interest acres primarily in Tyler and Wetzel Counties, West Virginia for 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 covering a portion of Tyler County and provided a firm gathering commitment, and the Company was released from its remaining obligations under the 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. During the third quarter of 2019, as a result of the Asset Exchange Transaction, the Company recorded 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, 2019, the liability for the reimbursement of certain firm gathering costs was $38.1 million, which is included in other current liabilities and other liabilities and credits in the Consolidated Balance Sheet.
The fair values of leases acquired and the liability for the reimbursement of certain firm gathering costs were 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 5 for a description of the fair value hierarchy. Key assumptions included in the calculation of fair values included market-based prices for comparable acreage and a calculation of net present value of the expected payments due for reimbursement.
7**.** Divestitures
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 5 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 5 for a description of the fair value hierarchy.
8**.** Rice Merger and Other Acquisitions
Rice Merger
On November 13, 2017, the Company completed its acquisition of Rice Energy (the Rice Merger). Total consideration for the Rice Merger was approximately $7.8 billion, consisting of approximately 91 million shares of EQT common stock and approximately $1.6 billion in cash, net of cash acquired and inclusive of amounts payable to Rice Energy employees for severance and other termination benefits and $555.5 million of aggregate cash payments made to affiliates of EIG Global Energy Partners to redeem the EIG Global Energy Partners' respective interests in Rice Midstream Holdings LLC (Rice Midstream Holdings) and Rice Midstream GP Holdings, LP. The Company accounted for the Rice Merger as a business combination using the acquisition method.
The fair value assigned to liabilities assumed was approximately $3.9 billion and was related primarily to long-term debt. In connection with the closing of the Rice Merger, the Company repaid $508.5 million of outstanding principal and $1.7 million of interest and fees under Rice Energy's credit facilities, and the credit agreements were terminated. In addition, in connection with Rice Energy's redemption and cancellation of its outstanding senior notes, the Company paid an aggregate $1.4 billion, including make whole call premiums of $63.8 million and interest payments of $13.4 million.
The fair value assigned to assets acquired was approximately $9.7 billion and was related primarily to acquired net property, plant and equipment, which included approximately 205,000 net Marcellus acres, approximately 65,000 net Ohio Utica acres and Upper Devonian and Utica drilling rights in Pennsylvania. In addition, the Company identified intangible assets associated with non-compete agreements for former Rice Energy executives. In 2019, the Company recognized impairment of these intangible assets. See Note 1.
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 estimates of recoverable reserves, production rates, future operating and development costs, future commodity prices and market-based weighted average cost of capital. The fair value of undeveloped property was based on a market approach of comparable transactions using Level 3 inputs. The fair value of the identified intangible assets was determined using the income approach based on inputs that are not observable in the market and, as such, are considered Level 3 fair value measurements. Significant unobservable inputs include estimates of future production levels, future revenues, future costs, the probability that former executives would compete in the absence of such non-compete agreements and customer retention rates.
The Company recorded approximately $2.0 billion in goodwill as a result of the Rice Merger. During the year ended December 31, 2018, the Company recorded impairment of goodwill of $0.5 billion from continuing operations and $0.3 billion for discontinued operations and allocated $1.2 billion of goodwill to discontinued operations, including $387.1 million in unamortized carryover tax basis of tax-deductible goodwill. See Note 1 for a discussion of the 2018 goodwill impairment test.
For the year ended December 31, 2018 and 2017, the Company recorded transaction costs related to the Rice Merger of $25.4 million and $152.2 million, respectively, from continuing operations and $13.5 million and $85.1 million, respectively, from discontinued operations. For the year ended December 31, 2017, the Company recorded debt issuance costs related to the Rice Merger of $5.1 million from continuing operations and $2.9 million discontinued operations.
Other 2017 Acquisitions
In addition to the Rice Merger, the Company completed other acquisitions with third parties during the year ended December 31, 2017, through which the Company acquired, in the aggregate, approximately 158,500 net Marcellus acres, located primarily in West Virginia, and drilling rights on Ohio Utica acres.
In 2017, the Company paid, in the aggregate, net cash of $740.1 million in connection with the other 2017 acquisitions. The fair value assigned, in the aggregate, to the acquired property, plant and equipment was $750.1 million. In connection with the other 2017 acquisitions, the Company assumed $5.3 million of net current liabilities and $4.7 million of non-current liabilities.
In 2017, as a result of post-closing adjustments on acquisitions completed in 2016, the Company paid $78.9 million for additional undeveloped acreage and recorded $14.3 million in other non-cash adjustments, which reduced the fair value assigned to the acquired property, plant and equipment.
The Company accounted for the other 2017 acquisitions as business combinations using the acquisition method. The fair value of undeveloped property was based on a market approach of comparable transactions using Level 3 inputs.
9**.** Income Taxes
The following table summarizes income tax (benefit) expense.
| Years Ended December 31, | |||||||||||
| 2019 | 2018 | 2017 | |||||||||
| (Thousands) | |||||||||||
| Current: | |||||||||||
| Federal | $ | (106,487 | ) | $ | (513,293 | ) | $ | (89,149 | ) | ||
| State | 5,774 | (46,218 | ) | (5,184 | ) | ||||||
| Subtotal | (100,713 | ) | (559,511 | ) | (94,333 | ) | |||||
| Deferred: | |||||||||||
| Federal | (213,397 | ) | 20,496 | (1,039,769 | ) | ||||||
| State | (61,666 | ) | (157,496 | ) | (54,314 | ) | |||||
| Subtotal | (275,063 | ) | (137,000 | ) | (1,094,083 | ) | |||||
| Total income tax benefit | $ | (375,776 | ) | $ | (696,511 | ) | $ | (1,188,416 | ) |
For the year ended December 31, 2019, the current federal income tax benefit consisted primarily of expected refunds of $120 million related to the Company's alternative minimum tax (AMT) credit carryforward and the Tax Cuts and Jobs Act. For the year ended December 31, 2018, the current 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. For the year ended December 31, 2017, the current federal income tax benefit consisted primarily of expected refunds of $65 million related to amended returns the Company had filed to carryback federal and AMT net operating losses (NOLs) that were generated in 2017 and 2016. The remaining current tax benefit of $435 million and $29 million for the years ended December 31, 2018 and 2017, respectively, 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. As a result of the change in the corporate tax rate the Company recorded a deferred tax benefit of $1.2 billion during the year ended December 31, 2017 to revalue its existing net deferred tax liabilities to the lower rate.
The Company applied the guidance in SAB 118 when accounting for the enactment-date effects of the Tax Cuts and Jobs Act in 2017 and throughout 2018. At December 31, 2017, the Company had not completed the accounting for all the enactment-date income tax effects of the legislation under Accounting Standards Codification (ASC) 740, Income Taxes, for the following aspects: remeasurement of deferred tax assets and liabilities and incentive-based compensation limitations. During 2018, the Company completed the accounting for all the enactment-date income tax effects of the Tax Cuts and Jobs Act and recognized adjustments of $5.3 million to the provisional amounts recorded at December 31, 2017. These adjustments were included as a component of income tax expense from continuing operations. The additional expense was primarily a result of adjustments to the increased limitations on deductible executive compensation.
The Tax Cuts and Jobs Act preserved deductibility of intangible drilling costs (IDCs) for 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 then 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 in tax years 2018 through 2020. In addition, 50% of any unused AMT credit carryforwards can be refunded during these years with any remaining AMT credit carryforward being fully refunded in 2021. 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.
As of December 31, 2019, the Company had current income tax receivable of $299 million, which consisted of refunds of AMT credits of $95 million and $190 million for 2019 and 2018, respectively, and $14 million in state taxes previously paid related to the Company's 2018 tax return. The Company expects to receive $95 million in refunds of AMT in 2020 and 2021.
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.
The Company has federal NOL 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.
Income tax benefit from continuing operations differed from amounts computed at the federal statutory rate of 21% for 2019 and 2018 and 35% for 2017 on pre-tax income for reasons summarized below.
| Years Ended December 31, | |||||||||||
| 2019 | 2018 | 2017 | |||||||||
| (Thousands) | |||||||||||
| Tax at statutory rate | $ | (335,469 | ) | $ | (646,261 | ) | $ | 69,515 | |||
| Federal tax law change | — | 5,288 | (1,205,140 | ) | |||||||
| State income taxes | (119,659 | ) | (251,780 | ) | (57,414 | ) | |||||
| Valuation allowance | 70,875 | 88,785 | 10,680 | ||||||||
| Regulatory liability/asset | — | (276 | ) | 10,488 | |||||||
| Federal tax credits | (7,908 | ) | (2,400 | ) | (34,956 | ) | |||||
| Goodwill impairment | — | 111,470 | — | ||||||||
| Other | 16,385 | (1,337 | ) | 18,411 | |||||||
| Income tax benefit | $ | (375,776 | ) | $ | (696,511 | ) | $ | (1,188,416 | ) | ||
| Effective tax rate | 23.5 | % | 22.6 | % | (598.4 | )% |
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's effective tax rate for the year ended December 31, 2017 was lower compared to the U.S. federal statutory rate due primarily to the effect of the Tax Cuts and Jobs Act on the Company's net deferred tax liability, which was remeasured at the updated corporate tax rate of 21%. The effective tax rate was also lower compared to the U.S. federal statutory rate due to an increase in federal tax credits generated during 2017 as a result of $30.2 million of federal marginal well tax credits. The IRS notice supporting the calculation of the credit was not published until 2017 and, absent the IRS notice, the Company was unable to estimate the amount of this credit in 2016. As a result, $6.1 million of this credit recorded in 2017 related to 2016 activity.
For the year ended December 31, 2017, the Company realized $10.5 million of tax expense associated with Federal Energy Regulatory Commission (FERC) regulated assets as a result of the corporate tax rate reduction from the Tax Cuts and Jobs Act. Following the normalization rules of the Internal Revenue Code (IRC), this regulatory liability is amortized on a straight-line basis over the estimated remaining life of the related assets. This regulatory liability was transferred to Equitrans Midstream in connection with the Separation and Distribution and was included in discontinued operations.
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, 2019, 2018 and 2017, 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 valuation allowance against a deferred tax asset related to the interest expense limitation for separate company state income tax purposes and 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 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.
| 2019 | 2018 | 2017 | |||||||||
| (Thousands) | |||||||||||
| Balance at January 1 | $ | 315,279 | $ | 301,558 | $ | 252,434 | |||||
| Additions for tax positions taken in current year | 19,431 | 8,459 | 50,469 | ||||||||
| Additions for tax positions taken in prior years | 8,929 | 14,396 | 8,978 | ||||||||
| Reductions for tax positions taken in prior years | (84,051 | ) | (9,134 | ) | (10,323 | ) | |||||
| Balance at December 31 | $ | 259,588 | $ | 315,279 | $ | 301,558 |
Included in the balances above are unrecognized tax benefits of $150.9 million, $124.6 million and $120.5 million that, if recognized, would affect the effective tax rates as of December 31, 2019, 2018 and 2017, respectively. Also included in the balances above are uncertain tax positions of $113.7 million, $88.2 million, and $84.1 million for the years ended December 31, 2019, 2018 and 2017, respectively, that were recorded in the Consolidated Balance Sheets as a reduction of the related deferred tax asset for AMT and general business credit carryforwards and NOLs. The Company released $84 million of reserves and reinstated the related deferred tax asset for AMT during 2019 due to settlement of the 2013 amended return refund claim with the IRS. The state deferred tax asset was reduced for uncertain tax positions of approximately $0.3 million during the year ended December 31, 2017.
Included in the balances above are $0.7 million, $0.7 million and $4.7 million, as of December 31, 2019, 2018 and 2017, 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 of approximately $3.3 million, $3.4 million and $3.2 million for 2019, 2018 and 2017, respectively. Interest and penalties of $15.2 million, $11.9 million and $8.4 million were included in the Consolidated Balance Sheets at December 31, 2019, 2018 and 2017, respectively.
As of December 31, 2019, 2018 and 2017, 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 $80.2 million, $33.3 million and $42.5 million, respectively, in unrecognized tax benefits related to federal tax positions may be necessary within twelve months.
The consolidated federal income tax liability of the Company has been settled with the IRS through 2009. The IRS has completed its review of the 2010, 2011 and 2012 tax years, and the Company is in the process of appealing its Research & Experimentation
(R&E) tax credit claim for such years. In addition, the Company has filed refund claims related to R&E and AMT preference adjustments for 2010 through 2013. The Company is under IRS audit for 2013 and agreed to a settlement related to a 2013 amended return refund claim in the fourth quarter of 2019. The Company is also the subject of various state income tax examinations. With few exceptions, as of December 31, 2019, the Company is no longer subject to state examinations by tax authorities for years before 2012.
There were no material changes to the Company's methodology for accounting for unrecognized tax benefits during 2019.
The following table summarizes the source and tax effects of temporary differences between financial reporting and tax bases of assets and liabilities.
| December 31, | |||||||
| 2019 | 2018 | ||||||
| (Thousands) | |||||||
| Deferred income taxes: | |||||||
| Total deferred income tax assets | $ | (643,227 | ) | $ | (549,969 | ) | |
| Total deferred income tax liabilities | 2,129,041 | 2,373,350 | |||||
| Total net deferred income tax liabilities | 1,485,814 | 1,823,381 | |||||
| Total deferred income tax liabilities (assets): | |||||||
| Drilling and development costs expensed for income tax reporting | 1,100,061 | 1,469,320 | |||||
| Tax depreciation in excess of book depreciation | 974,520 | 904,030 | |||||
| Investment in Equitrans Midstream | (109,883 | ) | (10,359 | ) | |||
| Incentive compensation and deferred compensation plans | (16,923 | ) | (24,682 | ) | |||
| Net operating loss carryforwards | (635,446 | ) | (429,983 | ) | |||
| Alternative minimum tax credit carryforward | (190,992 | ) | (308,727 | ) | |||
| Federal tax credits | (59,854 | ) | (37,710 | ) | |||
| Unrealized gains (losses) | 54,460 | (28,096 | ) | ||||
| Interest disallowance limitation | (46,776 | ) | (35,358 | ) | |||
| Other | (6,797 | ) | (26,462 | ) | |||
| Total excluding valuation allowances | 1,062,370 | 1,471,973 | |||||
| Valuation allowances | 423,444 | 351,408 | |||||
| Total net deferred income tax liabilities | $ | 1,485,814 | $ | 1,823,381 |
During 2019, net deferred tax liability decreased $337.6 million from 2018 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, 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 NOL 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 the retained stake of Equitrans Midstream of $42.4 million for separate company state income tax reporting purposes and $8.3 million for federal.
As of December 31, 2018, the Company had a deferred tax asset of $32.9 million, net of valuation allowances of $22.8 million, related to tax benefits from federal NOL carryforwards expiring in 2037 to 2038. As of December 31, 2018, the Company had a deferred tax asset of $94.7 million, net of valuation allowances of $279.5 million, related to tax benefits from state NOL
carryforwards with various expiration dates ranging from 2020 to 2037. In October 2017, Pennsylvania enacted a change in the limitation on Pennsylvania NOL utilization from 30% of taxable income to 35% of taxable income for tax years beginning in 2018 and 40% of taxable income for tax years beginning in 2019 and thereafter. However, due to the decrease in state apportionment rates, the Company will have less realizable NOL in future years. Additionally, the Tax Cuts and Jobs Act interest deduction limitation imposed for separate company state income tax reporting purposes resulted in a valuation allowance of $21.7 million. The Company also recorded a valuation allowance on the retained stake of Equitrans Midstream of $14 million for separate company state income tax reporting purposes. The Company reduced the valuation allowance on expected AMT credit refunds subject to federal sequestration to $13.3 million as a result of a change in estimate for the period ended December 31, 2018. 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, the Company reversed the related valuation allowance in the first quarter of 2019.
As of December 31, 2017, the Company had a deferred tax asset of $130 million, net of valuation allowances of $217.0 million, related to tax benefits from state NOL carryforwards with various expiration dates ranging from 2028 to 2038.
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, 2019 | December 31, 2018 | ||||||||||||||||||||||
| Principal Value | Carrying Value (a) | Fair Value (b) | Principal Value | Carrying Value (a) | Fair Value (b) | ||||||||||||||||||
| (Thousands) | |||||||||||||||||||||||
| Term Loan Facility due May 31, 2021 | $ | 1,000,000 | $ | 999,353 | $ | 999,353 | $ | — | $ | — | $ | — | |||||||||||
| Senior notes: | |||||||||||||||||||||||
| 8.125% notes due June 1, 2019 | — | — | — | 700,000 | 699,729 | 712,663 | |||||||||||||||||
| Floating rate notes due October 1, 2020 | 500,000 | 499,238 | 500,290 | 500,000 | 498,222 | 490,730 | |||||||||||||||||
| 2.50% notes due October 1, 2020 | 500,000 | 499,228 | 500,950 | 500,000 | 498,198 | 489,690 | |||||||||||||||||
| 8.81% to 9.00% series A due 2020 – 2021 | 35,200 | 35,200 | 37,380 | 35,200 | 35,200 | 37,920 | |||||||||||||||||
| 4.875% notes due November 15, 2021 | 750,000 | 747,571 | 774,173 | 750,000 | 746,245 | 762,555 | |||||||||||||||||
| 3.00% notes due October 1, 2022 | 750,000 | 745,579 | 737,025 | 750,000 | 743,972 | 712,980 | |||||||||||||||||
| 7.42% series B due 2023 | 10,000 | 10,000 | 10,788 | 10,000 | 10,000 | 10,666 | |||||||||||||||||
| 7.75% debentures due July 15, 2026 | 115,000 | 111,727 | 129,466 | 115,000 | 111,229 | 128,808 | |||||||||||||||||
| 3.90% notes due October 1, 2027 | 1,250,000 | 1,241,024 | 1,167,763 | 1,250,000 | 1,239,866 | 1,085,663 | |||||||||||||||||
| Note payable to EQM | 110,059 | 110,059 | 128,241 | 114,720 | 114,720 | 121,752 | |||||||||||||||||
| Total debt | 5,020,259 | 4,998,979 | 4,985,429 | 4,724,920 | 4,697,381 | 4,553,427 | |||||||||||||||||
| Less: Current portion of debt (c) | 16,204 | 16,204 | 17,436 | 704,661 | 704,390 | 717,609 | |||||||||||||||||
| Long-term debt | $ | 5,004,055 | $ | 4,982,775 | $ | 4,967,993 | $ | 4,020,259 | $ | 3,992,991 | $ | 3,835,818 |
| (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 Term Loan Facility approximates fair value as the interest rates are based on prevailing market rates; therefore, it is 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. |
| (c) | The Floating Rate notes and 2.50% notes due in 2020 were classified as long-term due to the repayment in February 2020 described below. |
Term Loan Facility. On May 31, 2019, the Company entered into a Term Loan Agreement (the Term Loan Agreement) providing for a $1.0 billion unsecured term loan facility (the Term Loan Facility) and borrowed $1.0 billion under the Term Loan Facility. The Company used the net proceeds to (i) repay $700 million aggregate principal amount of 8.125% senior notes, (ii) repay
outstanding borrowings under the Company's $2.5 billion credit facility and (iii) pay accrued interest and fees and expenses related to the foregoing and the Term Loan Agreement. Remaining proceeds from the borrowing were used by the Company for general corporate purposes.
At the Company's election, the $1.0 billion in borrowings under the Term Loan Facility bear interest at a Eurodollar rate defined in the Term Loan Agreement plus a margin based on the Company's credit ratings. The Company may voluntarily prepay borrowings under the Term Loan Facility, in whole or in part, without premium or penalty, but subject to reimbursement of funding losses with respect to prepayment. Borrowings under the Term Loan Facility that are repaid may not be reborrowed. During the year ended December 31, 2019, the Company incurred interest on Term Loan Facility borrowings at a weighted average annual interest rate of 3.1%. As a result of the Moody's, S&P and Fitch downgrades of the Company's senior notes credit rating (discussed in section "Security Ratings Events"), the margin on the Term Loan Facility borrowings increased from 1.00% as of December 31, 2019 to 1.25% as of February 26, 2020.
The Term Loan Agreement contains certain representations and warranties and various affirmative and negative covenants and events of default, including (i) a restriction on the ability of the Company or its subsidiaries to incur or permit liens on assets, subject to certain significant exceptions, (ii) the establishment of a maximum ratio of consolidated debt-to-total capital of the Company and its subsidiaries such that consolidated debt shall at no time exceed 65% of total capital, (iii) a limitation on certain fundamental changes to the Company's business, (iv) a limitation on dividends that may be issued by the Company and (v) certain restrictions related to mergers or acquisitions.
Senior Notes. As of December 31, 2019, aggregate maturities for the Company's senior notes were $1,011 million in 2020, $1,774 million in 2021, $750 million in 2022, $10 million in 2023, $0 million in 2024 and $1,365 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.
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 and $500 million aggregate principal amount of the Company's 2.50% senior notes and expects to use the remaining proceeds to repay or redeem other outstanding indebtedness. The Adjustable Rate Notes have covenants that are consistent with the Company's existing senior unsecured notes, with an additional interest rate adjustment provision that provides for adjustments to its interest rates based on credit ratings assigned by Moody's, S&P and Fitch to the Company's senior notes. As a result of the S&P and Fitch downgrades of the Company's senior notes credit rating (discussed in section "Security Ratings Events"), the interest rate on the 6.125% senior notes increased to 6.875% and the interest rate on the 7.000% senior notes increased to 7.750%.
On February 3, 2020, the Company's 2.50% senior notes and floating rate notes, each due October 1, 2020, were fully redeemed by the Company at a redemption price of 100.446% and 100%, respectively, plus accrued but unpaid interest of $4.2 million and $1.2 million, respectively. This resulted in the payment of make whole call premiums of $2.2 million related to the 2.50% senior notes.
On February 12, 2020, the Company announced its commencement of a cash tender offer (the Tender Offer) for up to $400 million aggregate principal amount of its 4.875% senior notes due 2021 (the 4.875% Notes). Consideration paid in the Tender Offer for the 4.875% Notes that are validly tendered on or prior to March 2, 2020, and accepted for purchase by the Company, will be $1,020 per $1,000 principal amount, including an early tender premium of $30 per $1,000 principal amount. The settlement date for such notes is expected to be March 4, 2020. Consideration paid in the Tender Offer for the 4.875% Notes that are validly tendered after March 2, 2020 and on or prior to March 16, 2020, and accepted for purchase by the Company, will be $990 per $1,000 principal amount. The settlement date for such notes is expected to be March 18, 2020. Payments for the 4.875% Notes purchased will also include accrued and unpaid interest from, and including, the last interest payment date on the 4.875% Notes up to, but not including, the applicable settlement date for such 4.875% Notes accepted for purchase by the Company.
Note Payable to EQM. EQM owns a preferred interest in EQT Energy Supply, LLC (EES) 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 $5.0 million in 2020, $5.2 million in 2021, $5.5 million in 2022, $5.8 million in 2023, $6.3 million in 2024 and $82.3 million thereafter.
$2.5 Billion 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 19 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. As a result of the Moody's, S&P and Fitch downgrades of the Company's senior notes credit rating (discussed in section "Security Ratings Events"), the margin on base rate loans increased from 0.50% as of December 31, 2019 to 0.75% as of February 26, 2020 and the margin on Eurodollar rate loans increased from 1.50% as of December 31, 2019 to 1.75% as of February 26, 2020.
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, 2019, the Company was in compliance with all debt provisions and covenants.
The Company had $0.3 billion and $0.8 billion of borrowings outstanding under its credit facility as of December 31, 2019 and 2018, respectively. The Company had no letters of credit outstanding under its credit facility as of both December 31, 2019 and 2018. For each of the years ended December 31, 2019, 2018 and 2017, the Company incurred commitment fees of approximately 20 basis points on the undrawn portion of its credit facility to maintain credit availability. As of December 31, 2019, the Company had approximately $2.2 billion available under its credit facility.
For the years ended December 31, 2019, 2018 and 2017, the maximum amount of outstanding borrowings at any time under the credit facility was $1.1 billion, $1.6 billion and $1.4 billion, respectively, the average daily balance was approximately $340 million, $854 million and $191 million, respectively, and interest was incurred at weighted average annual interest rates of 3.8%, 3.4% and 2.8%, respectively.
Security Ratings Events. As of December 31, 2019, the Company's senior notes were rated "Baa3" by Moody's, "BBB–" by S&P and "BBB–" by Fitch. In January 2020, Moody's downgraded the Company's senior notes credit rating to "Ba1," and, in February 2020, S&P and Fitch downgraded the Company's senior notes rating to "BB+" and "BB," respectively. As a result, certain of the Company's counterparties to its midstream services contracts requested additional assurances. As of February 26, 2020, these assurances were $0.6 billion in the aggregate, for which amount the Company posted letters of credit issued under its credit facility. The letters of credit do not increase the Company's total debt but instead represent a decrease to the Company's available borrowing capacity under the credit facility. In addition, the letters of credit are subject to a letters of credit fee based on the Company's credit ratings and a fronting fee.
As of February 26, 2020, the Company had sufficient unused borrowing capacity under its credit facility, net of letters of credit, to satisfy any requests for margin deposit or other collateral that its counterparties would be permitted to request of the Company pursuant to the Company's derivative instruments and midstream services contracts in the event that Moody's and S&P downgrade the Company's credit rating two categories further. As of February 26, 2020, such margin deposit or other collateral amounts could be up to approximately $1.4 billion, inclusive of assurances posted.
11**.** Common Stock
Shares of authorized and unissued EQT Common Stock were reserved as follows.
| December 31, 2019 | ||
| (Thousands) | ||
| Possible future acquisitions | 20,457 | |
| Stock compensation plans | 15,478 | |
| Total | 35,935 |
The Company made no share repurchases in 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.
In conjunction with the closing of the Rice Merger, on November 13, 2017 the Company issued approximately 91 million shares of EQT common stock to Rice Energy shareholders.
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, 2016 | $ | 9,607 | $ | (699 | ) | $ | (6,866 | ) | $ | 2,042 | |||||
| (Gains) losses reclassified from accumulated OCI, net of tax | (4,982 | ) | (a) | 144 | (a) | 338 | (b) | (4,500 | ) | ||||||
| December 31, 2017 | 4,625 | (555 | ) | (6,528 | ) | (2,458 | ) | ||||||||
| (Gains) losses reclassified from accumulated OCI, net of tax | (4,625 | ) | (a) | 168 | (a) | 606 | (b) | (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 | (a) | 316 | (b) | 703 | |||||||||
| Change in accounting principle | — | — | (496 | ) | (c) | (496 | ) | ||||||||
| December 31, 2019 | $ | — | $ | — | $ | (5,199 | ) | $ | (5,199 | ) |
| (a) | Losses (gains), net of tax related to natural gas cash flow hedges were reclassified from accumulated OCI into operating revenues. Losses, net of tax related to interest rate cash flow hedges were reclassified from accumulated OCI into interest expense. |
| (b) | Noted accumulated OCI reclassification is attributable to the net actuarial loss and net prior service cost related to the Company's other postretirement benefits plan. See Note 1. |
| (c) | Related to adoption of ASU 2018-02. See Note 1. |
13**.** Share-Based Compensation Plans
The following table summarizes the Company's share-based compensation expense.
| Years Ended December 31, | |||||||||||
| 2019 | 2018 | 2017 | |||||||||
| (Thousands) | |||||||||||
| 2015 Executive Performance Incentive Program | $ | — | $ | — | $ | 5,348 | |||||
| 2016 Incentive Performance Share Unit Program | — | 6,863 | 13,077 | ||||||||
| 2017 Incentive Performance Share Unit Program | (681 | ) | 2,467 | 5,038 | |||||||
| 2018 Incentive Performance Share Unit Program | (952 | ) | 4,742 | — | |||||||
| 2019 Incentive Performance Share Unit Program | 14,939 | — | — | ||||||||
| 2016 EQT Value Driver Performance Share Unit Award Program | — | — | 3,341 | ||||||||
| 2017 EQT Value Driver Performance Share Unit Award Program | — | 584 | 10,822 | ||||||||
| 2018 EQT Value Driver Performance Share Unit Award Program | (248 | ) | 8,224 | — | |||||||
| 2019 EQT Value Driver Performance Share Unit Award Program | 3,624 | — | — | ||||||||
| Restricted stock awards | 14,430 | 14,503 | 87,104 | ||||||||
| Non-qualified stock options | 4,774 | 2,757 | 2,626 | ||||||||
| Other programs, including non-employee director awards | 2,257 | 3,014 | 1,005 | ||||||||
| Less: Discontinued operations | — | (18,250 | ) | (15,595 | ) | ||||||
| Total share-based compensation expense (a) | $ | 38,143 | $ | 24,904 | $ | 112,766 |
| (a) | For the year ended December 31, 2019, share-based compensation expense of $28.6 million was included in proxy, transaction and reorganization expense. |
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 the 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 year ended December 31, 2019. Cash received from exercises under all share-based payment arrangements for employees and directors for the years ended December 31, 2018 and 2017 was $1.9 million and $0.2 million, respectively. During the years ended December 31, 2019, 2018 and 2017, share-based payment arrangements paid in stock generated tax benefits of $4.9 million, $13.4 million and $58.9 million, respectively.
Executive Performance Incentive Programs – Equity & Liability
The Management Development and Compensation Committee of the Company's Board of Directors (the Compensation Committee) has adopted:
| • | the 2015 Executive Performance Incentive Plan (the 2015 Incentive PSU Program) under the 2014 Long-Term Incentive Plan (the 2014 LTIP); |
| • | the 2016 Incentive Performance Share Unit Program (the 2016 Incentive PSU Program) under the 2014 LTIP; |
| • | the 2017 Incentive Performance Share Unit Program (the 2017 Incentive PSU Program) under the 2014 LTIP; |
| • | the 2018 Incentive Performance Share Unit Program (the 2018 Incentive PSU Program) under the 2014 LTIP; and |
| • | the 2019 Incentive Performance Share Unit Program (the 2019 Incentive PSU Program) under the 2014 LTIP. |
The 2015 Incentive PSU Program, 2016 Incentive PSU Program, 2017 Incentive PSU Program, 2018 Incentive PSU Program and 2019 Incentive PSU Program are collectively referred to as the Incentive PSU Programs. The 2015 Incentive PSU Program and 2016 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 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 2015, 2016 and 2017 were earned based on:
| • | 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. |
Beginning with the 2018 Incentive PSU Program, awards granted are earned based on:
| • | the level of total shareholder return relative to a predefined peer group; |
| • | the level of operating and development cost improvement; and |
| • | return on capital employed. |
The payout factor varies between zero and 300% of the number of outstanding units contingent upon the performance metrics listed above. The Company recorded the 2015 Incentive PSU Program, the 2016 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 for equity awards, one-year risk-free rate shown in the chart below for the 2018 Incentive PSU Program liability award and two-year risk-free rate shown in the chart below for the 2019 Incentive PSU Program liability award. 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. More detailed information on each award is set forth in the table below.
| Incentive PSU Program | Settled In | Accounting Treatment | Fair Value (a) | Risk-Free Rate | Vested/Payment Date | Awards Paid | Value (Millions) | Unvested/Expected Payment Date | Awards Outstanding as of December 31, 2019 (b) | ||||||
| 2015 | Stock | Equity | $ | 141.11 | 1.10% | February 2018 | 274,767 | $ | 38.8 | N/A | N/A | ||||
| 2016 | Stock | Equity | $ | 109.30 | 1.31% | February 2019 | 384,101 | $ | 34.8 | N/A | N/A | ||||
| 2017 (c) | Stock | Equity | $ | 120.60 | 1.47% | N/A | N/A | N/A | First Quarter of 2020 | 44,573 | |||||
| 2017 (d) | Cash | Liability | $ | 10.90 | N/A | N/A | N/A | N/A | First Quarter of 2020 | 93,953 | |||||
| 2018 (e) | Stock | Equity | $ | 76.53 | 1.97% | N/A | N/A | N/A | First Quarter of 2021 | 107,340 | |||||
| 2018 (f) | Cash | Liability | $ | 11.81 | 1.58% | N/A | N/A | N/A | First Quarter of 2021 | 113,517 | |||||
| 2019 (g) | Stock | Equity | $ | 29.45 | 2.44% | N/A | N/A | N/A | First Quarter of 2022 | 463,380 | |||||
| 2019 (h) | Cash | Liability | $ | 14.21 | 1.57% | N/A | N/A | N/A | First Quarter of 2022 | 244,940 |
| (a) | Information for the valuation of the liability plans is shown as of December 31, 2019. |
| (b) | Represents the number of outstanding units as of December 31, 2019 adjusted for forfeitures. The 2016 Incentive PSU Program settled in stock included 130,393 for Equitrans Midstream employees that was settled by the Company. The 2017 and 2018 Incentive PSU Programs to be settled in stock include 7,020 and 9,550 shares, respectively, for Equitrans Midstream employees that will be settled by the Company. The 2017 and 2018 Incentive PSU Programs to be settled in cash include 40,018 and 55,210 shares, respectively, for Equitrans Midstream employees that will be settled by the Company. |
| (c) | As of January 1, 2019, 44,573 units were outstanding under the 2017 Incentive PSU Program – Equity. There were no forfeitures in 2019 and 44,573 outstanding units as of December 31, 2019. |
| (d) | As of January 1, 2019, 105,018 units were outstanding under the 2017 Incentive PSU Program – Liability. Adjusting for 11,065 forfeitures, there were 93,953 outstanding units as of December 31, 2019. |
| (e) | As of January 1, 2019, 107,340 units were outstanding under the 2018 Incentive PSU Program – Equity. There were no forfeitures in 2019 and 107,340 total outstanding units as of December 31, 2018. |
| (f) | As of January 1, 2019, 124,820 units were outstanding under the 2018 Incentive PSU Program – Liability. Adjusting for 11,303 forfeitures, there were 113,517 outstanding units as of December 31, 2019. |
| (g) | A total of 463,380 units were granted under the 2019 Incentive PSU Program – Equity in 2019, and no additional units may be granted. There were no forfeitures in 2019 and 463,380 total outstanding units as of December 31, 2019. |
| (h) | A total of 255,920 units were granted under the 2019 Incentive PSU Program – Liability in 2019, and no additional units may be granted. Adjusting for 10,980 forfeitures, there were 244,940 outstanding units as of December 31, 2019. |
The following table presents total capitalized compensation costs related to the Incentive PSU Programs.
| Years Ended December 31, | |||||||||||
| 2019 | 2018 | 2017 | |||||||||
| (Millions) | |||||||||||
| 2015 Incentive PSU Program | $ | — | $ | — | $ | 2.2 | |||||
| 2016 Incentive PSU Program | — | 2.1 | 4.4 | ||||||||
| 2017 Incentive PSU Program (liability only) | (1.4 | ) | 1.0 | 1.7 | |||||||
| 2018 Incentive PSU Program (liability only) | (0.3 | ) | 0.6 | — | |||||||
| 2019 Incentive PSU Program (liability only) | 0.9 | — | — |
As of December 31, 2019, $0.2 million, $0.1 million and $1.2 million of unrecognized compensation cost (assuming no changes to the performance condition achievement level) related to the 2018 Incentive PSU Program – Liability, 2019 Incentive PSU Program – Equity and 2019 Incentive PSU Program – Liability, respectively, was expected to be recognized over the remainder of the performance periods. Assuming no changes to the performance condition achievement level, there is no remaining unrecognized compensation cost related to the 2018 Incentive PSU Program – Equity.
Fair value is estimated using a Monte Carlo simulation valuation method with the following weighted average assumptions:
| Incentive PSU Programs Issued During the Years Ended December 31, | |||||||||||||||
| 2019 | 2019 | 2018 | 2018 | 2017 | 2017 | 2016 | 2015 | ||||||||
| Accounting Treatment | Liability (a) | Equity | Liability (a) | Equity | Liability (b) | Equity | Equity | Equity | |||||||
| Risk-free rate | 1.57% | 2.44% | 1.58% | 1.97% | N/A | 1.47% | 1.31% | 1.10% | |||||||
| Dividend Yield (c) | N/A | N/A | N/A | N/A | N/A | N/A | N/A | N/A | |||||||
| Volatility factor | 59.90% | 54.60% | 52.10% | 32.60% | N/A | 32.30% | 28.43% | 27.45% | |||||||
| Expected term | 2 years | 3 years | 1 year | 3 years | N/A | 3 years | 3 years | 3 years |
| (a) | Information for the valuation of the liability plans is shown as of December 31, 2019. |
| (b) | The 2017 Incentive PSU Program – Liability award fair value per unit is equal to EQT common stock price on the measurement date. |
| (c) | Dividends paid from the beginning of the performance period will be cumulatively added as additional shares of common stock. |
Value Driver Award Programs
The Compensation Committee has also adopted:
| • | the 2016 Value Driver Performance Share Unit Award Program (the 2016 EQT VDPSU Program) under the 2014 LTIP; |
| • | the 2017 Value Driver Performance Share Unit Award Program (the 2017 EQT VDPSU Program) under the 2014 LTIP; |
| • | the 2018 Value Driver Performance Share Unit Award Program (the 2018 EQT VDPSU Program) under the 2014 LTIP; and |
| • | the 2019 Value Driver Performance Share Unit Award Program (the 2019 EQT VDPSU Program) under the 2014 LTIP. |
The 2016 EQT VDPSU Program, 2017 EQT VDPSU Program, 2018 EQT VDPSU Program and 2019 EQT VDPSU Program 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 vest upon payment following the first anniversary of the grant date; the remaining 50% of the confirmed awards vest 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 are 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 award.
| EQT VDPSU Program | Settled In | Accounting Treatment | Fair Value per Unit (a) | Vested/Payment Date | Number of awards (including accrued dividends) or cash paid (Millions) | Unvested/Expected Payment Date | Awards Outstanding (including accrued dividends) as of December 31, 2019 (b) | |||||
| 2016 (c) | Cash | Liability | $ | 65.40 | February 2017 | $ | 21.3 | N/A | N/A | |||
| $ | 56.92 | February 2018 | $ | 16.8 | N/A | N/A | ||||||
| 2017 | Cash | Liability | $ | 56.92 | February 2018 | $ | 14.0 | N/A | N/A | |||
| $ | 18.89 | February 2019 | $ | 4.0 | N/A | N/A | ||||||
| 2018 | Cash | Liability | $ | 18.89 | February 2019 | $ | 4.9 | N/A | N/A | |||
| $ | 10.90 | N/A | N/A | Second tranche first quarter of 2020 | 185,976 | |||||||
| 2019 (d) | Cash | Liability | $ | 10.90 | N/A | N/A | First tranche first quarter of 2020 | 169,417 | ||||
| N/A | N/A | N/A | Second tranche first quarter of 2021 | 170,180 |
| (a) | For liability awards, the fair value per unit is equal to EQT common stock price on the measurement date. |
| (b) | The 2017 EQT VDPSU Program and 2018 EQT VDPSU Program include 95,452 and 130,355 awards, respectively, for Equitrans Midstream employees that will be settled by the Company. |
| (c) | In addition to the $21.3 million in awards paid in February 2017, $0.2 million in awards were paid in 2017 in accordance with employee separation agreements. |
| (d) | The total liability recorded for the 2019 EQT VDPSU Program was $2.8 million as of December 31, 2019. |
The following table presents total capitalized compensation costs related to the VDPSU Programs.
| Years Ended December 31, | |||||||||||
| 2019 | 2018 | 2017 | |||||||||
| (Millions) | |||||||||||
| 2016 EQT VDPSU Program | $ | — | $ | — | $ | 7.0 | |||||
| 2017 EQT VDPSU Program | — | 0.1 | 10.3 | ||||||||
| 2018 EQT VDPSU Program | 0.1 | 3.3 | — | ||||||||
| 2019 EQT VDPSU Program | 2.4 | — | — |
Restricted Stock Awards – Equity
The Company granted 613,440, 145,540 and 85,350 restricted stock equity awards to key employees of the Company during the years ended December 31, 2019, 2018 and 2017, respectively. These restricted stock awards will be fully vested at the end of the three-year period commencing with the date of grant, assuming continued service through such date. For the years ended December 31, 2019, 2018 and 2017, the weighted average fair value of these restricted stock grants, based on the grant date fair value of EQT common stock, was approximately $17.42, $54.33 and $63.00, respectively.
In conjunction with the closing of the Rice Merger, the Company converted Rice Energy restricted stock equity awards and performance share equity awards to 2,290,234 Company restricted stock equity awards. Employees who were terminated on the Rice Merger closing date became immediately vested in their Company awards and received merger consideration cash of $5.30 per Rice Energy share. Company awards of those employees who continued employment with the Company under a transition agreement vest upon the earlier of the end of the vesting period set forth in the original award agreement or the end of the employee's employment period set forth in his or her transition agreement, in both cases subject to continued service through such date. Company awards of those employees who continued employment with the Company on an at-will basis vest in accordance with the vesting period set forth in the original award agreement, assuming continued service through such date. The fair value of these restricted stock grants, based on the grant date fair value of EQT common stock, was approximately $65.18. See Note 8 for further discussion of the Rice Merger.
The total fair value of restricted stock awards vested during the years ended December 31, 2019, 2018 and 2017 was $11.9 million, $39.8 million and $123.0 million, respectively. The 2017 amount includes $13.0 million for the cash payment for the merger consideration of $5.30 per Rice Energy share.
As of December 31, 2019, $2.1 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 2.1 years.
The following table summarizes restricted stock equity award activity as of December 31, 2019.
| Restricted Stock | Nonvested Shares (a) | Weighted Average Fair Value | Aggregate Fair Value | ||||||||
| Outstanding at January 1, 2019 | 192,782 | $ | 59.79 | $ | 11,525,593 | ||||||
| Granted | 613,440 | 17.42 | 10,685,274 | ||||||||
| Vested | (487,509 | ) | 24.33 | (11,862,608 | ) | ||||||
| Forfeited | (7,716 | ) | 35.16 | (271,295 | ) | ||||||
| Outstanding at December 31, 2019 | 310,997 | $ | 32.40 | $ | 10,076,964 |
| (a) | Nonvested shares outstanding at December 31, 2019 included 71,313 shares for Equitrans Midstream employees that will be settled by the Company. |
Restricted Stock Unit Awards – Liability
During the years ended December 31, 2019, 2018, and 2017, the Company granted 686,350, 373,750, and 292,400 restricted stock unit liability awards, respectively, to key employees of the Company that will be paid in cash. Adjusting for forfeitures, there were 741,819 awards outstanding as of December 31, 2019. 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 $4.4 million, $6.9 million, and $8.8 million as of December 31, 2019, 2018, and 2017, respectively.
Non-Qualified Stock Options
The fair value of the Company's option grants was estimated at the dates of grant using a Black-Scholes option-pricing model with the assumptions indicated in the table below for the years ended December 31, 2019, 2018 and 2017. 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, | |||||||||||
| 2019 (a) | 2018 | 2017 (a) | |||||||||
| Risk-free interest rate | 2.48 | % | 2.25 | % | 1.95 | % | |||||
| Dividend yield | 0.46 | % | 0.20 | % | 0.18 | % | |||||
| Volatility factor | 27.97 | % | 26.46 | % | 27.45 | % | |||||
| Expected term | 5 years | 5 years | 5 years | ||||||||
| Number of Options Granted | 779,300 | 287,800 | 153,700 | ||||||||
| Weighted Average Grant Date Fair Value | $ | 5.31 | $ | 15.39 | $ | 17.47 | |||||
| Total Intrinsic Value of Options Exercised (Millions) | $ | — | $ | — | $ | 1.7 |
| (a) | There were two grant dates for the 2019 and 2017 options. Amounts shown represent weighted average. |
As of December 31, 2019, $0.1 million of unrecognized compensation cost related to outstanding nonvested stock options was expected to be recognized by December 31, 2020.
The following table summarizes option activity as of December 31, 2019.
| Non-Qualified Stock Options | Shares | Weighted Average Exercise Price | Weighted Average Remaining Contractual Term | Aggregate Intrinsic Value | |||||||||
| Outstanding at January 1, 2019 | 1,775,429 | $ | 32.43 | ||||||||||
| Granted | 779,300 | 19.11 | |||||||||||
| Outstanding at December 31, 2019 | 2,554,729 | $ | 28.37 | 5.94 years | $ | — | |||||||
| Exercisable at December 31, 2019 | 2,447,020 | $ | 28.75 | 5.81 years | $ | — |
Non-employee Directors' Share-Based Awards
Prior to 2020, the Company historically granted to EQT non-employee directors share-based awards that vest upon grant. The share-based awards are 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 EQT 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 259,443 non-employee director share-based awards, including
accrued dividends, were outstanding as of December 31, 2019. A total of 146,790, 50,979 and 26,090 share-based awards were granted to non-employee directors during the years ended December 31, 2019, 2018 and 2017, 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 $18.11, $52.65 and $65.35 for the years ended December 31, 2019, 2018 and 2017, respectively.
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. No single customer accounted for more than 10% of the Company's revenues for 2019, 2018 and 2017.
Approximately 62% and 64% of the Company's accounts receivable balances as of December 31, 2019 and 2018, 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, 2019, 2018 or 2017.
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, 2019, 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, 2019, 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 leases drilling rigs, facilities and other equipment. As discussed in Note 1, the Company adopted ASU 2016-02, ASU 2018-11 and ASU 2019-01 on January 1, 2019 using the optional transition method of adoption. The Company elected a package of practical expedients that together allows an entity to not reassess whether a contract is or contains a lease, lease classification and initial direct lease costs. In addition, the Company elected the following practical expedients: (i) to not reassess certain land easements, (ii) to not apply the recognition requirements under the standard to short-term leases and (iii) to combine and account for lease and nonlease contract components as a lease, where fixed nonlease payments are capitalized to the Consolidated Balance Sheet and variable nonlease payments are recognized as variable lease expense in the Statement of Consolidated Operations. Nonlease payments include payments for property taxes and other operating and maintenance expenses incurred by the lessor but paid by the Company pursuant to the lease contract.
On January 1, 2019, the Company recorded in its Consolidated Balance Sheet a total of $89.0 million in right-of-use assets and corresponding lease liabilities, representing the present value of its future lease payments. Adoption of the lease standards did not require an adjustment to the opening balance of retained earnings. The discount rate used to determine present value was based on the rate of interest that the Company estimated it would have to pay to borrow, on a collateralized-basis over a similar term, an amount equal to the lease payments in a similar economic environment as of January 1, 2019. The Company reassess the discount rate for new and modified lease contracts as of the lease effective date.
The right-of-use assets and lease liabilities recognized upon adoption of lease standards were based on lease classifications, commitment amounts and terms determined under the prior lease accounting guidance. Leases with an initial term of twelve months or less are considered short-term leases and are not recorded in the Consolidated Balance Sheet. Certain of the Company's lease contracts have multiple renewal periods at the Company's option; if a renewal period option is reasonably assured to be
exercised, the associated operating lease payments are included in the present value of future operating lease payments. As of December 31, 2019, the Company had no finance leases and was not a lessor.
The following table summarizes the Company's lease costs.
| Year Ended December 31, 2019 | |||
| (Thousands) | |||
| Operating lease costs | $ | 57,517 | |
| Variable lease costs (a) | 17,143 | ||
| Total lease costs (b) | $ | 74,660 |
| (a) | Includes short-term lease costs. |
| (b) | Includes drilling rig lease costs capitalized to property, plant and equipment of $58.5 million, of which $48.1 million are operating lease costs. |
For the year ended December 31, 2019, cash paid for operating lease liabilities, and reported in cash flows provided by operating activities on the Statement of Consolidated Cash Flows, was $10.8 million. During the year ended December 31, 2019, the Company recorded $24.3 million of right-of-use assets in exchange for new lease liabilities.
The operating lease right-of-use assets were recorded in other assets and the current and noncurrent portions of the operating lease liabilities were recorded in other current liabilities and other liabilities and credits, respectively, on the Consolidated Balance Sheet. As of December 31, 2019, the operating right-of-use assets were $52.2 million and operating lease liabilities were $59.0 million, of which $29.0 million was classified as current. As of December 31, 2019, the weighted average remaining lease term was 3.3 years and the weighted average discount rate was 3.3%.
The following table summarizes undiscounted future cash flows owed by the Company to lessors pursuant to lease contracts in effect as of December 31, 2019.
| December 31, 2019 | |||
| (Thousands) | |||
| 2020 | $ | 30,488 | |
| 2021 | 9,186 | ||
| 2022 | 8,499 | ||
| 2023 | 8,417 | ||
| 2024 | 5,985 | ||
| Thereafter | 28 | ||
| Total lease payments | 62,603 | ||
| Less: Interest | (3,618 | ) | |
| Present value of lease liabilities | $ | 58,985 |
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, 2019 were $22.5 billion, composed of $1.4 billion in 2020, $1.8 billion in 2021, $1.8 billion in 2022, $1.7 billion in 2023, $1.7 billion in 2024 and $14.1 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, 2019, future commitments under these contracts were $104.3 million in 2020, $36.8 million in 2021 and $2.0 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, 2019.
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. In January 2020, Moody's downgraded the Company's senior notes credit rating to "Ba1," and, in February 2020, S&P and Fitch
downgraded the Company's senior notes rating to "BB+" and "BB," respectively. See Note 10 for a discussion of the effects of the downgrades on the Company's financial statements subsequent to December 31, 2019, including collateral posted as of February 26, 2020. See Note 4 for a discussion of what is deemed investment grade and other factors affecting margin deposit requirements on the Company's derivative contracts.
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 $12.1 million was recorded in other liabilities and credits in the Consolidated Balance Sheet as of December 31, 2019.
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 $58 million as of December 31, 2019, extending at a decreasing amount for approximately 9 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**.** The Equitrans Share Exchange
On February 26, 2020, the Company entered into share purchase agreements with Equitrans Midstream to sell approximately 50% of the Company's equity interest in Equitrans Midstream to Equitrans Midstream (the Equitrans Share Exchange) in exchange for a combination of cash and fee relief under the Company's gathering agreements with EQM. The Company currently owns approximately 19.9% of the outstanding shares of Equitrans Midstream's common stock; following the closing of the Equitrans Share Exchange, the Company will own approximately 9.95% of the outstanding shares of Equitrans Midstream's common stock.
19**.** Interim Financial Information (Unaudited)
The following summary of quarterly operating results reflects variations from various factors, including the volatility of natural gas commodity prices, impairments, the Separation and Distribution and the 2018 Divestitures. Quarterly operating results for the year ended December 31, 2018 have been recast to reflect the presentation of discontinued operations described in Note 2.
| Three Months Ended | |||||||||||||||
| March 31 | June 30 | September 30 | December 31 | ||||||||||||
| 2019 | (Thousands, except per share amounts) | ||||||||||||||
| Total operating revenues | $ | 1,143,173 | $ | 1,310,252 | $ | 951,576 | $ | 1,011,483 | |||||||
| Operating income (loss) | 175,456 | 296,030 | (161,529 | ) | (1,462,067 | ) | |||||||||
| Net income (loss) attributable to EQT Corporation (a) | 190,691 | 125,566 | (361,028 | ) | (1,176,924 | ) | |||||||||
| Earnings per share of common stock attributable to EQT Corporation: | |||||||||||||||
| Basic and diluted net income (loss) (b) | $ | 0.75 | $ | 0.49 | $ | (1.41 | ) | $ | (4.61 | ) | |||||
| 2018 | |||||||||||||||
| Total operating revenues | $ | 1,312,036 | $ | 950,648 | $ | 1,050,046 | $ | 1,245,138 | |||||||
| Operating loss | (1,950,332 | ) | (114,650 | ) | (147,451 | ) | (570,691 | ) | |||||||
| Amounts attributable to EQT Corporation: | |||||||||||||||
| Loss from continuing operations | $ | (1,578,533 | ) | $ | (76,978 | ) | $ | (127,347 | ) | $ | (598,062 | ) | |||
| (Loss) income from discontinued operations, net of tax | (7,461 | ) | 94,784 | 87,654 | (38,625 | ) | |||||||||
| Net (loss) income attributable to EQT Corporation | $ | (1,585,994 | ) | $ | 17,806 | $ | (39,693 | ) | $ | (636,687 | ) | ||||
| Earnings per share of common stock attributable to EQT Corporation: | |||||||||||||||
| Basic and diluted: | |||||||||||||||
| Loss from continuing operations | $ | (5.96 | ) | $ | (0.29 | ) | $ | (0.49 | ) | $ | (2.35 | ) | |||
| (Loss) income from discontinued operations | (0.03 | ) | 0.36 | 0.34 | (0.15 | ) | |||||||||
| Net (loss) income | $ | (5.99 | ) | $ | 0.07 | $ | (0.15 | ) | $ | (2.50 | ) |
| (a) | Includes impairment of long-lived assets of $1,124.4 million recognized for the three months ended December 31, 2019. See Note 1. |
| (b) | Quarterly net income (loss) per share amounts are standalone calculations and may not be additive to full-year amounts due to rounding and changes in outstanding shares. |
20**.** 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, | |||||||||||
| 2019 | 2018 | 2017 | |||||||||
| (Thousands) | |||||||||||
| Capitalized costs | |||||||||||
| Proved properties | $ | 17,994,820 | $ | 17,648,731 | $ | 18,920,855 | |||||
| Unproved properties | 3,322,014 | 4,166,048 | 5,016,299 | ||||||||
| Total capitalized costs | 21,316,834 | 21,814,779 | 23,937,154 | ||||||||
| Less: Accumulated depreciation and depletion | 5,402,515 | 4,666,212 | 5,121,646 | ||||||||
| Net capitalized costs | $ | 15,914,319 | $ | 17,148,567 | $ | 18,815,508 |
| Years Ended December 31, | |||||||||||
| 2019 | 2018 | 2017 | |||||||||
| (Thousands) | |||||||||||
| Costs incurred (a) | |||||||||||
| Property acquisition: | |||||||||||
| Proved properties (b) | $ | 40,316 | $ | 77,099 | $ | 5,251,711 | |||||
| Unproved properties (c) | 154,128 | 198,854 | 3,310,995 | ||||||||
| Exploration (d) | 7,223 | 1,708 | 15,505 | ||||||||
| Development | 1,560,346 | 2,443,980 | 1,357,165 |
| (a) | Amounts exclude capital expenditures for facilities and information technology. |
| (b) | 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 the 2017 acquisitions discussed in Note 8. Amounts in 2017 include $2,530.4 million and $1,192.0 million for the purchase of Marcellus wells and leases, respectively, acquired in the 2017 acquisitions discussed in Note 8, including the impact of measurement period adjustments for 2016 acquisitions. Amounts in 2017 also include $1,228.6 million and $0.3 million for the purchase of Utica wells and leases, respectively, acquired in the 2017 acquisitions discussed in Note 8. |
| (c) | Amounts in 2017 include $2,625.1 million and $0.5 million for the purchase of Marcellus leases and Utica leases, respectively, acquired in the 2017 acquisitions discussed in Note 8. |
| (d) | Amounts include capitalizable exploratory costs and exploration expense, excluding impairments. |
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, | |||||||||||
| 2019 | 2018 | 2017 | |||||||||
| (Thousands) | |||||||||||
| Sales of natural gas, NGLs and oil | $ | 3,791,414 | $ | 4,695,519 | $ | 2,651,318 | |||||
| Transportation and processing | 1,752,752 | 1,697,001 | 1,164,783 | ||||||||
| Production | 153,785 | 195,775 | 181,349 | ||||||||
| Exploration | 7,223 | 6,765 | 17,565 | ||||||||
| Depreciation and depletion | 1,538,745 | 1,569,038 | 970,985 | ||||||||
| Impairment/loss on sale/exchange of long-lived assets | 1,138,287 | 2,709,976 | — | ||||||||
| Impairment and expiration of leases | 556,424 | 279,708 | 7,552 | ||||||||
| Income tax (benefit) expense | (340,843 | ) | (454,009 | ) | 121,359 | ||||||
| Results of operations from producing activities, excluding corporate overhead | $ | (1,014,959 | ) | $ | (1,308,735 | ) | $ | 187,725 |
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 19 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 Ryder Scott Company, L.P. (Ryder Scott), an independent consulting firm hired by management. Since 1937, Ryder Scott has evaluated oil and gas properties and independently certified petroleum reserves quantities in the United States and internationally. There were no differences between the internally prepared and externally audited estimates.
In the course of its audit, Ryder Scott reviewed 100% of the total net natural gas, NGLs and oil proved reserves attributable to the Company's interests as of December 31, 2019. Ryder Scott conducted a detailed, well-by-well, audit of the Company's largest properties. For undeveloped locations, the Company determined, and Ryder Scott reviewed and approved, the areas within its acreage that the Company considered proven. Reserves were assigned and projected by the Company's reserve engineers for locations within these proven areas and approved by Ryder Scott based on offset production information and analogous type curves. In cases where historical production and pressure data was available and considered definitive, performance methods, including decline curve analysis, were used. Approximately 94% of the proved developed reserves attributable to producing wells or reserves that Ryder Scott reviewed were estimated using performance methods. The remaining 6% of those proved developed reserves were estimated by analogy, which calculates reserves based on correlation to comparable surrounding wells. 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, | ||||||||
| 2019 | 2018 | 2017 | ||||||
| (MMcf) | ||||||||
| Natural gas, NGLs and oil | ||||||||
| Proved developed and undeveloped reserves: | ||||||||
| Balance at January 1 | 21,816,776 | 21,445,667 | 13,508,407 | |||||
| Revision of previous estimates | (4,907,239 | ) | (1,124,904 | ) | (2,766,981 | ) | ||
| Purchase of hydrocarbons in place | — | — | 9,389,638 | |||||
| Sale of hydrocarbons in place | — | (1,748,557 | ) | (2,646 | ) | |||
| Extensions, discoveries and other additions | 2,067,753 | 4,739,233 | 2,225,141 | |||||
| Production | (1,507,896 | ) | (1,494,663 | ) | (907,892 | ) | ||
| Balance at December 31 | 17,469,394 | 21,816,776 | 21,445,667 | |||||
| Proved developed reserves: | ||||||||
| Balance at January 1 | 11,550,161 | 11,297,956 | 6,842,958 | |||||
| Balance at December 31 | 12,443,987 | 11,550,161 | 11,297,956 | |||||
| Proved undeveloped reserves: | ||||||||
| Balance at January 1 | 10,266,615 | 10,147,711 | 6,665,449 | |||||
| Balance at December 31 | 5,025,407 | 10,266,615 | 10,147,711 |
| Years Ended December 31, | ||||||||
| 2019 | 2018 | 2017 | ||||||
| (MMcf) | ||||||||
| Natural gas | ||||||||
| Proved developed and undeveloped reserves: | ||||||||
| Balance at January 1 | 20,805,452 | 19,830,236 | 12,331,867 | |||||
| Revision of previous estimates | (4,722,799 | ) | (960,285 | ) | (2,760,467 | ) | ||
| Purchase of natural gas in place | — | — | 8,890,145 | |||||
| Sale of natural gas in place | — | (1,331,391 | ) | (1,210 | ) | |||
| Extensions, discoveries and other additions | 2,029,683 | 4,659,835 | 2,164,578 | |||||
| Production | (1,435,134 | ) | (1,392,943 | ) | (794,677 | ) | ||
| Balance at December 31 | 16,677,202 | 20,805,452 | 19,830,236 | |||||
| Proved developed reserves: | ||||||||
| Balance at January 1 | 10,887,953 | 10,152,543 | 6,074,958 | |||||
| Balance at December 31 | 11,811,521 | 10,887,953 | 10,152,543 | |||||
| Proved undeveloped reserves: | ||||||||
| Balance at January 1 | 9,917,499 | 9,677,693 | 6,256,909 | |||||
| Balance at December 31 | 4,865,681 | 9,917,499 | 9,677,693 |
| Years Ended December 31, | ||||||||
| 2019 | 2018 | 2017 | ||||||
| (Mbbl) | ||||||||
| NGLs | ||||||||
| Proved developed and undeveloped reserves: | ||||||||
| Balance at January 1 | 162,395 | 258,507 | 189,695 | |||||
| Revision of previous estimates | (30,312 | ) | (33,653 | ) | (6,189 | ) | ||
| Purchase of NGLs in place | — | — | 82,894 | |||||
| Sale of NGLs in place | — | (59,080 | ) | (100 | ) | |||
| Extensions, discoveries and other additions | 6,177 | 12,895 | 10,084 | |||||
| Production | (11,305 | ) | (16,274 | ) | (17,877 | ) | ||
| Balance at December 31 | 126,955 | 162,395 | 258,507 | |||||
| Proved developed reserves: | ||||||||
| Balance at January 1 | 106,879 | 180,170 | 121,605 | |||||
| Balance at December 31 | 100,945 | 106,879 | 180,170 | |||||
| Proved undeveloped reserves: | ||||||||
| Balance at January 1 | 55,516 | 78,337 | 68,090 | |||||
| Balance at December 31 | 26,010 | 55,516 | 78,337 |
| Years Ended December 31, | ||||||||
| 2019 | 2018 | 2017 | ||||||
| (Mbbl) | ||||||||
| Oil | ||||||||
| Proved developed and undeveloped reserves: | ||||||||
| Balance at January 1 | 6,159 | 10,731 | 6,395 | |||||
| Revision of previous estimates | (428 | ) | 6,217 | 5,103 | ||||
| Purchase of oil in place | — | — | 355 | |||||
| Sale of oil in place | — | (10,447 | ) | (139 | ) | |||
| Extensions, discoveries and other additions | 168 | 338 | 9 | |||||
| Production | (822 | ) | (680 | ) | (992 | ) | ||
| Balance at December 31 | 5,077 | 6,159 | 10,731 | |||||
| Proved developed reserves: | ||||||||
| Balance at January 1 | 3,489 | 10,731 | 6,395 | |||||
| Balance at December 31 | 4,466 | 3,489 | 10,731 | |||||
| Proved undeveloped reserves: | ||||||||
| Balance at January 1 | 2,670 | — | — | |||||
| Balance at December 31 | 611 | 2,670 | — |
The change in reserves during the year ended December 31, 2019 resulted from the following:
| • | Conversions into 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 into 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. |
The change in reserves during the year ended December 31, 2017 resulted from the following:
| • | Conversions into 987 Bcfe of proved undeveloped reserves to proved developed reserves. |
| • | Increase of 3,330 Bcfe and 6,060 Bcfe associated with the acquisition of proved developed reserves and proved undeveloped reserves, respectively, in the Marcellus, Upper Devonian and Utica plays. |
| • | Extensions, discoveries and other additions of 2,225 Bcfe, which exceeded the 2017 production of 908 Bcfe. Extensions, discoveries and other additions included an increase of 300 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; 893 Bcfe from proved undeveloped reserves extensions from acreage proved by drilling activity in the Company's Ohio, Pennsylvania and West Virginia Marcellus fields; and 1,032 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 3,522 Bcfe from proved undeveloped locations, of which 3,074 Bcfe was 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 the Company's acquisition of new acreage. |
| • | Upward revisions of 477 Bcfe from proved developed locations, due primarily to increased reserves from producing wells. |
| • | Upward revisions of 278 Bcfe associated with previously booked locations whose economic lives had been extended due to improved commodity prices. |
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, | |||||||||||
| 2019 | 2018 | 2017 | |||||||||
| (Thousands) | |||||||||||
| Future cash inflows (a) | $ | 42,499,686 | $ | 60,603,624 | $ | 51,423,920 | |||||
| Future production costs (b) | (19,114,076 | ) | (20,463,567 | ) | (18,379,892 | ) | |||||
| Future development costs | (2,617,731 | ) | (5,854,503 | ) | (5,637,676 | ) | |||||
| Future income tax expenses | (3,013,667 | ) | (6,823,621 | ) | (5,811,125 | ) | |||||
| Future net cash flow | 17,754,212 | 27,461,933 | 21,595,227 | ||||||||
| 10% annual discount for estimated timing of cash flows | (9,261,539 | ) | (15,850,035 | ) | (12,593,293 | ) | |||||
| Standardized measure of discounted future net cash flows | $ | 8,492,673 | $ | 11,611,898 | $ | 9,001,934 |
| (a) | The majority of the Company's production is sold through liquid trading points on interstate pipelines. |
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.
For 2017, reserves were computed using average first-day-of-the-month closing prices for the prior twelve months of $51.34 per Bbl for WTI less regional adjustments, $2.801 per Dth for Columbia Gas Transmission Corp., $2.100 per Dth for Dominion Transmission, Inc., $2.914 per Dth for the East Tennessee Natural Gas Pipeline, $2.058 per Dth for Texas Eastern Transmission Corp., $1.995 per Dth for the Tennessee, zone 4-300 Leg of Tennessee Gas Pipeline Company, $2.321 per Dth for the Tennessee LA 500 Leg of Tennessee Gas Pipeline Company, $2.665 per Dth for Waha and $2.840 per Dth for the Rockies Express Pipeline Zone 3. For 2017, 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 $23.07 per Bbl from certain West Virginia Marcellus reserves, $31.11 per Bbl from certain Kentucky reserves, $29.47 per Bbl from Ohio Utica reserves and $27.93 per Bbl from Permian reserves.
| (b) | Includes approximately $1,186 million, $883 million and $1,400 million for future plugging and abandonment costs as of December 31, 2019, 2018 and 2017, respectively. |
Holding production and development costs constant, a change 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, 2019 discounted future net cash flows before income taxes of the Company's proved reserves of approximately $809 million, $163 million and $24 million, respectively.
The following table summarizes the changes in the standardized measure of discounted future net cash flows.
| Years Ended December 31, | |||||||||||
| 2019 | 2018 | 2017 | |||||||||
| (Thousands) | |||||||||||
| Net sales and transfers of natural gas and oil produced | $ | (1,884,877 | ) | $ | (2,802,742 | ) | $ | (1,305,186 | ) | ||
| Net changes in prices, production and development costs | (3,502,434 | ) | 2,949,606 | 2,236,183 | |||||||
| Extensions, discoveries and improved recovery, net of related costs | 870,504 | 1,616,653 | 1,269,712 | ||||||||
| Development costs incurred | 1,002,389 | 1,630,506 | 712,635 | ||||||||
| Net purchase of minerals in place | — | — | 5,357,921 | ||||||||
| Net sale of minerals in place | — | (849,162 | ) | (284 | ) | ||||||
| Revisions of previous quantity estimates | (2,080,040 | ) | (811,576 | ) | (297,437 | ) | |||||
| Accretion of discount | 900,004 | 834,026 | 115,437 | ||||||||
| Net change in income taxes | 1,444,368 | (289,549 | ) | (1,477,603 | ) | ||||||
| Timing and other (a) | 130,861 | 332,202 | 1,401,802 | ||||||||
| Net (decrease) increase | (3,119,225 | ) | 2,609,964 | 8,013,180 | |||||||
| Balance at January 1 | 11,611,898 | 9,001,934 | 988,754 | ||||||||
| Balance at December 31 | $ | 8,492,673 | $ | 11,611,898 | $ | 9,001,934 |
| (a) | Timing and other for the year ended December 31, 2017 was primarily driven by timing changes to the Company's development plan as a result of the Rice Merger described in Note 8. |
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