Document and Entity Information
Document and Entity Information - USD ($) shares in Thousands, $ in Billions | 12 Months Ended | ||
Dec. 31, 2018 | Jan. 31, 2019 | Jun. 30, 2018 | |
Document and Entity Information | |||
Entity Registrant Name | EQT Corp | ||
Entity Central Index Key | 33,213 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Large Accelerated Filer | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2018 | ||
Document Fiscal Year Focus | 2,018 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
Entity Shell Company | false | ||
Entity Common Stock, Shares Outstanding | 254,762 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Public Float | $ 14.5 |
STATEMENTS OF CONSOLIDATED OPER
STATEMENTS OF CONSOLIDATED OPERATIONS - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Operating revenues: | |||
Sales of natural gas, oil and NGLs | $ 4,709,384 | ||
(Loss) gain on derivatives not designated as hedges | (178,591) | $ 390,021 | $ (248,991) |
Total operating revenues | 4,557,868 | 3,091,020 | 1,387,054 |
Operating expenses: | |||
Transportation and processing | 1,697,001 | 1,164,783 | 880,191 |
Production | 195,775 | 181,349 | 174,170 |
Exploration | 6,765 | 17,565 | 4,663 |
Selling, general and administrative | 284,220 | 208,986 | 218,946 |
Depreciation and depletion | 1,569,038 | 970,985 | 856,451 |
Impairment/loss on sale of long-lived assets | 2,709,976 | 0 | 0 |
Impairment of goodwill | 530,811 | 0 | 0 |
Lease impairments and expirations | 279,708 | 7,552 | 15,686 |
Transaction costs | 26,331 | 152,188 | 0 |
Amortization of intangible assets | 41,367 | 5,400 | 0 |
Total operating expenses | 7,340,992 | 2,708,808 | 2,150,107 |
Gain on sale of assets | 0 | 0 | 8,025 |
Operating (loss) income | (2,783,124) | 382,212 | (755,028) |
Other expense | 65,349 | 2,987 | 8,075 |
Loss on debt extinguishment | 0 | 12,641 | 0 |
Interest expense | 228,958 | 167,971 | 131,159 |
(Loss) income from continuing operations before income taxes | (3,077,431) | 198,613 | (894,262) |
Income tax (benefit) | (696,511) | (1,188,416) | (362,769) |
(Loss) income from continuing operations | (2,380,920) | 1,387,029 | (531,493) |
Income from discontinued operations, net of tax (see Note 2) | 373,762 | 471,113 | 400,430 |
Net (loss) income | (2,007,158) | 1,858,142 | (131,063) |
Less: Net income from discontinued operations attributable to noncontrolling interests | 237,410 | 349,613 | 321,920 |
Amounts attributable to EQT Corporation: | |||
(Loss) income from continuing operations | (2,380,920) | 1,387,029 | (531,493) |
Income from discontinued operations, net of tax | 136,352 | 121,500 | 78,510 |
Net (loss) income attributable to EQT Corporation | $ (2,244,568) | $ 1,508,529 | $ (452,983) |
Basic: | |||
Weighted average common stock outstanding (in shares) | 260,932 | 187,380 | 166,978 |
(Loss) income from continuing operations (in dollars per share) | $ (9.12) | $ 7.40 | $ (3.18) |
Income from discontinued operations (in dollars per share) | 0.52 | 0.65 | 0.47 |
Net (loss) income (in dollars per share) | $ (8.60) | $ 8.05 | $ (2.71) |
Diluted: | |||
Weighted average common stock outstanding (in shares) | 260,932 | 187,727 | 166,978 |
(Loss) income from continuing operations (in dollars per share) | $ (9.12) | $ 7.39 | $ (3.18) |
Income from discontinued operations (in dollars per share) | 0.52 | 0.65 | 0.47 |
Net (loss) income (in dollars per share) | $ (8.60) | $ 8.04 | $ (2.71) |
Sales of natural gas, oil and NGLs | |||
Operating revenues: | |||
Sales of natural gas, oil and NGLs | $ 4,695,519 | $ 2,651,318 | $ 1,594,997 |
Net marketing services and other | |||
Operating revenues: | |||
Net marketing services and other | $ 40,940 | $ 49,681 | $ 41,048 |
STATEMENTS OF CONSOLIDATED COMP
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Statement of Comprehensive Income [Abstract] | |||
Net (loss) income | $ (2,007,158) | $ 1,858,142 | $ (131,063) |
Net change in cash flow hedges: | |||
Natural gas, net of tax expense (benefit) of $2,584, ($3,191) and ($36,296) | (4,625) | (4,982) | (55,155) |
Interest rate, net of tax expense of $80, $105 and $104 | 168 | 144 | 144 |
Pension and other post-retirement benefits liability adjustment, net of tax expense of $510, $193 and $6,778 | 606 | 338 | 10,675 |
Other comprehensive (loss) | (3,851) | (4,500) | (44,336) |
Comprehensive (loss) income | (2,011,009) | 1,853,642 | (175,399) |
Less: Comprehensive income from discontinued operations attributable to noncontrolling interests | 237,410 | 349,613 | 321,920 |
Comprehensive (loss) income attributable to EQT Corporation | $ (2,248,419) | $ 1,504,029 | $ (497,319) |
STATEMENTS OF CONSOLIDATED CO_2
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Net change in cash flow hedges: | |||
Natural gas, tax expense (benefit) | $ 2,584 | $ (3,191) | $ (36,296) |
Interest rate, tax expense | 80 | 105 | 104 |
Pension and other post-retirement benefits liability adjustment, tax (benefit) expense | $ 510 | $ 193 | $ 6,778 |
STATEMENTS OF CONSOLIDATED CASH
STATEMENTS OF CONSOLIDATED CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Cash flows from operating activities: | |||
Net (loss) income | $ (2,007,158) | $ 1,858,142 | $ (131,063) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Deferred income taxes (benefit) | (510,405) | (1,050,612) | (180,261) |
Depreciation and depletion | 1,729,739 | 1,077,559 | 927,920 |
Amortization of intangible assets | 77,374 | 10,940 | 0 |
Amortization of financing costs and accretion expense | 17,914 | 0 | 0 |
Asset and lease impairments and exploratory well costs | 2,989,684 | 20,327 | 75,434 |
Goodwill impairment | 798,689 | 0 | 0 |
Gain on sale of assets | 0 | 0 | (8,025) |
Loss on debt extinguishment | 0 | 12,641 | 0 |
Provision for (recoveries of) losses on accounts receivable | 3,078 | (979) | 3,856 |
Non-cash other expense (income) | 18,335 | (24,955) | (31,693) |
Share-based compensation expense | 25,189 | 94,592 | 44,605 |
Loss (gain) on derivatives not designated as hedges | 178,591 | (390,021) | 248,991 |
Cash settlements (paid) received on derivatives not designated as hedges | (225,279) | 40,728 | 279,425 |
Pension settlement charge | 0 | 0 | 9,403 |
Changes in other assets and liabilities: | |||
Accounts receivable | (439,062) | (8,979) | (165,507) |
Accounts payable | 457,113 | (16,680) | 40,548 |
Tax receivable | (117,188) | (12,285) | 34,880 |
Other items, net | (20,358) | 27,280 | (84,193) |
Net cash provided by operating activities | 2,976,256 | 1,637,698 | 1,064,320 |
Cash flows from investing activities: | |||
Capital expenditures | (2,964,924) | (1,549,351) | (942,810) |
Cash payments for Rice Merger (as defined in Note 3), net of cash acquired | 0 | (1,560,272) | 0 |
Capital expenditures for other acquisitions | (34,113) | (828,657) | (1,061,735) |
Capital expenditures from discontinued operations | (732,727) | (380,151) | (584,819) |
Net sales of trading securities | 0 | 283,758 | |
Net investments in trading securities | (284,882) | ||
Proceeds from sale of assets | 583,381 | 3,573 | 75,000 |
Exploratory dry hole costs | 0 | (11,420) | (1,369) |
Capital contributions to Mountain Valley Pipeline, LLC, net of sales of interest (Note 2) | (820,943) | (159,550) | (85,866) |
Other investing activities | (9,778) | 0 | 0 |
Net cash used in investing activities | (3,979,104) | (4,202,070) | (2,886,481) |
Cash flows from financing activities: | |||
Net proceeds from the issuance of common shares of EQT Corporation | 0 | 0 | 1,225,999 |
Net proceeds from the issuance of common units of EQM Midstream Partners, LP | 0 | 0 | 217,102 |
Proceeds from issuance of debt | 2,500,000 | 3,000,000 | 500,000 |
Increase in borrowings on credit facilities | 8,637,500 | 2,063,000 | 740,000 |
Repayment of borrowings on credit facilities | (8,953,500) | (1,076,500) | (1,039,000) |
Dividends paid | (31,375) | (20,827) | (20,156) |
Distributions to noncontrolling interests | (380,651) | (236,123) | (189,981) |
Net cash transferred at Separation and Distribution (Note 2) | (129,008) | 0 | 0 |
Contribution to Strike Force Midstream LLC by minority owner, net of distribution | 0 | 6,738 | 0 |
Acquisition of 25% of Strike Force Midstream LLC | (175,000) | 0 | 0 |
Repayments and retirements of debt | (8,376) | (2,000,000) | (5,119) |
Proceeds and excess tax benefits from awards under employee compensation plans | 1,946 | 244 | 6,165 |
Cash paid for taxes related to net settlement of share-based incentive awards | (22,647) | (72,116) | (26,931) |
Debt issuance costs and revolving credit facility origination fees | (40,966) | (41,876) | (8,580) |
Premiums paid on debt extinguishment | 0 | (89,363) | 0 |
Repurchase and retirement of common stock | (538,876) | 0 | 0 |
Repurchase of common stock | (27) | (30) | (30) |
Net cash provided by financing activities | 859,020 | 1,533,147 | 1,399,469 |
Net change in cash and cash equivalents | (143,828) | (1,031,225) | (422,692) |
Cash, cash equivalents and restricted cash at beginning of year | 147,315 | 1,178,540 | 1,601,232 |
Cash, cash equivalents and restricted cash at end of year | 3,487 | 147,315 | 1,178,540 |
Cash paid (received) during the year for: | |||
Interest, net of amount capitalized | 260,959 | 189,371 | 144,657 |
Income taxes, net | $ (3,675) | $ 3,637 | $ (41,142) |
STATEMENTS OF CONSOLIDATED CA_2
STATEMENTS OF CONSOLIDATED CASH FLOWS (PARENTHETICAL) | Dec. 31, 2018 |
Statement of Cash Flows [Abstract] | |
Ownership interest (as a percent) | 25.00% |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Current assets: | ||
Cash and cash equivalents | $ 3,487 | $ 26,311 |
Accounts receivable (less accumulated provision for doubtful accounts: $8,648 in 2018; $7,780 in 2017) | 1,241,843 | 664,685 |
Derivative instruments, at fair value | 481,654 | 241,952 |
Tax receivable | 131,573 | 14,385 |
Prepaid expenses and other | 111,107 | 59,462 |
Current assets of discontinued operations | 0 | 156,260 |
Total current assets | 1,969,664 | 1,163,055 |
Property, plant and equipment | 22,148,012 | 25,396,026 |
Less: accumulated depreciation and depletion | 4,755,505 | 5,666,018 |
Net property, plant and equipment | 17,392,507 | 19,730,008 |
Intangible assets, net | 77,333 | 118,700 |
Goodwill | 0 | 470,849 |
Investment in Equitrans Midstream Corporation | 1,013,002 | 0 |
Other assets | 268,838 | 250,734 |
Noncurrent assets of discontinued operations | 0 | 7,789,258 |
Total assets | 20,721,344 | 29,522,604 |
Current liabilities: | ||
Current portion of debt | 704,390 | 12,406 |
Accounts payable | 1,059,873 | 726,433 |
Derivative instruments, at fair value | 336,051 | 139,089 |
Other current liabilities | 254,687 | 274,276 |
Current liabilities of discontinued operations | 0 | 80,033 |
Total current liabilities | 2,355,001 | 1,232,237 |
Credit facility borrowings | 800,000 | 1,295,000 |
Senior Notes | 3,882,932 | 4,575,203 |
Notes payable to EQM Midstream Partners, LP | 110,059 | 114,720 |
Deferred income taxes | 1,823,381 | 1,889,962 |
Other liabilities and credits | 791,742 | 752,837 |
Noncurrent liabilities of discontinued operations | 0 | 1,248,032 |
Total liabilities | 9,763,115 | 11,107,991 |
Shareholders' Equity: | ||
Common stock, no par value, authorized 320,000 shares, shares issued: 257,225 in 2018 and 267,871 in 2017 | 7,828,554 | 9,388,903 |
Treasury stock, shares at cost: 2,753 in 2018 (no shares held in rabbi trust) and 3,551 in 2017 (including 253 held in rabbi trust) | (49,194) | (63,602) |
Retained earnings | 3,184,275 | 3,996,775 |
Accumulated other comprehensive loss | (5,406) | (2,458) |
Total common shareholders’ equity | 10,958,229 | 13,319,618 |
Noncontrolling interests in discontinued operations | 0 | 5,094,995 |
Total shareholder's equity | 10,958,229 | 18,414,613 |
Total liabilities and shareholders' equity | $ 20,721,344 | $ 29,522,604 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Statement of Financial Position [Abstract] | ||
Accounts receivable, accumulated provision for doubtful accounts | $ 8,648 | $ 7,780 |
Common stock, par value (in dollars per share) | $ 0 | $ 0 |
Common stock, authorized (in shares) | 320,000,000 | 320,000,000 |
Common stock, issued (in shares) | 257,225,000 | 267,871,000 |
Treasury stock (in shares) | 2,753,000 | 3,551,000 |
Treasury stock, held in rabbi trust (in shares) | 0 | 253,145 |
STATEMENTS OF CONSOLIDATED EQUI
STATEMENTS OF CONSOLIDATED EQUITY - USD ($) | Total | Common Stock | Retained Earnings | Accumulated Other Comprehensive (Loss) Income | Noncontrolling Interests in Discontinued Operations | Equitrans Midstream | Equitrans MidstreamCommon Stock | Equitrans MidstreamRetained Earnings | Equitrans MidstreamAccumulated Other Comprehensive (Loss) Income | Equitrans MidstreamNoncontrolling Interests in Discontinued Operations |
Beginning Balance (in shares) at Dec. 31, 2015 | 152,554,000 | |||||||||
Beginning Balance at Dec. 31, 2015 | $ 8,028,042,000 | $ 2,049,201,000 | $ 2,982,212,000 | $ 46,378,000 | $ 2,950,251,000 | |||||
Increase (Decrease) in Stockholders' Equity | ||||||||||
Net (loss) income | (131,063,000) | (452,983,000) | 321,920,000 | |||||||
Net change in cash flow hedges: | ||||||||||
Natural gas, net of tax | (55,155,000) | (55,155,000) | ||||||||
Interest rate, net of tax | 144,000 | 144,000 | ||||||||
Pension and other post-retirement benefits liability adjustment, net of tax | 10,675,000 | 10,675,000 | ||||||||
Dividends ($0.12 per share) | (20,156,000) | (20,156,000) | ||||||||
Stock-based compensation plans, net (in shares) | 724,000 | |||||||||
Share-based compensation plans, net | 42,943,000 | $ 42,782,000 | 161,000 | |||||||
Distributions to noncontrolling interests | (189,981,000) | (189,981,000) | ||||||||
Issuance of common shares of EQT Corporation (in shares) | 19,550,000 | |||||||||
Issuance of common shares of EQT Corporation | 1,225,999,000 | $ 1,225,999,000 | ||||||||
Issuance of common units | 217,102,000 | 217,102,000 | ||||||||
Elimination of deferred taxes | 5,921,000 | $ 5,921,000 | ||||||||
Repurchase and retirement of common stock (in shares) | (1,000) | |||||||||
Repurchase and retirement of common stock | (30,000) | $ (30,000) | ||||||||
Changes in ownership of consolidated subsidiaries | (15,194,000) | $ 25,293,000 | (40,487,000) | |||||||
Ending Balance (in shares) at Dec. 31, 2016 | 172,827,000 | |||||||||
Ending Balance at Dec. 31, 2016 | $ 9,119,247,000 | $ 3,349,166,000 | 2,509,073,000 | 2,042,000 | 3,258,966,000 | |||||
Net change in cash flow hedges: | ||||||||||
Common stock, authorized (in shares) | 320,000,000 | |||||||||
Preferred stock, authorized shares | 3,000,000 | |||||||||
Preferred stock, shares issued (in shares) | 0 | |||||||||
Net (loss) income | $ 1,858,142,000 | 1,508,529,000 | 349,613,000 | |||||||
Natural gas, net of tax | (4,982,000) | (4,982,000) | ||||||||
Interest rate, net of tax | 144,000 | 144,000 | ||||||||
Pension and other post-retirement benefits liability adjustment, net of tax | 338,000 | 338,000 | ||||||||
Dividends ($0.12 per share) | (20,827,000) | (20,827,000) | ||||||||
Stock-based compensation plans, net (in shares) | 580,000 | |||||||||
Share-based compensation plans, net | 26,626,000 | $ 26,436,000 | 190,000 | |||||||
Distributions to noncontrolling interests | (236,123,000) | (236,123,000) | ||||||||
Rice Merger, net of withholdings (in shares) | 90,914,000 | |||||||||
Rice Merger, net of withholdings | 7,665,340,000 | $ 5,949,729,000 | 1,715,611,000 | |||||||
Contribution from noncontrolling interest, net of distribution | 6,738,000 | 6,738,000 | ||||||||
Repurchase and retirement of common stock (in shares) | (1,000) | |||||||||
Repurchase and retirement of common stock | (30,000) | $ (30,000) | ||||||||
Ending Balance (in shares) at Dec. 31, 2017 | 264,320,000 | |||||||||
Ending Balance at Dec. 31, 2017 | $ 18,414,613,000 | $ 9,325,301,000 | 3,996,775,000 | (2,458,000) | 5,094,995,000 | |||||
Net change in cash flow hedges: | ||||||||||
Common stock, authorized (in shares) | 320,000,000 | |||||||||
Preferred stock, authorized shares | 3,000,000 | |||||||||
Preferred stock, shares issued (in shares) | 0 | |||||||||
Net (loss) income | $ (2,007,158,000) | (2,244,568,000) | 237,410,000 | |||||||
Natural gas, net of tax | (4,625,000) | (4,625,000) | ||||||||
Interest rate, net of tax | 168,000 | 168,000 | ||||||||
Pension and other post-retirement benefits liability adjustment, net of tax | 606,000 | 606,000 | ||||||||
Dividends ($0.12 per share) | (31,375,000) | (31,375,000) | ||||||||
Stock-based compensation plans, net (in shares) | 798,000 | |||||||||
Share-based compensation plans, net | 8,385,000 | $ 7,432,000 | 953,000 | |||||||
Distributions to noncontrolling interests | (380,651,000) | (380,651,000) | ||||||||
Repurchase and retirement of common stock (in shares) | (10,646,000) | |||||||||
Repurchase and retirement of common stock | (538,876,000) | $ (538,876,000) | ||||||||
Purchase of Strike Force Midstream LLC noncontrolling interests | (175,000,000) | 1,818,000 | (176,818,000) | |||||||
Changes in ownership of consolidated subsidiaries | 56,370,000 | $ (158,560,000) | 214,930,000 | |||||||
Distribution of Equitrans Midstream Corporation | $ (4,388,341,000) | $ (857,755,000) | $ 1,459,330,000 | $ 903,000 | $ (4,990,819,000) | |||||
Ending Balance (in shares) at Dec. 31, 2018 | 254,472,000 | |||||||||
Ending Balance at Dec. 31, 2018 | $ 10,958,229,000 | $ 7,779,360,000 | $ 3,184,275,000 | $ (5,406,000) | $ 0 | |||||
Net change in cash flow hedges: | ||||||||||
Common stock, authorized (in shares) | 320,000,000 | |||||||||
Preferred stock, authorized shares | 3,000,000 | |||||||||
Preferred stock, shares issued (in shares) | 0 |
STATEMENTS OF CONSOLIDATED EQ_2
STATEMENTS OF CONSOLIDATED EQUITY (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Statement of Stockholders' Equity [Abstract] | |||
Natural gas, tax (benefit) | $ 2,584 | $ (3,191) | $ (36,296) |
Interest rate, tax expense | 80 | 105 | 104 |
Pension and other post-retirement benefits liability adjustment, tax (benefit) expense | $ 510 | $ 193 | $ 6,778 |
Dividends (in dollars per share) | $ 0.12 | $ 0.12 | $ 0.12 |
Common stock, authorized shares (in shares) | 320,000,000 | 320,000,000 | 320,000,000 |
Preferred stock, authorized shares (in shares) | 3,000,000 | 3,000,000 | 3,000,000 |
Preferred stock, shares issued (in shares) | 0 | 0 | 0 |
Preferred shares, shares outstanding (in shares) | 0 | 0 | 0 |
EQM | |||
Distributions to noncontrolling interests (in dollars per common unit) | $ 4.295 | $ 3.655 | $ 3.05 |
EQGP | |||
Distributions to noncontrolling interests (in dollars per common unit) | 1.123 | $ 0.806 | $ 0.571 |
Rice Midstream Partners, LP | |||
Distributions to noncontrolling interests (in dollars per common unit) | $ 0.5966 |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | 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 a controlling interest is held (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 or 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. These investments are accounted for at cost. Interest earned on cash equivalents is included as a reduction of interest expense. Trading Securities: Trading securities consist of liquid debt securities that are carried at fair value. Realized losses of $2.6 million and unrealized gains of $1.5 million on these debt securities are included in other income in the Statements of Consolidated Operations for the years ended December 31, 2017 and 2016, respectively. The Company initiated its investments in trading securities in 2016 to enhance returns on a portion of its significant cash balance at that time. Investments within the Company's portfolio are subject to a minimum credit rating based on type of investment, and the portfolio's asset mix is subject to exposure limits to ensure issuer and asset class diversification. As of March 31, 2017, the Company closed its positions on all trading securities. Accounts Receivable: Accounts receivable primarily relate to the sales of natural gas, oil and natural gas liquids (NGLs) and amounts due from joint interest partners. Amounts due from contracts with customers were $783.0 million at December 31, 2018 . Joint interest receivables were $324.2 million and $149.3 million at December 31, 2018 and 2017 , respectively. Inventories: Generally, the Company’s inventory balance consists of natural gas stored underground or in pipelines and materials and supplies recorded at the lower of average cost or market. During the years ended December 31, 2018 , 2017 and 2016 , the Company recorded no lower of cost or market adjustments related to inventory. Investment in Equitrans Midstream Corporation : The Company owns approximately 19.9% of the outstanding shares of common stock of Equitrans Midstream Corporation (Equitrans Midstream). The Company does not have the ability to exercise significant influence and does not have a controlling financial interest in Equitrans Midstream or any of its subsidiaries. As such, this investment is accounted for as an investment in an equity security that is recorded at fair value in the Consolidated Balance Sheets. See Note 2 and 6 . Property, Plant and Equipment: The Company’s property, plant and equipment consist of the following: As of December 31, 2018 2017 (Thousands) Oil and gas producing properties, successful efforts method $ 21,814,779 $ 23,937,154 Accumulated depreciation and depletion (4,666,212 ) (5,121,646 ) Net oil and gas producing properties 17,148,567 18,815,508 Other properties, at cost less accumulated depreciation 243,940 914,500 Net property, plant and equipment $ 17,392,507 $ 19,730,008 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, as well as productive acreage, including productive mineral interests, are capitalized and depleted using the unit-of-production method. These capitalized costs include salaries, benefits and other internal costs directly attributable to these activities. The Company capitalized internal costs of $130.0 million , $114.6 million and $115.4 million in 2018 , 2017 and 2016 , respectively, for production related activities. The Company also capitalized $29.0 million , $20.5 million and $19.2 million of interest expense related to Marcellus, Upper Devonian and Utica well development in 2018 , 2017 and 2016 , respectively. Depletion expense is calculated based on the actual produced sales volumes multiplied by the applicable depletion rate per unit. The depletion rates are derived by dividing the net capitalized costs by the number of units expected to be produced over the life of the reserves for lease costs and well costs separately. Costs of exploratory dry holes, exploratory geological and geophysical activities, delay rentals and other property carrying costs are charged to expense. The majority of the Company’s producing oil and gas properties were depleted at an overall average rate of $1.04 per Mcfe, $1.04 per Mcfe and $1.06 per Mcfe for the years ended December 31, 2018 , 2017 and 2016 , respectively. 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. In order to determine whether impairment has occurred, the Company estimates the expected future cash flows (on an undiscounted basis) from its oil and gas properties and compares these estimates to the carrying values of the properties. The estimated future cash flows used to test those properties for recoverability are based on proved and, if determined reasonable by management, risk-adjusted probable reserves, utilizing assumptions generally consistent with the assumptions utilized by the Company's management 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 accordingly 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 rate and other assumptions that marketplace participants would use in their estimates of fair value. 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 management's intent to divest the Company's Huron and Permian assets prior to the end of their useful lives. As a result of the impairment evaluation during 2018, the Company recorded an impairment of $2.4 billion associated with the production and related midstream assets in the Huron and Permian plays that were divested during the year (collectively, the 2018 Divestitures). There were no indicators of impairment identified during 2017. During 2016, there were indicators that the carrying value of the Huron assets may be impaired due to declines in commodity prices. As a result of the impairment indicators as of December 31, 2016, the Company performed an undiscounted cash flow analysis and determined that no impairment existed during 2016. The Company impaired all of its goodwill in the fourth quarter 2018. This resulted in an impairment indicator for certain other long-lived assets including proved oil and gas properties and intangible assets. The Company performed an undiscounted cash flow analysis and determined that no additional impairment existed. Capitalized costs of unproved oil and gas properties are evaluated at least annually for recoverability on a prospective basis. Indicators of potential impairment include changes brought about by economic factors, potential shifts in business strategy employed by management and historical experience. The likelihood of an impairment of unproved oil and gas properties increases as the expiration of a lease term approaches if drilling activity has not commenced. If it is determined that the Company does not intend to drill on the property prior to expiration or does not have the intent and ability to extend, renew, trade, or sell the lease prior to expiration, an impairment expense is recorded. Expense for lease expirations that were not previously impaired are recorded as the leases expire. For the years ended December 31, 2018, 2017 and 2016, the Company recorded $279.7 million , $7.6 million and $15.7 million , respectively for lease impairments and expirations. The Company’s unproved properties had a net book value of $4,166.0 million and $5,016.3 million at December 31, 2018 and 2017 , respectively. During 2017, the Company drilled one exploratory dry hole within its non-core acreage and the related expenditures have been included within exploration expense in the Statements of Consolidated Operations for the year ended December 31, 2017. There were no exploratory wells drilled during 2018 and there were no capitalized exploratory wells costs at December 31, 2018 and 2017. Goodwill : Goodwill is the cost of an acquisition less the fair value of the identifiable net assets of the acquired business. At November 30, 2018, prior to the completion of the annual goodwill impairment test, the goodwill balance totaled $530.8 million . Goodwill is tested for impairment at the Company's single reporting unit level on an annual basis and between annual tests if events or circumstances indicate it is more likely than not that the fair value of a reporting unit is below its carrying value. The Company considered market capitalization and other valuation techniques, as applicable, when estimating fair value for goodwill impairment testing purposes. In connection with the annual goodwill impairment testing for 2018, the Company identified several qualitative factors that are considered in assessing goodwill for impairment. These factors included 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, exceeding the Company's capital budget as announced in October 2018, recent operational volume curtailments and the Company's new strategy to slow the cadence of its future drilling operations to generate near-term free cash flow. The Company conducted the first step of the goodwill impairment test for the single reporting unit as of November 30, 2018. The Company utilized its market capitalization plus a control premium approach to estimate the fair value of the Company (and in turn the single reporting unit). The estimated market capitalization was determined by multiplying the 30 day weighted average stock price and the Company's common shares outstanding as of November 30, 2018. Based on the analysis utilizing the market capitalization plus control premium approach, the estimated fair value of the reporting unit was significantly less than its carrying value. As the Company adopted ASU No. 2017-04 (ASU 2017-04), Simplifying the Test of Goodwill Impairment , all of the goodwill was impaired. This impairment charge was classified as a component of operating expenses. Intangible Assets : These intangible assets were initially recorded under the acquisition method of accounting at their estimated fair values at the Rice Merger (defined in Note 3 ) acquisition date. The Company’s intangible assets are composed of non-compete agreements with former Rice Energy Inc. executives. The non-compete agreements have a useful life of 3 years. The Company calculates amortization of intangible assets using the straight-line method over the estimated useful life of the intangible assets. Amortization expense recorded in the Statements of Consolidated Operations as of December 31, 2018 and 2017 was $41.4 million and $5.4 million . The estimated annual amortization expense over the remaining two years is as follows: 2019 $41.4 million and 2020 $35.9 million . Intangible assets, net as of December 31, 2018 and 2017 are detailed below. December 31, 2018 2017 (Thousands) Non-compete agreements $ 124,100 $ 124,100 Less: accumulated amortization (46,767 ) (5,400 ) Intangible assets, net $ 77,333 $ 118,700 Sales and Retirements Policies: No gain or loss is recognized on the partial sale of proved developed oil and gas reserves unless non-recognition would significantly alter the relationship between capitalized costs and remaining proved reserves for the affected amortization base. When gain or loss is not recognized, the amortization base is reduced by the amount of the proceeds. Derivative Instruments: Derivatives are held as part of a formally documented risk management program. The Company’s use of derivative instruments is implemented under a set of policies approved by the Company’s Hedge and Financial Risk Committee (HFRC) and reviewed by the Audit Committee of the Company's Board of Directors. The HFRC is composed of the president and chief executive officer, the chief financial officer and other officers of the Company. In regards to commodity price risk, the financial instruments currently utilized by the Company are primarily fixed price swap agreements, collar agreements and option agreements. The Company engages in basis swaps to protect earnings from undue exposure to the risk of geographic disparities in commodity prices and may engage in interest rate swaps to hedge exposure to interest rate fluctuations on potential debt issuances. The Company also uses a limited number of other contractual agreements in implementing its commodity hedging strategy. The Company has an insignificant number of natural gas derivative instruments for trading purposes. Any changes in fair value of derivative instruments are recognized net within operating revenues in the Statements of Consolidated Operations. Other Current Liabilities: Other current liabilities as of December 31, 2018 and 2017 are detailed below. December 31, 2018 2017 (Thousands) Incentive compensation $ 46,937 $ 72,910 Taxes other than income 75,978 62,091 Accrued interest payable 42,998 41,926 Legal reserve 53,500 — Severance accrual 8,893 41,474 All other accrued liabilities 26,381 55,875 Total other current liabilities $ 254,687 $ 274,276 Revenue Recognition: For information on revenue recognition from contracts with customers and gains and losses on derivative commodity instruments, see Note 4 and Note 5 , respectively. Unamortized Debt Discount and Issuance Expense: Discounts and expenses incurred with the issuance of debt are amortized over the term of the debt. These amounts are presented as a reduction of Senior Notes on the accompanying 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 utilizes 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 years’ taxes made due to subsequent 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 are determined based on temporary differences between the financial reporting and tax bases of 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 some portion or all of the deferred tax asset will not be realized. In accounting for uncertainty in income taxes of a tax position taken or expected to be taken in a tax return, the Company utilizes 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 in order to record any financial statement benefit. If it is more likely than not that a tax position will be sustained, then the Company must measure the tax position to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. The Company recognizes interest and penalties accrued related to unrecognized tax benefits in income tax expense. Provision for Doubtful Accounts: Judgment is required to assess the ultimate realization of the Company’s accounts receivable, including assessing the probability of collection and the creditworthiness of certain customers. Reserves for uncollectible accounts are recorded as part of selling, general and administrative expense in the Statements of Consolidated Operations. The reserves are based on historical experience, current and expected economic trends and specific information about customer accounts. Earnings Per Share (EPS): Basic EPS are computed by dividing net income attributable to EQT by the weighted average number of common shares outstanding during the period, without considering any dilutive items. Diluted EPS are 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. Purchases of treasury shares are calculated using the average share price for the Company’s common stock during the period. Potentially dilutive securities arise from the assumed conversion of outstanding stock options and other share-based awards. In periods when the Company reports a net loss, all options and restricted stock are excluded from the calculation of diluted weighted average shares outstanding because of their anti-dilutive effect on loss per share. As a result, all options and all restricted stock were excluded from the calculation of diluted EPS for the years ended December 31, 2018 and 2016. Potentially dilutive securities (options and restricted stock awards) 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 legal 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 required to be 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, and 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 in plugging and abandoning wells and reclaiming or disposing of other assets as well as the 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 which are included in other liabilities and credits in the Consolidated Balance Sheets. The Company does not have any assets that are legally restricted for purposes of settling these obligations. December 31, 2018 2017 (Thousands) Asset retirement obligation as of beginning of period $ 443,349 $ 243,600 Accretion expense 17,513 13,644 Liabilities incurred 7,785 19,678 Liabilities settled (3,722 ) (3,750 ) Liabilities assumed in the Rice Merger 27,999 41,655 Liabilities removed due to divestitures (231,936 ) (88 ) Change in estimates 26,817 128,610 Asset retirement obligation as of end of period $ 287,805 $ 443,349 During 2018 and 2017 , the Company had changes in estimates for the plugging of conventional and horizontal wells, primarily related to increased cost assumptions of complying with existing regulatory requirements which were derived, in part, based on recent plugging experience and actual costs incurred. The Company operates in several states that have implemented enhanced requirements that resulted in the use of additional materials during the plugging process which has increased the estimated cost to plug these wells over recent years. 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. The estimated liabilities are based on analyses of historical data and actuarial estimates and are not discounted. The liabilities are reviewed by management quarterly and by independent actuaries annually to ensure that they are appropriate. 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. Pension and Other Post-Retirement Benefit Plans: The Company, as sponsor of the EQT Corporation Retirement Plan for Employees (Retirement Plan), a defined benefit pension plan, terminated the Retirement Plan effective December 31, 2014. On March 2, 2016, the Internal Revenue Service (IRS) issued a favorable determination letter for the termination of the Retirement Plan. On June 28, 2016, the Company purchased annuities from, and transferred the Retirement Plan assets and liabilities to, American General Life Insurance Company. As a result, during 2016, the Company reclassified the actuarial losses remaining in accumulated other comprehensive loss of approximately $9.4 million to earnings. In connection with the purchase of annuities, the Company made a cash payment of approximately $5.4 million to fully fund the Retirement Plan upon liquidation during the second quarter of 2016. Currently, the Company recognizes expense for on-going post-retirement benefits other than pensions. Expense recognized by the Company related to its defined contribution plan totaled $17.3 million in 2018 , $16.6 million in 2017 and $16.0 million in 2016 . Discontinued Operations: For businesses classified as discontinued operations, the balance sheet amounts and results of operations are reclassified from their historical presentation to assets and liabilities of discontinued operations on the Consolidated Balance Sheet and to discontinued operations on the Statement of Consolidated Operations for all periods presented. The Statement of Consolidated Cash Flows is not required to be reclassified for discontinued operations for any period. See Note 2 . Supplemental Cash Flow Information: Non-cash investing activities for the year ended December 31, 2018 included $34.6 million for asset retirement cost additions, $(274.2) million for changes in accruals of property, plant and equipment, $14.4 million for measurement period adjustments for 2017 acquisitions, $4.3 million in capitalized non-cash share-based compensation and $176.6 million for the increase in the capital contributions payable to Mountain Valley Pipeline, LLC. Non-cash investing activities for the year ended December 31, 2017 included $143.6 million for asset retirement cost additions, $4.4 million for changes in accruals of property, plant and equipment, $10.0 million of net liabilities assumed in 2017 acquisitions, $(14.3) million for measurement period adjustments for 2016 acquisitions, $9.0 million in capitalized non-cash stock based compensation and $94.3 million for the increase in the capital contributions payable to Mountain Valley Pipeline, LLC. See discussion of equity issued in consideration for the Rice Merger in Note 3 . Non-cash investing activities for the year ended December 31, 2016 included $87.6 million of net liabilities assumed in acquisitions, $(27.7) million for changes in accruals of property, plant and equipment, $66.2 million for asset retirement cost additions, $16.6 million in capitalized non-cash stock based compensation and $11.5 million for the increase in the capital contributions payable to Mountain Valley Pipeline, LLC. Recently Issued Accounting Standards: In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers . The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Company adopted this standard on January 1, 2018 using the modified retrospective method of adoption. Adoption of the ASU did not require an adjustment to the opening balance of equity. For the disclosures required by this ASU, see Note 4 . In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities . The standard affects accounting for equity investments and financial liabilities under the fair value option, the presentation and disclosure requirements for financial instruments, and eliminates the cost method of accounting for equity investments. The Company adopted this standard in the first quarter of 2018 which resulted in a cumulative effect adjustment of $4.1 million on the Statement of Consolidated Equity. In February 2016, the FASB issued ASU No. 2016-02, Leases . The primary effect of adopting the new standard on leases will be to record assets and liabilities for contracts currently recognized as operating leases. In July 2018, the FASB issued targeted improvements to this ASU in ASU 2018-11. This update provides entities with an optional transition method, which permits an entity to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The Company adopted the ASUs using the optional transition method on January 1, 2019 and did not require an adjustment to the opening balance of equity. The Company has adopted the practical expedient package, the land easement and short-term lease recognition exemption provided for under the new standard. The Company also elected a practical expedient that permits combining lease and non-lease components in a contract and accounting for the combination as a lease. The quantitative impacts of the new standard are dependent on the leases in existence at the time of reporting. As a result, the evaluation of the effect of the new standard on the results of operations and liquidity will change as new leases are entered into in the future. However, the Company does not expect the standard to have a significant impact on its results of operations or liquidity in 2019. In 2019, the Company expects to record a lease liability and offsetting right of use asset between $100 million and $125 million on the Consolidated Balance Sheet sheet associated with its leases which are primarily related to facilities, production rigs and compressors. Additional disclosures will be required to describe the nature, amount, significant assumptions and judgments made, maturity analysis of its lease liabilities and accounting policy elections from leases. The Company has implemented a new lease accounting system and related processes to ensure that contracts that contain lease components are appropriately accounted for under ASC Topic 842, including both new contracts and modifications to existing contracts. In June 2016, the FASB issued ASU No. 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 in current GAAP and requires an entity to reflect its current estimate of all expected credit losses. The amendments affect loans, debt securities, trade receivables, net investments in leases, off balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. The ASU will be effective for annual reporting periods beginning after December 15, 2019, including interim periods within that reporting period. The Company is currently evaluating the impact this standard will have on its financial statements and related disclosures. In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows: Restricted Cash . This ASU requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning of period and end of period total amounts shown on the statement of cash flows. The Company adopted this standard in the first quarter of 2018. The Company had $75 million in restricted cash at December 31, 2016. In accordance with ASU 2016-18, restricted cash is included in the beginning of period cash balance and excluded from investing activities on the Statements of Consolidated Cash Flows for the year ended December 31, 2017. The Company had no restricted cash on the Consolidated Balance Sheet at December 31, 2018 or 2017. In January 2017, the FASB issued ASU No. 2017-01, Business Combinations: Clarifying the Definition of a Business . This ASU clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The Company adopted this standard in the first quarter of 2018 with no significant effect on its financial statements or related disclosures. In January 2017, the FASB issued ASU No. 2017-04, Simplifying the Test of Goodwill Impairment . This ASU simplifies the quantitative goodwill impairment test requirements by eliminating the requirement to calculate the implied fair value of goodwill. Instead, a company is required to record an impairment charge based on the excess of a reporting unit’s carrying value over its fair value. The standard’s provisions are to be applied prospectively. The Company adopted this standard in the first quarter of 2018 with no significant effect on its financial statements or related disclosures. However as discussed in Note 3 , the Company has recorded an i |
Separation and Distribution and
Separation and Distribution and Discontinued Operations | 12 Months Ended |
Dec. 31, 2018 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Separation and Distribution and Discontinued Operations | Separation and Distribution and Discontinued Operations On November 12, 2018, EQT completed the previously announced separation of its midstream business, which was composed of the separately operated natural gas gathering, transmission and storage, and water services businesses of EQT, from its upstream business, which is composed of the natural gas, oil and natural gas liquids development, production and sales and commercial operations of the Company (the Separation). The Separation was effected by the transfer of the midstream business from EQT to Equitrans Midstream and the distribution of 80.1% of the outstanding shares of Equitrans Midstream common stock to EQT's shareholders (the Distribution). EQT's shareholders of record as of the close of business on November 1, 2018 (the Record Date) received 0.80 shares of Equitrans Midstream common stock for every one share of EQT common stock held as of the close of business on the Record Date. EQT retained 19.9% of the outstanding shares of Equitrans Midstream common stock. EQT 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, this investment is accounted for as an investment in equity securities. As of December 31, 2018, the fair value was based on the closing stock price of Equitrans Midstream multiplied by the number of shares of common stock owned by the Company. The changes in fair value since November 12, 2018 were recorded in other expense in the Statement of Consolidated Operations and resulted in an unrealized loss of approximately $72.4 million . On November 12, 2018, 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. These agreements include a Separation and Distribution Agreement, Tax Matters Agreement, Employee Matters Agreement, Transition Services Agreement and Shareholder and Registration Rights Agreement. The Transition Services Agreement will terminate upon the earlier of (i) the expiration of the term of the last service provided under it, or (ii) November 12, 2019. 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 included all of the Company's former EQM Gathering, EQM Transmission and EQM Water segments. The Statements of Consolidated Operations and Consolidated Balance Sheets of Equitrans Midstream are reflected as discontinued operations for all periods presented. Prior periods have been recast to reflect this presentation. This recast also includes presenting certain transportation and processing expenses in continuing operations for all periods presented which were previously eliminated in consolidation prior to the Separation and Distribution. The cash flows related to Equitrans Midstream have not been segregated and are included within the Statements of Consolidated Cash Flows for all periods presented. The results of operations of Equitrans Midstream are presented as discontinued operations in the Statements of Consolidated Operations as summarized below. The Company allocated all of the transaction costs associated with the Separation and Distribution to discontinued operations. The transaction costs included in the table below also included amounts that the Company allocated to discontinued operations for the Rice Merger (see Note 3 ). January 1, 2018 to November 12, 2018 Years Ended December 31, 2017 2016 (Thousands) Operating revenues $ 388,854 $ 279,422 $ 217,952 Transportation and processing (803,858 ) (604,025 ) (514,373 ) Operation and maintenance 99,671 80,833 69,308 Selling, general and administrative 62,702 53,275 44,022 Depreciation 160,701 106,574 71,469 Impairment/loss on sale of long-lived assets — — 59,748 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 28,718 Interest expense 88,300 34,801 16,761 Income from discontinued operations before income taxes 435,405 543,910 499,735 Income tax expense 61,643 72,797 99,305 Income from discontinued operations after income taxes 373,762 471,113 400,430 Less: Net income from discontinued operations attributable to noncontrolling interests 237,410 349,613 321,920 Net income from discontinued operations $ 136,352 $ 121,500 $ 78,510 (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 that could reduce volumetric-based fee revenues of two reporting units to which the Company's goodwill was recorded. The two reporting units were Rice Retained Midstream and RMP PA Gas Gathering, which were allocated to discontinued operations as a result of the Separation and Distribution. Both of these reporting units earn 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 were utilized. The discounted cash flow method income approach applies significant inputs 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 and reference transaction method 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; however, 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 on the Consolidated Balance Sheet and allocated to discontinued operations. The carrying amount of the major classes of assets and liabilities related to Equitrans Midstream classified as assets and liabilities of discontinued operations in the Consolidated Balance Sheet at December 31, 2017 are presented in the below table. December 31, 2017 (Thousands) Total assets of discontinued operations Cash and cash equivalents $ 121,004 Accounts receivable, net 60,551 Prepaid expenses and other (a) (25,295 ) Current assets of discontinued operations 156,260 Net property, plant and equipment 5,155,007 Intangible assets, net 617,660 Goodwill 1,527,877 Investment in nonconsolidated entity 460,546 Other assets 28,168 Noncurrent assets of discontinued operations 7,789,258 Total assets of discontinued operations $ 7,945,518 Total liabilities of discontinued operations Accounts payable (a) $ (71,809 ) Other current liabilities 151,842 Current liabilities of discontinued operations 80,033 Credit facility borrowings 466,000 Senior Notes 987,352 Deferred income taxes (121,062 ) Notes payable to EQM Midstream Partners, LP (See Note 10) (114,720 ) Other liabilities and credits 30,462 Noncurrent liabilities of discontinued operations 1,248,032 Total liabilities of discontinued operations $ 1,328,065 (a) As of December 31, 2017, prepaid expenses and other represents the receivable from Equitrans Midstream and accounts payable represents the payable to Equitrans Midstream. The following table presents amounts of the discontinued operations related to Equitrans Midstream which are included in the Statements of Consolidated Cash Flows. January 1, 2018 to November 12, 2018 Years Ended December 31, 2017 2016 (Thousands) Operating activities: Deferred income tax (benefit) expense $ (373,405 ) $ 43,471 $ (21,936 ) Depreciation 160,701 106,574 71,469 Amortization of intangibles 36,007 5,540 — Asset impairments — — 59,748 Goodwill impairment 267,878 — — Other income (51,450 ) (27,281 ) (29,300 ) Share-based compensation expense $ 1,841 $ 468 $ 373 Investing activities: Capital expenditures $ (732,727 ) $ (380,151 ) $ (584,819 ) Capital contributions to Mountain Valley Pipeline, LLC (a) (820,943 ) (159,550 ) (98,399 ) Sales of interests in Mountain Valley Pipeline, LLC (a) $ — $ — $ 12,533 Financing activities: Net proceeds from the issuance of common units of EQM $ — $ — $ 217,102 Proceeds from issuance of debt 2,500,000 — 500,018 Increase in borrowings on credit facilities 3,378,500 544,084 740,000 Repayment of borrowings on credit facilities (3,219,500 ) (344,000 ) (1,039,000 ) Distributions to noncontrolling interests (380,651 ) (236,123 ) (189,981 ) Contribution to Strike Force Midstream LLC by minority owner, net of distribution — 6,738 — Acquisition of 25% of Strike Force Midstream LLC (175,000 ) — — Debt issuance costs and revolving credit facility origination fees $ (40,966 ) $ (2,257 ) $ (8,580 ) (a) The Mountain Valley Pipeline, LLC is a joint venture that is constructing the Mountain Valley Pipeline (MVP). EQM owns an interest in the joint venture and made capital contributions to the joint venture. |
Rice Merger
Rice Merger | 12 Months Ended |
Dec. 31, 2018 | |
Business Combinations [Abstract] | |
Rice Merger | Rice Merger On November 13, 2017 , the Company completed its previously announced acquisition of Rice Energy Inc. (Rice) pursuant to the Agreement and Plan of Merger, dated as of June 19, 2017 (as amended, the Merger Agreement), by and among the Company, Rice and a wholly owned indirect subsidiary of the Company (RE Merger Sub). Pursuant to the terms of the Merger Agreement, on November 13, 2017, RE Merger Sub merged with and into Rice (the Rice Merger) with Rice continuing as the surviving corporation and a wholly owned indirect subsidiary of the Company. Immediately after the effective time of the Rice Merger (the Effective Time), Rice merged with and into another wholly owned indirect subsidiary of the Company. At the Effective Time, each share of the common stock, par value $0.01 per share, of Rice (the Rice Common Stock) issued and outstanding immediately prior to the Effective Time was converted into the right to receive 0.37 (the Exchange Ratio) of a share of the common stock, no par value, of the Company (Company Common Stock) and $5.30 in cash (collectively, the Merger Consideration). The aggregate Merger Consideration consisted of approximately 91 million shares of Company Common Stock and approximately $1.6 billion in cash (net of cash acquired and inclusive of amounts payable to employees of Rice who did not continue with the Company following the Effective Time). See Note 13 for further details. In connection with the closing of the Rice Merger, the Company paid an aggregate of $555.5 million , included in the cash paid for the Merger Consideration of approximately $1.6 billion (net of cash acquired and inclusive of amounts payable to employees of Rice who did not continue with the Company following the Effective Time), to affiliates of EIG Global Energy Partners (collectively, the EIG Funds) to redeem the EIG Funds' respective interests in Rice Midstream Holdings LLC (Rice Midstream Holdings) and Rice Midstream GP Holdings, LP (the EIG Redemptions). Following the EIG Redemptions, each of Rice Midstream Holdings and Rice Midstream GP Holdings, LP became indirect wholly owned subsidiaries of the Company. In connection with the closing of the Rice Merger, the Company repaid the $321.0 million of outstanding principal under Rice Energy Operating LLC's revolving credit facility and the $187.5 million of outstanding principal under Rice Midstream Holdings' revolving credit facility, together with interest and fees of $1.4 million and $0.3 million , respectively, and the credit agreements were terminated. Also in connection with the Rice Merger, Rice redeemed and canceled all of its outstanding 6.25% Senior Notes due 2022 (the Rice 2022 Notes) and 7.25% Senior Notes due 2023 (the Rice 2023 Notes) on November 13, 2017. The Company made aggregate payments of $1.4 billion in connection with the note redemptions, including make whole call premiums of $42.2 million and $21.6 million for the Rice 2022 Notes and the Rice 2023 Notes, respectively, and $13.4 million of required interest payments on the Rice 2023 Notes. The Company acquired a total of approximately 270,000 net acres through the Rice Merger, which included approximately 205,000 net Marcellus acres, as well as approximately 65,000 net Utica acres in Ohio. The Company also acquired Upper Devonian and Utica drilling rights held in Pennsylvania. The Company recorded $25.4 million and $152.2 million in transaction costs in continuing operations and $13.5 million and $85.1 million in discontinued operations related to the Rice Merger during the years ended December 31, 2018 and 2017, respectively. Also, in 2017, the Company expensed $8.0 million in debt issuance costs related to a bridge financing commitment to support the Rice Merger, $5.1 million of which is in continuing operations and $2.9 million of which is in discontinued operations. Allocation of Purchase Price The Rice Merger was accounted for as a business combination, using the acquisition method. The following table summarizes the final purchase price and fair values of assets and liabilities assumed as of November 13, 2017 , with any excess of the purchase price over the fair value of the identified net assets acquired recorded as goodwill. Variances between the preliminary and final purchase price allocations related to standard closing purchase price adjustments. Final Purchase Price Allocation (Thousands) Consideration Given: Equity consideration $ 5,943,289 Cash consideration 1,299,407 Buyout of preferred equity in Rice Midstream Holdings 429,708 Buyout of common units in Rice Midstream GP Holdings, LP 125,828 Settlement of pre-existing relationships (14,699 ) Total consideration 7,783,533 Fair value of liabilities assumed: Current liabilities 577,053 Long-term debt 2,151,656 Deferred income taxes 1,106,773 Other long term liabilities 95,712 Amount attributable to liabilities assumed 3,931,194 Fair value of assets acquired: Cash 294,671 Accounts receivable 322,630 Current assets 109,465 Net property, plant and equipment 9,918,315 Intangible assets 747,300 Noncontrolling interests (1,715,611 ) Amount attributable to assets acquired 9,676,770 Goodwill from Rice Merger $ 2,037,957 Goodwill impairment - continuing operations (530,811 ) Goodwill impairment - discontinued operations (267,878 ) Goodwill allocated to discontinued operations (a) (1,239,268 ) Goodwill as of December 31, 2018 $ — (a) In conjunction with the Rice Merger, the Company had unamortized carryover tax basis of $387.1 million of tax deductible goodwill, of which the entire amount relates to discontinued operations. The fair values of natural gas and oil properties were based on inputs that were not observable in the market and therefore represent Level 3 inputs. The fair values of natural gas and oil properties were measured using valuation techniques that convert future cash flows into a single discounted amount. Significant inputs to the valuation of natural gas and oil properties included estimates of: (i) recoverable reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average cost of capital. These inputs had a significant impact on the valuation of oil and gas properties. The fair value of undeveloped property was determined based upon a market approach of comparable transactions using Level 3 inputs. The estimated fair value of midstream facilities and equipment, generally consisting of pipeline systems and compression stations, is estimated using the cost approach. Significant unobservable inputs in the estimate of fair value include management’s assumptions about the replacement costs for similar assets, the relative age of the acquired assets and any potential economic or functional obsolescence associated with the acquired assets. As a result, the estimated fair value of the midstream facilities and equipment represents a Level 3 fair value measurement. The non-controlling interest in the acquired business was comprised of the limited partner units in Rice Midstream Partners LP (RMP) which were not acquired by the Company as well as the non-controlling interest in Strike Force Midstream LLC (Strike Force Midstream). The RMP limited partner units were actively traded on the New York Stock Exchange, and were valued based on observable market prices as of the transaction date and therefore represent a Level 1 fair value measurement. The non-controlling interest in Strike Force Midstream was calculated based on the enterprise value of Strike Force Midstream and the percentage ownership not acquired by the Company. Significant unobservable inputs in the estimate of the enterprise value of Strike Force Midstream include the future revenue estimates and future cost assumptions. As a result, the non-controlling interest in Strike Force Midstream represents a Level 3 fair value measurement. The Company identified intangible assets for customer relationships with third party customers and non-compete agreements with certain former Rice executives. The fair value of the identified intangible assets was determined using the income approach which requires a forecast of the expected future cash flows generated and an estimated market-based weighted average cost of capital. Significant unobservable inputs in the determination of fair value include future production levels, future revenues estimates, future cost assumptions, the estimated probability that former executives would compete in the absence of such non-compete agreements and estimated customer retention rates. As a result, the estimated fair value of the identified intangible assets represents a level 3 fair value measurement. Acquisitions In addition to the Rice Merger discussed in Note 3 , the Company executed multiple transactions during 2016 and 2017 that resulted in the Company's acquisition of approximately 304,000 net Marcellus acres, including the transactions listed below: • On July 8, 2016, the Company acquired approximately 62,500 net Marcellus acres and 31 Marcellus wells, 24 of which were producing, from Statoil USA Onshore Properties, Inc. The net acres acquired are primarily located in Wetzel, Tyler and Harrison Counties of West Virginia. • In the fourth quarter of 2016, the Company acquired approximately 42,600 net Marcellus acres and 42 Marcellus wells, 32 of which were producing at the time of the acquisition, which were being jointly developed by Trans Energy, Inc. (Trans Energy) and Republic Energy Ventures, LLC and its affiliates (collectively, Republic). The net acres acquired are primarily located in Wetzel, Marshall and Marion Counties of West Virginia. The acquisitions were effected through simultaneous transaction agreements that were executed on October 24, 2016 including: (i) a purchase and sale agreement between the Company and Republic; and (ii) an agreement and plan of merger among the Company, a wholly owned subsidiary of the Company (TE Merger Sub) and Trans Energy. The Republic acquisition closed on November 3, 2016. On October 27, 2016, the Company commenced a tender offer, through its wholly owned subsidiary, to acquire the outstanding shares of common stock of Trans Energy, a publicly traded company, at an offer price of $3.58 per share in cash. Following the tender offer on December 5, 2016, TE Merger Sub merged with and into Trans Energy, at which time Trans Energy became an indirect wholly owned subsidiary of the Company (the Trans Energy Merger). • On December 16, 2016, the Company acquired approximately 17,000 net Marcellus acres located in Washington, Westmoreland and Greene Counties of Pennsylvania, and two related Marcellus wells both of which were producing from a third party. • On February 1, 2017, the Company acquired approximately 14,000 net Marcellus acres located in Marion, Monongalia and Wetzel Counties of West Virginia from a third party. • On February 27, 2017, the Company acquired approximately 85,000 net Marcellus acres, including drilling rights on approximately 44,000 net Utica acres and current natural gas production of approximately 110 MMcfe per day, from Stone Energy Corporation. The acquired acres are primarily located in Wetzel, Marshall, Tyler and Marion Counties of West Virginia. The acquired assets also included 174 Marcellus wells, 120 of which were producing at the time of the acquisition, and 20 miles of gathering pipeline. • On June 30, 2017, the Company acquired approximately 11,000 net Marcellus acres, and the associated Utica drilling rights, from a third party. The acquired acres are primarily located in Allegheny, Washington and Westmoreland Counties of Pennsylvania. In total, the Company paid net cash of $740.1 million during the year ended December 31, 2017 for the 2017 acquisitions previously described. The fair value assigned to the acquired property, plant and equipment from the 2017 acquisitions as of the opening balance sheet dates totaled $750.1 million . In connection with the 2017 acquisitions, the Company assumed $5.3 million of net current liabilities and $4.7 million of non-current liabilities. During the year ended December 31, 2017, the Company paid $78.9 million for additional undeveloped acreage as a result of post-closing adjustments on its 2016 acquisitions disclosed above and recorded other non-cash adjustments which reduced the fair values assigned to the acquired property, plant and equipment by $14.3 million . In total, the Company paid $1,130.1 million in net cash in connection with the 2016 acquisitions previously described. The fair value assigned to the acquired property, plant and equipment as of the opening balance sheet dates totaled $1,203.4 million : $256.2 million allocated to the acquired producing wells and $947.2 million allocated to undeveloped leases. In connection with the Trans Energy Merger, the Company also acquired $1.2 million of other non-current assets and assumed $14.4 million of current liabilities and $11.1 million of non-current liabilities. The $14.4 million of current liabilities included a $5.1 million note payable; the Company repaid this note in 2016. The Company also recorded a deferred tax liability of $49.0 million due to differences in the tax and book basis of the acquired assets and liabilities. Fair Value Measurement As these acquisitions qualified as business combinations under GAAP, the fair value of the acquired assets was determined using a market approach for the undeveloped acreage and a discounted cash flow model under the income approach for the wells. Significant unobservable inputs used in the analysis included the determination of estimated developed reserves and forward pricing estimates. As a result, valuation of the acquired assets was a Level 3 measurement. |
Revenue from Contracts with Cus
Revenue from Contracts with Customers | 12 Months Ended |
Dec. 31, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Revenue from Contracts with Customers | Revenue from Contracts with Customers As discussed in Note 1 , the Company adopted ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) , on January 1, 2018 using the modified retrospective method of adoption. Adoption of the ASU did not require an adjustment to the opening balance of equity and did not materially change the Company's amount and timing of revenues. The Company applied the ASU only to contracts that were not completed as of January 1, 2018. The Company has elected to exclude all taxes from the measurement of transaction price. For the sale of natural gas, oil and NGLs, 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 gas 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 contain fixed consideration (i.e. fixed price contracts or contracts with a fixed differential to New York Mercantile Exchange (NYMEX) or index prices). 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, oil and NGLs are satisfied at a point in time because the customer obtains control and legal title of the asset when the natural gas, oil or NGLs are delivered to the designated sales point. The sales of natural gas, oil and NGLs as presented on 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, oil and NGLs 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. Because the Company's performance obligations have been satisfied and an unconditional right to consideration exists as of the balance sheet date, the Company has recognized amounts due from contracts with customers of $783.0 million as accounts receivable within the Consolidated Balance Sheet. The table below provides disaggregated information regarding the Company’s revenues. Certain contracts that provide for the release of capacity that is not used to transport the Company’s produced volumes were deemed to be outside the scope of Revenue from Contracts with Customers. The cost of, and recoveries on, that capacity are reported within net marketing services and other. Derivative contracts are also outside the scope of Revenue from Contracts with Customers. Year Ended December 31, 2018 Revenues from contracts with customers Other sources of revenue Total (Thousands) Natural gas sales $ 4,217,684 $ — $ 4,217,684 NGLs sales 442,010 — 442,010 Oil sales 35,825 — 35,825 Sales of natural gas, oil and NGLs $ 4,695,519 $ — $ 4,695,519 Net marketing services and other 13,865 27,075 40,940 Loss on derivatives not designated as hedges — (178,591 ) (178,591 ) Total operating revenues (losses) $ 4,709,384 $ (151,516 ) $ 4,557,868 The following table includes the transaction price allocated to the Company's remaining performance obligations on all contracts with fixed consideration. The table excludes all contracts that qualified for the exception to the relative standalone selling price method. 2019 2020 Total (Thousands) Natural gas sales $ 54,116 $ 21,485 $ 75,601 |
Derivative Instruments
Derivative Instruments | 12 Months Ended |
Dec. 31, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments | Derivative Instruments The Company’s primary market risk exposure is the volatility of future prices for natural gas and NGLs, which can affect the operating results of the Company. The Company’s overall objective in its hedging program is to protect cash flows from undue exposure to the risk of changing commodity prices. The derivative commodity instruments currently utilized by the Company are primarily fixed price swap agreements, collar agreements and option agreements which 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 in implementing its commodity hedging strategy. The Company may engage in interest rate swaps to hedge exposure to fluctuations in interest rates. The Company’s over the counter (OTC) derivative commodity instruments are typically placed with financial institutions and the creditworthiness of all counterparties is regularly monitored. 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. The Company discontinued cash flow hedge accounting in 2014; therefore, all changes in fair value of the Company’s derivative instruments are recognized within operating revenues in the Statements of Consolidated Operations. In connection with the Rice Merger, the Company assumed all outstanding derivative commodity instruments held by Rice. The assets and liabilities assumed were recognized at fair value at the closing date and subsequent changes in fair value were recognized within operating revenues in the Statements of Consolidated Operations. The derivative commodity instruments assumed were substantially similar to instruments previously held by the Company. Contracts which result in physical delivery of a commodity expected to be sold by the Company in the normal course of business are designated as normal sales and are exempt from derivative accounting. If contracts that result in the physical receipt or delivery of a commodity are not designated or do not meet all the criteria to qualify for the normal purchase and normal sale scope exception, then the contracts are subject to derivative accounting. OTC arrangements require settlement in cash. The Company also enters into exchange traded derivative commodity instruments that are generally settled with offsetting positions. Settlements of derivative commodity instruments are reported as a component of cash flows from operations in the accompanying Statements of Consolidated Cash Flows. With respect to the derivative commodity instruments held by the Company, the Company hedged portions of expected sales of equity production and portions of its basis exposure covering approximately 3,128 Bcf of natural gas and 1,505 Mbbls of NGLs as of December 31, 2018 , and 2,148 Bcf of natural gas and 1,460 Mbbls of NGLs as of December 31, 2017 . The open positions at December 31, 2018 and December 31, 2017 had maturities extending through December 2024 and December 2022, respectively. When the net fair value of any of the Company’s swap agreements represents a liability to the Company which is in excess of the agreed-upon threshold between the Company and the counterparty, the counterparty requires the Company to remit funds as a margin deposit for the derivative liability which 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 which is in excess of the agreed-upon threshold between the Company and the counterparty, the Company requires the counterparty to remit funds as margin deposits in an amount equal to the portion of the derivative asset which 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 as of December 31, 2018 or 2017. 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 as well as the net liability position, if any, of the fair value of the associated contracts. The Company records these deposits as a current asset in the Consolidated Balance Sheets. In the case where the fair value of such contracts is in a net asset position, the broker may remit funds to the Company, in which case the Company records a current liability for such amounts received. The initial margin requirements are established by the exchanges based on the price, volatility and the time to expiration of the related contract. The margin requirements are subject to change at the exchanges’ discretion. The Company recorded current assets of $40.3 million as of December 31, 2018 for such deposits in its Consolidated Balance Sheets. The Company had no such deposits in its Consolidated Balance Sheets as of December 31, 2017. 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 as of December 31, 2018 and 2017 . As of December 31, 2018 Derivative instruments, recorded in the Consolidated Balance Sheet, gross Derivative instruments subject to master netting agreements Margin deposits remitted to counterparties Derivative instruments, net (Thousands) Asset derivatives: Derivative instruments, at fair value $ 481,654 $ (256,087 ) $ — $ 225,567 Liability derivatives: Derivative instruments, at fair value $ 336,051 $ (256,087 ) $ (40,283 ) $ 39,681 As of December 31, 2017 Derivative instruments, recorded in the Consolidated Balance Sheet, gross Derivative instruments subject to master netting agreements Margin deposits remitted to counterparties Derivative instruments, net (Thousands) Asset derivatives: Derivative instruments, at fair value $ 241,952 $ (86,856 ) $ — $ 155,096 Liability derivatives: Derivative instruments, at fair value $ 139,089 $ (86,856 ) $ — $ 52,233 Certain of the Company’s derivative instrument contracts provide that if the Company’s credit ratings by Standard & Poor’s Ratings Service (S&P) or Moody’s Investors Service (Moody's) are lowered below investment grade, additional collateral must be deposited with the counterparty if the amounts outstanding on those contracts exceed certain thresholds. The additional collateral can be up to 100% of the derivative liability. As of December 31, 2018 , the aggregate fair value of all derivative instruments with credit risk-related contingent features that were in a net liability position was $110.7 million , for which the Company had no collateral posted on December 31, 2018 . If the Company’s credit rating by S&P or Moody’s had been downgraded below investment grade on December 31, 2018 , the Company would not have been required to post any additional collateral under the agreements with the respective counterparties. The required margin on the Company's derivative instruments is subject to significant change as a result of factors other than credit rating, such as gas prices and credit thresholds set forth in agreements between the hedging counterparties and the Company. Investment grade refers to the quality of the Company’s credit as assessed by one or more credit rating agencies. The Company’s senior unsecured debt was rated BBB- by S&P and Baa3 by Moody’s at December 31, 2018 . In order to be considered investment grade, the Company must be rated BBB- or higher by S&P and Baa3 or higher by Moody’s. Anything below these ratings is considered non-investment grade. See also "Security Ratings and Financing Triggers" under Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations." |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | 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 using quoted market prices, where available. If quoted market prices are not available, fair value is based upon 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 of a risk-free instrument and credit default swaps rates where available. 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 utilized by the option pricing models include NYMEX forward curves, natural gas volatilities and LIBOR-based discount rates. The NYMEX natural gas forward curves, LIBOR-based discount rates, natural gas volatilities, basis forward curves and NGLs forward curves are validated to external sources at least monthly. The following assets and liabilities were measured at fair value on a recurring basis during the applicable period: Fair value measurements at reporting date using Description As of December 31, 2018 Quoted prices in active markets for identical assets (Level 1) Significant other observable inputs (Level 2) Significant unobservable inputs (Level 3) (Thousands) Assets Derivative instruments, at fair value $ 481,654 $ 112,107 $ 369,547 $ — Liabilities Derivative instruments, at fair value $ 336,051 $ 126,582 $ 209,469 $ — Fair value measurements at reporting date using Description As of December 31, 2017 Quoted prices in active markets for identical assets (Level 1) Significant other observable inputs (Level 2) Significant unobservable inputs (Level 3) (Thousands) Assets Derivative instruments, at fair value $ 241,952 $ — $ 241,952 $ — Liabilities Derivative instruments, at fair value $ 139,089 $ — $ 139,089 $ — The carrying values of cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term maturity of the instruments. The carrying value of the Equitrans Midstream investment approximates fair value as it was based on the closing stock price of Equitrans Midstream common stock multiplied by the number of shares of common stock of Equitrans Midstream owned by the Company. The carrying values of borrowings under the Company's credit facility approximate fair value as the interest rates are based on prevailing market rates. The Company also has an immaterial investment in a fund that invests in companies developing technology and operating solutions for exploration and production companies for which it recognized a cumulative effect of accounting change in the first quarter 2018. The investment is valued using the net asset value as a practical expedient as provided in the financial statements received from fund managers. The Company estimates the fair value of its Senior Notes using its 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. The estimated fair value of Senior Notes on the Consolidated Balance Sheets at December 31, 2018 and 2017 was approximately $4.4 billion and $4.7 billion , respectively. The carrying value of Senior Notes on the Consolidated Balance Sheets at December 31, 2018 and 2017 was approximately $4.6 billion for both periods. The fair value of the note payable to EQM is a Level 3 fair value measurement which is estimated using an income approach model utilizing a market-based discount rate. The estimated fair value of the note payable to EQM on the Consolidated Balance Sheets at December 31, 2018 and 2017 was approximately $121.8 million and $133.0 million , respectively. The carrying value of the note payable to EQM on the Consolidated Balance Sheets at December 31, 2018 and 2017 was approximately $114.7 million and $119.1 million , respectively. Refer to Note 10 for further information regarding the Company's debt as of December 31, 2018 and 2017 . The Company recognizes transfers between Levels as of the actual date of the event or change in circumstances that caused the transfer. There were no transfers between Levels 1, 2 and 3 during the periods presented. For information on the fair values of assets related to the impairments of proved and unproved oil and gas properties and of other long-lived assets, the assets acquired in the Rice Merger and the assets acquired in other acquisition transactions, see Notes 1 , 3 , and 7 . |
Acquisitions
Acquisitions | 12 Months Ended |
Dec. 31, 2018 | |
Business Combinations [Abstract] | |
Acquisitions | Rice Merger On November 13, 2017 , the Company completed its previously announced acquisition of Rice Energy Inc. (Rice) pursuant to the Agreement and Plan of Merger, dated as of June 19, 2017 (as amended, the Merger Agreement), by and among the Company, Rice and a wholly owned indirect subsidiary of the Company (RE Merger Sub). Pursuant to the terms of the Merger Agreement, on November 13, 2017, RE Merger Sub merged with and into Rice (the Rice Merger) with Rice continuing as the surviving corporation and a wholly owned indirect subsidiary of the Company. Immediately after the effective time of the Rice Merger (the Effective Time), Rice merged with and into another wholly owned indirect subsidiary of the Company. At the Effective Time, each share of the common stock, par value $0.01 per share, of Rice (the Rice Common Stock) issued and outstanding immediately prior to the Effective Time was converted into the right to receive 0.37 (the Exchange Ratio) of a share of the common stock, no par value, of the Company (Company Common Stock) and $5.30 in cash (collectively, the Merger Consideration). The aggregate Merger Consideration consisted of approximately 91 million shares of Company Common Stock and approximately $1.6 billion in cash (net of cash acquired and inclusive of amounts payable to employees of Rice who did not continue with the Company following the Effective Time). See Note 13 for further details. In connection with the closing of the Rice Merger, the Company paid an aggregate of $555.5 million , included in the cash paid for the Merger Consideration of approximately $1.6 billion (net of cash acquired and inclusive of amounts payable to employees of Rice who did not continue with the Company following the Effective Time), to affiliates of EIG Global Energy Partners (collectively, the EIG Funds) to redeem the EIG Funds' respective interests in Rice Midstream Holdings LLC (Rice Midstream Holdings) and Rice Midstream GP Holdings, LP (the EIG Redemptions). Following the EIG Redemptions, each of Rice Midstream Holdings and Rice Midstream GP Holdings, LP became indirect wholly owned subsidiaries of the Company. In connection with the closing of the Rice Merger, the Company repaid the $321.0 million of outstanding principal under Rice Energy Operating LLC's revolving credit facility and the $187.5 million of outstanding principal under Rice Midstream Holdings' revolving credit facility, together with interest and fees of $1.4 million and $0.3 million , respectively, and the credit agreements were terminated. Also in connection with the Rice Merger, Rice redeemed and canceled all of its outstanding 6.25% Senior Notes due 2022 (the Rice 2022 Notes) and 7.25% Senior Notes due 2023 (the Rice 2023 Notes) on November 13, 2017. The Company made aggregate payments of $1.4 billion in connection with the note redemptions, including make whole call premiums of $42.2 million and $21.6 million for the Rice 2022 Notes and the Rice 2023 Notes, respectively, and $13.4 million of required interest payments on the Rice 2023 Notes. The Company acquired a total of approximately 270,000 net acres through the Rice Merger, which included approximately 205,000 net Marcellus acres, as well as approximately 65,000 net Utica acres in Ohio. The Company also acquired Upper Devonian and Utica drilling rights held in Pennsylvania. The Company recorded $25.4 million and $152.2 million in transaction costs in continuing operations and $13.5 million and $85.1 million in discontinued operations related to the Rice Merger during the years ended December 31, 2018 and 2017, respectively. Also, in 2017, the Company expensed $8.0 million in debt issuance costs related to a bridge financing commitment to support the Rice Merger, $5.1 million of which is in continuing operations and $2.9 million of which is in discontinued operations. Allocation of Purchase Price The Rice Merger was accounted for as a business combination, using the acquisition method. The following table summarizes the final purchase price and fair values of assets and liabilities assumed as of November 13, 2017 , with any excess of the purchase price over the fair value of the identified net assets acquired recorded as goodwill. Variances between the preliminary and final purchase price allocations related to standard closing purchase price adjustments. Final Purchase Price Allocation (Thousands) Consideration Given: Equity consideration $ 5,943,289 Cash consideration 1,299,407 Buyout of preferred equity in Rice Midstream Holdings 429,708 Buyout of common units in Rice Midstream GP Holdings, LP 125,828 Settlement of pre-existing relationships (14,699 ) Total consideration 7,783,533 Fair value of liabilities assumed: Current liabilities 577,053 Long-term debt 2,151,656 Deferred income taxes 1,106,773 Other long term liabilities 95,712 Amount attributable to liabilities assumed 3,931,194 Fair value of assets acquired: Cash 294,671 Accounts receivable 322,630 Current assets 109,465 Net property, plant and equipment 9,918,315 Intangible assets 747,300 Noncontrolling interests (1,715,611 ) Amount attributable to assets acquired 9,676,770 Goodwill from Rice Merger $ 2,037,957 Goodwill impairment - continuing operations (530,811 ) Goodwill impairment - discontinued operations (267,878 ) Goodwill allocated to discontinued operations (a) (1,239,268 ) Goodwill as of December 31, 2018 $ — (a) In conjunction with the Rice Merger, the Company had unamortized carryover tax basis of $387.1 million of tax deductible goodwill, of which the entire amount relates to discontinued operations. The fair values of natural gas and oil properties were based on inputs that were not observable in the market and therefore represent Level 3 inputs. The fair values of natural gas and oil properties were measured using valuation techniques that convert future cash flows into a single discounted amount. Significant inputs to the valuation of natural gas and oil properties included estimates of: (i) recoverable reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average cost of capital. These inputs had a significant impact on the valuation of oil and gas properties. The fair value of undeveloped property was determined based upon a market approach of comparable transactions using Level 3 inputs. The estimated fair value of midstream facilities and equipment, generally consisting of pipeline systems and compression stations, is estimated using the cost approach. Significant unobservable inputs in the estimate of fair value include management’s assumptions about the replacement costs for similar assets, the relative age of the acquired assets and any potential economic or functional obsolescence associated with the acquired assets. As a result, the estimated fair value of the midstream facilities and equipment represents a Level 3 fair value measurement. The non-controlling interest in the acquired business was comprised of the limited partner units in Rice Midstream Partners LP (RMP) which were not acquired by the Company as well as the non-controlling interest in Strike Force Midstream LLC (Strike Force Midstream). The RMP limited partner units were actively traded on the New York Stock Exchange, and were valued based on observable market prices as of the transaction date and therefore represent a Level 1 fair value measurement. The non-controlling interest in Strike Force Midstream was calculated based on the enterprise value of Strike Force Midstream and the percentage ownership not acquired by the Company. Significant unobservable inputs in the estimate of the enterprise value of Strike Force Midstream include the future revenue estimates and future cost assumptions. As a result, the non-controlling interest in Strike Force Midstream represents a Level 3 fair value measurement. The Company identified intangible assets for customer relationships with third party customers and non-compete agreements with certain former Rice executives. The fair value of the identified intangible assets was determined using the income approach which requires a forecast of the expected future cash flows generated and an estimated market-based weighted average cost of capital. Significant unobservable inputs in the determination of fair value include future production levels, future revenues estimates, future cost assumptions, the estimated probability that former executives would compete in the absence of such non-compete agreements and estimated customer retention rates. As a result, the estimated fair value of the identified intangible assets represents a level 3 fair value measurement. Acquisitions In addition to the Rice Merger discussed in Note 3 , the Company executed multiple transactions during 2016 and 2017 that resulted in the Company's acquisition of approximately 304,000 net Marcellus acres, including the transactions listed below: • On July 8, 2016, the Company acquired approximately 62,500 net Marcellus acres and 31 Marcellus wells, 24 of which were producing, from Statoil USA Onshore Properties, Inc. The net acres acquired are primarily located in Wetzel, Tyler and Harrison Counties of West Virginia. • In the fourth quarter of 2016, the Company acquired approximately 42,600 net Marcellus acres and 42 Marcellus wells, 32 of which were producing at the time of the acquisition, which were being jointly developed by Trans Energy, Inc. (Trans Energy) and Republic Energy Ventures, LLC and its affiliates (collectively, Republic). The net acres acquired are primarily located in Wetzel, Marshall and Marion Counties of West Virginia. The acquisitions were effected through simultaneous transaction agreements that were executed on October 24, 2016 including: (i) a purchase and sale agreement between the Company and Republic; and (ii) an agreement and plan of merger among the Company, a wholly owned subsidiary of the Company (TE Merger Sub) and Trans Energy. The Republic acquisition closed on November 3, 2016. On October 27, 2016, the Company commenced a tender offer, through its wholly owned subsidiary, to acquire the outstanding shares of common stock of Trans Energy, a publicly traded company, at an offer price of $3.58 per share in cash. Following the tender offer on December 5, 2016, TE Merger Sub merged with and into Trans Energy, at which time Trans Energy became an indirect wholly owned subsidiary of the Company (the Trans Energy Merger). • On December 16, 2016, the Company acquired approximately 17,000 net Marcellus acres located in Washington, Westmoreland and Greene Counties of Pennsylvania, and two related Marcellus wells both of which were producing from a third party. • On February 1, 2017, the Company acquired approximately 14,000 net Marcellus acres located in Marion, Monongalia and Wetzel Counties of West Virginia from a third party. • On February 27, 2017, the Company acquired approximately 85,000 net Marcellus acres, including drilling rights on approximately 44,000 net Utica acres and current natural gas production of approximately 110 MMcfe per day, from Stone Energy Corporation. The acquired acres are primarily located in Wetzel, Marshall, Tyler and Marion Counties of West Virginia. The acquired assets also included 174 Marcellus wells, 120 of which were producing at the time of the acquisition, and 20 miles of gathering pipeline. • On June 30, 2017, the Company acquired approximately 11,000 net Marcellus acres, and the associated Utica drilling rights, from a third party. The acquired acres are primarily located in Allegheny, Washington and Westmoreland Counties of Pennsylvania. In total, the Company paid net cash of $740.1 million during the year ended December 31, 2017 for the 2017 acquisitions previously described. The fair value assigned to the acquired property, plant and equipment from the 2017 acquisitions as of the opening balance sheet dates totaled $750.1 million . In connection with the 2017 acquisitions, the Company assumed $5.3 million of net current liabilities and $4.7 million of non-current liabilities. During the year ended December 31, 2017, the Company paid $78.9 million for additional undeveloped acreage as a result of post-closing adjustments on its 2016 acquisitions disclosed above and recorded other non-cash adjustments which reduced the fair values assigned to the acquired property, plant and equipment by $14.3 million . In total, the Company paid $1,130.1 million in net cash in connection with the 2016 acquisitions previously described. The fair value assigned to the acquired property, plant and equipment as of the opening balance sheet dates totaled $1,203.4 million : $256.2 million allocated to the acquired producing wells and $947.2 million allocated to undeveloped leases. In connection with the Trans Energy Merger, the Company also acquired $1.2 million of other non-current assets and assumed $14.4 million of current liabilities and $11.1 million of non-current liabilities. The $14.4 million of current liabilities included a $5.1 million note payable; the Company repaid this note in 2016. The Company also recorded a deferred tax liability of $49.0 million due to differences in the tax and book basis of the acquired assets and liabilities. Fair Value Measurement As these acquisitions qualified as business combinations under GAAP, the fair value of the acquired assets was determined using a market approach for the undeveloped acreage and a discounted cash flow model under the income approach for the wells. Significant unobservable inputs used in the analysis included the determination of estimated developed reserves and forward pricing estimates. As a result, valuation of the acquired assets was a Level 3 measurement. |
Divestitures
Divestitures | 12 Months Ended |
Dec. 31, 2018 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Divestitures | Divestitures On June 19, 2018, the Company sold its non-core Permian Basin assets located in Texas for net proceeds of $56.9 million (the Permian Divestiture). The assets sold in the Permian Divestiture included approximately 970 productive wells with current net production of approximately 20 MMcfe per day, approximately 350 miles of low-pressure gathering lines and 26 compressors. On July 18, 2018, the Company sold approximately 2.5 million non-core, net acres in the Huron play for net proceeds of $523.6 million , subject to final purchase price adjustments (the Huron Divestiture). The assets sold in the Huron Divestiture included approximately 12,000 productive wells with current net production of approximately 200 MMcfe per day, approximately 6,400 miles of low-pressure gathering lines and 59 compressor stations. The Company retained the deep drilling rights across the divested acreage. As a result of these divestitures in 2018, the Company recorded an impairment/loss on sale of long-lived assets of $2.4 billion associated with the production and related midstream assets in the Huron and Permian plays. The impairment of these properties and related pipeline assets recorded was due to the carrying value of the assets exceeding the amounts received upon the closing of the transactions. See Note 1 for the Company's policy on impairment of proved and unproved properties. In connection with the closing of the Huron Divestiture, the Company also recorded a loss of $260.5 million related to certain capacity contracts that the Company no longer has existing production to satisfy and does not plan to utilize in the future. The loss was recorded in the impairment/loss on sale of long-lived assets within the Statements of Consolidated Operations. The fair value of the loss for the initial measurement was based upon significant inputs that were 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, if any, of potential future economic benefit from the contracts. See Note 6 for a description of the fair value hierarchy. On December 28, 2016, the Company sold a gathering system that primarily gathered gas for third-parties for $75.0 million . In conjunction with this transaction, the Company realized a pre-tax gain of $8.0 million , which is included in gain on sale of assets in the Statements of Consolidated Operations. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes Income tax (benefit) expense is summarized as follows: Years Ended December 31, 2018 2017 2016 (Thousands) Current: Federal $ (513,293 ) $ (89,149 ) $ (181,817 ) State (46,218 ) (5,184 ) (22,627 ) Subtotal (559,511 ) (94,333 ) (204,444 ) Deferred: Federal 20,496 (1,039,769 ) (110,734 ) State (157,496 ) (54,314 ) (47,591 ) Subtotal (137,000 ) (1,094,083 ) (158,325 ) Total income taxes $ (696,511 ) $ (1,188,416 ) $ (362,769 ) The Company recorded a current federal income tax benefit in 2018 which primarily consisted of approximately $141 million related to the refund it expects to receive as a result of its AMT credit carryforward and the Tax Cuts and Jobs Act and $16 million of current state tax expense. The current federal income tax benefit in 2017 primarily consisted of approximately $65 million related to refunds due to the Company as a result of amended returns it has filed to carry back federal and alternative minimum tax (AMT) net operating losses (NOLs) generated in 2016 and 2017. The current federal income tax benefit in 2016 consisted of approximately $83 million primarily related to amended return refund claims filed in 2016 and 2017 for open tax years 2010 through 2013. For all periods presented, the remaining current tax benefit of $435 million in 2018, $29 million in 2017 and $121 million in 2016 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 ASC 740, Income Taxes, for the following aspects: remeasurement of deferred tax assets and liabilities and incentive-based compensation limitations. At December 31, 2018, the Company completed the accounting for all the enactment-date income tax effects of the Tax Cuts and Jobs Act. During 2018, the Company recognized adjustments of $5.3 million to the provisional amounts recorded at December 31, 2017 and included these adjustments as a component of income tax expense from continuing operations. The additional expense is primarily the 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 has resulted in the Company paying AMT in periods when no other federal taxes were currently payable. The Tax Cuts and Jobs Act also repealed the AMT for tax years beginning January 1, 2018 and provides that existing AMT credit carryforwards can be utilized 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. The Company expects to receive a refund of $128 million of AMT credits relating to its 2018 tax return. The current income tax receivable at December 31, 2018 also includes expected refunds of $11 million relating to NOL carryback claims. As of December 31, 2018, there is $295 million of AMT credit carryforward remaining, net of valuation allowances for sequestration of $13 million . As a result of an announcement by the IRS in January 2019 reversing 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 will reverse the related valuation allowance in the first quarter of 2019. The Tax Cuts and Jobs Act also limits the deductibility of interest expense. As a result, the Company recorded a valuation allowance in 2018 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 the amounts carried back to prior years. The Company also has NOLs acquired in the Trans Energy Merger, of which a nominal amount is available to be utilized annually over the next 20 years. The Tax Cuts and Jobs Act limits the utilization of NOLs generated after December 31, 2017 that are carried forward into future years to 80% of taxable income and eliminates 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) expense from continuing operations differed from amounts computed at the federal statutory rate of 21% for 2018 and 35% for 2017 and 2016 on pre-tax income as follows: Years Ended December 31, 2018 2017 2016 (Thousands) Tax at statutory rate $ (646,261 ) $ 69,515 $ (312,992 ) Federal tax reform 5,288 (1,205,140 ) — State income taxes (251,780 ) (57,414 ) (76,043 ) Valuation allowance 88,785 10,680 23,808 Regulatory liability/asset (276 ) 10,488 — Federal tax credits (2,400 ) (34,956 ) (4,539 ) Goodwill impairment 111,470 — — Other (1,337 ) 18,411 6,997 Income tax (benefit) expense $ (696,511 ) $ (1,188,416 ) $ (362,769 ) Effective tax rate 22.6 % (598.4 )% 40.6 % The effective tax rate for the year ended December 31, 2018 was higher than the U.S. federal statutory rate primarily as a result of 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 continuing operations goodwill impaired during 2018. The effective tax rate for the year ended December 31, 2017 was lower than the U.S. federal statutory rate primarily due to the effect of the Tax Cuts and Jobs Act. The primary impact of the Tax Cuts and Jobs Act on the Company's effective tax rate was to revalue the Company's net deferred tax liability at the new corporate tax rate of 21% . The effective tax rate was also lower due to the federal tax credits generated during the year, which increased 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 the Company was unable to estimate the amount of this credit in 2016 absent the IRS notice. 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 a $10.5 million tax expense associated with FERC regulated assets as a result of the corporate tax rate reduction in 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 as part of discontinued operations. The effective tax rate for the year ended December 31, 2016 was higher than the U.S. federal statutory rate of 35% primarily due to the tax benefit generated from pre-tax loss on state income tax paying entities. 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, 2018, 2017 and 2016, positive evidence considered included 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 utilize them prior to expiration. Uncertainties such as future commodity prices can affect the Company's calculations and its ability to utilize these NOLs prior to expiration. Further, the Tax Cuts and Jobs Act resulted in the Company recording a valuation allowance against a deferred tax asset related to the interest expense limitation for separate company state income tax purposes. The Tax Cuts and Jobs Act also required the Company to write-off a deferred tax asset recorded for certain incentive-based awards to be paid in a future year. Management will continue to assess the potential for realizing deferred tax assets based upon income forecast data and 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): 2018 2017 2016 (Thousands) Balance at January 1 $ 301,558 $ 252,434 $ 259,301 Additions based on tax positions related to current year 8,459 50,469 23,978 Additions for tax positions of prior years 14,396 8,978 20,336 Reductions for tax positions of prior years (9,134 ) (10,323 ) (51,181 ) Balance at December 31 $ 315,279 $ 301,558 $ 252,434 Included in the balance above are unrecognized tax benefits that, if recognized, would affect the effective tax rate of $124.6 million , $120.5 million and $102.0 million as of December 31, 2018, 2017 and 2016, respectively. Additionally, there were uncertain tax positions included in the balance above of $88.2 million , $84.1 million , and $75.4 million for the years ended December 31, 2018, 2017 and 2016, respectively, that have been 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 state deferred tax asset was reduced for uncertain tax positions of approximately $0.3 million and $0.5 million during the years ended December 31, 2017 and 2016, respectively. Included in the tabular reconciliation above at December 31, 2018 , 2017 and 2016 are $0.7 million , $4.7 million and $5.5 million , respectively, for tax positions for which the ultimate deductibility is highly certain but for which 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 $3.4 million , $3.2 million and $1.6 million for 2018, 2017 and 2016, respectively. Interest and penalties of $11.9 million , $8.4 million and $5.2 million were included in the Consolidated Balance Sheets at December 31, 2018 , 2017 and 2016 , respectively. As of December 31, 2018 , the Company believed that it is reasonably possible that a decrease of $33.3 million in unrecognized tax benefits related to federal tax positions may be necessary within 12 months as a result of potential settlements with, or legal or administrative guidance by, relevant taxing authorities or the lapse of applicable statutes of limitation. As of December 31, 2017, the Company believed that it is reasonably possible that a decrease of $42.5 million in unrecognized tax benefits related to federal tax positions may be necessary within 12 months. As of December 31, 2016, the Company did not expect any of its unrecognized tax benefits to decrease within the next 12 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 relating to R&E and AMT preference adjustments for the years 2010 through 2013. These claims are under review by the IRS. The Company also is the subject of various state income tax examinations. With few exceptions, as of December 31, 2018, 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 2018. The following table summarizes the source and tax effects of temporary differences between financial reporting and tax bases of assets and liabilities: As of December 31, 2018 2017 (Thousands) Deferred income taxes: Total deferred income tax assets $ (901,377 ) $ (1,112,514 ) Total deferred income tax liabilities 2,724,758 3,002,476 Total net deferred income tax liabilities 1,823,381 1,889,962 Total deferred income tax liabilities (assets): Drilling and development costs expensed for income tax reporting 1,469,320 2,074,091 Tax depreciation in excess of book depreciation 904,030 644,590 Investment in Equitrans Midstream (10,359 ) — Incentive compensation and deferred compensation plans (24,682 ) (43,822 ) Net operating loss carryforwards (429,983 ) (564,180 ) Alternative minimum tax credit carryforward (308,727 ) (435,190 ) Federal tax credits (37,710 ) (50,341 ) Unrealized (losses) gains (28,096 ) 21,403 Interest disallowance limitation (35,358 ) — Other (26,462 ) (18,981 ) Total excluding valuation allowances 1,471,973 1,627,570 Valuation allowances 351,408 262,392 Total net deferred income tax liabilities $ 1,823,381 $ 1,889,962 The net deferred tax liability decreased $66.6 million primarily due to the 2018 Divestitures, partially offset by an increase in tax depreciation in excess of book during the current year, utilization of Federal net operating losses, and refund of AMT credit carryovers. 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. On October 30, 2017, Pennsylvania enacted a change in the limitation on Pennsylvania NOL utilization to 35% of taxable income from 30% of taxable income for tax years beginning in 2018 and to 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. The IRS announced in January 2019 that it was reversing its prior position that AMT refunds were subject to sequestration by the federal government at a rate equal to 6.2% of the refund. As a result, the Company will reverse this 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. |
Debt
Debt | 12 Months Ended |
Dec. 31, 2018 | |
Debt Disclosure [Abstract] | |
Debt | Debt December 31, 2018 December 31, 2017 Principal Value Carrying Value (a) Fair Value (b) Principal Value Carrying Value (a) Fair (Thousands) 8.13% Notes, due June 1, 2019 $ 700,000 $ 699,729 $ 712,663 $ 700,000 $ 698,918 $ 755,153 Floating Rate Notes due October 1, 2020 500,000 498,222 490,730 500,000 497,206 501,325 2.50% Notes due October 1, 2020 500,000 498,198 489,690 500,000 497,169 497,670 4.88% Notes, due November 15, 2021 750,000 746,245 762,555 750,000 744,920 801,953 3.00% Notes due October 1, 2022 750,000 743,972 712,980 750,000 742,364 743,550 7.75% debentures, due July 15, 2026 115,000 111,229 128,808 115,000 110,732 135,024 3.90% Notes due October 1, 2027 1,250,000 1,239,866 1,085,663 1,250,000 1,238,707 1,245,200 Medium-term notes: 7.42% Series B, due 2023 10,000 10,000 10,666 10,000 10,000 11,433 7.6% Series C, due 2018 — — — 8,000 7,999 8,012 8.8% to 9.0% Series A, due 2020 through 2021 35,200 35,200 37,920 35,200 35,187 40,510 Note payable to EQM 114,720 114,720 121,752 119,127 119,127 133,001 Total debt 4,724,920 4,697,381 4,553,427 4,737,327 4,702,329 4,872,831 Less current portion of debt 704,661 704,390 717,609 12,407 12,406 12,932 Long-term debt $ 4,020,259 $ 3,992,991 $ 3,835,818 $ 4,724,920 $ 4,689,923 $ 4,859,899 (a) For the note payable to EQM, the principal value represents the carrying value. For all other debt, the carrying value represents principal value less unamortized debt issuance costs and debt discounts. (b) For the note payable to EQM, fair value is measured using Level 3 inputs, as described below. For all other debt, fair value is measured using Level 2 inputs. 2017 Notes . In October 2017, the Company completed the public offering (the 2017 Notes Offering) of $500 million aggregate principal amount of Floating Rate Notes due 2020 (the Floating Rate Notes), $500 million aggregate principal amount of 2.50% Senior Notes due 2020, $750 million aggregate principal amount of 3.00% Senior Notes due 2022 and $1,250 million aggregate principal amount of 3.90% Senior Notes due 2027. The Company received net proceeds from the 2017 Notes Offering of approximately $2,974.2 million , which the Company used, together with other cash on hand and borrowings under the Company’s $2.5 billion credit facility, to fund the cash portion of the consideration for and expenses related to the Rice Merger and related transactions including the repayment of certain indebtedness of Rice and its subsidiaries, to redeem or repay $700 million of the Company's Senior Notes due in 2018 and for other general corporate purposes. As a result of redeeming or repaying $700 million of Company's Senior Notes due in 2018, the Company recorded loss on debt extinguishment of $12.6 million , which included the make whole call premiums and the write-off of unamortized deferred financing costs. 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. The covenants do not contain a rating trigger. Therefore, a change in the Company’s debt rating would not trigger a default under the indentures governing the indebtedness. Aggregate maturities of Senior Notes are $700.0 million in 2019 , $1,011.2 million in 2020 , $774.0 million in 2021 , $750.0 million in 2022 , $10.0 million in 2023 and $1,365.0 million in 2024 and thereafter. Note Payable to EQM . In April 2015, EQM acquired a preferred interest in EQT Energy Supply, LLC (EES). In October 2016, the operating agreement of EES was amended and the accounting for the preferred interest in EES converted to a note payable. Prior to the Separation and Distribution, the note payable to EQM was eliminated in consolidation. The fair value of the note payable to EQM is a Level 3 fair value measurement which is estimated using an income approach model utilizing a market-based discount rate. Principal amounts due are $4.7 million in 2019 , $5.0 million in 2020 , $5.2 million in 2021 , $5.5 million in 2022 , $5.8 million in 2023 and $88.5 million in 2024 and thereafter. $2.5 Billion Facility. The Company has a $2.5 billion revolving 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. Subject to certain terms and 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 . 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 then current credit ratings. Eurodollar rate loans bear interest at a Eurodollar rate plus a margin based on the Company’s then current credit ratings. The Company is not required to maintain compensating bank balances. The Company’s debt issuer credit ratings, as determined by S&P, Moody’s or Fitch Ratings Service (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 had $0.8 billion and $1.3 billion of borrowings and zero and $159.4 million letters of credit outstanding under its credit facility as of December 31, 2018 and 2017 , respectively. The Company incurred commitment fees averaging approximately 20 , 20 and 23 basis points for the years ended December 31, 2018 , 2017 and 2016 , respectively, to maintain credit availability under its credit facility. During 2018 and 2017 , the maximum amounts of outstanding borrowings at any time under the credit facility were $1.6 billion and $1.4 billion , respectively, the average daily balances were approximately $854 million and $191 million , respectively, and interest was incurred at weighted average annual interest rates of 3.4% and 2.8% , respectively. The Company had no borrowings or letters of credit outstanding under its revolving credit facility at any time during the year ended December 31, 2016 . 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 relate to 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 this ratio excludes the effects of accumulated OCI. As of December 31, 2018 , the Company was in compliance with all debt provisions and covenants. |
Changes in Accumulated Other Co
Changes in Accumulated Other Comprehensive Income (Loss) by Component | 12 Months Ended |
Dec. 31, 2018 | |
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract] | |
Changes in Accumulated Other Comprehensive Income (Loss) by Component | Changes in Accumulated Other Comprehensive Income (Loss) by Component The following tables explain the changes in accumulated OCI by component for the three years ended December 31, 2018 , 2017 , and 2016 . Accumulated OCI (loss), net of tax Natural gas cash flow hedges, net of tax Interest rate cash flow hedges, net of tax Pension and other post- retirement benefits liability adjustment, net of tax Distribution of Equitrans Midstream Corporation Accumulated OCI (loss), net of tax (Thousands) As of December 31, 2015 $ 64,762 $ (843 ) $ (17,541 ) $ — $ 46,378 (Gains) losses reclassified from accumulated OCI, net of tax (55,155 ) (a) 144 (a) 10,675 (b) — (44,336 ) As of 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 ) As of 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) 903 (2,948 ) As of December 31, 2018 $ — $ (387 ) $ (5,922 ) $ 903 $ (5,406 ) (a) Gains (losses) reclassified from accumulated OCI, net of tax related to natural gas cash flow hedges were reclassified into operating revenues. Losses from accumulated OCI, net of tax related to interest rate cash flow hedges were reclassified into interest expense. (b) This accumulated OCI reclassification is attributable to the net actuarial loss and net prior service cost related to the Company’s defined benefit pension plans and other post-retirement benefit plans. See Note 1 for additional information. |
Common Stock and Treasury Stock
Common Stock and Treasury Stock | 12 Months Ended |
Dec. 31, 2018 | |
Earnings Per Share [Abstract] | |
Common Stock and Treasury Stock | Common Stock and Treasury Stock Common Stock At December 31, 2018 , shares of EQT’s authorized and unissued common stock were reserved as follows: (Thousands) Possible future acquisitions 20,457 Stock compensation plans 12,813 Total 33,270 In conjunction with the closing of the Rice Merger, the Company issued approximately 91 million shares of common stock on November 13, 2017. On February 19, 2016, the Company entered into an Underwriting Agreement with Goldman, Sachs & Co. (Goldman) under which the Company sold to Goldman 6,500,000 shares of common stock at a price to the public of $58.50 per share (the February Offering). On February 22, 2016, Goldman exercised its option within the Underwriting Agreement to purchase an additional 975,000 shares of common stock on the same terms. The February Offering closed on February 24, 2016, and the Company received net proceeds of approximately $430.4 million , after deducting underwriting discounts and commissions and offering expenses. The Company used the net proceeds from the February Offering for general corporate purposes. On May 2, 2016, the Company entered into an Underwriting Agreement with Credit Suisse Securities (USA) LLC and J.P. Morgan Securities LLC, as representatives of the several underwriters named in the Underwriting Agreement (the Underwriters), under which the Company sold to the Underwriters 10,500,000 shares of common stock at a price to the public of $67.00 per share (the May Offering). On May 3, 2016, the Underwriters exercised their option within the Underwriting Agreement to purchase an additional 1,575,000 shares of common stock on the same terms. The May Offering closed on May 6, 2016, and the Company received net proceeds of approximately $795.6 million after deducting underwriting discounts and commissions and offering expenses. The Company used a portion of the net proceeds from the May Offering to fund the acquisitions discussed in Note 7 and the remainder for general corporate purposes. During 2018, the Company repurchased 10,646,382 shares at an average price of $50.62 , which includes $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. Treasury Stock Effective as of December 31, 2015, the Company transferred 17.0 million shares of treasury stock from issued to authorized but unissued shares. Additionally, during the year ended December 31, 2015, the Company funded 291,919 shares of treasury stock into a rabbi trust for the 2005 Directors’ Deferred Compensation Plan and the 1999 Directors' Deferred Compensation Plan. As of December 31, 2017 , there were 253,145 shares of treasury stock in the rabbi trust. During 2018, the Company unfunded the rabbi trust and the treasury shares were transferred from authorized but unissued to unissued. No shares of treasury stock were held in the rabbi trust as of December 31, 2018 . |
Share-Based Compensation Plans
Share-Based Compensation Plans | 12 Months Ended |
Dec. 31, 2018 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Share-Based Compensation Plans | Share-Based Compensation Plans Share-based compensation expense recorded by the Company was as follows: Years Ended December 31, 2018 2017 2016 (Thousands) 2014 Executive Performance Incentive Program $ — $ — $ 9,494 2015 Executive Performance Incentive Program — 5,348 12,456 2016 Incentive Performance Share Unit Program 6,863 13,077 7,166 2017 Incentive Performance Share Unit Program 2,467 5,038 — 2018 Incentive Performance Share Unit Program 4,742 — — 2015 EQT Value Driver Award Program — — 3,174 2016 EQT Value Driver Performance Share Unit Award Program — 3,341 15,694 2017 EQT Value Driver Performance Share Unit Award Program 584 10,822 — 2018 EQT Value Driver Performance Share Unit Award Program 8,224 — — Restricted stock awards 14,503 87,104 9,407 Non-qualified stock options 2,757 2,626 3,119 Other programs, including non-employee director awards 3,014 1,005 5,459 Less: Discontinued operations (18,250 ) (15,595 ) (18,631 ) Total share-based compensation expense $ 24,904 $ 112,766 $ 47,338 In connection with the Separation, the Company transferred obligations related to share-based compensation awards outstanding 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, resulting in participants retaining one unit of the existing Company incentive award while receiving an additional 0.80 units of an Equitrans Midstream-based award and includes awards that will be share-settled and awards expected to be satisfied in cash, which are treated as liability awards. The Company recognizes compensation cost related to unvested awards held by it's employees, regardless of who settles the obligation. In accordance with the Employee Matters Agreement, the Company will be 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 at the vesting date. Likewise, Equitrans Midstream will be obligated to settle all of the outstanding share-based compensation awards denominated in its equity at the vesting date 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 pursuant to the Employee Matters Agreement. 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 awards may be funded 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. Cash received from exercises under all share-based payment arrangements for employees and directors for the years ended December 31, 2018, 2017 and 2016 was $1.9 million , $0.2 million and $5.0 million , respectively. During the years ended December 31, 2018 , 2017 and 2016 , share-based payment arrangements paid in stock generated tax benefits of $13.4 million , $58.9 million and $22.2 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 2014 Executive Performance Incentive Plan (2014 Incentive PSU Program) under the 2009 LTIP; • the 2015 Executive Performance Incentive Plan (2015 Incentive PSU Program) under the 2014 Long-Term Incentive Plan (2014 LTIP); • the 2016 Incentive Performance Share Unit Program (2016 Incentive PSU Program) under the 2014 LTIP; • the 2017 Incentive Performance Share Unit Program (2017 Incentive PSU Program) under the 2014 LTIP; and • the 2018 Incentive Performance Share Unit Program (2018 Incentive PSU Program) under the 2014 LITP. The 2014 Incentive PSU Program, the 2015 Incentive PSU Program, the 2016 Incentive PSU Program, the 2017 Incentive PSU Program and the 2018 Incentive PSU Program are collectively referred to as the Incentive PSU Programs. The 2014 Incentive PSU Program, the 2015 Incentive PSU Program and the 2016 Incentive PSU Program granted equity awards. The 2017 Incentive PSU Program and the 2018 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 2014 - 2017 were earned based upon: • 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 upon: • 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. For the years ending December 31, 2019 and 2020, the 2018 Incentive PSU Program awards will be earned based on new performance goals to be established by the Compensation Committee, subject to continued employment through the payment date. 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 2014 Incentive PSU Program, the 2015 Incentive PSU Program, the 2016 Incentive PSU Program and the portion of the 2017 Incentive PSU Program and the 2018 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 ending point of the performance period. The 2017 Incentive PSU Program and the 2018 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 ending 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 chart below for the 2017 Incentive PSU Program liability award, and two -year risk free rate shown in chart below for the 2018 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. The vesting of the units under each Incentive PSU Program occurs upon payment after the end of the performance period. More detailed information about 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, 2018 (b) 2014 Stock Equity $ 189.68 0.78% February 2017 238,060 $ 45.2 N/A N/A 2015 Stock Equity $ 141.11 1.10% February 2018 274,767 $ 38.8 N/A N/A 2016 (c) Stock Equity $ 109.30 1.31% N/A N/A N/A First Quarter of 2019 384,101 2017 (d) Stock Equity $ 120.60 1.47% N/A N/A N/A First Quarter of 2020 44,573 2017 (e) Cash Liability $ 59.90 2.61% N/A N/A N/A First Quarter of 2020 105,018 2018 (f) Stock Equity $ 76.53 1.97% N/A N/A N/A First Quarter of 2021 107,340 2018 (g) Cash Liability $ 33.30 2.46% N/A N/A N/A First Quarter of 2021 124,820 (a) Information shown for the valuation of the liability plans is as of December 31, 2018. (b) Represents the number of outstanding units as of December 31, 2018 adjusted for forfeitures. The 2016, 2017, and 2018 Incentive PSU Programs to be settled in stock include 130,393 , 7,020 , and 34,640 shares, respectively, for Equitrans Midstream employees that will be settled by the Company under the Employee Matters Agreement. The 2017 and 2018 Incentive PSU Programs to be settled in cash include 43,134 and 57,240 shares, respectively, for Equitrans Midstream employees that will be settled by the Company under the Employee Matters Agreement. (c) As of January 1, 2018 , a total of 447,145 units were outstanding under the 2016 Incentive PSU Program. Adjusting for 63,044 forfeitures, there were 384,101 outstanding units as of December 31, 2018 . (d) As of January 1, 2018, a total of 79,070 units were outstanding under the 2017 Incentive PSU Program - Equity. Adjusting for 34,497 forfeitures, there were 44,573 outstanding units as of December 31, 2018 . (e) As of January 1, 2018, a total of 117,530 units were outstanding under the 2017 Incentive PSU Program - Liability. Adjusting for 12,512 forfeitures, there were 105,018 total outstanding units as of December 31, 2018. (f) A total of 172,350 units were granted under the 2018 Incentive PSU Program - Equity in 2018 and no additional units may be granted. Adjusting for 65,010 forfeitures, there were 107,340 outstanding units as of December 31, 2018 . (g) A total of 142,890 units were granted under the 2018 Incentive PSU Program - Liability in 2018 and no additional units may be granted. Adjusting for 18,070 forfeitures, there were 124,820 total outstanding units as of December 31, 2018 . The following table sets forth the total compensation costs capitalized related to each of the Incentive PSU Programs: For the Years Ended December 31, Award 2018 2017 2016 (Millions) 2014 Incentive PSU Program $ — $ — $ 4.2 2015 Incentive PSU Program — 2.2 4.9 2016 Incentive PSU Program 2.1 4.4 3.3 2017 Incentive PSU Program (liability only) 1.0 1.7 — 2018 Incentive PSU Program (liability only) 0.6 — — As of December 31, 2018, $0.6 million , $2.0 million , $1.1 million and $3.0 million of unrecognized compensation cost (assuming no changes to the performance condition achievement level) related to the 2017 Incentive PSU Program - Equity, the 2017 Incentive PSU Program - Liability, the 2018 Incentive PSU Program - Equity and 2018 Incentive PSU Program - Liability, respectively, was expected to be recognized over the remainder of the performance periods. Fair value is estimated using a Monte Carlo simulation valuation method with the following weighted average assumptions: For Incentive PSU Programs Issued During the Years Ended December 31, 2018 2018 2017 2017 2016 2015 2014 Accounting Treatment Liability (a) Equity Liability (a) Equity Equity Equity Equity Risk-free rate 2.46% 1.97% 2.61% 1.47% 1.31% 1.10% 0.78% Dividend Yield (b) N/A N/A N/A N/A N/A N/A N/A Volatility factor 35.70% 32.60% 41.17% 32.30% 28.43% 27.45% 31.38% Expected term 2 years 3 years 1 year 3 years 3 years 3 years 3 years (a) Information shown for the valuation of the liability plans is as of December 31, 2018. (b) 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 2015 Value Driver Award Program (2015 EQT VDPSU Program) under the 2014 LTIP; • the 2016 Value Driver Performance Share Unit Award Program (2016 EQT VDPSU Program) under the 2014 LTIP; • the 2017 Value Driver Performance Share Unit Award Program (2017 EQT VDPSU Program) under the 2014 LTIP; and • the 2018 Value Driver Performance Share Unit Award Program (2018 EQT VDPSU Program) under the 2014 LTIP. The 2015 EQT VDPSU Program, the 2016 EQT VDPSU Program, the 2017 EQT VDPSU Program and the 2018 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 awards confirmed vest upon payment following the first anniversary of the grant date; the remaining 50% of the awards confirmed 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. More detailed information about each award is set forth in the table below: EQT VDPSU Program Settled In Accounting Treatment Fair Value per Unit (a) Vested/Payment Date Number of awards (including accrued dividends) or cash (Millions) paid Unvested/Expected Payment Date Awards Outstanding (including accrued dividends) as of December 31, 2018 (d) 2015 Stock Equity $ 75.70 February 2016 222,751 N/A N/A $ 75.70 February 2017 208,567 N/A N/A 2016 (b) 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 N/A N/A Second tranche first quarter of 2019 214,384 2018 (c) Cash Liability $ 18.89 N/A N/A First tranche first quarter of 2019 256,803 N/A N/A N/A Second tranche first quarter of 2020 257,254 (a) For equity awards, the fair value per unit is equal to the Company's closing common stock price on the business day prior to the grant date. For liability awards, the fair value per unit is equal to the Company's common stock price on the measurement date. (b) 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. (c) The total liability recorded for the 2018 EQT VDPSU Program was $1.7 million as of December 31, 2018 . (d) The 2017 and 2018 EQT VDPSU Programs include 95,452 and 135,345 awards, respectively, for Equitrans Midstream employees that will be settled by the Company under the Employee Matters Agreement. The following table sets forth the total compensation costs capitalized related to each of the VDPSU Programs: For the Years Ended December 31, Award 2018 2017 2016 (Millions) 2015 EQT VDPSU Program $ — $ — $ 4.1 2016 EQT VDPSU Program — 7.0 16.3 2017 EQT VDPSU Program 0.1 10.3 — 2018 EQT VDPSU Program 3.3 — — Restricted Stock Awards - Equity The Company granted 145,540 , 85,350 and 158,360 restricted stock equity awards during the years ended December 31, 2018 , 2017 and 2016, respectively, to key employees of the Company. The restricted stock 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 weighted average fair value of these restricted stock grants, based on the grant date fair value of the Company’s common stock, was approximately $54.33 , $63.00 and $75.00 for the years ended December 31, 2018 , 2017 and 2016, respectively. The Company granted 7,900 restricted stock equity awards during the year ended December 31, 2016 to its then Chief Financial Officer. The restricted shares granted were fully vested at the end of the one -year period commencing on the date of grant. The fair value of this restricted stock grant, based on the Company's closing common stock price on the grant date, was $63.33 per share. In conjunction with the closing of the Rice Merger, the Company converted Rice restricted stock equity awards and performance share equity awards to 2,290,234 Company restricted stock equity awards on November 13, 2017 . Employees who were terminated on the closing date were immediately vested in their Company awards and received Merger Consideration cash of $5.30 per Rice share. Company awards of those employees who continued employment with the Company under a transition agreement will vest upon the earlier of (i) the end of the vesting period set forth in the original award agreement or (ii) the end of such employee's employment period set forth in his/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 will 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 the Company’s common stock, was approximately $65.18 . The total fair value of restricted stock awards vested during the years ended December 31, 2018 , 2017 and 2016 was $39.8 million , $123.0 million and $5.1 million , respectively. The $123.0 million in 2017 includes $13.0 million for the cash payment for the Merger Consideration of $5.30 per Rice share. As of December 31, 2018, $2.5 million of unrecognized compensation cost related to nonvested restricted stock equity awards was expected to be recognized over a remaining weighted average vesting term of approximately 1.3 years. A summary of restricted stock equity award activity as of December 31, 2018 , and changes during the year then ended, is presented below: Restricted Stock Non- Vested Shares (a) Weighted Average Fair Value Aggregate Fair Value Outstanding at January 1, 2018 729,500 $ 66.86 $ 48,776,872 Granted 145,540 54.33 7,906,734 Vested (596,888 ) 66.75 (39,843,286 ) Forfeited (85,370 ) 62.26 (5,314,727 ) Outstanding at December 31, 2018 192,782 $ 59.79 $ 11,525,593 (a) Non-vested shares outstanding at December 31, 2018 included 107,422 shares for Equitrans Midstream employees that will be settled by the Company under the Employee Matters Agreement. Restricted Stock Unit Awards - Liability During the years ended December 31, 2018 , 2017 , and 2016, respectively, the Company granted 373,750 , 292,400 , and 148,860 restricted stock unit liability awards that will be paid in cash to key employees of the Company. Adjusting for forfeitures, there were 639,780 awards outstanding as of December 31, 2018 . Because these awards are liability awards, the Company records compensation expense based upon 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 $6.9 million , $8.8 million , and $2.7 million as of December 31, 2018 , 2017, and 2016, 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, 2018 , 2017 and 2016 . 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 the Company’s common stock at the time of grant. Expected volatilities are based on historical volatility of the Company’s common stock. The expected term represents the period of time that options granted are expected to be outstanding based on historical option exercise experience. For the Years Ended December 31, 2018 2017 (a) 2016 (a) Risk-free interest rate 2.25 % 1.95 % 1.67 % Dividend yield 0.20 % 0.18 % 0.16 % Volatility factor 26.46 % 27.45 % 28.59 % Expected term 5 years 5 years 5 years Number of Options Granted 287,800 153,700 228,500 Weighted Average Grant Date Fair Value $ 15.39 $ 17.47 $ 15.10 Total Intrinsic Value of Options Exercised (millions) $ — $ 1.7 $ 3.5 (a) There were two grant dates for the 2017 and 2016 options. Amounts represent weighted average. As of December 31, 2018 , $0.4 million of unrecognized compensation cost related to outstanding nonvested stock options was expected to be recognized by December 31, 2019. A summary of option activity as of December 31, 2018 , and changes during the year then ended, is presented below: Non-qualified Stock Options Shares Weighted Average Exercise Price Weighted Average Remaining Contractual Term Aggregate Intrinsic Value Outstanding at January 1, 2018 1,129,200 $ 63.42 Granted 287,800 56.92 Exercised — — Forfeited (215,100 ) 58.14 Converted awards granted as a result of Separation 573,529 31.23 Expired — — Outstanding at December 31, 2018 1,775,429 $ 32.43 5.57 years $ — Exercisable at December 31, 2018 1,533,452 $ 32.88 5.22 years $ — Non-employee Directors’ Share-Based Awards The Company has historically granted to EQT non-employee directors share-based awards which vest upon grant of the awards. The share-based awards will be paid in cash or Company common stock following the directors’ termination of service on the Company’s Board of Directors. Awards that will be paid in cash are accounted for as liability awards and as such compensation expense is recorded based upon the fair value of the awards as remeasured at the end of each reporting period. Awards that will be settled in Company common stock are accounted for as equity awards and as such the Company recorded compensation expense for the fair value of the awards at the grant date fair value. A total of 267,906 non-employee director share-based awards including accrued dividends were outstanding as of December 31, 2018 . A total of 50,979 , 26,090 and 37,620 share-based awards were granted to non-employee directors during the years ended December 31, 2018 , 2017 and 2016 , respectively. The weighted average fair value of these grants, based on the Company’s closing common stock price on the business day prior to the grant date, was $52.65 , $65.35 and $52.13 for the years ended December 31, 2018 , 2017 and 2016 , respectively. 2019 Value Driver Performance Share Unit Award Program and 2019 Incentive Performance Share Unit Program Effective in 2019 , the Compensation Committee adopted the 2019 EQT Value Driver Performance Share Unit Award Program ( 2019 EQT VDPSU Program) and the 2019 Incentive Performance Share Unit Program ( 2019 Incentive PSU Program) under the 2014 LTIP. The 2019 EQT VDPSU Program and 2019 Incentive PSU Program were established to align the interests of key employees with the interests of shareholders and customers and the strategic objectives of the Company. A total of 614,680 units were granted under the 2019 EQT VDPSU Program. Fifty percent of the units confirmed under the 2019 EQT VDPSU Program will vest upon payment following the first anniversary of the grant date; the remaining 50% of the confirmed units under the 2019 EQT VDPSU Program will vest upon payment following the second anniversary of the grant date. The payout will vary between zero and 300% of the number of outstanding units contingent upon adjusted 2019 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 period January 1, 2019 through December 31, 2019 . If earned, the 2019 EQT VDPSU Program units are expected to be paid in cash. A total of 642,920 units were granted under the 2019 Incentive PSU Program. The vesting of the units under the 2019 Incentive PSU Program will occur upon payment after December 31, 2021 (the end of the three -year performance period). The payout will vary between zero and 300% of the number of outstanding units contingent upon a combination of 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 over the period January 1, 2019 through December 31, 2021 . If earned, 402,220 of the 2019 Incentive PSU Program units are expected to be distributed in Company common stock and 240,700 of the 2019 Incentive PSU Program units are expected to be paid in cash. 2019 Stock Options Effective January 1, 2019 , the Compensation Committee granted 669,200 non-qualified stock options to key employees of the Company. The 2019 options are ten -year options, with an exercise price of $18.89 , and are subject to three -year cliff vesting. 2019 Restricted Stock and Restricted Stock Unit Awards Effective January 1, 2019 , the Compensation Committee granted 201,130 restricted stock equity and 427,900 restricted stock unit liability awards. The restricted stock equity awards and restricted stock unit liability awards will be fully vested at the end of the three -year period commencing with the date of grant, assuming continued employment. |
Concentrations of Credit Risk
Concentrations of Credit Risk | 12 Months Ended |
Dec. 31, 2018 | |
Risks and Uncertainties [Abstract] | |
Concentrations of Credit Risk | 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 crude oil to marketers, utility and industrial customers located mainly in the Appalachian Basin and in markets available through the Company's current transportation portfolio, which includes markets in the Gulf Coast, Midwest and Northeast United States as well as 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 2018 , 2017 and 2016 . Approximately 64% and 59% of the Company’s accounts receivable balance as of December 31, 2018 and 2017 , respectively, represented amounts due from marketers. The Company manages the credit risk of sales to marketers by limiting its dealings to those marketers 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 marketer for that marketer to meet the Company’s credit criteria. As a result, the Company did not experience any significant defaults on sales of natural gas to marketers during the years ended December 31, 2018 , 2017 or 2016 . The Company is exposed to credit loss in the event of nonperformance by counterparties to 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 utilizes various processes and analyses to monitor and evaluate its credit risk exposures. These include monitoring current market conditions, counterparty credit fundamentals and credit default swap rates. 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, 2018 , 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, 2018 , the Company made no adjustments to the fair value of 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 derivative contracts reported in the Consolidated Balance Sheets. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | 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. Future payments for these items as of December 31, 2018 totaled $23.5 billion ( 2019 - $1.3 billion , 2020 - $1.7 billion , 2021 - $1.8 billion , 2022 - $1.8 billion , 2023 - $1.7 billion and thereafter - $15.2 billion ). The Company also has commitments to purchase equipment and frac sand to be used as a proppant in its hydraulic fracturing operations. As of December 31, 2018 , future commitments under these contracts due in 2019 totaled $74.0 million . Operating lease rentals for drilling contractors, office locations and warehouse buildings, as well as a limited amount of equipment, amounted to approximately $117.4 million in 2018 , $60.8 million in 2017 and $44.1 million in 2016 . As of December 31, 2018 , future lease payments under non-cancelable operating leases inclusive of drilling equipment and services obligations totaled $109.9 million ( 2019 - $70.3 million , 2020 - $8.4 million , 2021 - $8.4 million , 2022 – $8.4 million , 2023 - $8.4 million and thereafter - $6.0 million ). If any credit rating agency downgrades the Company's ratings, particularly below investment grade, the Company may be required to provide additional credit assurances in support of commercial agreements, such as pipeline capacity contracts, the amount of which may be substantial. On January 16, 2013, several royalty owners who had entered into leases with EQT Production Company, a subsidiary of the Company, filed a gas royalty class action lawsuit in the Circuit Court of Doddridge County, West Virginia. The suit alleged that EQT Production Company and a number of related companies failed to pay royalties on the fair value of the gas produced from the leases and took improper post-production deductions from the royalties paid. The plaintiffs sought more than $100 million (according to expert reports) in compensatory damages, punitive damages, and other relief. On May 31, 2013, the defendants removed the lawsuit to federal court. On September 6, 2017, the district court granted the plaintiffs’ motion to certify the class and granted the plaintiffs’ motion for summary judgment, finding that EQT Production Company and its marketing affiliate EQT Energy, LLC are alter egos of one another. The defendants sought immediate appeal of the class certification. On November 30, 2017, the Court of Appeals declined the request for an immediate review. On February 13, 2019, the Company announced that it and the other defendants reached a tentative settlement agreement with the class representatives. Pursuant to the terms of the proposed settlement agreement, the Company agreed to pay $53.5 million into a settlement fund that will be established to disburse payments to class participants, and stop taking future post production deductions on leases that are determined by the Court to not permit deductions. The Company and the class representatives also agreed that future royalty payments will be based on a clearly defined index pricing methodology. The tentative settlement agreement is subject to Court approval and achieving a threshold minimum percentage of participation by the class members. Each class member will have the opportunity to opt out of the settlement. If approved, the settlement will resolve the royalty claims for the class period, which spans from 2009 through 2017. The Company recorded a litigation reserve liability of $53.5 million in other current liabilities in the Consolidated Balance Sheets as of December 31, 2018 . 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 in certain instances 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 $11.8 million is included in other liabilities and credits in the Consolidated Balance Sheets as of December 31, 2018 . 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 or 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. |
Guarantees
Guarantees | 12 Months Ended |
Dec. 31, 2018 | |
Guarantees [Abstract] | |
Guarantees | Guarantees In connection with the sale of its NORESCO domestic operations in December 2005, the Company agreed to maintain in place guarantees of certain warranty obligations of NORESCO. The savings guarantees provided that once the energy-efficiency construction was completed by NORESCO, the customer would experience a certain dollar amount of energy savings over a period of years. The undiscounted maximum aggregate payments that may be due related to these guarantees were approximately $76 million as of December 31, 2018 , extending at a decreasing amount for approximately 10 years . In connection with EQM's IPO in 2012, EQT guaranteed all payment obligations, up to a maximum of $50 million , due and payable to Equitrans, L.P. (Equitrans), a wholly owned subsidiary of EQM, by EQT Energy, LLC (EQT Energy), one of Equitrans's largest customers and a wholly owned subsidiary of EQT (the EQM IPO Guaranty). The EQM IPO Guaranty will terminate on November 30, 2023 unless terminated earlier by EQT upon 10 days written notice. These guarantees are exempt from ASC Topic 460, Guarantees . The Company has determined that the likelihood it will be required to perform on these arrangements is remote and any potential payments are expected to be immaterial to the Company’s financial position, results of operations and liquidity. As such, the Company has not recorded any liabilities in its Consolidated Balance Sheets related to these guarantees. |
Interim Financial Information (
Interim Financial Information (Unaudited) | 12 Months Ended |
Dec. 31, 2018 | |
Quarterly Financial Information Disclosure [Abstract] | |
Interim Financial Information (Unaudited) | Interim Financial Information (Unaudited) The following quarterly summary of operating results reflects variations due to various factors including: the volatility of natural gas commodity prices, impairments, the Separation and Distribution, the impact of the Tax Cuts and Jobs Act and the inclusion of Rice operations beginning November 13, 2017. All prior periods presented have been recast to reflect the presentation of discontinued operations as described in Note 2 . Three Months Ended March 31 June 30 September 30 December 31 (Thousands, except per share amounts) 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: (Loss) from continuing operations $ (5.96 ) $ (0.29 ) $ (0.49 ) $ (2.35 ) Income from discontinued operations (0.03 ) 0.36 0.34 (0.15 ) Net (loss) income $ (5.99 ) $ 0.07 $ (0.15 ) $ (2.50 ) Diluted: (Loss) from continuing operations $ (5.96 ) $ (0.29 ) $ (0.49 ) $ (2.35 ) Income from discontinued operations (0.03 ) 0.36 0.34 (0.15 ) Net (loss) income $ (5.99 ) $ 0.07 $ (0.15 ) $ (2.50 ) 2017 Total operating revenues $ 828,662 $ 631,101 $ 597,718 $ 1,033,539 Operating income (loss) 243,572 47,763 (6,380 ) 97,257 Amounts attributable to EQT Corporation: (Loss) income from continuing operations 113,190 3,387 (6,238 ) 1,276,690 Income from discontinued operations, net of tax 50,802 37,739 29,578 3,381 Net income attributable to EQT Corporation $ 163,992 $ 41,126 $ 23,340 $ 1,280,071 Earnings per share of common stock attributable to EQT Corporation: Basic: (Loss) income from continuing operations $ 0.66 $ 0.02 $ (0.04 ) $ 5.83 Income from discontinued operations 0.29 0.22 0.17 0.02 Net income $ 0.95 $ 0.24 $ 0.13 $ 5.85 Diluted: (Loss) income from continuing operations $ 0.66 $ 0.02 $ (0.04 ) $ 5.81 Income from discontinued operations 0.29 0.22 0.17 0.02 Net income $ 0.95 $ 0.24 $ 0.13 $ 5.83 |
Natural Gas Producing Activitie
Natural Gas Producing Activities (Unaudited) | 12 Months Ended |
Dec. 31, 2018 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Natural Gas Producing Activities (Unaudited) | Natural Gas Producing Activities (Unaudited) The supplementary information summarized below 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 the total aggregate capitalized costs and the costs incurred relating to natural gas, NGLs and oil production activities (a): For the Years Ended December 31, 2018 2017 2016 (Thousands) At December 31: Capitalized Costs: Proved properties $ 17,648,731 $ 18,920,855 $ 12,179,833 Unproved properties 4,166,048 5,016,299 1,698,826 Total capitalized costs 21,814,779 23,937,154 13,878,659 Accumulated depreciation and depletion 4,666,212 5,121,646 4,217,154 Net capitalized costs $ 17,148,567 $ 18,815,508 $ 9,661,505 For the Years Ended December 31, 2018 2017 2016 (Thousands) Costs incurred: (a) Property acquisition: Proved properties (b) $ 77,099 $ 5,251,711 $ 403,314 Unproved properties (c) 198,854 3,310,995 880,545 Exploration (d) 1,708 15,505 6,047 Development 2,443,980 1,357,165 777,787 Geological and geophysical — — — (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, which includes the impact of measurement period adjustments for the 2017 acquisitions discussed in Note 3 and 7 . 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 transactions discussed in Notes 3 and 7 . The purchase of Marcellus leases includes measurement period adjustments to the 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 transactions discussed in Notes 3 and 7 . Amounts in 2016 include $256.2 million and $112.2 million for the purchase of Marcellus wells and leases, respectively, acquired in the 2016 transactions discussed in Note 7 . (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 transactions discussed in Notes 3 and 7 . Amounts in 2016 include $770.4 million for the purchase of Marcellus leases acquired in the 2016 transactions discussed in Note 7 . (d) Amounts include capitalizable exploratory costs and exploration expense, excluding impairments. Capitalized costs of unproved oil and gas properties are evaluated at least annually for recoverability on a prospective basis. Indicators of potential impairment include changes brought about by economic factors, potential shifts in business strategy employed by management and historical experience. The likelihood of an impairment of unproved oil and gas properties increases as the expiration of a lease term approaches if drilling activity has not commenced. If it is determined that the Company does not intend to drill on the property prior to expiration or does not have the intent and ability to extend, renew, trade, or sell the lease prior to expiration, an impairment expense is recorded. Expense for lease expirations that were not previously impaired are recorded as the leases expire. For the years ended December 31, 2018, 2017 and 2016, the Company recorded $279.7 million , $7.6 million and $15.7 million , respectively for lease impairments and expirations. The Company’s unproved properties had a net book value of $4,166.0 million and $5,016.3 million at December 31, 2018 and 2017 , respectively. Results of Operations for Producing Activities The following table presents the results of operations related to natural gas, NGLs and oil production: For the Years Ended December 31, 2018 2017 2016 (Thousands) Revenues $ 4,695,519 $ 2,651,318 $ 1,594,997 Transportation and processing 1,697,001 1,164,783 880,191 Production 195,775 181,349 174,170 Exploration 6,765 17,565 4,663 Depreciation and depletion 1,569,038 970,985 856,451 Impairment of long-lived assets 2,709,976 — — Lease impairments and expirations 279,708 7,552 15,686 Income tax (benefit) expense (454,009 ) 121,359 (135,029 ) Results of operations from producing activities (excluding corporate overhead) $ (1,308,735 ) $ 187,725 $ (201,135 ) Reserve Information The information presented below represents estimates of proved natural gas, NGLs and oil reserves prepared by Company engineers. The engineer primarily responsible for preparing the reserve report and the technical aspects of the reserves audit received a bachelor’s degree in Chemical Engineering from the Pennsylvania State University and has 21 years of experience in the oil and gas industry. To ensure that the reserves are materially accurate, management reviews the price, heat content conversion rate and cost assumptions used in the economic model to determine the reserves; division of interest and production volumes are reconciled between the system used to calculate the reserves and other accounting/measurement systems; the reserve reconciliation between prior year reserves and current year reserves is reviewed by senior management; and the estimates of proved natural gas, NGLs and oil reserves are audited by the independent consulting firm of Ryder Scott Company, L.P. (Ryder Scott), which is hired by the Company’s management. Since 1937, Ryder Scott has evaluated oil and gas properties and independently certified petroleum reserves quantities in the United States and internationally. Proved developed reserves represent only those reserves expected to be recovered from existing wells and support equipment. There were no differences between the internally prepared and externally audited estimates. Proved undeveloped reserves represent proved reserves expected to be recovered from new wells after substantial development costs are incurred. 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, 2018 . Ryder Scott conducted a detailed, well by well, audit of the Company’s largest properties. This audit covered 81% of the Company’s proved developed reserves. Ryder Scott’s audit of the remaining 19% of the Company’s proved developed properties consisted of an audit of aggregated groups not exceeding 200 wells per case for operated wells and 115 wells per case for non-operated wells. For undeveloped locations, the Company determined, and Ryder Scott reviewed and approved, the areas within the Company’s acreage considered to be 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 analogous type curves and offset production information. The audit utilized the performance method and the analogy method. Where historical reserve or production data was definitive, the performance method, which extrapolates historical data, was utilized. In other cases the analogy method, which calculates reserves based on correlations to comparable surrounding wells, was utilized. All of the Company’s proved reserves are located in the United States. Years Ended December 31, 2018 2017 2016 (Millions of Cubic Feet) Total - Natural Gas, Oil, and NGLs (a) Proved developed and undeveloped reserves: Beginning of year 21,445,667 13,508,407 9,976,597 Revision of previous estimates (1,124,904 ) (2,766,981 ) (472,285 ) Purchase of hydrocarbons in place — 9,389,638 2,395,776 Sale of hydrocarbons in place (1,748,557 ) (2,646 ) — Extensions, discoveries and other additions 4,739,233 2,225,141 2,384,682 Production (1,494,663 ) (907,892 ) (776,363 ) End of year 21,816,776 21,445,667 13,508,407 Proved developed reserves: Beginning of year 11,297,956 6,842,958 6,279,557 End of year 11,550,161 11,297,956 6,842,958 Proved undeveloped reserves: Beginning of year 10,147,711 6,665,449 3,697,040 End of year 10,266,615 10,147,711 6,665,449 (a) Oil and NGLs were converted at the rate of one thousand Bbl equal to approximately 6 million cubic feet (MMcf). Years Ended December 31, 2018 2017 2016 (Millions of Cubic Feet) Natural Gas Proved developed and undeveloped reserves: Beginning of year 19,830,236 12,331,867 9,110,311 Revision of previous estimates (960,285 ) (2,760,467 ) (607,171 ) Purchase of natural gas in place — 8,890,145 2,288,166 Sale of natural gas in place (1,331,391 ) (1,210 ) — Extensions, discoveries and other additions 4,659,835 2,164,578 2,241,528 Production (1,392,943 ) (794,677 ) (700,967 ) End of year 20,805,452 19,830,236 12,331,867 Proved developed reserves: Beginning of year 10,152,543 6,074,958 5,652,989 End of year 10,887,953 10,152,543 6,074,958 Proved undeveloped reserves: Beginning of year 9,677,693 6,256,909 3,457,322 End of year 9,917,499 9,677,693 6,256,909 Years Ended December 31, 2018 2017 2016 (Thousands of Bbls) Oil (a) Proved developed and undeveloped reserves: Beginning of year 10,731 6,395 5,900 Revision of previous estimates 6,217 5,103 1,159 Purchase of oil in place — 355 3 Sale of oil in place (10,447 ) (139 ) — Extensions, discoveries and other additions 338 9 62 Production (680 ) (992 ) (729 ) End of year 6,159 10,731 6,395 Proved developed reserves: Beginning of year 10,731 6,395 5,900 End of year 3,489 10,731 6,395 Proved undeveloped reserves: Beginning of year — — — End of year 2,670 — — (a) One thousand Bbl equals approximately 6 million cubic feet (MMcf). Years Ended December 31, 2018 2017 2016 (Thousands of Bbls) NGLs (a) Proved developed and undeveloped reserves: Beginning of year 258,507 189,695 138,481 Revision of previous estimates (33,653 ) (6,189 ) 21,322 Purchase of NGLs in place — 82,894 17,932 Sale of NGLs in place (59,080 ) (100 ) — Extensions, discoveries and other additions 12,895 10,084 23,797 Production (16,274 ) (17,877 ) (11,837 ) End of year 162,395 258,507 189,695 Proved developed reserves: Beginning of year 180,170 121,605 98,528 End of year 106,879 180,170 121,605 Proved undeveloped reserves: Beginning of year 78,337 68,090 39,953 End of year 55,516 78,337 68,090 (a) One thousand Bbl equals approximately 6 million cubic feet (MMcf). 2018 Changes in Reserves • Transfer of 2,722 Bcfe of proved undeveloped reserves to proved developed reserves. • Extensions, discoveries and other additions of 4,739 Bcfe, which exceeded the 2018 production of 1,495 Bcfe. ◦ 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. ◦ Increase of 886 Bcfe from proved undeveloped reserves extensions from acreage proved by drilling activity in the Company’s Ohio, Pennsylvania and West Virginia Marcellus fields. ◦ Increase of 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, resulting from 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 primarily due to increased reserves from producing wells and improved commodity prices. • The sale of hydrocarbons in place of 1,749 Bcfe is due to the 2018 Divestitures as described in Note 8 . 2017 Changes in Reserves • Transfer of 987 Bcfe of proved undeveloped reserves to proved developed reserves. • Increase of 9,390 Bcfe associated with the acquisition of proved developed reserves ( 3,330 Bcfe) and proved undeveloped reserves ( 6,060 Bcfe) in the Company’s Marcellus, Upper Devonian and Utica plays. • Extensions, discoveries and other additions of 2,225 Bcfe, which exceeded the 2017 production of 908 Bcfe. ◦ 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. ◦ Increase of 893 Bcfe from proved undeveloped reserves extensions from acreage proved by drilling activity in the Company’s Ohio, Pennsylvania and West Virginia Marcellus fields. ◦ Increase of 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, primarily due to 3,074 Bcfe from locations that are no longer anticipated to be drilled within 5 years of booking as a result of acquiring new acreage. The acquired acreage presents opportunities to drill considerably longer laterals, realize operational efficiencies and improve overall returns. • Upward revisions of 477 Bcfe from proved developed locations, primarily due 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. 2016 Changes in Reserves • Transfer of 647 Bcfe of proved undeveloped reserves to proved developed reserves. • Increase of 2,396 Bcfe associated with the acquisition of proved developed reserves ( 320 Bcfe) and proved undeveloped reserves ( 2,076 Bcfe) in the Company’s Marcellus and Upper Devonian plays. • Extensions, discoveries and other additions of 2,385 Bcfe, which exceeded the 2016 production of 776 Bcfe. ◦ Increase of 341 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. ◦ Increase of 673 Bcfe from proved undeveloped reserves extensions from acreage proved by drilling activity in the Company’s Ohio, Pennsylvania and West Virginia Marcellus fields. ◦ Increase of 1,371 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 509 Bcfe from proved undeveloped locations, primarily due to 389 Bcfe from economic locations that the Company no longer expects to develop within 5 years of booking, along with the removal of locations that are no longer economic as determined in accordance with Securities and Exchange Commission (SEC) pricing requirements. • Upward revisions of 68 Bcfe from proved developed locations, primarily due to increased reserves from producing wells. • Negative revisions of 31 Bcfe associated with previously booked locations whose economic lives had been shortened due to reduced 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 estimated future net cash flows from natural gas and oil reserves as of December 31, 2018 and 2017 includes the impact of the Tax Cuts and Jobs Act, which resulted in a lower federal income tax rate than as of December 31, 2016. Estimated future net cash flows from natural gas and oil reserves are as follows at December 31: 2018 2017 2016 (Thousands) Future cash inflows (a) $ 60,603,624 $ 51,423,920 $ 24,011,281 Future production costs (b) (20,463,567 ) (18,379,892 ) (14,864,126 ) Future development costs (5,854,503 ) (5,637,676 ) (3,778,698 ) Future income tax expenses (6,823,621 ) (5,811,125 ) (1,753,067 ) Future net cash flow 27,461,933 21,595,227 3,615,390 10% annual discount for estimated timing of cash flows (15,850,035 ) (12,593,293 ) (2,626,636 ) Standardized measure of discounted future net cash flows $ 11,611,898 $ 9,001,934 $ 988,754 (a) The majority of the Company’s production is sold through liquid trading points on interstate pipelines. For 2018, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2018 of $65.56 per Bbl of oil (first day of each month closing price for West Texas Intermediate (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 arithmetic averages of the closing prices on the first day of each month during 2018 for NGL components and adjusted using the regional component makeup of produced NGLs resulted in prices of $21.93 per Bbl of NGLs for certain West Virginia Marcellus reserves and $33.89 per Bbl of NGLs per Bbl for Ohio Utica reserves. The majority of the Company’s production is sold through liquid trading points on interstate pipelines. For 2017, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2017 of $51.34 per Bbl of oil (first day of each month closing price for West Texas Intermediate (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 arithmetic averages of the closing prices on the first day of each month during 2017 for NGL components and adjusted using the regional component makeup of produced NGLs resulted in prices of $23.07 per Bbl of NGLs from certain West Virginia Marcellus reserves, $31.11 per Bbl of NGLs from certain Kentucky reserves, $29.47 per Bbl for Ohio Utica reserves, and $27.93 per Bbl for Permian reserves. The majority of the Company’s production is sold through liquid trading points on interstate pipelines. For 2016, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2016 of $42.75 per Bbl of oil (first day of each month closing price for WTI) less regional adjustments, $2.342 per Dth for Columbia Gas Transmission Corp., $1.348 per Dth for Dominion Transmission, Inc., $2.334 per Dth for the East Tennessee Natural Gas Pipeline, $1.325 per Dth for Texas Eastern Transmission Corp., $1.305 per Dth for the Tennessee, zone 4-300 Leg of Tennessee Gas Pipeline Company, $1.862 per Dth for the Tennessee LA 500 Leg of Tennessee Gas Pipeline Company, $2.343 per Dth for Waha, and $2.402 per Dth for the Rockies Express Pipeline Zone 3. For 2016, NGL pricing using arithmetic averages of the closing prices on the first day of each month during 2016 for NGL components and adjusted using the regional component makeup of produced NGLs resulted in prices of $13.87 per Bbl of NGLs from certain West Virginia Marcellus reserves, $17.27 per Bbl of NGLs from certain Kentucky reserves, $14.71 per Bbl for Ohio Utica reserves, and $18.91 per Bbl for Permian reserves. (b) Includes approximately $883 million, $1,400 million and $790 million as of December 31, 2018, 2017 and 2016 respectively for future plugging and abandonment costs. Holding production and development costs constant, a change in price of $0.20 per Dth for natural gas, $10 per barrel for oil and $10 per barrel for NGLs would result in a change in the December 31, 2018 discounted future net cash flows before income taxes of the Company’s proved reserves of approximately $1.9 billion , $34.2 million and $665.7 million , respectively. Summary of changes in the standardized measure of discounted future net cash flows for the years ended December 31: 2018 2017 2016 (Thousands) Sales and transfers of natural gas and oil produced – net $ (2,802,742 ) $ (1,305,186 ) $ (540,636 ) Net changes in prices, production and development costs 2,949,606 2,236,183 (1,129,026 ) Extensions, discoveries and improved recovery, less related costs 1,616,653 1,269,712 590,885 Development costs incurred 1,630,506 712,635 402,891 Purchase of minerals in place – net — 5,357,921 592,078 Sale of minerals in place – net (849,162 ) (284 ) — Revisions of previous quantity estimates (811,576 ) (297,437 ) (60,959 ) Accretion of discount 834,026 115,437 122,674 Net change in income taxes (289,549 ) (1,477,603 ) (91,823 ) Timing and other (a) 332,202 1,401,802 125,116 Net increase (decrease) 2,609,964 8,013,180 11,200 Beginning of year 9,001,934 988,754 977,554 End of year $ 11,611,898 $ 9,001,934 $ 988,754 (a) Increase in 2017 primarily driven by timing changes to the Company’s development plan as a result of the Rice Merger. |
SCHEDULE II - VALUATION AND QUA
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES | 12 Months Ended |
Dec. 31, 2018 | |
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract] | |
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES | SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE THREE YEARS ENDED DECEMBER 31, 2018 Column A Column B Column C Column D Column E Description Balance at Beginning of Period (Deductions) Additions Charged to Costs and Expenses Additions Charged to Other Accounts Deductions Balance at End of Period (Thousands) Valuation allowance for deferred tax assets: 2018 $ 262,392 $ 98,311 $ — $ (9,295 ) $ 351,408 2017 $ 201,422 $ 70,063 $ — $ (9,093 ) $ 262,392 2016 $ 156,084 $ 24,706 $ 21,536 $ (904 ) $ 201,422 All other schedules are omitted since the subject matter thereof is either not present or is not present in amounts sufficient to require submission of the schedules. |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Principles of Consolidation | Principles of Consolidation: The Consolidated Financial Statements include the accounts of EQT Corporation and all subsidiaries, ventures and partnerships in which a controlling interest is held (EQT or the Company). All significant intercompany accounts and transactions have been eliminated in consolidation. |
Segments | 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 or located in the United States. |
Use of Estimates | 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 | Cash Equivalents: The Company considers all highly liquid investments with an original maturity of three months or less when purchased to be cash equivalents. These investments are accounted for at cost. Interest earned on cash equivalents is included as a reduction of interest expense. |
Trading Securities | Trading Securities: Trading securities consist of liquid debt securities that are carried at fair value. |
Accounts Receivable | Accounts Receivable: Accounts receivable primarily relate to the sales of natural gas, oil and natural gas liquids (NGLs) and amounts due from joint interest partners. |
Inventories | Inventories: Generally, the Company’s inventory balance consists of natural gas stored underground or in pipelines and materials and supplies recorded at the lower of average cost or market. |
Property, Plant and Equipment | 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, as well as productive acreage, including productive mineral interests, are capitalized and depleted using the unit-of-production method. These capitalized costs include salaries, benefits and other internal costs directly attributable to these activities. The Company capitalized internal costs of $130.0 million , $114.6 million and $115.4 million in 2018 , 2017 and 2016 , respectively, for production related activities. The Company also capitalized $29.0 million , $20.5 million and $19.2 million of interest expense related to Marcellus, Upper Devonian and Utica well development in 2018 , 2017 and 2016 , respectively. Depletion expense is calculated based on the actual produced sales volumes multiplied by the applicable depletion rate per unit. The depletion rates are derived by dividing the net capitalized costs by the number of units expected to be produced over the life of the reserves for lease costs and well costs separately. Costs of exploratory dry holes, exploratory geological and geophysical activities, delay rentals and other property carrying costs are charged to expense. The majority of the Company’s producing oil and gas properties were depleted at an overall average rate of $1.04 per Mcfe, $1.04 per Mcfe and $1.06 per Mcfe for the years ended December 31, 2018 , 2017 and 2016 , respectively. 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. In order to determine whether impairment has occurred, the Company estimates the expected future cash flows (on an undiscounted basis) from its oil and gas properties and compares these estimates to the carrying values of the properties. The estimated future cash flows used to test those properties for recoverability are based on proved and, if determined reasonable by management, risk-adjusted probable reserves, utilizing assumptions generally consistent with the assumptions utilized by the Company's management 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 accordingly 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 rate and other assumptions that marketplace participants would use in their estimates of fair value. 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 management's intent to divest the Company's Huron and Permian assets prior to the end of their useful lives. As a result of the impairment evaluation during 2018, the Company recorded an impairment of $2.4 billion associated with the production and related midstream assets in the Huron and Permian plays that were divested during the year (collectively, the 2018 Divestitures). There were no indicators of impairment identified during 2017. During 2016, there were indicators that the carrying value of the Huron assets may be impaired due to declines in commodity prices. As a result of the impairment indicators as of December 31, 2016, the Company performed an undiscounted cash flow analysis and determined that no impairment existed during 2016. The Company impaired all of its goodwill in the fourth quarter 2018. This resulted in an impairment indicator for certain other long-lived assets including proved oil and gas properties and intangible assets. The Company performed an undiscounted cash flow analysis and determined that no additional impairment existed. Capitalized costs of unproved oil and gas properties are evaluated at least annually for recoverability on a prospective basis. Indicators of potential impairment include changes brought about by economic factors, potential shifts in business strategy employed by management and historical experience. The likelihood of an impairment of unproved oil and gas properties increases as the expiration of a lease term approaches if drilling activity has not commenced. If it is determined that the Company does not intend to drill on the property prior to expiration or does not have the intent and ability to extend, renew, trade, or sell the lease prior to expiration, an impairment expense is recorded. Expense for lease expirations that were not previously impaired are recorded as the leases expire. |
Goodwill | Goodwill : Goodwill is the cost of an acquisition less the fair value of the identifiable net assets of the acquired business. At November 30, 2018, prior to the completion of the annual goodwill impairment test, the goodwill balance totaled $530.8 million . Goodwill is tested for impairment at the Company's single reporting unit level on an annual basis and between annual tests if events or circumstances indicate it is more likely than not that the fair value of a reporting unit is below its carrying value. The Company considered market capitalization and other valuation techniques, as applicable, when estimating fair value for goodwill impairment testing purposes. In connection with the annual goodwill impairment testing for 2018, the Company identified several qualitative factors that are considered in assessing goodwill for impairment. These factors included 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, exceeding the Company's capital budget as announced in October 2018, recent operational volume curtailments and the Company's new strategy to slow the cadence of its future drilling operations to generate near-term free cash flow. The Company conducted the first step of the goodwill impairment test for the single reporting unit as of November 30, 2018. The Company utilized its market capitalization plus a control premium approach to estimate the fair value of the Company (and in turn the single reporting unit). The estimated market capitalization was determined by multiplying the 30 day weighted average stock price and the Company's common shares outstanding as of November 30, 2018. Based on the analysis utilizing the market capitalization plus control premium approach, the estimated fair value of the reporting unit was significantly less than its carrying value. As the Company adopted ASU No. 2017-04 (ASU 2017-04), Simplifying the Test of Goodwill Impairment , all of the goodwill was impaired. This impairment charge was classified as a component of operating expenses. |
Intangible Assets | Intangible Assets : These intangible assets were initially recorded under the acquisition method of accounting at their estimated fair values at the Rice Merger (defined in Note 3 ) acquisition date. The Company’s intangible assets are composed of non-compete agreements with former Rice Energy Inc. executives. The non-compete agreements have a useful life of 3 years. The Company calculates amortization of intangible assets using the straight-line method over the estimated useful life of the intangible assets. |
Sales and Retirements Policies | Sales and Retirements Policies: No gain or loss is recognized on the partial sale of proved developed oil and gas reserves unless non-recognition would significantly alter the relationship between capitalized costs and remaining proved reserves for the affected amortization base. When gain or loss is not recognized, the amortization base is reduced by the amount of the proceeds. |
Derivative Instruments | Derivative Instruments: Derivatives are held as part of a formally documented risk management program. The Company’s use of derivative instruments is implemented under a set of policies approved by the Company’s Hedge and Financial Risk Committee (HFRC) and reviewed by the Audit Committee of the Company's Board of Directors. The HFRC is composed of the president and chief executive officer, the chief financial officer and other officers of the Company. In regards to commodity price risk, the financial instruments currently utilized by the Company are primarily fixed price swap agreements, collar agreements and option agreements. The Company engages in basis swaps to protect earnings from undue exposure to the risk of geographic disparities in commodity prices and may engage in interest rate swaps to hedge exposure to interest rate fluctuations on potential debt issuances. The Company also uses a limited number of other contractual agreements in implementing its commodity hedging strategy. The Company has an insignificant number of natural gas derivative instruments for trading purposes. Any changes in fair value of derivative instruments are recognized net within operating revenues in the Statements of Consolidated Operations. |
Revenue Recognition | Revenue Recognition: For information on revenue recognition from contracts with customers and gains and losses on derivative commodity instruments, see Note 4 and Note 5 , respectively. |
Unamortized Debt Discount and Issuance Expense | Unamortized Debt Discount and Issuance Expense: Discounts and expenses incurred with the issuance of debt are amortized over the term of the debt. These amounts are presented as a reduction of Senior Notes on the accompanying Consolidated Balance Sheets. See Note 10 . |
Transportation and Processing | 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 | Income Taxes: The Company files a consolidated federal income tax return and utilizes 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 years’ taxes made due to subsequent 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 are determined based on temporary differences between the financial reporting and tax bases of 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 some portion or all of the deferred tax asset will not be realized. In accounting for uncertainty in income taxes of a tax position taken or expected to be taken in a tax return, the Company utilizes 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 in order to record any financial statement benefit. If it is more likely than not that a tax position will be sustained, then the Company must measure the tax position to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. The Company recognizes interest and penalties accrued related to unrecognized tax benefits in income tax expense. |
Provision For Doubtful Accounts | Provision for Doubtful Accounts: Judgment is required to assess the ultimate realization of the Company’s accounts receivable, including assessing the probability of collection and the creditworthiness of certain customers. Reserves for uncollectible accounts are recorded as part of selling, general and administrative expense in the Statements of Consolidated Operations. The reserves are based on historical experience, current and expected economic trends and specific information about customer accounts. |
Earnings Per Share (EPS) | Earnings Per Share (EPS): Basic EPS are computed by dividing net income attributable to EQT by the weighted average number of common shares outstanding during the period, without considering any dilutive items. Diluted EPS are 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. Purchases of treasury shares are calculated using the average share price for the Company’s common stock during the period. Potentially dilutive securities arise from the assumed conversion of outstanding stock options and other share-based awards. In periods when the Company reports a net loss, all options and restricted stock are excluded from the calculation of diluted weighted average shares outstanding because of their anti-dilutive effect on loss per share. |
Asset Retirement Obligations | Asset Retirement Obligations : The Company accrues a liability for legal 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 required to be 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, and 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 in plugging and abandoning wells and reclaiming or disposing of other assets as well as the estimated remaining lives of the wells and assets. |
Self-Insurance | 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. The estimated liabilities are based on analyses of historical data and actuarial estimates and are not discounted. The liabilities are reviewed by management quarterly and by independent actuaries annually to ensure that they are appropriate. 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. |
Pension and Other Post-Retirement Benefit Plans | Pension and Other Post-Retirement Benefit Plans: The Company, as sponsor of the EQT Corporation Retirement Plan for Employees (Retirement Plan), a defined benefit pension plan, terminated the Retirement Plan effective December 31, 2014. On March 2, 2016, the Internal Revenue Service (IRS) issued a favorable determination letter for the termination of the Retirement Plan. On June 28, 2016, the Company purchased annuities from, and transferred the Retirement Plan assets and liabilities to, American General Life Insurance Company. |
Recently Issued Accounting Standards | Recently Issued Accounting Standards: In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers . The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Company adopted this standard on January 1, 2018 using the modified retrospective method of adoption. Adoption of the ASU did not require an adjustment to the opening balance of equity. For the disclosures required by this ASU, see Note 4 . In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities . The standard affects accounting for equity investments and financial liabilities under the fair value option, the presentation and disclosure requirements for financial instruments, and eliminates the cost method of accounting for equity investments. The Company adopted this standard in the first quarter of 2018 which resulted in a cumulative effect adjustment of $4.1 million on the Statement of Consolidated Equity. In February 2016, the FASB issued ASU No. 2016-02, Leases . The primary effect of adopting the new standard on leases will be to record assets and liabilities for contracts currently recognized as operating leases. In July 2018, the FASB issued targeted improvements to this ASU in ASU 2018-11. This update provides entities with an optional transition method, which permits an entity to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The Company adopted the ASUs using the optional transition method on January 1, 2019 and did not require an adjustment to the opening balance of equity. The Company has adopted the practical expedient package, the land easement and short-term lease recognition exemption provided for under the new standard. The Company also elected a practical expedient that permits combining lease and non-lease components in a contract and accounting for the combination as a lease. The quantitative impacts of the new standard are dependent on the leases in existence at the time of reporting. As a result, the evaluation of the effect of the new standard on the results of operations and liquidity will change as new leases are entered into in the future. However, the Company does not expect the standard to have a significant impact on its results of operations or liquidity in 2019. In 2019, the Company expects to record a lease liability and offsetting right of use asset between $100 million and $125 million on the Consolidated Balance Sheet sheet associated with its leases which are primarily related to facilities, production rigs and compressors. Additional disclosures will be required to describe the nature, amount, significant assumptions and judgments made, maturity analysis of its lease liabilities and accounting policy elections from leases. The Company has implemented a new lease accounting system and related processes to ensure that contracts that contain lease components are appropriately accounted for under ASC Topic 842, including both new contracts and modifications to existing contracts. In June 2016, the FASB issued ASU No. 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 in current GAAP and requires an entity to reflect its current estimate of all expected credit losses. The amendments affect loans, debt securities, trade receivables, net investments in leases, off balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. The ASU will be effective for annual reporting periods beginning after December 15, 2019, including interim periods within that reporting period. The Company is currently evaluating the impact this standard will have on its financial statements and related disclosures. In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows: Restricted Cash . This ASU requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning of period and end of period total amounts shown on the statement of cash flows. The Company adopted this standard in the first quarter of 2018. The Company had $75 million in restricted cash at December 31, 2016. In accordance with ASU 2016-18, restricted cash is included in the beginning of period cash balance and excluded from investing activities on the Statements of Consolidated Cash Flows for the year ended December 31, 2017. The Company had no restricted cash on the Consolidated Balance Sheet at December 31, 2018 or 2017. In January 2017, the FASB issued ASU No. 2017-01, Business Combinations: Clarifying the Definition of a Business . This ASU clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The Company adopted this standard in the first quarter of 2018 with no significant effect on its financial statements or related disclosures. In January 2017, the FASB issued ASU No. 2017-04, Simplifying the Test of Goodwill Impairment . This ASU simplifies the quantitative goodwill impairment test requirements by eliminating the requirement to calculate the implied fair value of goodwill. Instead, a company is required to record an impairment charge based on the excess of a reporting unit’s carrying value over its fair value. The standard’s provisions are to be applied prospectively. The Company adopted this standard in the first quarter of 2018 with no significant effect on its financial statements or related disclosures. However as discussed in Note 3 , the Company has recorded an impairment charge in 2018 under this standard. In March 2017, the FASB issued ASU No. 2017-07, Compensation - Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost . This ASU provides additional guidance on the presentation of net benefit cost in the income statement and on the components eligible for capitalization in assets. The Company adopted this standard in the first quarter of 2018 with no significant effect on its financial statements or related disclosures. In May 2017, the FASB issued ASU No. 2017-09, Compensation - Stock Compensation: Scope of Modification Accounting . This ASU provides guidance regarding which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting. The Company adopted this standard in the first quarter of 2018 with no significant effect on its financial statements or related disclosures. This ASU will be applied prospectively to awards modified on or after the adoption date. In February 2018, the FASB issued ASU No. 2018-02, Income Statement—Reporting Comprehensive Income: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. This ASU allows companies to reclassify stranded tax effects resulting from the Tax Cuts and Jobs Act from accumulated other comprehensive income to retained earnings. The 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 in the Tax Cuts and Jobs Act is recognized. The Company adopted the ASU on January 1, 2019 with an immaterial adjustment to other comprehensive income. In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement, Changes to the Disclosure Requirements for Fair Value Measurement , which makes a number of changes to 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. Early adoption is permitted. The Company is currently evaluating the effect this standard will have on its financial statements and related disclosures but does not expect the adoption of this standard to have a material impact on its financial statements and related disclosures. |
Subsequent Events | Subsequent Events: The Company has evaluated subsequent events through the date of the financial statement issuance. |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Schedule of property, plant and equipment | The Company’s property, plant and equipment consist of the following: As of December 31, 2018 2017 (Thousands) Oil and gas producing properties, successful efforts method $ 21,814,779 $ 23,937,154 Accumulated depreciation and depletion (4,666,212 ) (5,121,646 ) Net oil and gas producing properties 17,148,567 18,815,508 Other properties, at cost less accumulated depreciation 243,940 914,500 Net property, plant and equipment $ 17,392,507 $ 19,730,008 |
Schedule intangible assets | ble assets, net as of December 31, 2018 and 2017 are detailed below. December 31, 2018 2017 (Thousands) Non-compete agreements $ 124,100 $ 124,100 Less: accumulated amortization (46,767 ) (5,400 ) Intangible assets, net $ 77,333 $ 118,700 Sales |
Schedule of other current liabilities | urrent liabilities as of December 31, 2018 and 2017 are detailed below. December 31, 2018 2017 (Thousands) Incentive compensation $ 46,937 $ 72,910 Taxes other than income 75,978 62,091 Accrued interest payable 42,998 41,926 Legal reserve 53,500 — Severance accrual 8,893 41,474 All other accrued liabilities 26,381 55,875 Total other current liabilities $ 254,687 $ 274,276 Reven |
Reconciliation of the beginning and ending carrying amounts of asset retirement obligations | pany does not have any assets that are legally restricted for purposes of settling these obligations. December 31, 2018 2017 (Thousands) Asset retirement obligation as of beginning of period $ 443,349 $ 243,600 Accretion expense 17,513 13,644 Liabilities incurred 7,785 19,678 Liabilities settled (3,722 ) (3,750 ) Liabilities assumed in the Rice Merger 27,999 41,655 Liabilities removed due to divestitures (231,936 ) (88 ) Change in estimates 26,817 128,610 Asset retirement obligation as of end of period $ 287,805 $ 443,349 Durin |
Separation and Distribution a_2
Separation and Distribution and Discontinued Operations (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Disposal Groups, Including Discontinued Operations | The results of operations of Equitrans Midstream are presented as discontinued operations in the Statements of Consolidated Operations as summarized below. The Company allocated all of the transaction costs associated with the Separation and Distribution to discontinued operations. The transaction costs included in the table below also included amounts that the Company allocated to discontinued operations for the Rice Merger (see Note 3 ). January 1, 2018 to November 12, 2018 Years Ended December 31, 2017 2016 (Thousands) Operating revenues $ 388,854 $ 279,422 $ 217,952 Transportation and processing (803,858 ) (604,025 ) (514,373 ) Operation and maintenance 99,671 80,833 69,308 Selling, general and administrative 62,702 53,275 44,022 Depreciation 160,701 106,574 71,469 Impairment/loss on sale of long-lived assets — — 59,748 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 28,718 Interest expense 88,300 34,801 16,761 Income from discontinued operations before income taxes 435,405 543,910 499,735 Income tax expense 61,643 72,797 99,305 Income from discontinued operations after income taxes 373,762 471,113 400,430 Less: Net income from discontinued operations attributable to noncontrolling interests 237,410 349,613 321,920 Net income from discontinued operations $ 136,352 $ 121,500 $ 78,510 (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 that could reduce volumetric-based fee revenues of two reporting units to which the Company's goodwill was recorded. The two reporting units were Rice Retained Midstream and RMP PA Gas Gathering, which were allocated to discontinued operations as a result of the Separation and Distribution. Both of these reporting units earn 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 were utilized. The discounted cash flow method income approach applies significant inputs 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 and reference transaction method 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; however, 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 on the Consolidated Balance Sheet and allocated to discontinued operations. The carrying amount of the major classes of assets and liabilities related to Equitrans Midstream classified as assets and liabilities of discontinued operations in the Consolidated Balance Sheet at December 31, 2017 are presented in the below table. December 31, 2017 (Thousands) Total assets of discontinued operations Cash and cash equivalents $ 121,004 Accounts receivable, net 60,551 Prepaid expenses and other (a) (25,295 ) Current assets of discontinued operations 156,260 Net property, plant and equipment 5,155,007 Intangible assets, net 617,660 Goodwill 1,527,877 Investment in nonconsolidated entity 460,546 Other assets 28,168 Noncurrent assets of discontinued operations 7,789,258 Total assets of discontinued operations $ 7,945,518 Total liabilities of discontinued operations Accounts payable (a) $ (71,809 ) Other current liabilities 151,842 Current liabilities of discontinued operations 80,033 Credit facility borrowings 466,000 Senior Notes 987,352 Deferred income taxes (121,062 ) Notes payable to EQM Midstream Partners, LP (See Note 10) (114,720 ) Other liabilities and credits 30,462 Noncurrent liabilities of discontinued operations 1,248,032 Total liabilities of discontinued operations $ 1,328,065 (a) As of December 31, 2017, prepaid expenses and other represents the receivable from Equitrans Midstream and accounts payable represents the payable to Equitrans Midstream. The following table presents amounts of the discontinued operations related to Equitrans Midstream which are included in the Statements of Consolidated Cash Flows. January 1, 2018 to November 12, 2018 Years Ended December 31, 2017 2016 (Thousands) Operating activities: Deferred income tax (benefit) expense $ (373,405 ) $ 43,471 $ (21,936 ) Depreciation 160,701 106,574 71,469 Amortization of intangibles 36,007 5,540 — Asset impairments — — 59,748 Goodwill impairment 267,878 — — Other income (51,450 ) (27,281 ) (29,300 ) Share-based compensation expense $ 1,841 $ 468 $ 373 Investing activities: Capital expenditures $ (732,727 ) $ (380,151 ) $ (584,819 ) Capital contributions to Mountain Valley Pipeline, LLC (a) (820,943 ) (159,550 ) (98,399 ) Sales of interests in Mountain Valley Pipeline, LLC (a) $ — $ — $ 12,533 Financing activities: Net proceeds from the issuance of common units of EQM $ — $ — $ 217,102 Proceeds from issuance of debt 2,500,000 — 500,018 Increase in borrowings on credit facilities 3,378,500 544,084 740,000 Repayment of borrowings on credit facilities (3,219,500 ) (344,000 ) (1,039,000 ) Distributions to noncontrolling interests (380,651 ) (236,123 ) (189,981 ) Contribution to Strike Force Midstream LLC by minority owner, net of distribution — 6,738 — Acquisition of 25% of Strike Force Midstream LLC (175,000 ) — — Debt issuance costs and revolving credit facility origination fees $ (40,966 ) $ (2,257 ) $ (8,580 ) (a) The Mountain Valley Pipeline, LLC is a joint venture that is constructing the Mountain Valley Pipeline (MVP). EQM owns an interest in the joint venture and made capital contributions to the joint venture. |
Rice Merger (Tables)
Rice Merger (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Business Combinations [Abstract] | |
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed | Final Purchase Price Allocation (Thousands) Consideration Given: Equity consideration $ 5,943,289 Cash consideration 1,299,407 Buyout of preferred equity in Rice Midstream Holdings 429,708 Buyout of common units in Rice Midstream GP Holdings, LP 125,828 Settlement of pre-existing relationships (14,699 ) Total consideration 7,783,533 Fair value of liabilities assumed: Current liabilities 577,053 Long-term debt 2,151,656 Deferred income taxes 1,106,773 Other long term liabilities 95,712 Amount attributable to liabilities assumed 3,931,194 Fair value of assets acquired: Cash 294,671 Accounts receivable 322,630 Current assets 109,465 Net property, plant and equipment 9,918,315 Intangible assets 747,300 Noncontrolling interests (1,715,611 ) Amount attributable to assets acquired 9,676,770 Goodwill from Rice Merger $ 2,037,957 Goodwill impairment - continuing operations (530,811 ) Goodwill impairment - discontinued operations (267,878 ) Goodwill allocated to discontinued operations (a) (1,239,268 ) Goodwill as of December 31, 2018 $ — (a) In conjunction with the Rice Merger, the Company had unamortized carryover tax basis of $387.1 million of tax deductible goodwill, of which the entire amount relates to discontinued operations. |
Revenue from Contracts with C_2
Revenue from Contracts with Customers (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of Revenue | The table below provides disaggregated information regarding the Company’s revenues. Certain contracts that provide for the release of capacity that is not used to transport the Company’s produced volumes were deemed to be outside the scope of Revenue from Contracts with Customers. The cost of, and recoveries on, that capacity are reported within net marketing services and other. Derivative contracts are also outside the scope of Revenue from Contracts with Customers. Year Ended December 31, 2018 Revenues from contracts with customers Other sources of revenue Total (Thousands) Natural gas sales $ 4,217,684 $ — $ 4,217,684 NGLs sales 442,010 — 442,010 Oil sales 35,825 — 35,825 Sales of natural gas, oil and NGLs $ 4,695,519 $ — $ 4,695,519 Net marketing services and other 13,865 27,075 40,940 Loss on derivatives not designated as hedges — (178,591 ) (178,591 ) Total operating revenues (losses) $ 4,709,384 $ (151,516 ) $ 4,557,868 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | The following table includes the transaction price allocated to the Company's remaining performance obligations on all contracts with fixed consideration. The table excludes all contracts that qualified for the exception to the relative standalone selling price method. 2019 2020 Total (Thousands) Natural gas sales $ 54,116 $ 21,485 $ 75,601 |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Offsetting Assets | The table below reflects the impact of netting agreements and margin deposits on gross derivative assets and liabilities as of December 31, 2018 and 2017 . As of December 31, 2018 Derivative instruments, recorded in the Consolidated Balance Sheet, gross Derivative instruments subject to master netting agreements Margin deposits remitted to counterparties Derivative instruments, net (Thousands) Asset derivatives: Derivative instruments, at fair value $ 481,654 $ (256,087 ) $ — $ 225,567 Liability derivatives: Derivative instruments, at fair value $ 336,051 $ (256,087 ) $ (40,283 ) $ 39,681 As of December 31, 2017 Derivative instruments, recorded in the Consolidated Balance Sheet, gross Derivative instruments subject to master netting agreements Margin deposits remitted to counterparties Derivative instruments, net (Thousands) Asset derivatives: Derivative instruments, at fair value $ 241,952 $ (86,856 ) $ — $ 155,096 Liability derivatives: Derivative instruments, at fair value $ 139,089 $ (86,856 ) $ — $ 52,233 |
Offsetting Liabilities | The table below reflects the impact of netting agreements and margin deposits on gross derivative assets and liabilities as of December 31, 2018 and 2017 . As of December 31, 2018 Derivative instruments, recorded in the Consolidated Balance Sheet, gross Derivative instruments subject to master netting agreements Margin deposits remitted to counterparties Derivative instruments, net (Thousands) Asset derivatives: Derivative instruments, at fair value $ 481,654 $ (256,087 ) $ — $ 225,567 Liability derivatives: Derivative instruments, at fair value $ 336,051 $ (256,087 ) $ (40,283 ) $ 39,681 As of December 31, 2017 Derivative instruments, recorded in the Consolidated Balance Sheet, gross Derivative instruments subject to master netting agreements Margin deposits remitted to counterparties Derivative instruments, net (Thousands) Asset derivatives: Derivative instruments, at fair value $ 241,952 $ (86,856 ) $ — $ 155,096 Liability derivatives: Derivative instruments, at fair value $ 139,089 $ (86,856 ) $ — $ 52,233 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Schedule of assets and liabilities measured at fair value on a recurring basis | The following assets and liabilities were measured at fair value on a recurring basis during the applicable period: Fair value measurements at reporting date using Description As of December 31, 2018 Quoted prices in active markets for identical assets (Level 1) Significant other observable inputs (Level 2) Significant unobservable inputs (Level 3) (Thousands) Assets Derivative instruments, at fair value $ 481,654 $ 112,107 $ 369,547 $ — Liabilities Derivative instruments, at fair value $ 336,051 $ 126,582 $ 209,469 $ — Fair value measurements at reporting date using Description As of December 31, 2017 Quoted prices in active markets for identical assets (Level 1) Significant other observable inputs (Level 2) Significant unobservable inputs (Level 3) (Thousands) Assets Derivative instruments, at fair value $ 241,952 $ — $ 241,952 $ — Liabilities Derivative instruments, at fair value $ 139,089 $ — $ 139,089 $ — |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Schedule of income tax expense (benefit) from continuing operations | Income tax (benefit) expense is summarized as follows: Years Ended December 31, 2018 2017 2016 (Thousands) Current: Federal $ (513,293 ) $ (89,149 ) $ (181,817 ) State (46,218 ) (5,184 ) (22,627 ) Subtotal (559,511 ) (94,333 ) (204,444 ) Deferred: Federal 20,496 (1,039,769 ) (110,734 ) State (157,496 ) (54,314 ) (47,591 ) Subtotal (137,000 ) (1,094,083 ) (158,325 ) Total income taxes $ (696,511 ) $ (1,188,416 ) $ (362,769 ) |
Schedule of reconciliation of income tax expense to amount computed at the federal statutory rate | Income tax (benefit) expense from continuing operations differed from amounts computed at the federal statutory rate of 21% for 2018 and 35% for 2017 and 2016 on pre-tax income as follows: Years Ended December 31, 2018 2017 2016 (Thousands) Tax at statutory rate $ (646,261 ) $ 69,515 $ (312,992 ) Federal tax reform 5,288 (1,205,140 ) — State income taxes (251,780 ) (57,414 ) (76,043 ) Valuation allowance 88,785 10,680 23,808 Regulatory liability/asset (276 ) 10,488 — Federal tax credits (2,400 ) (34,956 ) (4,539 ) Goodwill impairment 111,470 — — Other (1,337 ) 18,411 6,997 Income tax (benefit) expense $ (696,511 ) $ (1,188,416 ) $ (362,769 ) Effective tax rate 22.6 % (598.4 )% 40.6 % |
Schedule of reconciliation of the beginning and ending amount of reserve for uncertain tax positions(excluding interest and penalties) | The following table reconciles the beginning and ending amount of reserve for uncertain tax positions (excluding interest and penalties): 2018 2017 2016 (Thousands) Balance at January 1 $ 301,558 $ 252,434 $ 259,301 Additions based on tax positions related to current year 8,459 50,469 23,978 Additions for tax positions of prior years 14,396 8,978 20,336 Reductions for tax positions of prior years (9,134 ) (10,323 ) (51,181 ) Balance at December 31 $ 315,279 $ 301,558 $ 252,434 |
Summary of source and tax effects of temporary differences between financial reporting and tax bases of assets and liabilities | The following table summarizes the source and tax effects of temporary differences between financial reporting and tax bases of assets and liabilities: As of December 31, 2018 2017 (Thousands) Deferred income taxes: Total deferred income tax assets $ (901,377 ) $ (1,112,514 ) Total deferred income tax liabilities 2,724,758 3,002,476 Total net deferred income tax liabilities 1,823,381 1,889,962 Total deferred income tax liabilities (assets): Drilling and development costs expensed for income tax reporting 1,469,320 2,074,091 Tax depreciation in excess of book depreciation 904,030 644,590 Investment in Equitrans Midstream (10,359 ) — Incentive compensation and deferred compensation plans (24,682 ) (43,822 ) Net operating loss carryforwards (429,983 ) (564,180 ) Alternative minimum tax credit carryforward (308,727 ) (435,190 ) Federal tax credits (37,710 ) (50,341 ) Unrealized (losses) gains (28,096 ) 21,403 Interest disallowance limitation (35,358 ) — Other (26,462 ) (18,981 ) Total excluding valuation allowances 1,471,973 1,627,570 Valuation allowances 351,408 262,392 Total net deferred income tax liabilities $ 1,823,381 $ 1,889,962 |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Debt Disclosure [Abstract] | |
Schedule of long-term debt | December 31, 2018 December 31, 2017 Principal Value Carrying Value (a) Fair Value (b) Principal Value Carrying Value (a) Fair (Thousands) 8.13% Notes, due June 1, 2019 $ 700,000 $ 699,729 $ 712,663 $ 700,000 $ 698,918 $ 755,153 Floating Rate Notes due October 1, 2020 500,000 498,222 490,730 500,000 497,206 501,325 2.50% Notes due October 1, 2020 500,000 498,198 489,690 500,000 497,169 497,670 4.88% Notes, due November 15, 2021 750,000 746,245 762,555 750,000 744,920 801,953 3.00% Notes due October 1, 2022 750,000 743,972 712,980 750,000 742,364 743,550 7.75% debentures, due July 15, 2026 115,000 111,229 128,808 115,000 110,732 135,024 3.90% Notes due October 1, 2027 1,250,000 1,239,866 1,085,663 1,250,000 1,238,707 1,245,200 Medium-term notes: 7.42% Series B, due 2023 10,000 10,000 10,666 10,000 10,000 11,433 7.6% Series C, due 2018 — — — 8,000 7,999 8,012 8.8% to 9.0% Series A, due 2020 through 2021 35,200 35,200 37,920 35,200 35,187 40,510 Note payable to EQM 114,720 114,720 121,752 119,127 119,127 133,001 Total debt 4,724,920 4,697,381 4,553,427 4,737,327 4,702,329 4,872,831 Less current portion of debt 704,661 704,390 717,609 12,407 12,406 12,932 Long-term debt $ 4,020,259 $ 3,992,991 $ 3,835,818 $ 4,724,920 $ 4,689,923 $ 4,859,899 (a) For the note payable to EQM, the principal value represents the carrying value. For all other debt, the carrying value represents principal value less unamortized debt issuance costs and debt discounts. (b) For the note payable to EQM, fair value is measured using Level 3 inputs, as described below. For all other debt, fair value is measured using Level 2 inputs. |
Changes in Accumulated Other _2
Changes in Accumulated Other Comprehensive Income (Loss) by Component (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract] | |
Schedule of the changes in accumulated OCI by component | The following tables explain the changes in accumulated OCI by component for the three years ended December 31, 2018 , 2017 , and 2016 . Accumulated OCI (loss), net of tax Natural gas cash flow hedges, net of tax Interest rate cash flow hedges, net of tax Pension and other post- retirement benefits liability adjustment, net of tax Distribution of Equitrans Midstream Corporation Accumulated OCI (loss), net of tax (Thousands) As of December 31, 2015 $ 64,762 $ (843 ) $ (17,541 ) $ — $ 46,378 (Gains) losses reclassified from accumulated OCI, net of tax (55,155 ) (a) 144 (a) 10,675 (b) — (44,336 ) As of 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 ) As of 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) 903 (2,948 ) As of December 31, 2018 $ — $ (387 ) $ (5,922 ) $ 903 $ (5,406 ) (a) Gains (losses) reclassified from accumulated OCI, net of tax related to natural gas cash flow hedges were reclassified into operating revenues. Losses from accumulated OCI, net of tax related to interest rate cash flow hedges were reclassified into interest expense. (b) This accumulated OCI reclassification is attributable to the net actuarial loss and net prior service cost related to the Company’s defined benefit pension plans and other post-retirement benefit plans. See Note 1 for additional information. |
Common Stock and Treasury Sto_2
Common Stock and Treasury Stock (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Earnings Per Share [Abstract] | |
Schedule of shares of authorized and unissued common stock | At December 31, 2018 , shares of EQT’s authorized and unissued common stock were reserved as follows: (Thousands) Possible future acquisitions 20,457 Stock compensation plans 12,813 Total 33,270 |
Share-Based Compensation Plans
Share-Based Compensation Plans (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Schedule of share-based compensation expense | Share-based compensation expense recorded by the Company was as follows: Years Ended December 31, 2018 2017 2016 (Thousands) 2014 Executive Performance Incentive Program $ — $ — $ 9,494 2015 Executive Performance Incentive Program — 5,348 12,456 2016 Incentive Performance Share Unit Program 6,863 13,077 7,166 2017 Incentive Performance Share Unit Program 2,467 5,038 — 2018 Incentive Performance Share Unit Program 4,742 — — 2015 EQT Value Driver Award Program — — 3,174 2016 EQT Value Driver Performance Share Unit Award Program — 3,341 15,694 2017 EQT Value Driver Performance Share Unit Award Program 584 10,822 — 2018 EQT Value Driver Performance Share Unit Award Program 8,224 — — Restricted stock awards 14,503 87,104 9,407 Non-qualified stock options 2,757 2,626 3,119 Other programs, including non-employee director awards 3,014 1,005 5,459 Less: Discontinued operations (18,250 ) (15,595 ) (18,631 ) Total share-based compensation expense $ 24,904 $ 112,766 $ 47,338 |
Schedule of details of award types | More detailed information about 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, 2018 (b) 2014 Stock Equity $ 189.68 0.78% February 2017 238,060 $ 45.2 N/A N/A 2015 Stock Equity $ 141.11 1.10% February 2018 274,767 $ 38.8 N/A N/A 2016 (c) Stock Equity $ 109.30 1.31% N/A N/A N/A First Quarter of 2019 384,101 2017 (d) Stock Equity $ 120.60 1.47% N/A N/A N/A First Quarter of 2020 44,573 2017 (e) Cash Liability $ 59.90 2.61% N/A N/A N/A First Quarter of 2020 105,018 2018 (f) Stock Equity $ 76.53 1.97% N/A N/A N/A First Quarter of 2021 107,340 2018 (g) Cash Liability $ 33.30 2.46% N/A N/A N/A First Quarter of 2021 124,820 (a) Information shown for the valuation of the liability plans is as of December 31, 2018. (b) Represents the number of outstanding units as of December 31, 2018 adjusted for forfeitures. The 2016, 2017, and 2018 Incentive PSU Programs to be settled in stock include 130,393 , 7,020 , and 34,640 shares, respectively, for Equitrans Midstream employees that will be settled by the Company under the Employee Matters Agreement. The 2017 and 2018 Incentive PSU Programs to be settled in cash include 43,134 and 57,240 shares, respectively, for Equitrans Midstream employees that will be settled by the Company under the Employee Matters Agreement. (c) As of January 1, 2018 , a total of 447,145 units were outstanding under the 2016 Incentive PSU Program. Adjusting for 63,044 forfeitures, there were 384,101 outstanding units as of December 31, 2018 . (d) As of January 1, 2018, a total of 79,070 units were outstanding under the 2017 Incentive PSU Program - Equity. Adjusting for 34,497 forfeitures, there were 44,573 outstanding units as of December 31, 2018 . (e) As of January 1, 2018, a total of 117,530 units were outstanding under the 2017 Incentive PSU Program - Liability. Adjusting for 12,512 forfeitures, there were 105,018 total outstanding units as of December 31, 2018. (f) A total of 172,350 units were granted under the 2018 Incentive PSU Program - Equity in 2018 and no additional units may be granted. Adjusting for 65,010 forfeitures, there were 107,340 outstanding units as of December 31, 2018 . (g) A total of 142,890 units were granted under the 2018 Incentive PSU Program - Liability in 2018 and no additional units may be granted. Adjusting for 18,070 forfeitures, there were 124,820 total outstanding units as of December 31, 2018 . More detailed information about each award is set forth in the table below: EQT VDPSU Program Settled In Accounting Treatment Fair Value per Unit (a) Vested/Payment Date Number of awards (including accrued dividends) or cash (Millions) paid Unvested/Expected Payment Date Awards Outstanding (including accrued dividends) as of December 31, 2018 (d) 2015 Stock Equity $ 75.70 February 2016 222,751 N/A N/A $ 75.70 February 2017 208,567 N/A N/A 2016 (b) 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 N/A N/A Second tranche first quarter of 2019 214,384 2018 (c) Cash Liability $ 18.89 N/A N/A First tranche first quarter of 2019 256,803 N/A N/A N/A Second tranche first quarter of 2020 257,254 (a) For equity awards, the fair value per unit is equal to the Company's closing common stock price on the business day prior to the grant date. For liability awards, the fair value per unit is equal to the Company's common stock price on the measurement date. (b) 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. (c) The total liability recorded for the 2018 EQT VDPSU Program was $1.7 million as of December 31, 2018 . (d) The 2017 and 2018 EQT VDPSU Programs include 95,452 and 135,345 awards, respectively, for Equitrans Midstream employees that will be settled by the Company under the Employee Matters Agreement. |
Schedule of employee service share-based compensation, allocation of recognized period costs | The following table sets forth the total compensation costs capitalized related to each of the VDPSU Programs: For the Years Ended December 31, Award 2018 2017 2016 (Millions) 2015 EQT VDPSU Program $ — $ — $ 4.1 2016 EQT VDPSU Program — 7.0 16.3 2017 EQT VDPSU Program 0.1 10.3 — 2018 EQT VDPSU Program 3.3 — — The following table sets forth the total compensation costs capitalized related to each of the Incentive PSU Programs: For the Years Ended December 31, Award 2018 2017 2016 (Millions) 2014 Incentive PSU Program $ — $ — $ 4.2 2015 Incentive PSU Program — 2.2 4.9 2016 Incentive PSU Program 2.1 4.4 3.3 2017 Incentive PSU Program (liability only) 1.0 1.7 — 2018 Incentive PSU Program (liability only) 0.6 — — |
Summary of restricted stock awards activity | A summary of restricted stock equity award activity as of December 31, 2018 , and changes during the year then ended, is presented below: Restricted Stock Non- Vested Shares (a) Weighted Average Fair Value Aggregate Fair Value Outstanding at January 1, 2018 729,500 $ 66.86 $ 48,776,872 Granted 145,540 54.33 7,906,734 Vested (596,888 ) 66.75 (39,843,286 ) Forfeited (85,370 ) 62.26 (5,314,727 ) Outstanding at December 31, 2018 192,782 $ 59.79 $ 11,525,593 (a) Non-vested shares outstanding at December 31, 2018 included 107,422 shares for Equitrans Midstream employees that will be settled by the Company under the Employee Matters Agreement. |
Non-qualified stock options, assumptions used to value share-based compensation | air value is estimated using a Monte Carlo simulation valuation method with the following weighted average assumptions: For Incentive PSU Programs Issued During the Years Ended December 31, 2018 2018 2017 2017 2016 2015 2014 Accounting Treatment Liability (a) Equity Liability (a) Equity Equity Equity Equity Risk-free rate 2.46% 1.97% 2.61% 1.47% 1.31% 1.10% 0.78% Dividend Yield (b) N/A N/A N/A N/A N/A N/A N/A Volatility factor 35.70% 32.60% 41.17% 32.30% 28.43% 27.45% 31.38% Expected term 2 years 3 years 1 year 3 years 3 years 3 years 3 years (a) Information shown for the valuation of the liability plans is as of December 31, 2018. (b) Dividends paid from the beginning of the performance period will be cumulatively added as additional shares of common stock. The expected term represents the period of time that options granted are expected to be outstanding based on historical option exercise experience. For the Years Ended December 31, 2018 2017 (a) 2016 (a) Risk-free interest rate 2.25 % 1.95 % 1.67 % Dividend yield 0.20 % 0.18 % 0.16 % Volatility factor 26.46 % 27.45 % 28.59 % Expected term 5 years 5 years 5 years Number of Options Granted 287,800 153,700 228,500 Weighted Average Grant Date Fair Value $ 15.39 $ 17.47 $ 15.10 Total Intrinsic Value of Options Exercised (millions) $ — $ 1.7 $ 3.5 (a) There were two grant dates for the 2017 and 2016 options. Amounts represent weighted average. |
Summary of option activity | A summary of option activity as of December 31, 2018 , and changes during the year then ended, is presented below: Non-qualified Stock Options Shares Weighted Average Exercise Price Weighted Average Remaining Contractual Term Aggregate Intrinsic Value Outstanding at January 1, 2018 1,129,200 $ 63.42 Granted 287,800 56.92 Exercised — — Forfeited (215,100 ) 58.14 Converted awards granted as a result of Separation 573,529 31.23 Expired — — Outstanding at December 31, 2018 1,775,429 $ 32.43 5.57 years $ — Exercisable at December 31, 2018 1,533,452 $ 32.88 5.22 years $ — |
Interim Financial Information_2
Interim Financial Information (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Quarterly Financial Information Disclosure [Abstract] | |
Interim Financial Information (Unaudited) | The following quarterly summary of operating results reflects variations due to various factors including: the volatility of natural gas commodity prices, impairments, the Separation and Distribution, the impact of the Tax Cuts and Jobs Act and the inclusion of Rice operations beginning November 13, 2017. All prior periods presented have been recast to reflect the presentation of discontinued operations as described in Note 2 . Three Months Ended March 31 June 30 September 30 December 31 (Thousands, except per share amounts) 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: (Loss) from continuing operations $ (5.96 ) $ (0.29 ) $ (0.49 ) $ (2.35 ) Income from discontinued operations (0.03 ) 0.36 0.34 (0.15 ) Net (loss) income $ (5.99 ) $ 0.07 $ (0.15 ) $ (2.50 ) Diluted: (Loss) from continuing operations $ (5.96 ) $ (0.29 ) $ (0.49 ) $ (2.35 ) Income from discontinued operations (0.03 ) 0.36 0.34 (0.15 ) Net (loss) income $ (5.99 ) $ 0.07 $ (0.15 ) $ (2.50 ) 2017 Total operating revenues $ 828,662 $ 631,101 $ 597,718 $ 1,033,539 Operating income (loss) 243,572 47,763 (6,380 ) 97,257 Amounts attributable to EQT Corporation: (Loss) income from continuing operations 113,190 3,387 (6,238 ) 1,276,690 Income from discontinued operations, net of tax 50,802 37,739 29,578 3,381 Net income attributable to EQT Corporation $ 163,992 $ 41,126 $ 23,340 $ 1,280,071 Earnings per share of common stock attributable to EQT Corporation: Basic: (Loss) income from continuing operations $ 0.66 $ 0.02 $ (0.04 ) $ 5.83 Income from discontinued operations 0.29 0.22 0.17 0.02 Net income $ 0.95 $ 0.24 $ 0.13 $ 5.85 Diluted: (Loss) income from continuing operations $ 0.66 $ 0.02 $ (0.04 ) $ 5.81 Income from discontinued operations 0.29 0.22 0.17 0.02 Net income $ 0.95 $ 0.24 $ 0.13 $ 5.83 |
Natural Gas Producing Activit_2
Natural Gas Producing Activities (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Schedule of cost incurred relating to property acquisition, exploration and development | The following tables present the total aggregate capitalized costs and the costs incurred relating to natural gas, NGLs and oil production activities (a): For the Years Ended December 31, 2018 2017 2016 (Thousands) At December 31: Capitalized Costs: Proved properties $ 17,648,731 $ 18,920,855 $ 12,179,833 Unproved properties 4,166,048 5,016,299 1,698,826 Total capitalized costs 21,814,779 23,937,154 13,878,659 Accumulated depreciation and depletion 4,666,212 5,121,646 4,217,154 Net capitalized costs $ 17,148,567 $ 18,815,508 $ 9,661,505 For the Years Ended December 31, 2018 2017 2016 (Thousands) Costs incurred: (a) Property acquisition: Proved properties (b) $ 77,099 $ 5,251,711 $ 403,314 Unproved properties (c) 198,854 3,310,995 880,545 Exploration (d) 1,708 15,505 6,047 Development 2,443,980 1,357,165 777,787 Geological and geophysical — — — (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, which includes the impact of measurement period adjustments for the 2017 acquisitions discussed in Note 3 and 7 . 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 transactions discussed in Notes 3 and 7 . The purchase of Marcellus leases includes measurement period adjustments to the 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 transactions discussed in Notes 3 and 7 . Amounts in 2016 include $256.2 million and $112.2 million for the purchase of Marcellus wells and leases, respectively, acquired in the 2016 transactions discussed in Note 7 . (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 transactions discussed in Notes 3 and 7 . Amounts in 2016 include $770.4 million for the purchase of Marcellus leases acquired in the 2016 transactions discussed in Note 7 . (d) Amounts include capitalizable exploratory costs and exploration expense, excluding impairments. |
Results of operations related to natural gas, NGL and oil producing Activities | The following table presents the results of operations related to natural gas, NGLs and oil production: For the Years Ended December 31, 2018 2017 2016 (Thousands) Revenues $ 4,695,519 $ 2,651,318 $ 1,594,997 Transportation and processing 1,697,001 1,164,783 880,191 Production 195,775 181,349 174,170 Exploration 6,765 17,565 4,663 Depreciation and depletion 1,569,038 970,985 856,451 Impairment of long-lived assets 2,709,976 — — Lease impairments and expirations 279,708 7,552 15,686 Income tax (benefit) expense (454,009 ) 121,359 (135,029 ) Results of operations from producing activities (excluding corporate overhead) $ (1,308,735 ) $ 187,725 $ (201,135 ) |
Schedule of the entity's proved reserves | Years Ended December 31, 2018 2017 2016 (Millions of Cubic Feet) Total - Natural Gas, Oil, and NGLs (a) Proved developed and undeveloped reserves: Beginning of year 21,445,667 13,508,407 9,976,597 Revision of previous estimates (1,124,904 ) (2,766,981 ) (472,285 ) Purchase of hydrocarbons in place — 9,389,638 2,395,776 Sale of hydrocarbons in place (1,748,557 ) (2,646 ) — Extensions, discoveries and other additions 4,739,233 2,225,141 2,384,682 Production (1,494,663 ) (907,892 ) (776,363 ) End of year 21,816,776 21,445,667 13,508,407 Proved developed reserves: Beginning of year 11,297,956 6,842,958 6,279,557 End of year 11,550,161 11,297,956 6,842,958 Proved undeveloped reserves: Beginning of year 10,147,711 6,665,449 3,697,040 End of year 10,266,615 10,147,711 6,665,449 (a) Oil and NGLs were converted at the rate of one thousand Bbl equal to approximately 6 million cubic feet (MMcf). Years Ended December 31, 2018 2017 2016 (Millions of Cubic Feet) Natural Gas Proved developed and undeveloped reserves: Beginning of year 19,830,236 12,331,867 9,110,311 Revision of previous estimates (960,285 ) (2,760,467 ) (607,171 ) Purchase of natural gas in place — 8,890,145 2,288,166 Sale of natural gas in place (1,331,391 ) (1,210 ) — Extensions, discoveries and other additions 4,659,835 2,164,578 2,241,528 Production (1,392,943 ) (794,677 ) (700,967 ) End of year 20,805,452 19,830,236 12,331,867 Proved developed reserves: Beginning of year 10,152,543 6,074,958 5,652,989 End of year 10,887,953 10,152,543 6,074,958 Proved undeveloped reserves: Beginning of year 9,677,693 6,256,909 3,457,322 End of year 9,917,499 9,677,693 6,256,909 Years Ended December 31, 2018 2017 2016 (Thousands of Bbls) Oil (a) Proved developed and undeveloped reserves: Beginning of year 10,731 6,395 5,900 Revision of previous estimates 6,217 5,103 1,159 Purchase of oil in place — 355 3 Sale of oil in place (10,447 ) (139 ) — Extensions, discoveries and other additions 338 9 62 Production (680 ) (992 ) (729 ) End of year 6,159 10,731 6,395 Proved developed reserves: Beginning of year 10,731 6,395 5,900 End of year 3,489 10,731 6,395 Proved undeveloped reserves: Beginning of year — — — End of year 2,670 — — (a) One thousand Bbl equals approximately 6 million cubic feet (MMcf). Years Ended December 31, 2018 2017 2016 (Thousands of Bbls) NGLs (a) Proved developed and undeveloped reserves: Beginning of year 258,507 189,695 138,481 Revision of previous estimates (33,653 ) (6,189 ) 21,322 Purchase of NGLs in place — 82,894 17,932 Sale of NGLs in place (59,080 ) (100 ) — Extensions, discoveries and other additions 12,895 10,084 23,797 Production (16,274 ) (17,877 ) (11,837 ) End of year 162,395 258,507 189,695 Proved developed reserves: Beginning of year 180,170 121,605 98,528 End of year 106,879 180,170 121,605 Proved undeveloped reserves: Beginning of year 78,337 68,090 39,953 End of year 55,516 78,337 68,090 (a) One thousand Bbl equals approximately 6 million cubic feet (MMcf). |
Schedule of estimated future net cash flows from natural gas and oil reserves | Estimated future net cash flows from natural gas and oil reserves are as follows at December 31: 2018 2017 2016 (Thousands) Future cash inflows (a) $ 60,603,624 $ 51,423,920 $ 24,011,281 Future production costs (b) (20,463,567 ) (18,379,892 ) (14,864,126 ) Future development costs (5,854,503 ) (5,637,676 ) (3,778,698 ) Future income tax expenses (6,823,621 ) (5,811,125 ) (1,753,067 ) Future net cash flow 27,461,933 21,595,227 3,615,390 10% annual discount for estimated timing of cash flows (15,850,035 ) (12,593,293 ) (2,626,636 ) Standardized measure of discounted future net cash flows $ 11,611,898 $ 9,001,934 $ 988,754 (a) The majority of the Company’s production is sold through liquid trading points on interstate pipelines. For 2018, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2018 of $65.56 per Bbl of oil (first day of each month closing price for West Texas Intermediate (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 arithmetic averages of the closing prices on the first day of each month during 2018 for NGL components and adjusted using the regional component makeup of produced NGLs resulted in prices of $21.93 per Bbl of NGLs for certain West Virginia Marcellus reserves and $33.89 per Bbl of NGLs per Bbl for Ohio Utica reserves. The majority of the Company’s production is sold through liquid trading points on interstate pipelines. For 2017, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2017 of $51.34 per Bbl of oil (first day of each month closing price for West Texas Intermediate (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 arithmetic averages of the closing prices on the first day of each month during 2017 for NGL components and adjusted using the regional component makeup of produced NGLs resulted in prices of $23.07 per Bbl of NGLs from certain West Virginia Marcellus reserves, $31.11 per Bbl of NGLs from certain Kentucky reserves, $29.47 per Bbl for Ohio Utica reserves, and $27.93 per Bbl for Permian reserves. The majority of the Company’s production is sold through liquid trading points on interstate pipelines. For 2016, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2016 of $42.75 per Bbl of oil (first day of each month closing price for WTI) less regional adjustments, $2.342 per Dth for Columbia Gas Transmission Corp., $1.348 per Dth for Dominion Transmission, Inc., $2.334 per Dth for the East Tennessee Natural Gas Pipeline, $1.325 per Dth for Texas Eastern Transmission Corp., $1.305 per Dth for the Tennessee, zone 4-300 Leg of Tennessee Gas Pipeline Company, $1.862 per Dth for the Tennessee LA 500 Leg of Tennessee Gas Pipeline Company, $2.343 per Dth for Waha, and $2.402 per Dth for the Rockies Express Pipeline Zone 3. For 2016, NGL pricing using arithmetic averages of the closing prices on the first day of each month during 2016 for NGL components and adjusted using the regional component makeup of produced NGLs resulted in prices of $13.87 per Bbl of NGLs from certain West Virginia Marcellus reserves, $17.27 per Bbl of NGLs from certain Kentucky reserves, $14.71 per Bbl for Ohio Utica reserves, and $18.91 per Bbl for Permian reserves. (b) Includes approximately $883 million, $1,400 million and $790 million as of December 31, 2018, 2017 and 2016 respectively for future plugging and abandonment costs. |
Schedule of changes in the standardized measure of discounted net cash flows from natural gas and oil reserves | Summary of changes in the standardized measure of discounted future net cash flows for the years ended December 31: 2018 2017 2016 (Thousands) Sales and transfers of natural gas and oil produced – net $ (2,802,742 ) $ (1,305,186 ) $ (540,636 ) Net changes in prices, production and development costs 2,949,606 2,236,183 (1,129,026 ) Extensions, discoveries and improved recovery, less related costs 1,616,653 1,269,712 590,885 Development costs incurred 1,630,506 712,635 402,891 Purchase of minerals in place – net — 5,357,921 592,078 Sale of minerals in place – net (849,162 ) (284 ) — Revisions of previous quantity estimates (811,576 ) (297,437 ) (60,959 ) Accretion of discount 834,026 115,437 122,674 Net change in income taxes (289,549 ) (1,477,603 ) (91,823 ) Timing and other (a) 332,202 1,401,802 125,116 Net increase (decrease) 2,609,964 8,013,180 11,200 Beginning of year 9,001,934 988,754 977,554 End of year $ 11,611,898 $ 9,001,934 $ 988,754 (a) Increase in 2017 primarily driven by timing changes to the Company’s development plan as a result of the Rice Merger. |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies - Narrative (Details) | Jan. 01, 2019USD ($) | Nov. 12, 2018 | Jun. 30, 2016USD ($) | Dec. 31, 2018USD ($)$ / Mcfedry_holesegment | Dec. 31, 2017USD ($)$ / Mcfedry_holeshares | Dec. 31, 2016USD ($)$ / Mcfe | Mar. 31, 2018USD ($) | Jan. 01, 2018USD ($) | |
Property, Plant and Equipment [Line Items] | |||||||||
Number of segments | segment | 1 | ||||||||
Unrealized holding gain (loss) | $ (2,600,000) | $ 1,500,000 | |||||||
Contract with customer, asset, net | 783,000,000 | ||||||||
Oil and gas joint interest billing receivables | 324,200,000 | 149,300,000 | |||||||
Losses for lower of cost or market adjustments | 0 | 0 | $ 0 | ||||||
Percentage of ownership after transaction | 19.90% | ||||||||
Internal costs | 130,000,000 | 114,600,000 | 115,400,000 | ||||||
Interest costs capitalized | $ 29,000,000 | $ 20,500,000 | $ 19,200,000 | ||||||
Overall average rate of depletion | $ / Mcfe | 1.04 | 1.04 | 1.06 | ||||||
Impairment/loss on sale of long-lived assets | $ 2,709,976,000 | $ 0 | $ 0 | ||||||
Lease impairments and expirations | 279,708,000 | 7,552,000 | 15,686,000 | ||||||
Unproved properties | $ 4,166,048,000 | $ 5,016,299,000 | 1,698,826,000 | ||||||
Number of exploratory dry holes | dry_hole | 0 | 1 | |||||||
Capitalized exploratory well costs | $ 0 | $ 0 | |||||||
Impairment of goodwill | $ 530,811,000 | 0 | 0 | ||||||
Number of days used in calculation | 30 days | ||||||||
Amortization of intangible assets | $ 41,367,000 | $ 5,400,000 | 0 | ||||||
Amortization expense, year 1 | 41,400,000 | ||||||||
Amortization expense, year 2 | $ 35,900,000 | ||||||||
Largest amount of benefit threshold, percentage (no greater than) | 50.00% | ||||||||
Stock options and awards (in shares) | shares | 346,528 | ||||||||
Anti-dilutive securities (in shares) | shares | 429,785 | ||||||||
Net loss of defined benefit pension plans, amortized from accumulated OCI, net of tax, into net periodic benefit cost | 9,400,000 | ||||||||
Benefits paid | $ 5,400,000 | ||||||||
Expense recognized related to defined contribution plan | $ 17,300,000 | $ 16,600,000 | 16,000,000 | ||||||
Asset retirement obligations, period increase | 34,600,000 | 143,600,000 | 66,200,000 | ||||||
Measurement adjustments | 14,400,000 | (14,300,000) | |||||||
Capitalization of non-cash stock based compensation | 4,300,000 | 9,000,000 | 16,600,000 | ||||||
Increase in capital contributions payable | (274,200,000) | (4,400,000) | (27,700,000) | ||||||
Liabilities assumed | 10,000,000 | 87,600,000 | |||||||
Change in accounting principle | [1] | $ 4,113,000 | |||||||
Restricted cash | 75,000,000 | ||||||||
Mountain Valley Pipeline | |||||||||
Property, Plant and Equipment [Line Items] | |||||||||
Increase in capital contributions payable | $ (176,600,000) | $ (94,300,000) | $ (11,500,000) | ||||||
Minimum | Subsequent Event | |||||||||
Property, Plant and Equipment [Line Items] | |||||||||
Right-of-use asset obtained | $ 100,000,000 | ||||||||
Maximum | Subsequent Event | |||||||||
Property, Plant and Equipment [Line Items] | |||||||||
Right-of-use asset obtained | $ 125,000,000 | ||||||||
Accounting Standards Update 2016-01 | |||||||||
Property, Plant and Equipment [Line Items] | |||||||||
Change in accounting principle | $ 4,100,000 | ||||||||
Noncompete Agreements | |||||||||
Property, Plant and Equipment [Line Items] | |||||||||
Intangible asset useful life | 3 years | ||||||||
Oil and Gas Receivable | |||||||||
Property, Plant and Equipment [Line Items] | |||||||||
Contract with customer, asset, net | $ 783,000,000 | ||||||||
Huron and Permian Basin of Texas | |||||||||
Property, Plant and Equipment [Line Items] | |||||||||
Impairment/loss on sale of long-lived assets | $ 2,400,000,000 | ||||||||
[1] | Related to adoption of ASU No. 2016-01. See Note 1 for additional information. |
Summary of Significant Accoun_5
Summary of Significant Accounting Policies - Schedule of Property, Plant and Equipment (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Property, Plant and Equipment [Line Items] | |||
Oil and gas producing properties, successful efforts method | $ 21,814,779 | $ 23,937,154 | $ 13,878,659 |
Accumulated depreciation and depletion | (4,666,212) | (5,121,646) | (4,217,154) |
Net capitalized costs | 17,148,567 | 18,815,508 | $ 9,661,505 |
Net property, plant and equipment | 17,392,507 | 19,730,008 | |
Other Properties | |||
Property, Plant and Equipment [Line Items] | |||
Net property, plant and equipment | $ 243,940 | $ 914,500 |
Summary of Significant Accoun_6
Summary of Significant Accounting Policies - Schedule of Intangible Assets (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Accounting Policies [Abstract] | ||
Finite-lived intangible assets, gross | $ 124,100 | $ 124,100 |
Less: accumulated amortization | (46,767) | (5,400) |
Intangible assets, net | $ 77,333 | $ 118,700 |
Summary of Significant Accoun_7
Summary of Significant Accounting Policies - Other Current Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Other Current Liabilities: | ||
Incentive compensation | $ 46,937 | $ 72,910 |
Taxes other than income | 75,978 | 62,091 |
Accrued interest payable | 42,998 | 41,926 |
Legal reserve | 53,500 | 0 |
Severance accrual | 8,893 | 41,474 |
All other accrued liabilities | 26,381 | 55,875 |
Total other current liabilities | $ 254,687 | $ 274,276 |
Summary of Significant Accoun_8
Summary of Significant Accounting Policies - Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Asset retirement obligations | ||
Asset retirement obligation as of beginning of period | $ 443,349 | $ 243,600 |
Accretion expense | 17,513 | 13,644 |
Liabilities incurred | 7,785 | 19,678 |
Liabilities settled | (3,722) | (3,750) |
Liabilities assumed in the Rice Merger | 27,999 | 41,655 |
Liabilities removed due to divestitures | (231,936) | (88) |
Change in estimates | 26,817 | 128,610 |
Asset retirement obligation as of end of period | $ 287,805 | $ 443,349 |
Separation and Distribution a_3
Separation and Distribution and Discontinued Operations - Additional Information (Details) - USD ($) $ in Millions | Nov. 12, 2018 | Dec. 31, 2018 |
Discontinued Operations and Disposal Groups [Abstract] | ||
Percentage of ownership transferred | 80.10% | |
Stock dividend (in dollars per share) | 0.80 | |
Percentage of ownership after transaction | 19.90% | |
Unrealized loss on investment | $ 72.4 | |
Term of agreement | 20 years |
Separation and Distribution a_4
Separation and Distribution and Discontinued Operations - Schedule of Results from Discontinued Operations (Details) - USD ($) $ in Thousands | 3 Months Ended | 10 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Nov. 12, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||
Impairment of goodwill | $ 798,689 | $ 0 | $ 0 | |||||||||
Income from discontinued operations after income taxes | 373,762 | 471,113 | 400,430 | |||||||||
Net income from discontinued operations | $ (38,625) | $ 87,654 | $ 94,784 | $ (7,461) | $ 3,381 | $ 29,578 | $ 37,739 | $ 50,802 | $ 136,352 | 121,500 | 78,510 | |
Midstream Business | Spinoff | ||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||
Operating revenues | $ 388,854 | 279,422 | 217,952 | |||||||||
Transportation and processing | (803,858) | (604,025) | (514,373) | |||||||||
Operation and maintenance | 99,671 | 80,833 | 69,308 | |||||||||
Selling, general and administrative | 62,702 | 53,275 | 44,022 | |||||||||
Depreciation | 160,701 | 106,574 | 71,469 | |||||||||
Impairment/loss on sale of long-lived assets | 0 | 0 | 59,748 | |||||||||
Impairment of goodwill | 267,878 | 0 | 0 | |||||||||
Transaction costs | 93,062 | 85,124 | 0 | |||||||||
Amortization of intangible assets | 36,007 | 5,540 | 0 | |||||||||
Other income | 51,014 | 26,610 | 28,718 | |||||||||
Interest expense | 88,300 | 34,801 | 16,761 | |||||||||
Income from discontinued operations before income taxes | 435,405 | 543,910 | 499,735 | |||||||||
Income tax expense | 61,643 | 72,797 | 99,305 | |||||||||
Income from discontinued operations after income taxes | 373,762 | 471,113 | 400,430 | |||||||||
Less: Net income from discontinued operations attributable to noncontrolling interests | 237,410 | 349,613 | 321,920 | |||||||||
Net income from discontinued operations | $ 136,352 | $ 121,500 | $ 78,510 |
Separation and Distribution a_5
Separation and Distribution and Discontinued Operations - Schedule of Assets and Liabilities of Discontinued Operations (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Total assets of discontinued operations | ||
Current assets of discontinued operations | $ 0 | $ 156,260 |
Noncurrent assets of discontinued operations | 0 | 7,789,258 |
Total liabilities of discontinued operations | ||
Current liabilities of discontinued operations | 0 | 80,033 |
Noncurrent liabilities of discontinued operations | $ 0 | 1,248,032 |
Midstream Business | Spinoff | ||
Total assets of discontinued operations | ||
Cash and cash equivalents | 121,004 | |
Accounts receivable, net | 60,551 | |
Prepaid expenses and other | (25,295) | |
Current assets of discontinued operations | 156,260 | |
Net property, plant and equipment | 5,155,007 | |
Intangible assets, net | 617,660 | |
Goodwill | 1,527,877 | |
Investment in nonconsolidated entity | 460,546 | |
Other assets | 28,168 | |
Noncurrent assets of discontinued operations | 7,789,258 | |
Total assets of discontinued operations | 7,945,518 | |
Total liabilities of discontinued operations | ||
Accounts payable | (71,809) | |
Other current liabilities | 151,842 | |
Current liabilities of discontinued operations | 80,033 | |
Credit facility borrowings | 466,000 | |
Senior Notes | 987,352 | |
Deferred income taxes | (121,062) | |
Notes payable to EQM Midstream Partners, LP (See Note 10) | (114,720) | |
Other liabilities and credits | 30,462 | |
Noncurrent liabilities of discontinued operations | 1,248,032 | |
Total liabilities of discontinued operations | $ 1,328,065 |
Separation and Distribution a_6
Separation and Distribution and Discontinued Operations - Schedule of Cash Provided by Discontinued Operations (Details) - USD ($) $ in Thousands | 10 Months Ended | 12 Months Ended | ||
Nov. 12, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Operating activities: | ||||
Goodwill impairment | $ 798,689 | $ 0 | $ 0 | |
Share-based compensation expense | $ 18,250 | 15,595 | 18,631 | |
Midstream Business | Spinoff | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Disposal Group, Including Discontinued Operation, Increase (Decrease) in Deferred Income Taxes | $ (373,405) | 43,471 | (21,936) | |
Operating activities: | ||||
Depreciation | 160,701 | 106,574 | 71,469 | |
Amortization of intangible assets | 36,007 | 5,540 | 0 | |
Asset impairments | 0 | 0 | 59,748 | |
Goodwill impairment | 267,878 | 0 | 0 | |
Other income | (51,450) | (27,281) | (29,300) | |
Share-based compensation expense | 1,841 | 468 | 373 | |
Investing activities: | ||||
Capital expenditures | (732,727) | (380,151) | (584,819) | |
Capital contributions to Mountain Valley Pipeline, LLC (a) | (820,943) | (159,550) | (98,399) | |
Sales of interests in Mountain Valley Pipeline, LLC (a) | 0 | 0 | 12,533 | |
Financing activities: | ||||
Net proceeds from the issuance of common units of EQM | 0 | 0 | 217,102 | |
Proceeds from issuance of debt | 2,500,000 | 0 | 500,018 | |
Increase in borrowings on credit facilities | 3,378,500 | 544,084 | 740,000 | |
Repayment of borrowings on credit facilities | (3,219,500) | (344,000) | (1,039,000) | |
Distributions to noncontrolling interests | (380,651) | (236,123) | (189,981) | |
Contribution to Strike Force Midstream LLC by minority owner, net of distribution | 0 | 6,738 | 0 | |
Acquisition of 25% of Strike Force Midstream LLC | (175,000) | 0 | 0 | |
Debt issuance costs and revolving credit facility origination fees | $ (40,966) | $ (2,257) | $ (8,580) |
Rice Merger - Additional Inform
Rice Merger - Additional Information (Details) $ / shares in Units, a in Thousands, $ in Thousands, shares in Millions | Nov. 13, 2017USD ($)a$ / sharesshares | Dec. 31, 2018USD ($)a | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) |
Business Acquisition [Line Items] | ||||
Payments to acquire businesses, net | $ 0 | $ (1,560,272) | $ 0 | |
Payment for acquisition | 34,113 | 828,657 | 1,061,735 | |
Unamortized premium | $ 0 | 89,363 | 0 | |
Number of acres acquired (in acres) | a | 304 | |||
Merger related expenses | $ 26,331 | 152,188 | $ 0 | |
Rice Merger Agreement | ||||
Business Acquisition [Line Items] | ||||
Common share conversion ratio | 0.37 | |||
Cash conversion (in dollars per share) | $ / shares | $ 5.30 | |||
Number of shares issued in business combination (in shares) | shares | 91 | |||
Payments to acquire businesses, net | $ (1,600,000) | |||
Payment for acquisition | 1,299,407 | |||
Payment for debt extinguishment | $ 1,400,000 | |||
Number of acres acquired (in acres) | a | 270 | |||
Amortization of debt issuance costs | 8,000 | |||
Goodwill, expected tax deductible amount | $ 387,100 | |||
Rice Merger Agreement | Continuing Operations | ||||
Business Acquisition [Line Items] | ||||
Amortization of debt issuance costs | 5,100 | |||
Merger related expenses | 25,400 | 152,200 | ||
Rice Merger Agreement | Discontinued Operations | ||||
Business Acquisition [Line Items] | ||||
Amortization of debt issuance costs | 2,900 | |||
Merger related expenses | $ 13,500 | $ 85,100 | ||
Rice Merger Agreement | Marcellus Acres | ||||
Business Acquisition [Line Items] | ||||
Number of acres acquired (in acres) | a | 205 | |||
Rice Merger Agreement | Utica Acres | ||||
Business Acquisition [Line Items] | ||||
Number of acres acquired (in acres) | a | 65 | |||
Rice Merger Agreement | Rice Energy Operating LLC's Revolving Credit Facility | ||||
Business Acquisition [Line Items] | ||||
Extinguishment of debt, amount | $ 321,000 | |||
Interest expense | 1,400 | |||
Rice Merger Agreement | Rice Midstream Holdings' Revolving Credit Facility | ||||
Business Acquisition [Line Items] | ||||
Extinguishment of debt, amount | 187,500 | |||
Interest expense | $ 300 | |||
Rice Merger Agreement | Rice 2022 Notes | ||||
Business Acquisition [Line Items] | ||||
Interest rate | 6.25% | |||
Unamortized premium | $ 42,200 | |||
Rice Merger Agreement | Rice 2023 Notes | ||||
Business Acquisition [Line Items] | ||||
Interest expense | $ 13,400 | |||
Interest rate | 7.25% | |||
Unamortized premium | $ 21,600 | |||
Rice Merger Agreement | EIG Global Energy Partners | ||||
Business Acquisition [Line Items] | ||||
Payment for acquisition | $ 555,500 | |||
Rice Energy Inc. | ||||
Business Acquisition [Line Items] | ||||
Par value (in dollars per share) | $ / shares | $ 0.01 |
Rice Merger - Purchase Price Al
Rice Merger - Purchase Price Allocation (Details) - USD ($) $ in Thousands | Nov. 13, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Consideration Given: | ||||
Cash consideration | $ 34,113 | $ 828,657 | $ 1,061,735 | |
Fair value of assets acquired: | ||||
Goodwill | 0 | $ 470,849 | ||
Rice Merger Agreement | ||||
Business Acquisition [Line Items] | ||||
Goodwill, expected tax deductible amount | $ 387,100 | |||
Consideration Given: | ||||
Equity consideration | 5,943,289 | |||
Cash consideration | 1,299,407 | |||
Buyout of preferred equity in Rice Midstream Holdings | 429,708 | |||
Buyout of common units in Rice Midstream GP Holdings, LP | 125,828 | |||
Settlement of pre-existing relationships | (14,699) | |||
Total consideration | 7,783,533 | |||
Fair value of liabilities assumed: | ||||
Current liabilities | 577,053 | |||
Long-term debt | 2,151,656 | |||
Deferred income taxes | 1,106,773 | |||
Other long term liabilities | 95,712 | |||
Amount attributable to liabilities assumed | 3,931,194 | |||
Fair value of assets acquired: | ||||
Cash | 294,671 | |||
Accounts receivable | 322,630 | |||
Current assets | 109,465 | |||
Net property, plant and equipment | 9,918,315 | |||
Intangible assets | 747,300 | |||
Noncontrolling interests | (1,715,611) | |||
Amount attributable to assets acquired | 9,676,770 | |||
Goodwill | $ 2,037,957 | 0 | ||
Goodwill allocated to discontinued operations | (1,239,268) | |||
Rice Merger Agreement | Continuing Operations | ||||
Fair value of assets acquired: | ||||
Goodwill impairment | (530,811) | |||
Rice Merger Agreement | Discontinued Operations | ||||
Fair value of assets acquired: | ||||
Goodwill impairment | $ (267,878) |
Revenue from Contracts with C_3
Revenue from Contracts with Customers - Disaggregation of Revenue (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Disaggregation of Revenue [Line Items] | |||||||||||
Number of days in which payment is required | 25 days | ||||||||||
Contract with customer, asset, net | $ 783,000 | $ 783,000 | |||||||||
Sales of natural gas, oil and NGLs | 4,709,384 | ||||||||||
Loss on derivatives not designated as hedges | (178,591) | $ 390,021 | $ (248,991) | ||||||||
Other sources of revenue | (151,516) | ||||||||||
Total operating revenues | $ 1,245,138 | $ 1,050,046 | $ 950,648 | $ 1,312,036 | $ 1,033,539 | $ 597,718 | $ 631,101 | $ 828,662 | 4,557,868 | $ 3,091,020 | $ 1,387,054 |
Natural Gas Sales | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Sales of natural gas, oil and NGLs | 4,217,684 | ||||||||||
Total, excluding gain (loss) on derivatives | 4,217,684 | ||||||||||
NGLs Sales | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Sales of natural gas, oil and NGLs | 442,010 | ||||||||||
Total, excluding gain (loss) on derivatives | 442,010 | ||||||||||
Oil Sales | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Sales of natural gas, oil and NGLs | 35,825 | ||||||||||
Total, excluding gain (loss) on derivatives | 35,825 | ||||||||||
Natural Gas, Oil, and NGLs Sales | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Sales of natural gas, oil and NGLs | 4,695,519 | ||||||||||
Total, excluding gain (loss) on derivatives | 4,695,519 | ||||||||||
Net Marketing Services and Other | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Sales of natural gas, oil and NGLs | 13,865 | ||||||||||
Other sources of revenue, excluding gain (loss) on derivatives | 27,075 | ||||||||||
Total, excluding gain (loss) on derivatives | $ 40,940 |
Revenue from Contracts with C_4
Revenue from Contracts with Customers - Remaining Performance Obligations (Details) - Natural Gas Sales $ in Thousands | Dec. 31, 2018USD ($) |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, remaining performance obligation | $ 54,116 |
Remaining performance obligation, expected timing of satisfaction, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, remaining performance obligation | $ 21,485 |
Remaining performance obligation, expected timing of satisfaction, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, remaining performance obligation | $ 0 |
Remaining performance obligation, expected timing of satisfaction, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, remaining performance obligation | $ 75,601 |
Remaining performance obligation, expected timing of satisfaction, period |
Derivative Instruments - Narra
Derivative Instruments - Narrative (Details) | 12 Months Ended | |
Dec. 31, 2018USD ($)BcfMBbls | Dec. 31, 2017USD ($)BcfMBbls | |
Derivative Instruments, Gain (Loss) [Line Items] | ||
Derivative instruments, at fair value | $ 481,654,000 | $ 241,952,000 |
Percentage of derivative liability (up to) | 100.00% | |
Aggregate fair value of derivative instruments with credit-risk related contingencies | $ 110,700,000 | |
Collateral posted | $ 0 | |
Natural Gas Liquid Instrument | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Absolute quantities of derivative commodity instruments (in MMcf) | MBbls | 1,505 | 1,460 |
Derivative instruments, at fair value | $ 40,300,000 | |
Commodity Derivatives | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Derivative instruments, at fair value | $ 481,654,000 | $ 241,952,000 |
Cash flow Hedges | Commodity Derivatives | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Absolute quantities of derivative commodity instruments (in MMcf) | Bcf | 3,128 | 2,148 |
Derivative Instruments - Sched
Derivative Instruments - Schedule of Impact of Netting Agreements and Margin Deposits on Gross Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Asset derivatives: | ||
Derivative instruments, recorded in the Consolidated Balance Sheet, gross | $ 481,654 | $ 241,952 |
Liability derivatives: | ||
Derivative instruments, recorded in the Consolidated Balance Sheet, gross | 336,051 | 139,089 |
Commodity Contract | ||
Asset derivatives: | ||
Derivative instruments, recorded in the Consolidated Balance Sheet, gross | 481,654 | 241,952 |
Derivative instruments, recorded in the Consolidated Balance Sheet, gross | (256,087) | (86,856) |
Margin deposits remitted to counterparties | 0 | 0 |
Derivative instruments, net | 225,567 | 155,096 |
Liability derivatives: | ||
Derivative instruments, recorded in the Consolidated Balance Sheet, gross | 336,051 | 139,089 |
Derivative instruments subject to master netting agreements | (256,087) | (86,856) |
Margin deposits remitted to counterparties | (40,283) | 0 |
Derivative instruments, at fair value | $ 39,681 | $ 52,233 |
Fair Value Measurements - Sched
Fair Value Measurements - Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Assets | ||
Derivative instruments, at fair value | $ 481,654 | $ 241,952 |
Derivative instruments, recorded in the Consolidated Balance Sheet, gross | 336,051 | 139,089 |
Fair Value, Measurements, Recurring | Quoted prices in active markets for identical assets (Level 1) | ||
Assets | ||
Derivative instruments, at fair value | 112,107 | 0 |
Liabilities | ||
Derivative instruments, at fair value | 126,582 | 0 |
Fair Value, Measurements, Recurring | Significant other observable inputs (Level 2) | ||
Assets | ||
Derivative instruments, at fair value | 369,547 | 241,952 |
Liabilities | ||
Derivative instruments, at fair value | 209,469 | 139,089 |
Fair Value, Measurements, Recurring | Significant unobservable inputs (Level 3) | ||
Assets | ||
Derivative instruments, at fair value | 0 | 0 |
Liabilities | ||
Derivative instruments, at fair value | 0 | 0 |
Commodity Contract | ||
Assets | ||
Derivative instruments, at fair value | 481,654 | 241,952 |
Derivative instruments, recorded in the Consolidated Balance Sheet, gross | 336,051 | 139,089 |
Liabilities | ||
Derivative instruments, at fair value | $ 256,087 | $ 86,856 |
Fair Value Measurements - Narra
Fair Value Measurements - Narrative (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Estimated fair value of total debt | $ 4,553,427 | $ 4,872,831 |
Carrying value of total debt | 4,697,381 | 4,702,329 |
Senior Notes | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Estimated fair value of total debt | 4,400,000 | 4,700,000 |
Carrying value of total debt | 4,600,000 | 4,600,000 |
EQT Midstream Notes | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Estimated fair value of total debt | 121,752 | 133,001 |
Carrying value of total debt | $ 114,720 | $ 119,127 |
Acquisitions (Details)
Acquisitions (Details) $ / shares in Units, $ in Thousands | Jun. 30, 2017a | Feb. 27, 2017aBcfewellmi | Feb. 01, 2017a | Dec. 16, 2016awell | Jul. 08, 2016awell | Dec. 31, 2017USD ($)awell | Dec. 31, 2016USD ($)well | Dec. 31, 2018USD ($)a | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Oct. 27, 2016$ / shares |
Business Acquisition [Line Items] | |||||||||||
Number of acres acquired (in acres) | a | 304,000 | ||||||||||
Payments to acquire businesses, net | $ 0 | $ 1,560,272 | $ 0 | ||||||||
Marion, Monongalia, and Wetzel Counties | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Number of acres acquired (in acres) | a | 14,000 | ||||||||||
Statoil Acquisition | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Number of acres acquired (in acres) | a | 62,500 | ||||||||||
Number of wells acquired | well | 31 | ||||||||||
Number of producing wells acquired | well | 24 | ||||||||||
Republic and Trans Energy Transactions | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Number of acres acquired (in acres) | a | 42,600 | ||||||||||
Number of wells acquired | well | 42 | ||||||||||
Number of producing wells acquired | well | 32 | ||||||||||
Trans Energy Merger | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Share price (in dollars per share) | $ / shares | $ 3.58 | ||||||||||
Pennsylvania Acquisition | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Number of acres acquired (in acres) | a | 17,000 | ||||||||||
Number of producing wells acquired | well | 2 | ||||||||||
Stone Energy Corporation | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Number of acres acquired (in acres) | a | 85,000 | ||||||||||
Number of wells acquired | well | 174 | ||||||||||
Number of producing wells acquired | well | 120 | ||||||||||
Number of acres with drilling rights | a | 44,000 | ||||||||||
Production of well (in MMcfe) | Bcfe | 0.11 | ||||||||||
Number of miles of pipeline acquired | mi | 20 | ||||||||||
Allegheny, Washington, and Westmore Counties | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Number of acres acquired (in acres) | a | 11,000 | ||||||||||
2017 Acquisitions | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Payments to acquire businesses, net | 740,100 | ||||||||||
Net property, plant and equipment | $ 750,100 | 750,100 | |||||||||
Current liabilities | 5,300 | 5,300 | |||||||||
Noncurrent liabilities assumed | $ 4,700 | 4,700 | |||||||||
2016 Acquisitions | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Payments to acquire businesses, net | 1,130,100 | ||||||||||
Net property, plant and equipment | $ 1,203,400 | 1,203,400 | |||||||||
Current liabilities | 14,400 | 14,400 | |||||||||
Noncurrent liabilities assumed | 11,100 | 11,100 | |||||||||
Payments to acquire land | 78,900 | ||||||||||
Adjustment to PPE | $ 14,300 | ||||||||||
Other noncurrent assets acquired | 1,200 | 1,200 | |||||||||
Notes payable assumed | 5,100 | 5,100 | |||||||||
Deferred income taxes | 49,000 | 49,000 | |||||||||
2016 Acquisitions | Proved Property | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Net property, plant and equipment | 256,200 | 256,200 | |||||||||
2016 Acquisitions | Unproved Property | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Net property, plant and equipment | $ 947,200 | $ 947,200 |
Divestitures (Details)
Divestitures (Details) $ in Thousands, a in Millions | Jul. 18, 2018USD ($)Bcfemiwellacompressor_station | Jun. 19, 2018USD ($)Bcfemiwellcompressor_station | Dec. 28, 2016USD ($) | Sep. 30, 2018USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||
Impairment/loss on sale of long-lived assets | $ 2,709,976 | $ 0 | $ 0 | ||||
Asset impairment charges | $ 260,500 | ||||||
Gain on sale of assets | 0 | $ 0 | $ 8,025 | ||||
Huron and Permian Basin of Texas | |||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||
Impairment/loss on sale of long-lived assets | $ 2,400,000 | ||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | |||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||
Consideration | $ 523,600 | $ 56,900 | |||||
Number of wells sold | well | 12,000 | 970 | |||||
Reduction in sales volume | Bcfe | 0.2 | 0.02 | |||||
Number of miles of gathering lines sold | mi | 6,400 | 350 | |||||
Number of compressors sold | compressor_station | 59 | 26 | |||||
Number of acres sold | a | 2.5 | ||||||
Non-core Marcellus Gathering System | |||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||
Proceeds from sale of oil and gas property and equipment | $ 75,000 | ||||||
Gain on sale of assets | $ 8,000 |
Income Taxes - Schedule of Inco
Income Taxes - Schedule of Income Tax Expense (Benefit) from Continuing Operations (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Current: | |||
Federal | $ (513,293) | $ (89,149) | $ (181,817) |
State | (46,218) | (5,184) | (22,627) |
Subtotal | (559,511) | (94,333) | (204,444) |
Deferred: | |||
Federal | 20,496 | (1,039,769) | (110,734) |
State | (157,496) | (54,314) | (47,591) |
Subtotal | (137,000) | (1,094,083) | (158,325) |
Total income taxes | $ (696,511) | $ (1,188,416) | $ (362,769) |
Income Taxes - Narrative (Detai
Income Taxes - Narrative (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Tax Credit Carryforward [Line Items] | |||
Income tax benefit resulting from refund | $ 141,000 | $ 65,000 | $ 83,000 |
Current state expense | 16,000 | ||
Amount offset by current expense | 435,000 | 29,000 | 121,000 |
Federal tax reform benefit | (5,288) | $ 1,205,140 | $ 0 |
Expected refund for alternative minimum tax credits | 128,000 | ||
Expected refund for net operating loss carryback claims | 11,000 | ||
Tax credit carryforward, amount | 295,000 | ||
Valuation allowance | $ 13,300 | ||
Statutory income tax rate | 21.00% | 35.00% | 35.00% |
Income tax expense from government regulated asset | $ 10,500 | ||
Effective tax rate, amount | $ 124,600 | 120,500 | $ 102,000 |
DTA, decrease resulting from uncertain tax positions | 300 | 500 | |
Tax positions for which the ultimate deductibility is highly certain | 700 | 4,700 | 5,500 |
Interest expense | 3,400 | 3,200 | 1,600 |
Interests and penalties | 11,900 | 8,400 | 5,200 |
Decrease in unrecognized tax benefits is reasonably possible | 33,300 | 42,500 | |
Deferred tax liability, disposition of business | 66,600 | ||
Valuation allowances | 217,000 | ||
Interest disallowance limitation, valuation Allowance | 21,700 | ||
Net operating loss carryforwards | 130,000 | ||
Equitrans Midstream | |||
Tax Credit Carryforward [Line Items] | |||
Valuation allowances | 14,000 | ||
Domestic Tax Authority | |||
Tax Credit Carryforward [Line Items] | |||
Operating loss carryforwards | 32,900 | ||
Valuation allowances | 22,800 | ||
State and Local Jurisdiction | |||
Tax Credit Carryforward [Line Items] | |||
Valuation allowances | 279,500 | ||
Deferred tax asset, NOL, state and local | 94,700 | ||
Deferred Tax Assets | |||
Tax Credit Carryforward [Line Items] | |||
Uncertain tax positions | $ 88,200 | 84,100 | $ 75,400 |
Federal Marginal Well Tax Credit | |||
Tax Credit Carryforward [Line Items] | |||
Tax credit carryforward, amount | 30,200 | ||
Federal Marginal Well Tax Credit | Tax Year 2016 | |||
Tax Credit Carryforward [Line Items] | |||
Tax credit carryforward, amount | $ 6,100 |
Income Taxes - Schedule of Reco
Income Taxes - Schedule of Reconciliation of Income Tax Expense to Amount Computed at the Federal Statutory Rate (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |||
Tax at statutory rate | $ (646,261) | $ 69,515 | $ (312,992) |
Federal tax reform | 5,288 | (1,205,140) | 0 |
State income taxes | (251,780) | (57,414) | (76,043) |
Valuation allowance | 88,785 | 10,680 | 23,808 |
Regulatory liability/asset | (276) | 10,488 | 0 |
Federal tax credits | (2,400) | (34,956) | (4,539) |
Goodwill impairment | 111,470 | 0 | 0 |
Other | (1,337) | 18,411 | 6,997 |
Total income taxes | $ (696,511) | $ (1,188,416) | $ (362,769) |
Effective tax rate | 22.60% | (598.40%) | 40.60% |
Income Taxes - Schedule of Re_2
Income Taxes - Schedule of Reconciliation of the Beginning and Ending Amount of Reserve for Uncertain Tax Positions(Excluding Interest and Penalties) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Reconciliation of reserve for uncertain tax positions, Excluding Amounts Pertaining to Examined Tax Returns | |||
Beginning Balance | $ 301,558 | $ 252,434 | $ 259,301 |
Additions based on tax positions related to current year | 8,459 | 50,469 | 23,978 |
Additions for tax positions of prior years | 14,396 | 8,978 | 20,336 |
Reductions for tax positions of prior years | (9,134) | (10,323) | (51,181) |
Ending Balance | $ 315,279 | $ 301,558 | $ 252,434 |
Income Taxes - Summary of Sourc
Income Taxes - Summary of Source and Tax Effects of Temporary Differences between Financial Reporting and Tax Bases of Assets and Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Deferred income taxes: | ||
Total deferred income tax assets | $ (901,377) | $ (1,112,514) |
Total deferred income tax liabilities | 2,724,758 | 3,002,476 |
Total net deferred income tax liabilities | 1,823,381 | 1,889,962 |
Total deferred income tax liabilities (assets): | ||
Drilling and development costs expensed for income tax reporting | 1,469,320 | 2,074,091 |
Tax depreciation in excess of book depreciation | 904,030 | 644,590 |
Investment in Equitrans Midstream | (10,359) | 0 |
Incentive compensation and deferred compensation plans | (24,682) | (43,822) |
Net operating loss carryforwards | (429,983) | (564,180) |
Alternative minimum tax credit carryforward | (308,727) | (435,190) |
Federal tax credits | (37,710) | (50,341) |
Unrealized (losses) gains | (28,096) | 21,403 |
Interest disallowance limitation | (35,358) | 0 |
Other | (26,462) | (18,981) |
Total excluding valuation allowances | 1,471,973 | 1,627,570 |
Valuation allowances | $ 351,408 | $ 262,392 |
Debt - Schedule of Long-Term De
Debt - Schedule of Long-Term Debt (Details) - USD ($) | Dec. 31, 2018 | Dec. 31, 2017 | Oct. 31, 2017 |
Debt Instrument [Line Items] | |||
Principal Value | $ 4,724,920,000 | $ 4,737,327,000 | |
Carrying Value | 4,697,381,000 | 4,702,329,000 | |
Fair Value | 4,553,427,000 | 4,872,831,000 | |
Debt payable within one year, principal value | 704,661,000 | 12,407,000 | |
Debt payable within one year, carrying value | 704,390,000 | 12,406,000 | |
Debt payable within one year, fair value | 717,609,000 | 12,932,000 | |
Total long-term debt, principal value | 4,020,259,000 | 4,724,920,000 | |
Total long-term debt, carrying value | 3,992,991,000 | 4,689,923,000 | |
Total long-term debt, fair value | 3,835,818,000 | 4,859,899,000 | |
8.13% Notes, due June 1, 2019 | |||
Debt Instrument [Line Items] | |||
Principal Value | 700,000,000 | 700,000,000 | |
Carrying Value | 699,729,000 | 698,918,000 | |
Fair Value | $ 712,663,000 | 755,153,000 | |
Interest rate | 8.13% | ||
Floating Rate Notes due October 1, 2020 | |||
Debt Instrument [Line Items] | |||
Principal Value | $ 500,000,000 | 500,000,000 | $ 500,000,000 |
Carrying Value | 498,222,000 | 497,206,000 | |
Fair Value | 490,730,000 | 501,325,000 | |
2.50% Notes due October 1, 2020 | |||
Debt Instrument [Line Items] | |||
Principal Value | 500,000,000 | 500,000,000 | 500,000,000 |
Carrying Value | 498,198,000 | 497,169,000 | |
Fair Value | $ 489,690,000 | 497,670,000 | |
Interest rate | 2.50% | ||
4.88% Notes, due November 15, 2021 | |||
Debt Instrument [Line Items] | |||
Principal Value | $ 750,000,000 | 750,000,000 | |
Carrying Value | 746,245,000 | 744,920,000 | |
Fair Value | $ 762,555,000 | 801,953,000 | |
Interest rate | 4.88% | ||
3.00% Notes due October 1, 2022 | |||
Debt Instrument [Line Items] | |||
Principal Value | $ 750,000,000 | 750,000,000 | 750,000,000 |
Carrying Value | 743,972,000 | 742,364,000 | |
Fair Value | $ 712,980,000 | 743,550,000 | |
Interest rate | 3.00% | ||
7.75% debentures, due July 15, 2026 | |||
Debt Instrument [Line Items] | |||
Principal Value | $ 115,000,000 | 115,000,000 | |
Carrying Value | 111,229,000 | 110,732,000 | |
Fair Value | $ 128,808,000 | 135,024,000 | |
Interest rate | 7.75% | ||
3.90% Notes due October 1, 2027 | |||
Debt Instrument [Line Items] | |||
Principal Value | $ 1,250,000,000 | 1,250,000,000 | $ 1,250,000,000 |
Carrying Value | 1,239,866,000 | 1,238,707,000 | |
Fair Value | $ 1,085,663,000 | 1,245,200,000 | |
Interest rate | 3.90% | ||
7.42% Series B, due 2023 | |||
Debt Instrument [Line Items] | |||
Principal Value | $ 10,000,000 | 10,000,000 | |
Carrying Value | 10,000,000 | 10,000,000 | |
Fair Value | $ 10,666,000 | 11,433,000 | |
Interest rate | 7.42% | ||
7.6% Series C, due 2018 | |||
Debt Instrument [Line Items] | |||
Principal Value | $ 0 | 8,000,000 | |
Carrying Value | 0 | 7,999,000 | |
Fair Value | $ 0 | 8,012,000 | |
Interest rate | 7.60% | ||
8.8% to 9.0% Series A, due 2020 through 2021 | |||
Debt Instrument [Line Items] | |||
Principal Value | $ 35,200,000 | 35,200,000 | |
Carrying Value | 35,200,000 | 35,187,000 | |
Fair Value | $ 37,920,000 | 40,510,000 | |
8.8% to 9.0% Series A, due 2020 through 2021 | Minimum | |||
Debt Instrument [Line Items] | |||
Interest rate | 8.80% | ||
8.8% to 9.0% Series A, due 2020 through 2021 | Maximum | |||
Debt Instrument [Line Items] | |||
Interest rate | 9.00% | ||
EQT Midstream Notes | |||
Debt Instrument [Line Items] | |||
Principal Value | $ 114,720,000 | 119,127,000 | |
Carrying Value | 114,720,000 | 119,127,000 | |
Fair Value | $ 121,752,000 | $ 133,001,000 |
Debt - Narrative (Details)
Debt - Narrative (Details) | Nov. 03, 2017USD ($) | Oct. 31, 2017USD ($) | Dec. 31, 2018USD ($)extensionfinancial_institution | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Nov. 13, 2017USD ($) |
Debt Instrument [Line Items] | ||||||
Principal value | $ 4,724,920,000 | $ 4,737,327,000 | ||||
Proceeds from issuance of long-term debt | $ 2,974,200,000 | |||||
Loss on extinguishment of debt | $ 12,600,000 | 0 | $ 12,641,000 | $ 0 | ||
Maturities of Senior Notes | ||||||
Aggregate maturities in 2019 | 700,000,000 | |||||
Aggregate maturities in 2020 | 1,011,200,000 | |||||
Aggregate maturities in 2021 | 774,000,000 | |||||
Aggregate maturities in 2022 | 750,000,000 | |||||
Aggregate maturities in 2023 | 10,000,000 | |||||
Aggregate maturities in 2024 and thereafter | $ 1,365,000,000 | |||||
Letters of credit outstanding | $ 0 | |||||
Commitment fee paid to maintain credit facility | 0.20% | 0.20% | 0.23% | |||
Debt-to-total capitalization ratio (no greater than) | 65.00% | |||||
Revolving Credit Facility | ||||||
Debt Instrument [Line Items] | ||||||
Maximum borrowing capacity | $ 2,500,000,000 | |||||
Floating Rate Notes due October 1, 2020 | ||||||
Debt Instrument [Line Items] | ||||||
Principal value | 500,000,000 | $ 500,000,000 | $ 500,000,000 | |||
2.50% Notes due October 1, 2020 | ||||||
Debt Instrument [Line Items] | ||||||
Principal value | 500,000,000 | $ 500,000,000 | 500,000,000 | |||
Interest rate | 2.50% | |||||
3.00% Notes due October 1, 2022 | ||||||
Debt Instrument [Line Items] | ||||||
Principal value | 750,000,000 | $ 750,000,000 | 750,000,000 | |||
Interest rate | 3.00% | |||||
3.90% Notes due October 1, 2027 | ||||||
Debt Instrument [Line Items] | ||||||
Principal value | 1,250,000,000 | $ 1,250,000,000 | 1,250,000,000 | |||
Interest rate | 3.90% | |||||
Senior Notes due 2018 | ||||||
Debt Instrument [Line Items] | ||||||
Repurchased face amount | $ 700,000,000 | |||||
EQT Midstream Notes | ||||||
Debt Instrument [Line Items] | ||||||
Principal value | $ 114,720,000 | 119,127,000 | ||||
Maturities of Senior Notes | ||||||
Aggregate maturities in 2019 | 4,700,000 | |||||
Aggregate maturities in 2020 | 5,000,000 | |||||
Aggregate maturities in 2021 | 5,200,000 | |||||
Aggregate maturities in 2022 | 5,500,000 | |||||
Aggregate maturities in 2023 | 5,800,000 | |||||
Aggregate maturities in 2024 and thereafter | 88,500,000 | |||||
EQT $2.5 Billion Facility | Revolving Credit Facility | ||||||
Debt Instrument [Line Items] | ||||||
Maximum borrowing capacity | $ 2,500,000,000 | |||||
Maturities of Senior Notes | ||||||
Number of times the maturity date of the credit facility can be extended by one year | extension | 2 | |||||
Extension term | 1 year | |||||
Number of financial institutions underwriting credit facility of the entity | financial_institution | 19 | |||||
Long-term line of credit | $ 800,000,000 | 1,300,000,000 | $ 0 | |||
Letters of credit outstanding | 0 | 159,400,000 | ||||
Maximum amount of outstanding borrowings | 1,600,000,000 | 1,400,000,000 | ||||
Average daily balance of loans outstanding | $ 854,000,000 | $ 191,000,000 | ||||
Weighted average interest rates | 3.40% | 2.80% | ||||
EQT $2.5 Billion Facility | Revolving Credit Facility | Maximum | ||||||
Debt Instrument [Line Items] | ||||||
Maximum borrowing capacity | $ 3,000,000,000 |
Changes in Accumulated Other _3
Changes in Accumulated Other Comprehensive Income (Loss) by Component (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | |||
Beginning Balance | $ 18,414,613 | $ 9,119,247 | $ 8,028,042 |
(Gains) losses reclassified from accumulated OCI, net of tax | (2,948) | (4,500) | (44,336) |
Ending Balance | 10,958,229 | 18,414,613 | 9,119,247 |
Cash flow hedge, net of tax | Natural gas cash flow hedges, net of tax | |||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | |||
Beginning Balance | 4,625 | 9,607 | 64,762 |
(Gains) losses reclassified from accumulated OCI, net of tax | (4,625) | (4,982) | (55,155) |
Ending Balance | 0 | 4,625 | 9,607 |
Cash flow hedge, net of tax | Interest rate cash flow hedges, net of tax | |||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | |||
Beginning Balance | (555) | (699) | (843) |
(Gains) losses reclassified from accumulated OCI, net of tax | 168 | 144 | 144 |
Ending Balance | (387) | (555) | (699) |
Pension and other post- retirement benefits liability adjustment, net of tax | |||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | |||
Beginning Balance | (6,528) | (6,866) | (17,541) |
(Gains) losses reclassified from accumulated OCI, net of tax | 606 | 338 | 10,675 |
Ending Balance | (5,922) | (6,528) | (6,866) |
Accumulated Net Investment Gain (Loss) Including Portion Attributable to Noncontrolling Interest | |||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | |||
Beginning Balance | 0 | 0 | 0 |
(Gains) losses reclassified from accumulated OCI, net of tax | 903 | 0 | 0 |
Ending Balance | 903 | 0 | 0 |
Accumulated Other Comprehensive Income (Loss) | |||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | |||
Beginning Balance | (2,458) | 2,042 | 46,378 |
Ending Balance | $ (5,406) | $ (2,458) | $ 2,042 |
Common Stock and Treasury Sto_3
Common Stock and Treasury Stock - Schedule of Shares of Authorized and Unissued Common Stock (Details) shares in Thousands | Dec. 31, 2018shares |
Earnings Per Share [Abstract] | |
Possible future acquisitions (in shares) | 20,457 |
Stock compensation plans (in shares) | 12,813 |
Total (in shares) | 33,270 |
Common Stock and Treasury Sto_4
Common Stock and Treasury Stock - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions | Nov. 13, 2017 | May 06, 2016 | May 03, 2016 | May 02, 2016 | Feb. 24, 2016 | Feb. 22, 2016 | Feb. 19, 2016 | Dec. 31, 2018 | Dec. 31, 2015 | Dec. 31, 2017 |
Class of Stock [Line Items] | ||||||||||
Shares of treasury stock into a rabbi trust (in shares) | 10,646,382 | 291,919 | ||||||||
Average cost (in dollars per share) | $ 50.62 | |||||||||
Average cost, commission (in dollars per share) | $ 0.02 | |||||||||
Shares of treasury stock transferred (in shares) | 17,000,000 | |||||||||
Treasury stock, held in rabbi trust (in shares) | 0 | 253,145 | ||||||||
Public Stock Offering | ||||||||||
Class of Stock [Line Items] | ||||||||||
Number of shares issued in transaction (in shares) | 10,500,000 | 6,500,000 | ||||||||
Price per share (in dollars per share) | $ 67 | $ 58.50 | ||||||||
Consideration received | $ 795.6 | $ 430.4 | ||||||||
Over-Allotment Option | ||||||||||
Class of Stock [Line Items] | ||||||||||
Number of shares issued in transaction (in shares) | 1,575,000 | 975,000 | ||||||||
Rice Merger Agreement | ||||||||||
Class of Stock [Line Items] | ||||||||||
Number of shares issued in business combination (in shares) | 91,000,000 |
Share-Based Compensation Plan_2
Share-Based Compensation Plans - Schedule of Share-Based Compensation Expense (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation expense | $ 24,904 | $ 112,766 | $ 47,338 |
Less: Discontinued operations | (18,250) | (15,595) | (18,631) |
Cash received from exercises of all share-based payment arrangements for employees and directors | 1,900 | 200 | 5,000 |
Income tax benefit by the exercise of nonqualified employee stock options and vesting of restricted share awards | 13,400 | 58,900 | 22,200 |
Restricted stock awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation expense | 14,503 | 87,104 | 9,407 |
Non-qualified stock options | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation expense | 2,757 | 2,626 | 3,119 |
Other programs, including non-employee director awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation expense | 3,014 | 1,005 | 5,459 |
2014 Executive Performance Incentive Program | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation expense | 0 | 0 | 9,494 |
2015 Executive Performance Incentive Program | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation expense | 0 | 5,348 | 12,456 |
2016 Incentive Performance Share Unit Program | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation expense | 6,863 | 13,077 | 7,166 |
2017 Incentive Performance Share Unit Program | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation expense | 2,467 | 5,038 | 0 |
2018 Incentive Performance Share Unit Program | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation expense | 4,742 | 0 | 0 |
2015 EQT Value Driver Award Program | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation expense | 0 | 0 | 3,174 |
2016 EQT Value Driver Performance Share Unit Award Program | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation expense | 0 | 3,341 | 15,694 |
2017 EQT Value Driver Performance Share Unit Award Program | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation expense | 584 | 10,822 | 0 |
2018 EQT Value Driver Performance Share Unit Award Program | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation expense | $ 8,224 | $ 0 | $ 0 |
Share-Based Compensation Plan_3
Share-Based Compensation Plans - Narrative (Details) | Jan. 01, 2019$ / sharesshares | Nov. 12, 2018 | Nov. 13, 2017USD ($)$ / sharesshares | Dec. 31, 2018USD ($)$ / sharesshares | Dec. 31, 2017USD ($)$ / sharesshares | Dec. 31, 2016USD ($)$ / sharesshares | Jan. 01, 2018shares |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Stock dividend (in dollars per share) | 0.80 | ||||||
Cash received from exercises of all share-based payment arrangements for employees and directors | $ | $ 1,900,000 | $ 200,000 | $ 5,000,000 | ||||
Income tax benefit by the exercise of nonqualified employee stock options and vesting of restricted share awards | $ | $ 13,400,000 | 58,900,000 | 22,200,000 | ||||
Rice Merger Agreement | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Aggregate cash conversion | $ | $ 13,000,000 | ||||||
Cash conversion (in dollars per share) | $ / shares | $ 5.30 | ||||||
Value Driver Performance Programs | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Award requisite service period | 1 year | ||||||
Award vested at end of year one | 50.00% | ||||||
Award vested at end of year two | 50.00% | ||||||
2018 EQT Value Driver Performance Share Unit Award Program | Subsequent Event | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Award vested at end of year one | 50.00% | ||||||
Award vested at end of year two | 50.00% | ||||||
Number of shares granted (in shares) | 614,680 | ||||||
2018 Incentive Performance Share Unit Program | Subsequent Event | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Number of shares granted (in shares) | 642,920 | ||||||
Period after which the shares granted will be fully vested | 3 years | ||||||
Expected to be distributed in common stock (in shares) | 402,220 | ||||||
Expected to be paid in cash (in shares) | 240,700 | ||||||
Minimum | 2018 EQT Value Driver Performance Share Unit Award Program | Subsequent Event | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Compensation plan, award as a percentage of target award level | 0.00% | ||||||
Minimum | 2018 Incentive Performance Share Unit Program | Subsequent Event | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Compensation plan, award as a percentage of target award level | 0.00% | ||||||
Maximum | 2018 EQT Value Driver Performance Share Unit Award Program | Subsequent Event | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Compensation plan, award as a percentage of target award level | 300.00% | ||||||
Maximum | 2018 Incentive Performance Share Unit Program | Subsequent Event | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Compensation plan, award as a percentage of target award level | 300.00% | ||||||
Performance Shares | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Award requisite service period | 36 months | ||||||
Performance Shares | 2016 Executive Performance Incentive Program | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Grant date fair value (in dollars per share) | $ / shares | $ 109.30 | ||||||
Awards outstanding (in shares) | 384,101 | 447,145 | |||||
Performance Shares | 2017 Executive Performance Incentive Program, Equity | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Unrecognized compensation costs on non-vested awards | $ | $ 600,000 | ||||||
Grant date fair value (in dollars per share) | $ / shares | $ 120.60 | ||||||
Awards outstanding (in shares) | 44,573 | 79,070 | |||||
Performance Shares | 2017 Executive Performance Incentive Program, Liability | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Unrecognized compensation costs on non-vested awards | $ | $ 2,000,000 | ||||||
Grant date fair value (in dollars per share) | $ / shares | $ 59.90 | ||||||
Awards outstanding (in shares) | 105,018 | 117,530 | |||||
Performance Shares | 2018 Executive Performance Incentive Program, Equity | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Unrecognized compensation costs on non-vested awards | $ | $ 1,100,000 | ||||||
Number of shares granted (in shares) | 172,350 | ||||||
Grant date fair value (in dollars per share) | $ / shares | $ 76.53 | ||||||
Awards outstanding (in shares) | 107,340 | ||||||
Performance Shares | 2018 Executive Performance Incentive Program, Liability | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Unrecognized compensation costs on non-vested awards | $ | $ 3,000,000 | ||||||
Number of shares granted (in shares) | 142,890 | ||||||
Grant date fair value (in dollars per share) | $ / shares | $ 33.30 | ||||||
Awards outstanding (in shares) | 124,820 | ||||||
Performance Shares | Minimum | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Compensation plan, award as a percentage of target award level | 0.00% | ||||||
Performance Shares | Maximum | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Compensation plan, award as a percentage of target award level | 300.00% | ||||||
Performance Share, Equity Awards | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Risk-free rate term | 3 years | ||||||
Performance Shares, Liability Awards | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Risk-free rate term | 1 year | ||||||
Performance Shares, Liability Awards | 2018 Executive Performance Incentive Program, Liability | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Risk-free rate term | 2 years | ||||||
Restricted Stock | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Unrecognized compensation costs on non-vested awards | $ | $ 2,500,000 | ||||||
Period for recognition | 1 year 3 months | ||||||
Number of shares granted (in shares) | 145,540 | ||||||
Grant date fair value (in dollars per share) | $ / shares | $ 54.33 | ||||||
Value | $ | $ 39,843,286 | $ 123,000,000 | $ 5,100,000 | ||||
Awards outstanding (in shares) | 192,782 | 729,500 | |||||
Restricted Stock | Subsequent Event | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Number of shares granted (in shares) | 201,130 | ||||||
Period after which the shares granted will be fully vested | 3 years | ||||||
Restricted Stock | Rice Merger Agreement | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Number of shares granted (in shares) | 2,290,234 | ||||||
Grant date fair value (in dollars per share) | $ / shares | $ 65.18 | $ 65.18 | |||||
Restricted Stock | Key Employees | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Number of shares granted (in shares) | 145,540 | 85,350 | 158,360 | ||||
Period after which the shares granted will be fully vested | 3 years | ||||||
Grant date fair value (in dollars per share) | $ / shares | $ 54.33 | $ 63 | $ 75 | ||||
Restricted Stock | Chief Financial Officer | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Number of shares granted (in shares) | 7,900 | ||||||
Period after which the shares granted will be fully vested | 1 year | ||||||
Grant date fair value (in dollars per share) | $ / shares | $ 63.33 | ||||||
Restricted Stock Units, Liability | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Number of shares granted (in shares) | 373,750 | 292,400 | 148,860 | ||||
Period after which the shares granted will be fully vested | 3 years | ||||||
Awards outstanding (in shares) | 639,780 | ||||||
Deferred compensation liability | $ | $ 6,900,000 | $ 8,800,000 | $ 2,700,000 | ||||
Restricted Stock Units, Liability | Subsequent Event | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Number of shares granted (in shares) | 427,900 | ||||||
Non-qualified Stock Options | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Unrecognized compensation costs on non-vested awards | $ | $ 400,000 | ||||||
Granted (in shares) | 287,800 | ||||||
Weighted average remaining contractual term, outstanding | 5 years 6 months 26 days | ||||||
Non-qualified Stock Options | Subsequent Event | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Period after which the shares granted will be fully vested | 3 years | ||||||
Granted (in shares) | 669,200 | ||||||
Exercise price (in dollars per share) | $ / shares | $ 18.89 | ||||||
Weighted average remaining contractual term, outstanding | 10 years | ||||||
Non-employee Directors' Share-Based Awards | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Shares outstanding (in shares) | 267,906 | ||||||
Shares granted (in shares) | 50,979 | 26,090 | 37,620 | ||||
Weighted average fair value, granted (in dollars per share) | $ / shares | $ 52.65 | $ 65.35 | $ 52.13 |
Share-Based Compensation Plan_4
Share-Based Compensation Plans - Schedule of Executive Performance Incentive Programs (Details) $ / shares in Units, $ in Millions | Nov. 12, 2018 | Dec. 31, 2018USD ($)$ / sharesshares | Jan. 01, 2018shares |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock dividend (in dollars per share) | 0.80 | ||
Performance Shares | 2014 Executive Performance Incentive Program | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Grant date fair value (in dollars per share) | $ / shares | $ 189.68 | ||
Risk-free interest rate | 0.78% | ||
Awards paid (in shares) | 238,060,000 | ||
Value | $ | $ 45.2 | ||
Performance Shares | 2015 Executive Performance Incentive Program | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Grant date fair value (in dollars per share) | $ / shares | $ 141.11 | ||
Risk-free interest rate | 1.10% | ||
Awards paid (in shares) | 274,767,000 | ||
Value | $ | $ 0 | ||
Performance Shares | 2016 Executive Performance Incentive Program | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Grant date fair value (in dollars per share) | $ / shares | $ 109.30 | ||
Risk-free interest rate | 1.31% | ||
Awards outstanding (in shares) | 384,101 | 447,145 | |
Non-vested shares, forfeited (in shares) | 63,044 | ||
Performance Shares | 2016 Executive Performance Incentive Program | Equitrans Midstream Employees | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Awards outstanding (in shares) | 130,393 | ||
Performance Shares | 2017 Executive Performance Incentive Program, Equity | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Grant date fair value (in dollars per share) | $ / shares | $ 120.60 | ||
Risk-free interest rate | 1.47% | ||
Awards outstanding (in shares) | 44,573 | 79,070 | |
Non-vested shares, forfeited (in shares) | 34,497 | ||
Performance Shares | 2017 Executive Performance Incentive Program, Equity | Equitrans Midstream Employees | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Awards outstanding (in shares) | 7,020 | ||
Performance Shares | 2017 Executive Performance Incentive Program, Liability | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Grant date fair value (in dollars per share) | $ / shares | $ 59.90 | ||
Risk-free interest rate | 2.61% | ||
Awards outstanding (in shares) | 105,018 | 117,530 | |
Non-vested shares, forfeited (in shares) | 12,512 | ||
Performance Shares | 2017 Executive Performance Incentive Program, Liability | Equitrans Midstream Employees | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Awards outstanding (in shares) | 43,134 | ||
Performance Shares | 2018 Executive Performance Incentive Program, Equity | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Grant date fair value (in dollars per share) | $ / shares | $ 76.53 | ||
Risk-free interest rate | 1.97% | ||
Awards outstanding (in shares) | 107,340 | ||
Number of shares granted (in shares) | 172,350 | ||
Non-vested shares, forfeited (in shares) | 65,010 | ||
Performance Shares | 2018 Executive Performance Incentive Program, Equity | Equitrans Midstream Employees | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Awards outstanding (in shares) | 34,640 | ||
Performance Shares | 2018 Executive Performance Incentive Program, Liability | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Grant date fair value (in dollars per share) | $ / shares | $ 33.30 | ||
Risk-free interest rate | 2.46% | ||
Awards outstanding (in shares) | 124,820 | ||
Number of shares granted (in shares) | 142,890 | ||
Non-vested shares, forfeited (in shares) | 18,070 | ||
Performance Shares | 2018 Executive Performance Incentive Program, Liability | Equitrans Midstream Employees | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Awards outstanding (in shares) | 57,240 |
Share-Based Compensation Plan_5
Share-Based Compensation Plans - Schedule of Compensation Costs by Performance Incentive Plan (Details) - Performance Shares - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
2014 Executive Performance Incentive Program | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Capitalized compensation cost | $ 0 | $ 0 | $ 4.2 |
2015 Executive Performance Incentive Program | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Capitalized compensation cost | 0 | 2.2 | 4.9 |
2016 Executive Performance Incentive Program | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Capitalized compensation cost | 2.1 | 4.4 | 3.3 |
2017 Executive Performance Incentive Program, Liability | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Capitalized compensation cost | 1 | 1.7 | 0 |
2018 Executive Performance Incentive Program, Liability | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Capitalized compensation cost | $ 0.6 | $ 0 | $ 0 |
Share-Based Compensation Plan_6
Share-Based Compensation Plans - Summary of Valuation Assumptions for Incentive Performance Plan (Details) | 12 Months Ended | ||||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Performance Shares, Liability Awards | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Risk-free interest rate | 2.46% | 2.61% | |||
Volatility factor | 35.70% | 41.17% | |||
Expected term | 2 years | 1 year | |||
Performance Share, Equity Awards | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Risk-free interest rate | 1.97% | 1.47% | 1.31% | 1.10% | 0.78% |
Volatility factor | 32.60% | 32.30% | 28.43% | 27.45% | 31.38% |
Expected term | 3 years | 3 years | 3 years | 3 years | 3 years |
Share-Based Compensation Plan_7
Share-Based Compensation Plans - Schedule of Value Driver Award Programs (Details) - Value Driver Award - USD ($) $ / shares in Units, $ in Millions | 1 Months Ended | 12 Months Ended | |
Feb. 28, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | |
2015 Value Driver Award Program | Tranche One | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Weighted average fair value, granted (in dollars per share) | $ 75.70 | ||
Awards paid (in shares) | 222,751 | ||
2015 Value Driver Award Program | Tranche Two | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Weighted average fair value, granted (in dollars per share) | $ 75.70 | ||
Awards paid (in shares) | 208,567 | ||
2016 Value Driver Award Program | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Cash paid | $ 21.3 | ||
2016 Value Driver Award Program | Tranche One | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Weighted average fair value, granted (in dollars per share) | $ 65.40 | ||
Cash paid | $ 21.3 | ||
2016 Value Driver Award Program | Tranche Two | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Weighted average fair value, granted (in dollars per share) | $ 56.92 | ||
Cash paid | $ 16.8 | ||
Deferred compensation liability | $ 1.7 | ||
2017 Value Driver Performance Share Unit Award Program | Equitrans Midstream Employees | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Outstanding units (in shares) | 95,452 | ||
2017 Value Driver Performance Share Unit Award Program | Tranche One | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Weighted average fair value, granted (in dollars per share) | $ 56.92 | ||
Cash paid | $ 14 | ||
2017 Value Driver Performance Share Unit Award Program | Tranche Two | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Weighted average fair value, granted (in dollars per share) | $ 18.89 | ||
Outstanding units (in shares) | 214,384 | ||
2018 EQT Value Driver Performance Share Unit Award Program | Equitrans Midstream Employees | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Outstanding units (in shares) | 135,345 | ||
2018 EQT Value Driver Performance Share Unit Award Program | Tranche One | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Weighted average fair value, granted (in dollars per share) | $ 18.89 | ||
Outstanding units (in shares) | 256,803 | ||
2018 EQT Value Driver Performance Share Unit Award Program | Tranche Two | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Outstanding units (in shares) | 257,254 | ||
Value Driver Award Program 2016, Employee Separation Agreements | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Cash paid | $ 0.2 |
Share-Based Compensation Plan_8
Share-Based Compensation Plans - Schedule of Compensation Costs by Value Driver Award Programs (Details) - Value Driver Award - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
2015 Value Driver Award Program | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Compensation cost | $ 0 | $ 0 | $ 4.1 |
2016 Value Driver Award Program | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Compensation cost | 0 | 7 | 16.3 |
2017 Value Driver Performance Share Unit Award Program | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Compensation cost | 0.1 | 10.3 | 0 |
2018 EQT Value Driver Performance Share Unit Award Program | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Compensation cost | $ 3.3 | $ 0 | $ 0 |
Share-Based Compensation Plan_9
Share-Based Compensation Plans - Summary of Restricted Stock Activity (Details) - Restricted Stock - USD ($) | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Non- Vested Shares(a) | |||
Non-vested shares, outstanding, beginning balance (in shares) | 729,500 | ||
Number of shares granted (in shares) | 145,540 | ||
Non-vested shares, vested (in shares) | (596,888) | ||
Non-vested shares, forfeited (in shares) | (85,370) | ||
Non-vested shares, outstanding, ending balance (in shares) | 192,782 | 729,500 | |
Weighted Average Fair Value | |||
Weighted average fair value, outstanding, beginning balance (in dollars per share) | $ 66.86 | ||
Weighted average fair value, granted (in dollars per share) | 54.33 | ||
Weighted Average Fair Value, Vested (in dollars per share) | 66.75 | ||
Weighted Average Fair Value, Forfeited (in dollars per share) | 62.26 | ||
Weighted average fair value, outstanding, ending balance (in dollars per share) | $ 59.79 | $ 66.86 | |
Aggregate Fair Value | |||
Aggregate fair value, outstanding, beginning balance | $ 48,776,872 | ||
Aggregate fair value, granted | 7,906,734 | ||
Aggregate fair value, vested | (39,843,286) | $ (123,000,000) | $ (5,100,000) |
Aggregate fair value, forfeited | (5,314,727) | ||
Aggregate fair value, outstanding, ending balance | $ 11,525,593 | $ 48,776,872 | |
Equitrans Midstream Employees | |||
Non- Vested Shares(a) | |||
Non-vested shares, outstanding, beginning balance (in shares) | |||
Non-vested shares, outstanding, ending balance (in shares) | 107,422 |
Share-Based Compensation Pla_10
Share-Based Compensation Plans - Schedule of Valuation Assumptions for Non-Qualified Stock Options (Details) - Non-qualified Stock Options $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2018USD ($)$ / sharesshares | Dec. 31, 2017USD ($)grant_date$ / sharesshares | Dec. 31, 2016USD ($)$ / sharesshares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Risk-free interest rate | 2.25% | 1.95% | 1.67% |
Dividend yield | 0.20% | 0.18% | 0.16% |
Volatility factor | 26.46% | 27.45% | 28.59% |
Expected term | 5 years | 5 years | 5 years |
Number of options granted (in shares) | shares | 287,800 | 153,700 | 228,500 |
Weighted average grant date fair value (in dollars per share) | $ / shares | $ 15.39 | $ 17.47 | $ 15.10 |
Total intrinsic value of options exercised | $ | $ 0 | $ 1.7 | $ 3.5 |
Number of grant dates | grant_date | 2 |
Share-Based Compensation Pla_11
Share-Based Compensation Plans - Summary of Non-qualified Option Activity (Details) - Non-qualified Stock Options | 12 Months Ended |
Dec. 31, 2018USD ($)$ / sharesshares | |
Shares | |
Outstanding, beginning balance (in shares) | shares | 1,129,200 |
Granted (in shares) | shares | 287,800 |
Exercised (in shares) | shares | 0 |
Forfeited (in shares) | shares | (215,100) |
Awards granted in conversion, as a result of separation (in shares) | shares | 573,529 |
Expired (in shares) | shares | 0 |
Outstanding, ending balance (in shares) | shares | 1,775,429 |
Exercisable (in shares) | shares | 1,533,452 |
Weighted Average Exercise Price | |
Weighted average exercise price, outstanding, beginning balance (in dollars per share) | $ / shares | $ 63.42 |
Weighted average exercise price, granted (in dollars per share) | $ / shares | 56.92 |
Weighted average exercise price, exercised (in dollars per share) | $ / shares | 0 |
Weighted average exercise price, forfeited (in dollars per share) | $ / shares | 58.14 |
Weighted average exercise price, awards granted in conversion, as a result of separation (in dollars per share) | $ / shares | 31.23 |
Weighted average exercise price, expired (in dollars per share) | $ / shares | 0 |
Weighted average exercise price, outstanding, ending balance (in dollars per share) | $ / shares | 32.43 |
Weighted average exercise price, exercisable (in dollars per share) | $ / shares | $ 32.88 |
Weighted Average Remaining Contractual Term | |
Weighted average remaining contractual term, outstanding | 5 years 6 months 26 days |
Weighted average remaining contractual term, exercisable | 5 years 2 months 19 days |
Aggregate Intrinsic Value | |
Aggregate intrinsic value, outstanding, end of period | $ | $ 0 |
Aggregate intrinsic value, exercisable, end of period | $ | $ 0 |
Concentrations of Credit Risk (
Concentrations of Credit Risk (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Concentration Risk | ||
Adjustments to the fair value of derivative contracts due to credit related concerns outside of the normal non-performance risk adjustment | $ 0 | |
Accounts receivable | Customer concentration | ||
Concentration Risk | ||
Concentration risk | 64.00% | 59.00% |
Commitments and Contingencies (
Commitments and Contingencies (Details) - USD ($) $ in Millions | Feb. 13, 2019 | Jan. 16, 2013 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Commitments for demand charges under existing long-term contracts and binding precedent agreements with various pipelines | |||||
Operating leases, rent expense | $ 117.4 | $ 60.8 | $ 44.1 | ||
Future lease payments under non-cancelable operating leases | 109.9 | ||||
Future lease payments under non-cancelable operating leases, 2019 | 70.3 | ||||
Future lease payments under non-cancelable operating leases, 2020 | 8.4 | ||||
Future lease payments under non-cancelable operating leases, 2021 | 8.4 | ||||
Future lease payments under non-cancelable operating leases, 2022 | 8.4 | ||||
Future lease payments under non-cancelable operating leases, 2023 | 8.4 | ||||
Future lease payments under non-cancelable operating leases, thereafter | 6 | ||||
Damages sought | 100 | ||||
Remedial action included in other credits | 11.8 | ||||
Pipeline Demand Charges | |||||
Commitments for demand charges under existing long-term contracts and binding precedent agreements with various pipelines | |||||
Amount due as of the balance sheet date | 23,500 | ||||
Amount due in 2019 | 1,300 | ||||
Amount due in 2020 | 1,700 | ||||
Amount due in 2021 | 1,800 | ||||
Amount due in 2022 | 1,800 | ||||
Amount due in 2023 | 1,700 | ||||
Amount due thereafter | 15,200 | ||||
Frac Sand and Equipment | |||||
Commitments for demand charges under existing long-term contracts and binding precedent agreements with various pipelines | |||||
Amount due as of the balance sheet date | $ 74 | ||||
Subsequent Event | |||||
Commitments for demand charges under existing long-term contracts and binding precedent agreements with various pipelines | |||||
Payments for legal settlements | $ 53.5 |
Guarantees (Details)
Guarantees (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2018USD ($) | |
NORESCO Guarantees, Energy Savings | |
Guarantor Obligations [Line Items] | |
Undiscounted maximum aggregate payments related to guarantees | $ 76 |
Guarantee obligations term | 10 years |
EQM IPO Guaranty | |
Guarantor Obligations [Line Items] | |
Undiscounted maximum aggregate payments related to guarantees | $ 50 |
Written notice period | 10 days |
Interim Financial Information_3
Interim Financial Information (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Total operating revenues | $ 1,245,138 | $ 1,050,046 | $ 950,648 | $ 1,312,036 | $ 1,033,539 | $ 597,718 | $ 631,101 | $ 828,662 | $ 4,557,868 | $ 3,091,020 | $ 1,387,054 |
Operating (loss) | (570,691) | (147,451) | (114,650) | (1,950,332) | 97,257 | (6,380) | 47,763 | 243,572 | (2,783,124) | 382,212 | (755,028) |
Amounts attributable to EQT Corporation: | |||||||||||
(Loss) income from continuing operations | (598,062) | (127,347) | (76,978) | (1,578,533) | 1,276,690 | (6,238) | 3,387 | 113,190 | (2,380,920) | 1,387,029 | (531,493) |
Income from discontinued operations, net of tax | (38,625) | 87,654 | 94,784 | (7,461) | 3,381 | 29,578 | 37,739 | 50,802 | 136,352 | 121,500 | 78,510 |
Net (loss) income attributable to EQT Corporation | $ (636,687) | $ (39,693) | $ 17,806 | $ (1,585,994) | $ 1,280,071 | $ 23,340 | $ 41,126 | $ 163,992 | $ (2,244,568) | $ 1,508,529 | $ (452,983) |
Basic: | |||||||||||
(Loss) income from continuing operations (in dollars per share) | $ (2.35) | $ (0.49) | $ (0.29) | $ (5.96) | $ 5.83 | $ (0.04) | $ 0.02 | $ 0.66 | $ (9.12) | $ 7.40 | $ (3.18) |
Income from discontinued operations (in dollars per share) | (0.15) | 0.34 | 0.36 | (0.03) | 0.02 | 0.17 | 0.22 | 0.29 | 0.52 | 0.65 | 0.47 |
Net (loss) income (in dollars per share) | (2.50) | (0.15) | 0.07 | (5.99) | 5.85 | 0.13 | 0.24 | 0.95 | (8.60) | 8.05 | (2.71) |
Diluted: | |||||||||||
(Loss) income from continuing operations (in dollars per share) | (2.35) | (0.49) | (0.29) | (5.96) | 5.81 | (0.04) | 0.02 | 0.66 | (9.12) | 7.39 | (3.18) |
Income from discontinued operations (in dollars per share) | (0.15) | 0.34 | 0.36 | (0.03) | 0.02 | 0.17 | 0.22 | 0.29 | 0.52 | 0.65 | 0.47 |
Net (loss) income (in dollars per share) | $ (2.50) | $ (0.15) | $ 0.07 | $ (5.99) | $ 5.83 | $ 0.13 | $ 0.24 | $ 0.95 | $ (8.60) | $ 8.04 | $ (2.71) |
Natural Gas Producing Activit_3
Natural Gas Producing Activities (Unaudited) - Costs Incurred Relating to Natural Gas, NGL, and Oil Production Activities (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Capitalized Costs: | |||
Proved properties | $ 17,648,731 | $ 18,920,855 | $ 12,179,833 |
Unproved properties | 4,166,048 | 5,016,299 | 1,698,826 |
Total capitalized costs | 21,814,779 | 23,937,154 | 13,878,659 |
Accumulated depreciation and depletion | 4,666,212 | 5,121,646 | 4,217,154 |
Net capitalized costs | 17,148,567 | 18,815,508 | 9,661,505 |
Property acquisition: | |||
Proved properties | 77,099 | 5,251,711 | 403,314 |
Unproved properties | 198,854 | 3,310,995 | 880,545 |
Exploration | 1,708 | 15,505 | 6,047 |
Development | 2,443,980 | 1,357,165 | 777,787 |
Geological and geophysical | 0 | 0 | 0 |
2017 Acquisitions | Marcellus Acres | |||
Property acquisition: | |||
Unproved properties | 2,625,100 | ||
Proved properties, wells | 5,200 | 2,530,400 | |
Proved properties, leases | 1,192,000 | ||
2017 Acquisitions | Utica Acres | |||
Property acquisition: | |||
Unproved properties | 500 | ||
Proved properties, wells | $ 9,200 | 1,228,600 | |
Proved properties, leases | $ 300 | ||
2016 Acquisitions | |||
Property acquisition: | |||
Proved properties, wells | 256,200 | ||
Proved properties, leases | 112,200 | ||
2016 Acquisitions | Marcellus Acres | |||
Property acquisition: | |||
Unproved properties | $ 770,400 |
Natural Gas Producing Activit_4
Natural Gas Producing Activities (Unaudited) - Additional Information (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018USD ($)Bcfewell$ / bbl$ / Dekatherm | Dec. 31, 2017USD ($)Bcfe | Dec. 31, 2016USD ($)Bcfe | |
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||
Lease impairments and expirations | $ | $ 279,708 | $ 7,552 | $ 15,686 |
Unproved properties | $ | $ 4,166,048 | $ 5,016,299 | $ 1,698,826 |
Engineer experience (in years) | 21 years | ||
Percentage of total net natural gas, NGL and oil proved reserves reviewed | 100.00% | ||
Percentage of proved developed reserves covered in the audit | 81.00% | ||
Percentage of audit coverage of remaining properties | 19.00% | ||
Wells per case, operated wells | well | 200 | ||
Wells per case, non-operated wells | well | 115 | ||
Transfers (in Bcfe) | 2,722 | 987 | 647 |
Period increase (decrease) (in Bcfe) | 4,739 | 2,225 | 2,385 |
Production (in Bcfe) | 1,495 | 908 | 776 |
Inclusion in drilling plan (in Bcfe) | 3,538 | 1,032 | 1,371 |
Increased reserves (in Bcfe) | 148 | 477 | 68 |
Removal of locations, economic and lack of development (in Bcfe) | 1,273 | 3,522 | 509 |
Change in economic life (in Bcfe) | 278 | 31 | |
Sale of mineral in place (in Bcfe) | 1,749 | ||
Acquisitions (in Bcfe) | 9,390 | 2,396 | |
Acquisitions, developed (in Bcfe) | 3,330 | 320 | |
Acquisitions, undeveloped (in Bcfe) | 6,060 | 2,076 | |
Removal of locations not expected to develop within 5 years (in Bcfe) | 3,074 | 389 | |
Discount rate to compute standard measure of future cash flow (as a percent) | 10.00% | ||
Discounted future net cash flows relating to proved oil and gas reserves, change in price of natural gas sensitivity (in usd per dth) | $ / Dekatherm | 0.2 | ||
Discounted future net cash flows relating to proved oil and gas reserves, change in price of oil sensitivity (in usd per bbl) | $ / bbl | 10 | ||
Discounted future net cash flows relating to proved oil and gas reserves, change in price of natural gas liquids (in usd per bbl) | $ / bbl | 10 | ||
Change in discounted future cash flows for assumed natural gas price change | $ | $ 1,900,000 | ||
Change in discounted future cash flows for assumed oil price change | $ | 34,200 | ||
Change in discounted future cash flows for assumed natural gas liquids price change | $ | $ 665,700 | ||
Ohio, Pennsylvania, and West Virginia Marcellus | |||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||
Increased reserves (in Bcfe) | 315 | 300 | 341 |
Ohio, Pennsylvania, and West Virginia Marcellus Acres | |||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||
Increased reserves (in Bcfe) | 886 | 893 | 673 |
Natural Gas Producing Activit_5
Natural Gas Producing Activities (Unaudited) - Results of Operations Related to Natural Gas, NGL and Oil Production (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Reserve Quantities [Line Items] | |||
Revenues | $ 4,709,384 | ||
Transportation and processing | 1,697,001 | $ 1,164,783 | $ 880,191 |
Production | 195,775 | 181,349 | 174,170 |
Exploration | 6,765 | 17,565 | 4,663 |
Depreciation and depletion | 1,569,038 | 970,985 | 856,451 |
Impairment of long-lived assets | 2,709,976 | 0 | 0 |
Lease impairments and expirations | 279,708 | 7,552 | 15,686 |
Income tax (benefit) expense | (454,009) | 121,359 | (135,029) |
Results of operations from producing activities (excluding corporate overhead) | (1,308,735) | 187,725 | (201,135) |
Sales of natural gas, oil and NGLs | |||
Reserve Quantities [Line Items] | |||
Revenues | $ 4,695,519 | $ 2,651,318 | $ 1,594,997 |
Natural Gas Producing Activit_6
Natural Gas Producing Activities (Unaudited) - Schedule of the Entity's Proved and Unproved Reserves (Details) | 12 Months Ended | ||
Dec. 31, 2018MBblsMMcf | Dec. 31, 2017MBblsMMcf | Dec. 31, 2016MBblsMMcf | |
Proved developed and undeveloped reserves: | |||
Beginning of year | 21,445,667 | 13,508,407 | 9,976,597 |
Revision of previous estimates | (1,124,904) | (2,766,981) | (472,285) |
Purchase | 0 | 9,389,638 | 2,395,776 |
Sale | (1,748,557) | (2,646) | 0 |
Extensions, discoveries and other additions | 4,739,233 | 2,225,141 | 2,384,682 |
Production | (1,494,663) | (907,892) | (776,363) |
End of year | 21,816,776 | 21,445,667 | 13,508,407 |
Proved developed reserves: | |||
Beginning of year | 11,297,956 | 6,842,958 | 6,279,557 |
End of year | 11,550,161 | 11,297,956 | 6,842,958 |
Proved undeveloped reserves: | |||
Beginning of year | 10,147,711 | 6,665,449 | 3,697,040 |
End of year | 10,266,615 | 10,147,711 | 6,665,449 |
Natural Gas | |||
Proved developed and undeveloped reserves: | |||
Beginning of year | 19,830,236 | 12,331,867 | 9,110,311 |
Revision of previous estimates | (960,285) | (2,760,467) | (607,171) |
Purchase | 0 | 8,890,145 | 2,288,166 |
Sale | (1,331,391) | (1,210) | 0 |
Extensions, discoveries and other additions | 4,659,835 | 2,164,578 | 2,241,528 |
Production | (1,392,943) | (794,677) | (700,967) |
End of year | 20,805,452 | 19,830,236 | 12,331,867 |
Proved developed reserves: | |||
Beginning of year | 10,152,543 | 6,074,958 | 5,652,989 |
End of year | 10,887,953 | 10,152,543 | 6,074,958 |
Proved undeveloped reserves: | |||
Beginning of year | 9,677,693 | 6,256,909 | 3,457,322 |
End of year | 9,917,499 | 9,677,693 | 6,256,909 |
Oil | |||
Proved developed and undeveloped reserves: | |||
Beginning of year | MBbls | 10,731 | 6,395 | 5,900 |
Revision of previous estimates | MBbls | 6,217 | 5,103 | 1,159 |
Purchase | MBbls | 0 | 355 | 3 |
Sale | MBbls | (10,447) | (139) | 0 |
Extensions, discoveries and other additions | MBbls | 338 | 9 | 62 |
Production | MBbls | (680) | (992) | (729) |
End of year | MBbls | 6,159 | 10,731 | 6,395 |
Proved developed reserves: | |||
Beginning of year | MBbls | 10,731 | 6,395 | 5,900 |
End of year | MBbls | 3,489 | 10,731 | 6,395 |
Proved undeveloped reserves: | |||
Beginning of year | MBbls | 0 | 0 | 0 |
End of year | MBbls | 2,670 | 0 | 0 |
Cubic feet per thousand barrel (in mmcf) | 6 | ||
Natural Gas Liquids | |||
Proved developed and undeveloped reserves: | |||
Beginning of year | MBbls | 258,507 | 189,695 | 138,481 |
Revision of previous estimates | MBbls | (33,653) | (6,189) | 21,322 |
Purchase | MBbls | 0 | 82,894 | 17,932 |
Sale | MBbls | (59,080) | (100) | 0 |
Extensions, discoveries and other additions | MBbls | 12,895 | 10,084 | 23,797 |
Production | MBbls | (16,274) | (17,877) | (11,837) |
End of year | MBbls | 162,395 | 258,507 | 189,695 |
Proved developed reserves: | |||
Beginning of year | MBbls | 180,170 | 121,605 | 98,528 |
End of year | MBbls | 106,879 | 180,170 | 121,605 |
Proved undeveloped reserves: | |||
Beginning of year | MBbls | 78,337 | 68,090 | 39,953 |
End of year | MBbls | 55,516 | 78,337 | 68,090 |
Cubic feet per thousand barrel (in mmcf) | 6 |
Natural Gas Producing Activit_7
Natural Gas Producing Activities (Unaudited) - Estimated Future Net Cash Flows from Natural Gas and Oil Reserves (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Extractive Industries [Abstract] | ||||
Future cash inflows | $ 60,603,624 | $ 51,423,920 | $ 24,011,281 | |
Future production costs (b) | (20,463,567) | (18,379,892) | (14,864,126) | |
Future development costs | (5,854,503) | (5,637,676) | (3,778,698) | |
Future income tax expenses | (6,823,621) | (5,811,125) | (1,753,067) | |
Future net cash flow | 27,461,933 | 21,595,227 | 3,615,390 | |
10% annual discount for estimated timing of cash flows | (15,850,035) | (12,593,293) | (2,626,636) | |
Standardized measure of discounted future net cash flows | $ 11,611,898 | $ 9,001,934 | $ 988,754 | $ 977,554 |
Natural Gas Producing Activit_8
Natural Gas Producing Activities (Unaudited) - Standard Measure of Discounted Future Cash Flow (Narrative) (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018USD ($)$ / bbl$ / Dekatherm | Dec. 31, 2017USD ($)$ / bbl$ / Dekatherm | Dec. 31, 2016USD ($)$ / bbl$ / Dekatherm | |
Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | |||
Future abandonment costs | $ | $ 883 | $ 1,400 | $ 790 |
West Texas Intermediate | |||
Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | |||
Price used in computation of reserves (in usd per bbl) | $ / bbl | 65.56 | 51.34 | 42.75 |
Columbia Gas Transmission Corp. | |||
Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | |||
Price used in computation of oil and gas reserves (in usd per dth) | 2.888 | 2.801 | 2.342 |
Dominion Transmission, Inc. | |||
Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | |||
Price used in computation of oil and gas reserves (in usd per dth) | 2.568 | 2.100 | 1.348 |
East Tennessee Natural Gas Pipeline | |||
Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | |||
Price used in computation of oil and gas reserves (in usd per dth) | 2.914 | 2.334 | |
Texas Eastern Transmission Corp | |||
Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | |||
Price used in computation of oil and gas reserves (in usd per dth) | 2.587 | 2.058 | 1.325 |
Tennessee Zone 4-300 Leg of Tennessee Gas Pipeline Company | |||
Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | |||
Price used in computation of oil and gas reserves (in usd per dth) | 2.320 | 1.995 | 1.305 |
Tennessee LA 500 Leg of Tennessee Gas Pipeline Company | |||
Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | |||
Price used in computation of oil and gas reserves (in usd per dth) | 2.321 | 1.862 | |
Waha | |||
Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | |||
Price used in computation of oil and gas reserves (in usd per dth) | 2.665 | 2.343 | |
Rockies Express Pipeline Zone 3 | |||
Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | |||
Price used in computation of oil and gas reserves (in usd per dth) | $ / bbl | 2.939 | 2.840 | 2.402 |
West Virginia Marcellus reserves | |||
Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | |||
Price used in computation of reserves (in usd per bbl) | $ / bbl | 21.93 | 23.07 | 13.87 |
Kentucky | |||
Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | |||
Price used in computation of reserves (in usd per bbl) | $ / bbl | 31.11 | 17.27 | |
Utica | |||
Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | |||
Price used in computation of reserves (in usd per bbl) | $ / bbl | 33.89 | 29.47 | 14.71 |
Permian | |||
Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | |||
Price used in computation of reserves (in usd per bbl) | $ / bbl | 27.93 | 18.91 |
Natural Gas Producing Activit_9
Natural Gas Producing Activities (Unaudited) - Summary of Changes in the Standardized Measure of Discounted Net Cash Flows (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward] | |||
Sales and transfers of natural gas and oil produced – net | $ (2,802,742) | $ (1,305,186) | $ (540,636) |
Net changes in prices, production and development costs | 2,949,606 | 2,236,183 | (1,129,026) |
Extensions, discoveries and improved recovery, less related costs | 1,616,653 | 1,269,712 | 590,885 |
Development costs incurred | 1,630,506 | 712,635 | 402,891 |
Purchase of minerals in place – net | 0 | 5,357,921 | 592,078 |
Sale of minerals in place – net | (849,162) | (284) | 0 |
Revisions of previous quantity estimates | (811,576) | (297,437) | (60,959) |
Accretion of discount | 834,026 | 115,437 | 122,674 |
Net change in income taxes | (289,549) | (1,477,603) | (91,823) |
Timing and other | 332,202 | 1,401,802 | 125,116 |
Net increase (decrease) | 2,609,964 | 8,013,180 | 11,200 |
Beginning of year | 9,001,934 | 988,754 | 977,554 |
End of year | $ 11,611,898 | $ 9,001,934 | $ 988,754 |
SCHEDULE II - VALUATION AND Q_2
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Details) - Deferred Tax Assets - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward] | |||
Balance at Beginning of Period | $ 262,392 | $ 201,422 | $ 156,084 |
(Deductions) Additions Charged to Costs and Expenses | 98,311 | 70,063 | 24,706 |
Additions Charged to Other Accounts | 0 | 0 | 21,536 |
Deductions | (9,295) | (9,093) | (904) |
Balance at End of Period | $ 351,408 | $ 262,392 | $ 201,422 |
Uncategorized Items - eqt-20181
Label | Element | Value | |
Retained Earnings [Member] | |||
Cumulative Effect of New Accounting Principle in Period of Adoption | us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption | $ 4,113,000 | [1] |
[1] | Related to adoption of ASU No. 2016-01. See Note 1 for additional information. |