Item 8. Financial Statements and Supplementary Data

		Page Reference
Reports of Independent Registered Public Accounting Firm		63
Statements of Consolidated Operations for each of the three years in the period ended December 31, 2018		65
Statements of Consolidated Comprehensive Income for each of the three years in the period ended December 31, 2018		66
Statements of Consolidated Cash Flows for each of the three years in the period ended December 31, 2018		67
Consolidated Balance Sheets as of December 31, 2018 and 2017		68
Statements of Consolidated Equity for each of the three years in the period ended December 31, 2018		70
Notes to Consolidated Financial Statements		71

Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of EQT Corporation

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of EQT Corporation and subsidiaries (the Company) as of December 31, 2018 and 2017, the related statements of consolidated operations, comprehensive income, cash flows and equity for each of the three years in the period ended December 31, 2018, and the related notes and the financial statement schedule listed in the Index at Item 15 (a) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the consolidated financial position of the Company at December 31, 2018 and 2017, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 14, 2019 expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 1950.

Pittsburgh, Pennsylvania

February 14, 2019

Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of EQT Corporation

Opinion on Internal Control over Financial Reporting

We have audited EQT Corporation and subsidiaries’ internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, EQT Corporation and subsidiaries (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2018 and 2017, and the related statements of consolidated operations, comprehensive income, cash flows and equity for each of the three years in the period ended December 31, 2018 and the related notes and the financial statement schedule listed in the Index at Item 15 (a) of the Company and our report dated February 14, 2019 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP

Pittsburgh, Pennsylvania

February 14, 2019

EQT CORPORATION AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED OPERATIONS

YEARS ENDED DECEMBER 31,

	2018				2017				2016
	(Thousands except per share amounts)
Operating revenues:
Sales of natural gas, oil and NGLs	$	4,695,519			$	2,651,318			$	1,594,997
Net marketing services and other	40,940				49,681				41,048
(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				—				—
Impairment of goodwill	530,811				—				—
Lease impairments and expirations	279,708				7,552				15,686
Transaction costs	26,331				152,188				—
Amortization of intangible assets	41,367				5,400				—
Total operating expenses	7,340,992				2,708,808				2,150,107
Gain on sale of assets	—				—				8,025
Operating (loss) income	(2,783,124		)		382,212				(755,028		)
Other expense	65,349				2,987				8,075
Loss on debt extinguishment	—				12,641				—
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
Net (loss) income attributable to EQT Corporation	$	(2,244,568	)		$	1,508,529			$	(452,983	)
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	)
Earnings per share of common stock attributable to EQT Corporation:
Basic:
Weighted average common stock outstanding	260,932				187,380				166,978
(Loss) income from continuing operations	$	(9.12	)		$	7.40			$	(3.18	)
Income from discontinued operations	0.52				0.65				0.47
Net (loss) income	$	(8.60	)		$	8.05			$	(2.71	)
Diluted:
Weighted average common stock outstanding	260,932				187,727				166,978
(Loss) income from continuing operations	$	(9.12	)		$	7.39			$	(3.18	)
Income from discontinued operations	0.52				0.65				0.47
Net (loss) income	$	(8.60	)		$	8.04			$	(2.71	)

See notes to consolidated financial statements.

EQT CORPORATION AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

YEARS ENDED DECEMBER 31,

	2018				2017				2016
	(Thousands)
Net (loss) income	$	(2,007,158	)		$	1,858,142			$	(131,063	)
Other comprehensive loss, net of tax:
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	)

See notes to consolidated financial statements.

EQT CORPORATION AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS

YEARS ENDED DECEMBER 31,

	2018				2017				2016
	(Thousands)
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 intangibles assets	77,374				10,940				—
Amortization of financing costs and accretion expense	17,914				—				—
Asset and lease impairments and exploratory well costs	2,989,684				20,327				75,434
Goodwill impairment	798,689				—				—
Gain on sale of assets	—				—				(8,025		)
Loss on debt extinguishment	—				12,641				—
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	—				—				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	—				(1,560,272		)		—
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 (investments in) trading securities	—				283,758				(284,882		)
Proceeds from sale of assets	583,381				3,573				75,000
Exploratory dry hole costs	—				(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		)		—				—
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	—				—				1,225,999
Net proceeds from the issuance of common units of EQM Midstream Partners, LP	—				—				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		)		—				—
Contribution to Strike Force Midstream LLC by minority owner, net of distribution	—				6,738				—
Acquisition of 25% of Strike Force Midstream LLC	(175,000		)		—				—
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	—				(89,363		)		—
Repurchase and retirement of common stock	(538,876		)		—				—
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	)

See notes to consolidated financial statements. See Note 1 for supplemental cash flow information.

EQT CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

DECEMBER 31,

	2018				2017
	(Thousands)
Assets
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	—				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	—				470,849
Investment in Equitrans Midstream Corporation	1,013,002				—
Other assets	268,838				250,734
Noncurrent assets of discontinued operations	—				7,789,258
Total assets	$	20,721,344			$	29,522,604

EQT CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

DECEMBER 31,

	2018				2017
	(Thousands)
Liabilities and Shareholders’ Equity
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	—				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	—				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	—				5,094,995
Total shareholder's equity	10,958,229				18,414,613
Total liabilities and shareholders' equity	$	20,721,344			$	29,522,604

See notes to consolidated financial statements.

EQT CORPORATION AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED EQUITY

YEARS ENDED DECEMBER 31, 2018, 2017 and 2016

	Common Stock
	Shares Outstanding			No Par Value				Retained Earnings				Accumulated Other Comprehensive (Loss) Income				Noncontrolling Interests in Discontinued Operations				Total Shareholders' Equity
								(Thousands)
Balance, December 31, 2015	152,554			$	2,049,201			$	2,982,212			$	46,378			$	2,950,251			$	8,028,042
Comprehensive income (net of tax):
Net (loss) income								(452,983		)						321,920				(131,063		)
Net change in cash flow hedges:
Natural gas, net of tax of ($36,296)												(55,155		)						(55,155		)
Interest rate, net of tax of $104												144								144
Pension and other post retirement benefits liability adjustment, net of tax of $6,778												10,675								10,675
Dividends ($0.12 per share)								(20,156		)										(20,156		)
Share-based compensation plans, net	724			42,782												161				42,943
Distributions to noncontrolling interests in discontinued operations ($3.05 and $0.571 per common unit for EQM Midstream Partners, LP and EQGP Holdings, LP, respectively)																(189,981		)		(189,981		)
Issuance of common shares of EQT Corporation	19,550			1,225,999												—				1,225,999
Issuance of common units of EQM Midstream Partners, LP																217,102				217,102
Elimination of deferred taxes				5,921																5,921
Changes in ownership of consolidated subsidiaries				25,293												(40,487		)		(15,194		)
Repurchase and retirement of common stock	(1	)		(30		)														(30		)
Balance, December 31, 2016	172,827			$	3,349,166			$	2,509,073			$	2,042			$	3,258,966			$	9,119,247
Comprehensive income (net of tax):
Net income								1,508,529								349,613				1,858,142
Net change in cash flow hedges:
Natural gas, net of tax of ($3,191)												(4,982		)						(4,982		)
Interest rate, net of tax of $105												144								144
Pension and other post retirement benefits liability adjustment, net of tax of $193												338								338
Dividends ($0.12 per share)								(20,827		)										(20,827		)
Share-based compensation plans, net	580			26,436												190				26,626
Distributions to noncontrolling interests in discontinued operations ($3.655 and $0.806 per common unit for EQM Midstream Partners, LP and EQGP Holdings, LP, respectively)																(236,123		)		(236,123		)
Rice Merger, net of withholdings	90,914			5,949,729												1,715,611				7,665,340
Contribution from noncontrolling interest, net of distribution																6,738				6,738
Repurchase of common stock	(1	)		(30		)														(30		)
Balance, December 31, 2017	264,320			$	9,325,301			$	3,996,775			$	(2,458	)		$	5,094,995			$	18,414,613
Comprehensive income (net of tax):
Net (loss) income								(2,244,568		)						237,410				(2,007,158		)
Net change in cash flow hedges:
Natural gas, net of tax of $2,584												(4,625		)						(4,625		)
Interest rate, net of tax of $80												168								168
Other post retirement benefits liability adjustment, net of tax of $510												606								606
Dividends ($0.12 per share)								(31,375		)										(31,375		)
Share-based compensation plans, net	798			7,432												953				8,385
Distributions to noncontrolling interests in discontinued operations ($4.295, $1.123 and $0.5966 per common unit for EQM Midstream Partners, LP, EQGP Holdings, LP and RM Partners LP (formerly known as Rice Midstream Partners LP), respectively)																(380,651		)		(380,651		)
Change in accounting principle (a)								4,113												4,113
Repurchase and retirement of common stock	(10,646	)		(538,876		)														(538,876		)
Purchase of Strike Force Midstream LLC noncontrolling interests				1,818												(176,818		)		(175,000		)
Changes in ownership of consolidated subsidiaries				(158,560		)										214,930				56,370
Distribution of Equitrans Midstream Corporation				(857,755		)		1,459,330				903				(4,990,819		)		(4,388,341		)
Balance, December 31, 2018	254,472			$	7,779,360			$	3,184,275			$	(5,406	)		$	—			$	10,958,229

(a) Related to adoption of ASU No. 2016-01. See Note 1 for additional information.

Common shares authorized: 320,000 shares. Preferred shares authorized: 3,000 shares. There are no preferred shares issued or outstanding.

See notes to consolidated financial statements.

EQT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2018

1. Summary of Significant Accounting Policies

Principles of Consolidation: The Consolidated Financial Statements include the accounts of EQT Corporation and all subsidiaries, ventures and partnerships in which 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 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: The Company has evaluated subsequent events through the date of the financial statement issuance.

2. Separation and Distribution and Discontinued Operations

On November 12, 2018, 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.

3. 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.

4. 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

5. 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."

6. 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.

7. 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.

8. 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.

9. 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.

10. Debt

		December 31, 2018										December 31, 2017
		Principal Value			Carrying Value (a)			Fair Value (b)				Principal Value			Carrying Value (a)			Fair Value (b)
		(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.

11. 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.

12. 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.

13. 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.

14. Concentrations of Credit Risk

Revenues and related accounts receivable from the Company’s operations are generated primarily from the sale of produced natural gas, NGLs and 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.

15. 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.

16. 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.

17. 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

18. 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.