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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2018


☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 001-36120

ANTERO RESOURCES CORPORATION

(Exact name of registrant as specified in its charter)


Delaware		80-0162034
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)

1615 Wynkoop Street Denver, Colorado		80202
(Address of principal executive offices)		(Zip Code)

(303) 357-7310

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☒ Yes ☐ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.


Large accelerated filer ☒		Accelerated filer ☐
Non-accelerated filer ☐		Smaller reporting company ☐
Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ◻

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act) ☐ Yes ☒ No

The registrant had 317,114,931 shares of common stock outstanding as of October 26, 2018.

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TABLE OF CONTENTS


CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS		2
PART I—FINANCIAL INFORMATION		4
Item 1.	Financial Statements (Unaudited)	4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	43
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	66
Item 4.	Controls and Procedures	68
PART II—OTHER INFORMATION		68
Item 1.	Legal Proceedings	68
Item 1A.	Risk Factors	70
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	71
Item 6.	Exhibits	71
SIGNATURES		72

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Some of the information in this Quarterly Report on Form 10-Q may contain forward-looking statements. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Quarterly Report on Form 10-Q. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

business strategy;

reserves;

financial strategy, liquidity, and capital required for our development program;

natural gas, natural gas liquids (“NGLs”), and oil prices;

timing and amount of future production of natural gas, NGLs, and oil;

hedging strategy and results;

the Company’s ability to successfully complete its share repurchase program;

the possibility that the proposed simplification and related transactions described elsewhere in this Quarterly Report on Form 10-Q (the “Transactions”) are not consummated in a timely manner or at all;

the diversion of management in connection with the Transactions and the ability of the resulting entity of the Transactions to realize the anticipated benefits of the Transactions;

ability to meet minimum volume commitments and to utilize or monetize our firm transportation commitments;

future drilling plans;

competition and government regulations;

pending legal or environmental matters;

marketing of natural gas, NGLs, and oil;

leasehold or business acquisitions;

costs of developing our properties;

operations of Antero Midstream Partners LP (“Antero Midstream”), including the operations of its unconsolidated affiliates;

general economic conditions;

credit markets;

uncertainty regarding our future operating results; and

plans, objectives, expectations, and intentions.

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We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incidental to our business. These risks include, but are not limited to, commodity price volatility, inflation, availability of drilling, completion, and production equipment and services, environmental risks, drilling and completion and other operating risks, marketing and transportation risks, regulatory changes, the uncertainty inherent in estimating natural gas, NGLs, and oil reserves and in projecting future rates of production, cash flows and access to capital, the timing of development expenditures, conflicts of interest among our stockholders, and the other risks described under the heading “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2017 (the “2017 Form 10-K”) on file with the Securities and Exchange Commission (“SEC”).

Reserve engineering is a process of estimating underground accumulations of natural gas, NGLs, and oil that cannot be measured in an exact manner. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data, and the price and cost assumptions made by reservoir engineers. In addition, the results of drilling, testing, and production activities, or changes in commodity prices, may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of natural gas, NGLs, and oil that are ultimately recovered.

Should one or more of the risks or uncertainties described in this report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report on Form 10-Q.

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PART I—FINANCIAL INFORMATION

ANTERO RESOURCES CORPORATION

Condensed Consolidated Balance Sheets

December 31, 2017 and September 30, 2018

(Unaudited)

(In thousands, except per share amounts)


	December 31, 2017		September 30, 2018
Assets
Current assets:
Cash and cash equivalents	$	28,441		—
Accounts receivable, net of allowance for doubtful accounts of $1,320 at December 31, 2017 and $1,195 at September 30, 2018, respectively		34,896		46,604
Accrued revenue		300,122		354,010
Derivative instruments		460,685		493,354
Other current assets		8,943		12,664
Total current assets		833,087		906,632
Property and equipment:
Natural gas properties, at cost (successful efforts method):
Unproved properties		2,266,673		1,928,990
Proved properties		11,096,462		12,306,198
Water handling and treatment systems		946,670		993,285
Gathering systems and facilities		2,050,490		2,384,041
Other property and equipment		57,429		62,739
		16,417,724		17,675,253
Less accumulated depletion, depreciation, and amortization		(3,182,171)		(3,890,834)
Property and equipment, net		13,235,553		13,784,419
Derivative instruments		841,257		672,768
Investments in unconsolidated affiliates		303,302		392,893
Other assets		48,291		45,823
Total assets	$	15,261,490		15,802,535

Liabilities and Equity
Current liabilities:
Accounts payable	$	62,982		91,940
Accrued liabilities		443,225		457,216
Revenue distributions payable		209,617		245,832
Derivative instruments		28,476		10,456
Other current liabilities		17,796		8,427
Total current liabilities		762,096		813,871
Long-term liabilities:
Long-term debt		4,800,090		5,487,004
Deferred income tax liability		779,645		782,145
Derivative instruments		207		—
Other liabilities		43,316		48,363
Total liabilities		6,385,354		7,131,383
Commitments and contingencies (notes 12 and 13)
Equity:
Stockholders' equity:
Preferred stock, $0.01 par value; authorized - 50,000 shares; none issued		—		—
Common stock, $0.01 par value; authorized - 1,000,000 shares; 316,379 shares and 317,086 shares issued and outstanding at December 31, 2017 and September 30, 2018, respectively		3,164		3,171
Additional paid-in capital		6,570,952		6,611,348
Accumulated earnings		1,575,065		1,299,094
Total stockholders' equity		8,149,181		7,913,613
Noncontrolling interests in consolidated subsidiary		726,955		757,539
Total equity		8,876,136		8,671,152
Total liabilities and equity	$	15,261,490		15,802,535

See accompanying notes to the unaudited condensed consolidated financial statements.

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ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Operations and Comprehensive Loss

Three Months Ended September 30, 2017 and 2018

(Unaudited)

(In thousands, except per share amounts)


	Three Months Ended September 30,
	2017		2018
Revenue:
Natural gas sales	$	409,141		527,122
Natural gas liquids sales		224,533		338,269
Oil sales		26,527		59,722
Commodity derivative fair value gains (losses)		(65,957)		57,019
Gathering, compression, water handling and treatment		2,869		4,844
Marketing		50,767		89,598
Marketing derivative fair value losses		—		(42)
Total revenue		647,880		1,076,532
Operating expenses:
Lease operating		23,491		36,269
Gathering, compression, processing, and transportation		282,134		326,504
Production and ad valorem taxes		22,995		30,518
Marketing		78,884		151,764
Exploration		1,599		666
Impairment of unproved properties		41,000		221,094
Impairment of gathering systems and facilities		—		1,157
Depletion, depreciation, and amortization		206,968		243,186
Accretion of asset retirement obligations		658		710
General and administrative (including equity-based compensation expense of $26,447 and $16,202 in 2017 and 2018, respectively)		62,203		59,860
Total operating expenses		719,932		1,071,728
Operating income (loss)		(72,052)		4,804
Other income (expenses):
Equity in earnings of unconsolidated affiliates		7,033		10,705
Interest		(70,059)		(74,528)
Total other expenses		(63,026)		(63,823)
Loss before income taxes		(135,078)		(59,019)
Provision for income tax (expense) benefit		45,078		(18,953)
Net loss and comprehensive loss including noncontrolling interests		(90,000)		(77,972)
Net income and comprehensive income attributable to noncontrolling interests		45,063		76,447
Net loss and comprehensive loss attributable to Antero Resources Corporation	$	(135,063)		(154,419)

Loss per common share—basic and diluted	$	(0.43)		(0.49)

Weighted average number of shares outstanding:
Basic and diluted		315,463		317,082

See accompanying notes to the unaudited condensed consolidated financial statements.

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ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Operations and Comprehensive Income

Nine Months Ended September 30, 2017 and 2018

(Unaudited)

(In thousands, except per share amounts)


	Nine Months Ended September 30,
	2017		2018
Revenue and other:
Natural gas sales	$	1,330,062		1,498,324
Natural gas liquids sales		590,004		828,424
Oil sales		79,999		128,869
Commodity derivative fair value gains		458,459		134,793
Gathering, compression, water handling and treatment		8,665		15,298
Marketing		166,659		394,189
Marketing derivative fair value gains		—		94,081
Total revenue and other		2,633,848		3,093,978
Operating expenses:
Lease operating		56,034		93,155
Gathering, compression, processing, and transportation		815,710		926,228
Production and ad valorem taxes		70,341		82,232
Marketing		246,298		560,924
Exploration		5,510		4,022
Impairment of unproved properties		83,098		406,068
Impairment of gathering systems and facilities		—		9,658
Depletion, depreciation, and amortization		610,879		709,480
Accretion of asset retirement obligations		1,944		2,101
General and administrative (including equity-based compensation expense of $78,925 and $56,429 in 2017 and 2018, respectively)		191,000		181,576
Total operating expenses		2,080,814		2,975,444
Operating income		553,034		118,534
Other income (expenses):
Equity in earnings of unconsolidated affiliates		12,887		27,832
Interest		(205,311)		(208,303)
Total other expenses		(192,424)		(180,471)
Income (loss) before income taxes		360,610		(61,937)
Provision for income tax expense		(105,087)		(2,500)
Net income (loss) and comprehensive income (loss) including noncontrolling interests		255,523		(64,437)
Net income and comprehensive income attributable to noncontrolling interests		127,322		211,534
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$	128,201		(275,971)


Earnings (loss) per common share—basic	$	0.41		(0.87)

Earnings (loss) per common share—assuming dilution	$	0.41		(0.87)

Weighted average number of shares outstanding:
Basic		315,275		316,850
Diluted		316,140		316,850

See accompanying notes to the unaudited condensed consolidated financial statements.

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ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Equity

Nine Months Ended September 30, 2017

(Unaudited)

(In thousands)


	Common Stock				Additional paid-		Accumulated		Noncontrolling		Total
	Shares		Amount		in capital		earnings		interests		equity
Balances, December 31, 2016		314,877	$	3,149		5,299,481		959,995		1,465,953		7,728,578
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		129		1		(1,658)		—		—		(1,657)
Issuance of common units by Antero Midstream Partners LP, net of underwriter discounts and offering costs		—		—		—		—		223,119		223,119
Equity-based compensation		—		—		23,354		—		2,149		25,503
Net income and comprehensive income		—		—		—		268,396		37,162		305,558
Effects of changes in ownership interests in consolidated subsidiaries		—		—		1,085,981		—		(1,085,981)		—
Distributions to noncontrolling interests		—		—		—		—		(27,149)		(27,149)
Balances, March 31, 2017		315,006	$	3,150		6,407,158		1,228,391		615,253		8,253,952
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		442		4		(5,848)		—		—		(5,844)
Issuance of common units by Antero Midstream Partners LP, net of underwriter discounts and offering costs		—		—		—		—		23,466		23,466
Issuance of common units in Antero Midstream Partners LP upon vesting of equity-based compensation awards, net of units withheld for income taxes		—		—		(1,559)		—		627		(932)
Equity-based compensation		—		—		24,543		—		2,432		26,975
Net income (loss) and comprehensive income (loss)		—		—		—		(5,132)		45,097		39,965
Effects of changes in ownership interests in consolidated subsidiaries		—		—		10,753		—		(10,753)		—
Distributions to noncontrolling interests		—		—		—		—		(34,720)		(34,720)
Balances, June 30, 2017		315,448	$	3,154		6,435,047		1,223,259		641,402		8,302,862
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		22		1		(68)		—		—		(67)
Issuance of common units by Antero Midstream Partners LP, net of underwriter discounts and offering costs		—		—		—		—		2,364		2,364
Sale of common units of Antero Midstream Partners LP held by Antero Resources Corporation, net of tax		—		—		205,780		—		(19,940)		185,840
Net income (loss) and comprehensive income (loss)		—		—		—		(135,063)		45,063		(90,000)
Equity-based compensation		—		—		23,889		—		2,558		26,447
Effects of changes in ownership interests in consolidated subsidiaries		—		—		(100,328)		—		100,328		—
Distributions to noncontrolling interests		—		—		—		—		(40,184)		(40,184)
Balances, September 30, 2017		315,470	$	3,155		6,564,320		1,088,196		731,591		8,387,262

See accompanying notes to the unaudited condensed consolidated financial statements.

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ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Equity

Nine Months Ended September 30, 2018

(Unaudited)

(In thousands)


	Common Stock				Additional paid-		Accumulated		Noncontrolling		Total
	Shares		Amount		in capital		earnings		interests		equity
Balances, December 31, 2017		316,379	$	3,164		6,570,952		1,575,065		726,955		8,876,136
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		145		1		(1,067)		—		—		(1,066)
Issuance of common units in Antero Midstream Partners LP upon vesting of equity-based compensation awards, net of units withheld for income taxes		—		—		(50)		—		32		(18)
Equity-based compensation		—		—		18,802		—		2,354		21,156
Net income and comprehensive income		—		—		—		14,833		65,977		80,810
Effects of changes in ownership interests in consolidated subsidiaries		—		—		(555)		—		555		—
Distributions to noncontrolling interests		—		—		—		—		(55,915)		(55,915)
Other		—		—		—		—		(5)		(5)
Balances, March 31, 2018		316,524	$	3,165		6,588,082		1,589,898		739,953		8,921,098
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		528		6		(5,589)		—		—		(5,583)
Issuance of common units in Antero Midstream Partners LP upon vesting of equity-based compensation awards, net of units withheld for income taxes		—		—		(4,007)		—		2,707		(1,300)
Equity-based compensation		—		—		16,930		—		2,141		19,071
Net income (loss) and comprehensive income (loss)		—		—		—		(136,385)		69,110		(67,275)
Effects of changes in ownership interests in consolidated subsidiaries		—		—		2,121		—		(2,121)		—
Distributions to noncontrolling interests		—		—		—		—		(63,108)		(63,108)
Other		—		—		—		—		8		8
Balances, June 30, 2018		317,052	$	3,171		6,597,537		1,453,513		748,690		8,802,911
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		34		—		(157)		—		—		(157)
Issuance of common units in Antero Midstream Partners LP upon vesting of equity-based compensation awards, net of units withheld for income taxes		—		—		(306)		—		226		(80)
Equity-based compensation		—		—		14,646		—		1,556		16,202
Net income (loss) and comprehensive income (loss)		—		—		—		(154,419)		76,447		(77,972)
Effects of changes in ownership interests in consolidated subsidiaries		—		—		(372)		—		372		—
Distributions to noncontrolling interests		—		—		—		—		(69,752)		(69,752)
Balances, September 30, 2018		317,086	$	3,171		6,611,348		1,299,094		757,539		8,671,152

See accompanying notes to the unaudited condensed consolidated financial statements.

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ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Cash Flows

Nine Months Ended September 30, 2017 and 2018

(Unaudited)

(In thousands)


	Nine Months Ended September 30,
	2017		2018
Cash flows provided by (used in) operating activities:
Net income (loss) including noncontrolling interests	$	255,523		(64,437)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, amortization, and accretion		612,823		711,581
Impairment of unproved properties		83,098		406,068
Impairment of gathering systems and facilities		—		9,658
Commodity derivative fair value gains		(458,459)		(134,793)
Gains on settled commodity derivatives		137,392		268,369
Proceeds from derivative monetizations		749,906		—
Marketing derivative fair value gains		—		(94,081)
Gains on settled marketing derivatives		—		78,098
Deferred income tax expense		105,087		2,500
Equity-based compensation expense		78,925		56,429
Equity in earnings of unconsolidated affiliates		(12,887)		(27,832)
Distributions of earnings from unconsolidated affiliates		10,120		29,660
Other		1,191		2,945
Changes in current assets and liabilities:
Accounts receivable		1,771		4,653
Accrued revenue		28,375		(53,888)
Other current assets		(3,836)		(3,721)
Accounts payable		4,731		8,177
Accrued liabilities		43,043		27,446
Revenue distributions payable		56,982		36,215
Other current liabilities		(977)		(2,649)
Net cash provided by operating activities		1,692,808		1,260,398
Cash flows used in investing activities:
Additions to proved properties		(179,318)		—
Additions to unproved properties		(182,207)		(130,381)
Drilling and completion costs		(946,508)		(1,125,660)
Additions to water handling and treatment systems		(143,470)		(77,385)
Additions to gathering systems and facilities		(254,619)		(337,448)
Additions to other property and equipment		(11,417)		(5,371)
Investments in unconsolidated affiliates		(216,776)		(91,419)
Change in other assets		(16,148)		(2,675)
Other		2,156		—
Net cash used in investing activities		(1,948,307)		(1,770,339)
Cash flows provided by (used in) financing activities:
Issuance of common units by Antero Midstream Partners LP		248,949		—
Proceeds from sale of common units of Antero Midstream Partners LP held by Antero Resources Corporation		311,100		—
Borrowings (repayments) on bank credit facilities, net		(198,000)		682,000
Distributions to noncontrolling interests in consolidated subsidiary		(102,053)		(188,775)
Employee tax withholding for settlement of equity compensation awards		(8,500)		(8,205)
Other		(3,913)		(3,520)
Net cash provided by financing activities		247,583		481,500
Net decrease in cash and cash equivalents		(7,916)		(28,441)
Cash and cash equivalents, beginning of period		31,610		28,441
Cash and cash equivalents, end of period	$	23,694		—

Supplemental disclosure of cash flow information:
Cash paid during the period for interest	$	174,324		179,489

Increase (decrease) in accounts payable and accrued liabilities for additions to property and equipment	$	(3,084)		7,325

See accompanying notes to the unaudited condensed consolidated financial statements.

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ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2017 and September 30, 2018

(1)Organization

Antero Resources Corporation (individually referred to as “Antero” or the “Parent”) and its consolidated subsidiaries (collectively referred to as the “Company”) are engaged in the exploration, development, and acquisition of natural gas, NGLs, and oil properties in the Appalachian Basin in West Virginia and Ohio. The Company targets large, repeatable resource plays where horizontal drilling and advanced fracture stimulation technologies provide the means to economically develop and produce natural gas, NGLs, and oil from unconventional formations. Through its consolidated subsidiary, Antero Midstream Partners LP, a publicly-traded limited partnership (“Antero Midstream”), the Company has gathering and compression, as well as water handling and treatment operations in the Appalachian Basin. The Company’s corporate headquarters are located in Denver, Colorado.

(2)Summary of Significant Accounting Policies

(a)Basis of Presentation

These unaudited condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC applicable to interim financial information and should be read in the context of the December 31, 2017 consolidated financial statements and notes thereto for a more complete understanding of the Company’s operations, financial position, and accounting policies. The December 31, 2017 consolidated financial statements have been filed with the Securities and Exchange Commission (“SEC”) in the Company’s 2017 Form 10-K.

The accompanying unaudited condensed consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information, and, accordingly, do not include all of the information and footnotes required by GAAP for complete consolidated financial statements. In the opinion of management, the accompanying unaudited condensed consolidated financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly the Company’s financial position as of December 31, 2017 and September 30, 2018, the results of its operations for the three and nine months ended September 30, 2017 and 2018, and its cash flows for the nine months ended September 30, 2017 and 2018. The Company has no items of other comprehensive income or loss; therefore, its net income or loss is equal to its comprehensive income or loss. Operating results for the period ended September 30, 2018 are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received for natural gas, NGLs, and oil, natural production declines, the uncertainty of exploration and development drilling results, fluctuations in the fair value of derivative instruments, and other factors.

The Company’s exploration and production activities are accounted for under the successful efforts method.

As of the date these financial statements were filed with the SEC, the Company completed its evaluation of potential subsequent events for disclosure and no items requiring disclosure were identified except for the proposed simplification and related transactions announced on October 9, 2018. See note 17 for descriptions of the Simplification Agreement and share repurchase program.

(b)Principles of Consolidation

The accompanying unaudited condensed consolidated financial statements include the accounts of Antero, its wholly-owned subsidiaries, any entities in which the Company owns a controlling interest, and variable interest entities (“VIEs”) for which the Company is the primary beneficiary.

We have determined that Antero Midstream is a VIE for which Antero is the primary beneficiary. Therefore, Antero Midstream’s accounts are consolidated in the Company’s unaudited condensed consolidated financial statements. Antero is the primary beneficiary of Antero Midstream based on its power to direct the activities that most significantly impact Antero Midstream’s economic performance, and its obligation to absorb losses of, or right to receive benefits from, Antero Midstream that could be significant to Antero Midstream. In reaching the determination that Antero is the primary beneficiary of Antero Midstream, the Company considered the following:

Antero Midstream was formed to own, operate, and develop midstream energy assets to service Antero’s production and completion activities under long-term service contracts.

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ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2017 and September 30, 2018

Antero owned 52.9% of the outstanding limited partner interests in Antero Midstream at September 30, 2018.

Antero Midstream GP LP (“AMGP”) indirectly controls the general partnership interest in Antero Midstream and directly controls Antero IDR Holdings LLC (“IDR LLC”), which owns the incentive distribution rights in Antero Midstream. However, AMGP has not provided, and is not expected to provide, financial support to Antero Midstream. Antero does not control AMGP and does not have any investment in AMGP.

Antero’s officers and management group also act as management of Antero Midstream and AMGP under services and secondment agreements between the respective parties.

Antero and Antero Midstream have contracts with 20-year initial terms and automatic renewal provisions, whereby Antero has dedicated the rights for gathering and compression, and water delivery and treatment services to Antero Midstream. Such dedications cover a substantial portion of Antero’s current acreage and future acquired acreage, in each case, except for acreage that was already dedicated to other parties prior to entering into the service contracts or that was acquired subject to a pre-existing dedication. The contracts call for Antero to present, in advance, its drilling and completion plans in order for Antero Midstream to develop gathering and compression and water delivery and handling assets to service Antero’s operations. Consequently, the drilling and completion capital investment decisions made by Antero control the development and operation of all of Antero Midstream’s assets. Because of these contractual obligations and the capital requirements related to these obligations, Antero Midstream has and, for the foreseeable future, will devote substantially all of its resources to servicing Antero’s operations.

Revenues from Antero provide substantially all of Antero Midstream’s financial support and, therefore, its ability to finance its operations.

As a result of the long-term contractual commitment to support Antero’s substantial growth plans, Antero Midstream will be practically and physically constrained from providing any substantive amount of services to third-parties.

All significant intercompany accounts and transactions have been eliminated in the Company’s unaudited condensed consolidated financial statements. Noncontrolling interest in the Company’s unaudited condensed consolidated financial statements represents the interests in Antero Midstream which are owned by the public and the incentive distribution rights in Antero Midstream. Noncontrolling interests in consolidated subsidiaries is included as a component of equity in the Company’s unaudited condensed consolidated balance sheets.

Investments in entities for which the Company exercises significant influence, but not control, are accounted for under the equity method. Such investments are included in Investments in unconsolidated affiliates on the Company’s unaudited condensed consolidated balance sheets. Income from investees that are accounted for under the equity method is included in Equity in earnings of unconsolidated affiliates on the Company’s unaudited condensed consolidated statements of operations and cash flows.

(c)Use of Estimates

The preparation of the unaudited condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions which affect revenues, expenses, assets, and liabilities, as well as the disclosure of contingent assets and liabilities. Changes in facts and circumstances or discovery of new information may result in revised estimates, and actual results could differ from those estimates.

The Company’s unaudited condensed consolidated financial statements are based on a number of significant estimates including estimates of natural gas, NGLs, and oil reserve quantities, which are the basis for the calculation of depletion and impairment of oil and gas properties. Reserve estimates, by their nature, are inherently imprecise. Other items in the Company’s unaudited condensed consolidated financial statements which involve the use of significant estimates include derivative assets and liabilities, accrued revenue, deferred income taxes, equity-based compensation, asset retirement obligations, depreciation, amortization, and commitments and contingencies.

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ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2017 and September 30, 2018

(d)Risks and Uncertainties

The markets for natural gas, NGLs, and oil have, and continue to, experience significant price fluctuations. Price fluctuations can result from variations in weather, levels of production, availability of transportation capacity to other regions of the country, the level of imports to and exports from the United States, and various other factors. Increases or decreases in the prices the Company receives for its production could have a significant impact on the Company’s future results of operations and reserve quantities.

(e)Cash and Cash Equivalents

The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments. From time to time, the Company may be in the position of a “book overdraft” in which outstanding checks exceed cash and cash equivalents. The Company classifies book overdrafts within accounts payable and revenue distributions payable within its unaudited condensed consolidated balance sheets, and classifies the change in accounts payable and revenue distributions payable associated with book overdrafts as an operating activity within its unaudited condensed consolidated statements of cash flows. As of September 30, 2018, the overdraft included within accounts payable and revenue distributions payable was $11.7 million and $26.7 million, respectively.

(f)Derivative Financial Instruments

In order to manage its exposure to natural gas, NGLs, and oil price volatility, the Company enters into derivative transactions from time to time, which may include commodity swap agreements, basis swap agreements, collar agreements, and other similar agreements related to the price risk associated with the Company’s production. To the extent legal right of offset exists with a counterparty, the Company reports derivative assets and liabilities on a net basis. The Company has exposure to credit risk to the extent that the counterparty is unable to satisfy its settlement obligations. The Company actively monitors the creditworthiness of counterparties and assesses the impact, if any, on its derivative positions.

The Company records derivative instruments on the unaudited condensed consolidated balance sheets as either assets or liabilities measured at fair value and records changes in the fair value of derivatives in current earnings as they occur. Changes in the fair value of commodity derivatives, including gains or losses on settled derivatives, are classified as revenues on the Company’s unaudited condensed consolidated statements of operations. The Company’s derivatives have not been designated as hedges for accounting purposes.

(g)Asset Retirement Obligations

The Company is obligated to dispose of certain long‑lived assets upon their abandonment. The Company’s asset retirement obligations (“AROs”) relate primarily to its obligation to plug and abandon oil and gas wells at the end of their lives, as well as Antero Midstream’s future closure and postclosure costs associated with the landfill at its wastewater treatment facility. AROs are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations, which is then discounted at the Company’s credit‑adjusted, risk‑free interest rate. Revisions to estimated AROs often result from changes in retirement cost estimates or changes in the estimated timing of abandonment. The fair value of the liability is added to the carrying amount of the associated asset, and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. If an obligation is settled for an amount other than the carrying amount of the liability, the Company will recognize a gain or loss on settlement.

(h)Income Taxes

For the three and nine months ended September 30, 2017, the Company’s overall effective tax rate was different than the statutory rate of 35% primarily due to the effects of noncontrolling interests, state tax rates, and permanent differences on vested equity compensation awards. For the three and nine months ended September 30, 2018, the Company’s overall effective tax rate was different than the statutory rate of 21% primarily due to the effects of noncontrolling interests, state tax rates, and permanent differences on vested equity compensation awards.

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ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2017 and September 30, 2018

(i)Industry Segments and Geographic Information

Management has evaluated how the Company is organized and managed and has identified the following segments: (1) the exploration, development, and production of natural gas, NGLs, and oil; (2) gathering and processing; (3) water handling and treatment; and (4) marketing and utilization of excess firm transportation capacity.

All of the Company’s assets are located in the United States and substantially all of its production revenues are attributable to customers located in the United States; however, some of the Company’s production revenues are attributable to customers who resell the Company’s production to third parties located in foreign countries.

(j)Earnings per Common Share

Earnings per common share—basic for each period is computed by dividing net income attributable to Antero by the basic weighted average number of shares outstanding during the period. Earnings per common share—assuming dilution for each period is computed after giving consideration to the potential dilution from outstanding equity awards, calculated using the treasury stock method. The Company includes performance share unit awards in the calculation of diluted weighted average shares outstanding based on the number of common shares that would be issuable if the end of the period was also the end of the performance period required for the vesting of the awards. During periods in which the Company incurs a net loss, diluted weighted average shares outstanding are equal to basic weighted average shares outstanding because the effect of all equity awards is antidilutive. The following is a reconciliation of the Company’s basic weighted average shares outstanding to diluted weighted average shares outstanding during the periods presented (in thousands):


	Three Months Ended September 30,		Nine Months Ended September 30,
	2017	2018	2017	2018
Basic weighted average number of shares outstanding	315,463	317,082	315,275	316,850
Add: Dilutive effect of restricted stock units	—	—	828	—
Add: Dilutive effect of outstanding stock options	—	—	—	—
Add: Dilutive effect of performance stock units	—	—	37	—
Diluted weighted average number of shares outstanding	315,463	317,082	316,140	316,850

Weighted average number of outstanding equity awards excluded from calculation of diluted earnings per common share(1):
Restricted stock units	5,054	2,813	2,293	2,996
Outstanding stock options	674	619	679	637
Performance stock units	1,293	1,880	1,002	1,665

(1) The potential dilutive effects of these awards were excluded from the computation of earnings per common share—assuming dilution because the inclusion of these awards would have been anti-dilutive.

(k)Adoption of New Accounting Principle

On May 28, 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers, which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The ASU replaced most existing revenue recognition guidance in GAAP when it became effective and was incorporated into GAAP as Accounting Standards Codification (“ASC”) Topic 606. The new standard became effective for the Company on January 1, 2018. The standard permits the use of either the full retrospective or modified retrospective transition method. The Company elected the modified retrospective transition method. The adoption of this standard had no impact on the Company’s consolidated financial statements. See Note 4 to the unaudited condensed consolidated financial statements for the Company’s disclosures under ASC 606.

(l)Recently Issued Accounting Standard

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ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2017 and September 30, 2018

lease guidance in GAAP when it becomes effective. The new standard becomes effective for the Company on January 1, 2019. Although early application is permitted, the Company does not plan to early adopt the ASU. The standard requires the use of the modified retrospective transition method. The Company is evaluating the effect that ASU 2016-02 will have on its consolidated financial statements and related disclosures. Currently, the Company is evaluating the standard’s applicability to its various contractual arrangements. The Company believes that adoption of the standard will result in increases to its assets and liabilities on its consolidated balance sheet as well as changes to the presentation of certain operating expenses on its consolidated statement of operations. However, the Company has not yet determined the extent of the adjustments that will be required upon implementation of the standard. The Company is updating its accounting policies and internal controls that would be impacted by the new guidance and implementing information technology tools to assist in its ongoing lease data collection and analysis to ensure readiness for adoption in the first quarter of 2019. The Company continues to monitor relevant industry guidance regarding the implementation of ASU 2016-02 and will adjust its implementation strategies as necessary. The Company does not believe that adoption of the standard will impact its operational strategies, growth prospects, or cash flows.

(3)Antero Midstream Partners LP

In 2014, the Company formed Antero Midstream to own, operate, and develop midstream energy assets that service Antero’s production. Antero Midstream’s assets consist of gathering systems and compression facilities, water handling and treatment facilities, and interests in processing and fractionation plants, through which it provides services to Antero under long-term, fixed-fee contracts. AMGP indirectly owns the general partnership interest in Antero Midstream and directly owns capital interests in IDR LLC, which owns the incentive distribution rights in Antero Midstream. Antero Midstream is an unrestricted subsidiary as defined by Antero’s senior secured revolving bank credit facility (the “Credit Facility”). As an unrestricted subsidiary, Antero Midstream and its subsidiaries are not guarantors of Antero’s obligations, and Antero is not a guarantor of Antero Midstream’s obligations (see Note 16).

In connection with Antero’s contribution of its water handling and treatment assets to Antero Midstream in September 2015, Antero Midstream agreed to pay Antero (a) $125 million in cash if Antero Midstream delivers 176,295,000 barrels or more of fresh water during the period between January 1, 2017 and December 31, 2019 and (b) an additional $125 million in cash if Antero Midstream delivers 219,200,000 barrels or more of fresh water during the period between January 1, 2018 and December 31, 2020.

Antero Midstream has an Equity Distribution Agreement (the “Distribution Agreement”) pursuant to which Antero Midstream may sell, from time to time through brokers acting as its sales agents, common units representing limited partner interests having an aggregate offering price of up to $250 million. Sales of the common units are made by means of ordinary brokers’ transactions on the New York Stock Exchange, at market prices, in block transactions, or as otherwise agreed to between Antero Midstream and the sales agents. Proceeds are used for general partnership purposes, which may include repayment of indebtedness and funding working capital or capital expenditures. Antero Midstream is under no obligation to offer and sell common units under the Distribution Agreement.

During the nine months ended September 30, 2018, Antero Midstream did not sell any common units under the Distribution Agreement. As of September 30, 2018, Antero Midstream had the capacity to issue additional common units under the Distribution Agreement up to an aggregate sales price of $157.3 million.

On February 6, 2017, Antero Midstream formed a joint venture (the “Joint Venture”) to develop processing assets in Appalachia with MarkWest Energy Partners, L.P. (“MarkWest”), a wholly owned subsidiary of MPLX, L.P. (see note 5). In conjunction with the formation of the Joint Venture, on February 10, 2017, Antero Midstream issued 6,900,000 common units, including common units issued pursuant to the underwriters’ option to purchase additional common units, generating net proceeds of approximately $223 million. Antero Midstream used the net proceeds to fund the initial contribution to the Joint Venture, repay outstanding borrowings under its credit facility, and for general partnership purposes.

Antero owned approximately 52.9% of the limited partner interests of Antero Midstream at December 31, 2017 and September 30, 2018.

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ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2017 and September 30, 2018

(4)Revenue

(a) Revenue from Contracts with Customers

Product revenue

Our revenues are primarily derived from the sale of natural gas and oil production, as well as the sale of NGLs that are extracted from our natural gas. Sales of natural gas, NGLs, and oil are recognized when we satisfy a performance obligation by transferring control of a product to a customer. Payment is generally received in the month following the month that the sale occurred.

Under our natural gas sales contracts, we deliver natural gas to the purchaser at an agreed upon delivery point. Natural gas is transported from our wellheads to delivery points specified under sales contracts. To deliver natural gas to these points, Antero Midstream or third parties gather, compress, process and transport our natural gas. We maintain control of the natural gas during gathering, compression, processing, and transportation. Our sales contracts provide that we receive a specific index price adjusted for pricing differentials. We transfer control of the product at the delivery point and recognize revenue based on the contract price. The costs to gather, compress, process and transport the natural gas are recorded as Gathering, compression, processing and transportation expenses.

NGLs, which are extracted from natural gas through processing, are either sold by us directly or by the processor under processing contracts. For NGLs sold by us directly, our sales contracts provide that we deliver the product to the purchaser at an agreed upon delivery point and that we receive a specific index price adjusted for pricing differentials. We transfer control of the product to the purchaser at the delivery point and recognize revenue based on the contract price. The costs to further process and transport NGLs are recorded as Gathering, compression, processing, and transportation expenses. For NGLs sold by the processor, our processing contracts provide that we transfer control to the processor at the tailgate of the processing plant and we recognize revenue based on the price received from the processor.

Under our oil sales contracts, we generally sell oil to the purchaser and collect a contractually agreed upon index price, net of pricing differentials. We recognize revenue based on the contract price when we transfer control of the product to the purchaser.

Gathering, compression, water handling and treatment revenue

Substantially all revenues from our gathering, compression, water handling and treatment operations are derived from intersegment transactions for services Antero Midstream provides to our exploration and production operations. The portion of such fees shown in our consolidated financial statements represent amounts charged to interest owners in Antero-operated wells, as well as fees charged to other third parties for water handling and treatment services provided by Antero Midstream or usage of Antero Midstream’s gathering and compression systems. For gathering and compression revenue, Antero Midstream satisfies its performance obligations and recognizes revenue when low pressure volumes are delivered to a compressor station, high pressure volumes are delivered to a processing plant or transmission pipeline, and compression volumes are delivered to a high pressure line. Revenue is recognized based on the per Mcf gathering or compression fee charged by Antero Midstream in accordance with the gathering and compression agreement. For water handling and treatment revenue, Antero Midstream satisfies its performance obligations and recognizes revenue when the fresh water volumes have been delivered to the hydration unit of a specified well pad and the wastewater volumes have been delivered to its wastewater treatment facility. For services contracted through third party providers, Antero Midstream’s performance obligation is satisfied when the service performed by the third party provider has been completed. Revenue is recognized based on the per barrel fresh water delivery or wastewater treatment fee charged by Antero Midstream in accordance with the water services agreement.

Marketing revenue

Marketing revenues are derived from activities to purchase and sell third-party natural gas and NGLs and to market excess firm transportation capacity to third parties. We retain control of the purchased natural gas and NGLs prior to delivery to the purchaser. The Company has concluded that we are the principal in these arrangements and therefore we recognize revenue on a gross basis, with costs to purchase and transport natural gas and NGLs presented as marketing expenses. Contracts to sell third party gas and NGLs are generally subject to similar terms as contracts to sell our produced natural gas and NGLs. We satisfy performance obligations to the purchaser by transferring control of the product at the delivery point and recognize revenue based on the price received from the purchaser.

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ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2017 and September 30, 2018

(b) Disaggregation of Revenue

In the following table, revenue is disaggregated by type (in thousands). The table also identifies the reportable segment to which the disaggregated revenues relate. For more information on reportable segments, see Note 15—Reportable Segments.


	Three Months Ended September 30,				Nine Months Ended September 30,				Segment to which
	2017		2018		2017		2018		revenues relate
Revenues from contracts with customers:
Natural gas sales	$	409,141		527,122		1,330,062		1,498,324	Exploration and production
Natural gas liquids sales (ethane)		24,205		56,185		64,078		115,947	Exploration and production
Natural gas liquids sales (C3+ NGLs)		200,328		282,084		525,926		712,477	Exploration and production
Oil sales		26,527		59,722		79,999		128,869	Exploration and production
Gathering and compression		2,609		4,439		7,472		12,848	Gathering and processing
Water handling and treatment		260		405		1,193		2,450	Water handling and treatment
Marketing		50,767		89,598		166,659		394,189	Marketing
Total		713,837		1,019,555		2,175,389		2,865,104
Income from derivatives and other sources		(65,957)		56,977		458,459		228,874
Total revenue and other	$	647,880		1,076,532		2,633,848		3,093,978

For our product sales that have a contract term greater than one year, we have utilized the practical expedient in ASC 606, which states that a company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under our product sales contracts, each unit of product delivered to the customer represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. For our product sales that have a contract term of one year or less, we have utilized the practical expedient in ASC 606, which states that a company is not required to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

(d) Contract Balances

Under our sales contracts, we invoice customers after our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our contracts do not give rise to contract assets or liabilities under ASC 606. At December 31, 2017 and September 30, 2018, our receivables from contracts with customers were $300 million and $354 million, respectively.

(5)Equity Method Investments

In 2016, Antero Midstream acquired a 15% equity interest in Stonewall Gas Gathering LLC (“Stonewall”), which operates a regional gathering pipeline on which Antero is an anchor shipper.

On February 6, 2017, Antero Midstream formed the Joint Venture to develop gas processing and fractionation assets in Appalachia with MarkWest, a wholly owned subsidiary of MPLX. Antero Midstream and MarkWest each own a 50% equity interest in the Joint Venture and MarkWest operates the Joint Venture assets, which consist of processing plants in West Virginia, and a one-third interest in a MarkWest fractionator in Ohio.

The Company’s consolidated statements of operations and comprehensive income (loss) includes Antero Midstream’s proportionate share of the net income of equity method investees. When Antero Midstream records its proportionate share of net income, it increases equity income in the consolidated statements of operations and comprehensive income (loss) and the carrying value of that investment on the Company’s consolidated balance sheet. When a distribution is received, it is recorded as a reduction to the carrying value of that investment on the consolidated balance sheet. The Company uses the equity method of accounting to account for its investments in Stonewall and the Joint Venture because Antero Midstream exercises significant influence, but not control, over the entities. The Company’s judgment regarding the level of influence over its equity investments includes considering key factors such as Antero Midstream’s ownership interest, representation on the board of directors, and participation in the policy-making decisions of Stonewall and the Joint Venture.

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ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2017 and September 30, 2018

The following table is a reconciliation of investments in unconsolidated affiliates for the nine months ended September 30, 2018 (in thousands):


	Stonewall		MarkWest Joint Venture		Total
Balance at December 31, 2017	$	67,128		236,174		303,302
Investments		—		91,419		91,419
Equity in net income of unconsolidated affiliates		8,346		19,486		27,832
Distributions from unconsolidated affiliates		(7,515)		(22,145)		(29,660)
Balance at September 30, 2018	$	67,959		324,934		392,893

Investments in the Joint Venture during the nine months ended September 30, 2018 relate to capital contributions for construction of additional processing facilities.

(6)Accrued Liabilities

Accrued liabilities as of December 31, 2017 and September 30, 2018 consisted of the following items (in thousands):


	December 31, 2017		September 30, 2018
Capital expenditures	$	155,300		143,170
Gathering, compression, processing, and transportation expenses		88,850		112,937
Marketing expenses		59,049		46,537
Interest expense		40,861		64,641
Other		99,165		89,931
	$	443,225		457,216

(7)Long-Term Debt

Long-term debt was as follows at December 31, 2017 and September 30, 2018 (in thousands):


	December 31, 2017		September 30, 2018
Antero Resources:
Credit Facility(a)	$	185,000		547,000
5.375% senior notes due 2021(b)		1,000,000		1,000,000
5.125% senior notes due 2022(c)		1,100,000		1,100,000
5.625% senior notes due 2023(d)		750,000		750,000
5.00% senior notes due 2025(e)		600,000		600,000
Net unamortized premium		1,520		1,312
Net unamortized debt issuance costs		(32,430)		(28,162)
Antero Midstream:
Midstream Credit Facility(g)		555,000		875,000
5.375% senior notes due 2024(h)		650,000		650,000
Net unamortized debt issuance costs		(9,000)		(8,146)
	$	4,800,090		5,487,004

Antero Resources Corporation

(a)Senior Secured Revolving Credit Facility

Antero’s Credit Facility is with a consortium of bank lenders. Borrowings under the Credit Facility are subject to borrowing base limitations based on the collateral value of Antero’s assets and are subject to regular annual redeterminations. At September 30, 2018, the borrowing base under the Credit Facility was $4.5 billion and lender commitments were $2.5 billion. Each of these amounts were reaffirmed in the annual redetermination in April 2018. The next redetermination of the borrowing base is scheduled to occur in

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ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2017 and September 30, 2018

April 2019. The maturity date of the Credit Facility is the earlier of (i) October 26, 2022 and (ii) the date that is 91 days prior to the earliest stated redemption date of any series of Antero’s senior notes, unless such series of notes is refinanced.

During any period that is not an Investment Grade Period, the Credit Facility is ratably secured by mortgages on substantially all of Antero’s properties and guarantees from Antero’s restricted subsidiaries, as applicable. During an Investment Grade Period, the liens securing the obligations under the Credit Facility shall be automatically released (subject to the provisions of the Credit Facility). The Credit Facility contains certain covenants, including restrictions on indebtedness and dividends, and requirements with respect to working capital and interest coverage ratios. During any period that is not an Investment Grade Period, interest is payable at a variable rate based on LIBOR or the prime rate determined by Antero’s election at the time of borrowing, plus an applicable rate based on Antero’s borrowing base utilization which ranges from 25 basis points to 225 basis points. During an Investment Grade Period, interest is payable at a variable rate based on LIBOR or the prime rate determined by Antero’s election at the time of borrowing, plus an applicable rate based on Antero’s credit rating which ranges from 12.5 basis points to 175 basis points. Antero was in compliance with all of the financial covenants under the Credit Facility as of December 31, 2017 and September 30, 2018.

As of September 30, 2018, Antero had an outstanding balance under the Credit Facility of $547 million, with a weighted average interest rate of 3.75%, and outstanding letters of credit of $692 million. As of December 31, 2017, Antero had an outstanding balance under the Credit Facility of $185 million, with a weighted average interest rate of 2.96%, and outstanding letters of credit of $705 million. Commitment fees on the unused portion of the Credit Facility are due quarterly at rates ranging from (i) 0.300% to 0.375% (during any period that is not an Investment Grade Period) of the unused portion based on utilization and (ii) 0.150% to 0.300% (during an Investment Grade Period) of the unused portion based on Antero’s credit rating.

(b)5.375% Senior Notes Due 2021

On November 5, 2013, Antero issued $1 billion of 5.375% senior notes due November 1, 2021 (the “2021 notes”) at par. The 2021 notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2021 notes rank pari passu to Antero’s other outstanding senior notes. The 2021 notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by Antero’s wholly-owned subsidiaries and certain of its future restricted subsidiaries. Interest on the 2021 notes is payable on May 1 and November 1 of each year. Antero may redeem all or part of the 2021 notes at any time at redemption prices ranging from 102.688% currently to 100.00% on or after November 1, 2019. If Antero undergoes a change of control, the holders of the 2021 notes will have the right to require Antero to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the 2021 notes, plus accrued and unpaid interest.

On May 6, 2014, Antero issued $600 million of 5.125% senior notes due December 1, 2022 (the “2022 notes”) at par. On September 18, 2014, Antero issued an additional $500 million of the 2022 notes at 100.5% of par. The 2022 notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2022 notes rank pari passu to Antero’s other outstanding senior notes. The 2022 notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by Antero’s wholly-owned subsidiaries and certain of its future restricted subsidiaries. Interest on the 2022 notes is payable on June 1 and December 1 of each year. Antero may redeem all or part of the 2022 notes at any time at redemption prices ranging from 102.563% currently to 100.00% on or after June 1, 2020. If Antero undergoes a change of control, the holders of the 2022 notes will have the right to require Antero to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the 2022 notes, plus accrued and unpaid interest.

(d)5.625% Senior Notes Due 2023

On March 17, 2015, Antero issued $750 million of 5.625% senior notes due June 1, 2023 (the “2023 notes”) at par. The 2023 notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2023 notes rank pari passu to Antero’s other outstanding senior notes. The 2023 notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by Antero’s wholly-owned subsidiaries and certain of its future

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ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2017 and September 30, 2018

restricted subsidiaries. Interest on the 2023 notes is payable on June 1 and December 1 of each year. Antero may redeem all or part of the 2023 notes at any time at redemption prices ranging from 104.219% to 100.00% on or after June 1, 2021. If Antero undergoes a change of control, the holders of the 2023 notes will have the right to require Antero to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the 2023 notes, plus accrued and unpaid interest.

(e) 5.00% Senior Notes Due 2025

On December 21, 2016, Antero issued $600 million of 5.00% senior notes due March 1, 2025 (the “2025 notes”) at par. The 2025 notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2025 notes rank pari passu to Antero’s other outstanding senior notes. The 2025 notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by Antero’s wholly-owned subsidiaries and certain of its future restricted subsidiaries. Interest on the 2025 notes is payable on March 1 and September 1 of each year. Antero may redeem all or part of the 2025 notes at any time on or after March 1, 2020 at redemption prices ranging from 103.750% on or after March 1, 2020 to 100.00% on or after March 1, 2023. In addition, on or before March 1, 2020, Antero may redeem up to 35% of the aggregate principal amount of the 2025 notes with the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 105.00% of the principal amount of the 2025 notes, plus accrued and unpaid interest. At any time prior to March 1, 2020, Antero may also redeem the 2025 notes, in whole or in part, at a price equal to 100% of the principal amount of the 2025 notes plus a “make-whole” premium and accrued and unpaid interest. If Antero undergoes a change of control, the holders of the 2025 notes will have the right to require Antero to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the 2025 notes, plus accrued and unpaid interest.

(f)Treasury Management Facility

Antero has a stand-alone revolving note with a lender which provides for up to $25 million of cash management obligations in order to facilitate Antero’s daily treasury management. Borrowings under the revolving note are secured by the collateral for the Credit Facility. Borrowings under the revolving note bear interest at the lender’s prime rate plus 1.0%. The note matures on June 1, 2019. At December 31, 2017 and September 30, 2018, there were no outstanding borrowings under this note.

Antero Midstream Partners LP

(g)Senior Secured Revolving Credit Facility – Antero Midstream

Antero Midstream has a secured revolving credit facility (the “Midstream Credit Facility”) with a syndicate of bank lenders. At September 30, 2018, lender commitments under the Midstream Credit Facility were $1.5 billion. The maturity date of the Midstream Credit Facility is October 26, 2022. The revolving credit facility was amended on October 31, 2018 to increase lender commitments from $1.5 billion to $2.0 billion.

During any period that is not an Investment Grade Period (as such term is defined in the Midstream Credit Facility), the Midstream Credit Facility is ratably secured by mortgages on substantially all of the properties of Antero Midstream and guarantees from its restricted subsidiaries, as applicable. During an Investment Grade Period under the Midstream Credit Facility, the liens securing the Midstream Credit Facility are automatically released (subject to the provisions of the Midstream Credit Facility). The Midstream Credit Facility contains certain covenants, including restrictions on indebtedness and certain distributions to owners, and requirements with respect to leverage and interest coverage ratios. During any period that is not an Investment Grade Period under the Midstream Credit Facility, interest is payable at a variable rate based on LIBOR or the prime rate determined by Antero Midstream’s election at the time of borrowing, plus an applicable rate based on Antero Midstream’s borrowing base utilization which ranges from 25 basis points to 225 basis points. During an Investment Grade Period under the Midstream Credit Facility, interest is payable at a variable rate based on LIBOR or the prime rate determined by Antero Midstream’s election at the time of borrowing, plus an applicable rate based on Antero Midstream’s credit rating which ranges from 12.5 basis points to 200 basis points. Antero Midstream was in compliance with all of the financial covenants under the Midstream Credit Facility as of December 31, 2017 and September 30, 2018.

As of September 30, 2018, Antero Midstream had an outstanding balance under the Midstream Credit Facility of $875 million with a weighted average interest rate of 3.39%, and no letters of credit outstanding. As of December 31, 2017, Antero Midstream had an outstanding balance under the Midstream Credit Facility of $555 million with a weighted average interest rate of 2.81%. Commitment fees on the unused portion of the Midstream Credit Facility are due quarterly at rates ranging from (i) 0.25% to

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ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2017 and September 30, 2018

0.375% of the unused portion (during an period that is not an Investment Grade Period) based on the leverage ratio and (ii) 0.175% to 0.375% of the unused portion (during an Investment Grade Period) based on Antero Midstream’s credit rating.

(h)5.375% Senior Notes Due 2024 – Antero Midstream

On September 13, 2016, Antero Midstream and its wholly-owned subsidiary, Antero Midstream Finance Corporation (“Midstream Finance Corp.”) as co-issuers, issued $650 million in aggregate principal amount of 5.375% senior notes due September 15, 2024 (the “2024 Midstream notes”) at par. The 2024 Midstream notes are unsecured and effectively subordinated to the Midstream Credit Facility to the extent of the value of the collateral securing the Midstream Credit Facility. The 2024 Midstream notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by Antero Midstream’s wholly-owned subsidiaries, excluding Midstream Finance Corp., and certain of Antero Midstream’s future restricted subsidiaries. Interest on the 2024 Midstream notes is payable on March 15 and September 15 of each year. Antero Midstream may redeem all or part of the 2024 Midstream notes at any time on or after September 15, 2019 at redemption prices ranging from 104.031% on or after September 15, 2019 to 100.00% on or after September 15, 2022. In addition, prior to September 15, 2019, Antero Midstream may redeem up to 35% of the aggregate principal amount of the 2024 Midstream notes with an amount of cash not greater than the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 105.375% of the principal amount of the 2024 Midstream notes, plus accrued and unpaid interest. At any time prior to September 15, 2019, Antero Midstream may also redeem the 2024 Midstream notes, in whole or in part, at a price equal to 100% of the principal amount of the 2024 Midstream notes plus a “make-whole” premium and accrued and unpaid interest. If Antero Midstream undergoes a change of control, the holders of the 2024 Midstream notes will have the right to require Antero Midstream to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the 2024 Midstream notes, plus accrued and unpaid interest.

(8)Asset Retirement Obligations

The following is a reconciliation of the Company’s asset retirement obligations for the nine months ended September 30, 2018 (in thousands):


	2018
Asset retirement obligations—December 31, 2017	$	34,610
Obligations settled		—
Obligations incurred		5,019
Revisions to prior estimates		—
Accretion expense		2,101
Asset retirement obligations—September 30, 2018	$	41,730

Asset retirement obligations are included in other liabilities on the Company’s unaudited condensed consolidated balance sheets.

(9)Equity-Based Compensation

Antero is authorized to grant up to 16,906,500 shares of common stock to employees and directors of the Company under the Antero Resources Corporation Long-Term Incentive Plan (the “Plan”). The Plan allows equity-based compensation awards to be granted in a variety of forms, including stock options, stock appreciation rights, restricted stock awards, restricted stock unit awards, dividend equivalent awards, and other types of awards. The terms and conditions of the awards granted are established by the Compensation Committee of Antero’s Board of Directors. A total of 7,843,312 shares were available for future grant under the Plan as of September 30, 2018.

Antero Midstream’s general partner is authorized to grant up to 10,000,000 common units representing limited partner interests in Antero Midstream under the Antero Midstream Partners LP Long-Term Incentive Plan (the “Midstream Plan”) to non-employee directors of its general partner and certain officers, employees, and consultants of Antero Midstream and its affiliates (which include Antero). A total of 7,739,077 common units were available for future grant under the Midstream Plan as of September 30, 2018.

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ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2017 and September 30, 2018

The Company’s equity-based compensation expense, by type of award, was as follows for the three and nine months ended September 30, 2017 and 2018 (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2018		2017		2018
Restricted stock unit awards	$	17,910		10,001		54,816		33,676
Stock options		614		452		1,850		1,428
Performance share unit awards		3,014		1,017		7,897		7,018
Antero Midstream phantom unit awards		4,420		4,193		12,906		12,752
Equity awards issued to directors		489		539		1,456		1,555
Total expense	$	26,447		16,202		78,925		56,429

Restricted Stock Unit Awards

Restricted stock unit awards vest subject to the satisfaction of service requirements. Expense related to each restricted stock unit award is recognized on a straight-line basis over the requisite service period of the entire award. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period. The grant date fair values of these awards are determined based on the closing price of the Company’s common stock on the date of the grant.

A summary of restricted stock unit awards activity for the nine months ended September 30, 2018 is as follows:


		Weighted average		Aggregate
	Number of shares	grant date fair value		intrinsic value (in thousands)
Total awarded and unvested—December 31, 2017	3,424,084	$	28.51	$	65,058
Granted	668,662	$	20.74
Vested	(950,644)	$	39.30
Forfeited	(362,670)	$	25.91
Total awarded and unvested—September 30, 2018	2,779,432	$	23.29	$	49,224

Intrinsic values are based on the closing price of the Company’s stock on the referenced dates. As of September 30, 2018, there was $37.1 million of unamortized equity-based compensation expense related to unvested restricted stock units. That expense is expected to be recognized over a weighted average period of approximately 2.2 years.

Stock Options

Stock options granted under the Plan have a maximum contractual life of 10 years. Expense related to stock options is recognized on a straight-line basis over the requisite service period of the entire award. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period. Stock options were granted with an exercise price equal to or greater than the market price of the Company’s common stock on the dates of grant.

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ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2017 and September 30, 2018

A summary of stock option activity for the nine months ended September 30, 2018 is as follows:


				Weighted
		Weighted average		average remaining	Intrinsic
	Stock options	exercise price		contractual life	value (in thousands)
Outstanding at December 31, 2017	660,512	$	50.48	7.06	$	—
Granted	—	$	—
Exercised	—	$	—
Forfeited	(51,582)	$	50.00
Expired	—	$	—
Outstanding at September 30, 2018	608,930	$	50.52	6.15	$	—
Vested or expected to vest as of September 30, 2018	608,930	$	50.52	6.15	$	—
Exercisable at September 30, 2018	481,842	$	50.66	6.05	$	—

Intrinsic values are based on the exercise price of the options and the closing price of the Company’s stock on the referenced dates. As of September 30, 2018, there was $1.0 million of unamortized equity-based compensation expense related to unvested stock options. That expense is expected to be recognized over a weighted average period of approximately 0.5 years.

Performance Share Unit Awards

Performance Share Unit Awards Based on Price Targets

In 2016, the Company granted performance share unit awards (“PSUs”) to certain of its executive officers that are based on price targets. The vesting of these PSUs is conditioned on the closing price of the Company’s common stock achieving specific price thresholds over 10-day periods, subject to the following vesting restrictions: no PSUs may vest before the first anniversary of the grant date; no more than one-third of the PSUs may vest before the second anniversary of the grant date; and no more than two-thirds of the PSUs may vest before the third anniversary of the grant date. Any PSUs which have not vested by the fifth anniversary of the grant date will expire. Expense related to these PSUs is recognized on a graded basis over three years.

Performance Share Unit Awards Based on Total Shareholder Return (“TSR”)

In 2016 and 2017, the Company granted PSUs to certain of its employees and executive officers that vest based on the TSR of the Company’s common stock relative to the TSR of a peer group of companies over a three-year performance period. The number of common shares which may ultimately be earned ranges from zero to 200% of the PSUs granted. Expense related to these PSUs is recognized on a straight-line basis over three years.

Performance Share Unit Awards Based on TSR and Return on Capital Employed (“ROCE”)

In 2018, the Company granted PSUs to certain of its employees and executive officers, a portion of which vest based on the Company’s common stock reaching a target price per share equal to 125% of the beginning price (as defined in the award agreement) at the end of a three-year performance period (“TSR PSUs”). The number of awards actually earned with respect to the TSR PSUs will be subject to further adjustment based on the TSR of the Company’s common stock relative to the TSR of a peer group of companies over the same period. The number of shares of common stock that may ultimately be earned with respect to the TSR PSUs ranges from zero to 200% of the target number of TSR PSUs originally granted. Expense related to the TSR PSUs is recognized on a straight-line basis over three years.

The other portion of the PSUs granted in 2018 vest based on the Company’s actual ROCE (as defined in the award agreement) over a three-year period as compared to a targeted ROCE (“ROCE PSUs”). The number of shares of common stock that may ultimately be earned with respect to the ROCE PSUs ranges from zero to 200% of the target number of ROCE PSUs originally granted. Expense related to the ROCE PSUs is recognized based on the number of shares of common stock that are expected to be issued at the end of the measurement period, and is reversed if the likelihood of achieving the performance condition decreases.

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ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2017 and September 30, 2018

Summary Information for Performance Share Unit Awards

A summary of PSU activity for the nine months ended September 30, 2018 is as follows:


	Number of units	Weighted average grant date fair value
Total awarded and unvested—December 31, 2017	1,283,843	$	28.29
Granted	756,466	$	23.61
Vested	(41,666)	$	27.38
Forfeited	(167,193)	$	27.85
Total awarded and unvested—September 30, 2018	1,831,450	$	26.42

The grant-date fair values of market-based PSUs were determined using Monte Carlo simulations, which use a probabilistic approach for estimating the fair values of the awards. Expected volatilities were derived from the volatility of the historical stock prices of a peer group of similar publicly-traded companies. The risk-free interest rate was determined using the yield available for zero-coupon U.S. government issues with remaining terms corresponding to the service periods of the PSUs. A dividend yield of zero was assumed. The grant-date fair value for the ROCE-based PSUs is based on the closing price of the Company’s common stock on the date of the grant, assuming the achievement of the performance condition.

The following table presents information regarding the weighted average fair values for market-based PSUs granted during the nine months ended September 30, 2017 and 2018, and the assumptions used to determine the fair values:


	Nine Months Ended September 30,
	2017			2018
Dividend yield		—	%		—	%
Volatility		42	%		41	%
Risk-free interest rate		1.40	%		2.49	%
Weighted average fair value of awards granted	$	26.21		$	24.85

As of September 30, 2018, there was $24.2 million of unamortized equity-based compensation expense related to unvested PSUs. That expense is expected to be recognized over a weighted average period of approximately 2.1 years.

Antero Midstream Partners Phantom Unit Awards

Phantom units granted by Antero Midstream vest subject to the satisfaction of service requirements, upon the completion of which common units in Antero Midstream are delivered to the holder of the phantom units. Phantom units also contain distribution equivalent rights which entitle the holder of vested common units to receive a “catch up” payment equal to common unit distributions paid by Antero Midstream during the vesting period of the phantom unit award. These phantom units are treated, for accounting purposes, as if Antero Midstream distributed the units to Antero. Antero recognizes compensation expense as the units are granted to its employees, and a portion of the expense is allocated to Antero Midstream. Expense related to each phantom unit award is recognized on a straight-line basis over the requisite service period of the entire award. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period. The grant date fair values of these awards are determined based on the closing price of Antero Midstream’s common units on the date of grant.

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ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2017 and September 30, 2018

A summary of phantom unit awards activity for the nine months ended September 30, 2018 is as follows:


	Number of units	Weighted average grant date fair value		Aggregate intrinsic value (in thousands)
Total awarded and unvested—December 31, 2017	1,042,963	$	28.69	$	30,288
Granted	260,847	$	25.84
Vested	(157,775)	$	27.65
Forfeited	(93,419)	$	28.64
Total awarded and unvested—September 30, 2018	1,052,616	$	28.15	$	30,168

Intrinsic values are based on the closing price of Antero Midstream’s common units on the referenced dates. As of September 30, 2018, there was $16.3 million of unamortized equity-based compensation expense related to unvested phantom unit awards. That expense is expected to be recognized over a weighted average period of approximately 2.5 years.

(10) Financial Instruments

The carrying values of accounts receivable and accounts payable at December 31, 2017 and September 30, 2018 approximated market values because of their short-term nature. The carrying values of the amounts outstanding under the Credit Facility and Midstream Credit Facility at December 31, 2017 and September 30, 2018 approximated fair value because the variable interest rates are reflective of current market conditions.

Based on Level 2 market data inputs, the fair value of Antero’s senior notes was approximately $3.5 billion at December 31, 2017 and September 30, 2018. Based on Level 2 market data inputs, the fair value of Antero Midstream’s senior notes was approximately $670 million at December 31, 2017 and $652 million at September 30, 2018.

See Note 11 for information regarding the fair value of derivative financial instruments.

(11) Derivative Instruments

(a)Commodity Derivative Positions

The Company periodically enters into natural gas, NGLs, and oil derivative contracts with counterparties to hedge the price risk associated with its production. These derivatives are not entered into for trading purposes. To the extent that changes occur in the market prices of natural gas, NGLs, and oil, the Company is exposed to market risk on these open contracts. This market risk exposure is generally offset by the change in market prices of natural gas, NGLs, and oil recognized upon the ultimate sale of the Company’s production.

The Company was party to various fixed price commodity swap contracts that settled during the nine months ended September 30, 2017 and 2018. The Company enters into these swap contracts when management believes that favorable future sales prices for the Company’s production can be secured. Under these swap agreements, when actual commodity prices upon settlement exceed the fixed price provided by the swap contracts, the Company pays the difference to the counterparty. When actual commodity prices upon settlement are less than the contractually provided fixed price, the Company receives the difference from the counterparty.

The Company’s derivative swap contracts have not been designated as hedges for accounting purposes; therefore, all gains and losses are recognized in the Company’s statements of operations.

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ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2017 and September 30, 2018

As of September 30, 2018, the Company’s fixed price natural gas, NGLs, and oil swap positions from July 1, 2018 through December 31, 2023 were as follows (abbreviations in the table refer to the index to which the swap position is tied, as follows: NYMEX=Henry Hub; Mont Belvieu-Propane=Mont Belvieu Propane; NYMEX-WTI=West Texas Intermediate):


	Natural gas MMbtu/day	Oil Bbls/day	Natural Gas Liquids Bbls/day	Weighted average index price
Three months ending December 31, 2018:
NYMEX ($/MMBtu)	2,002,500	—	—	$	3.53
NYMEX-WTI ($/Bbl)	—	6,000	—	$	56.99
Mont Belvieu-Propane ($/Gallon)	—	—	26,000	$	0.77
Total	2,002,500	6,000	26,000
Year ending December 31, 2019:
NYMEX ($/MMBtu)	2,330,000			$	3.50
Year ending December 31, 2020:
NYMEX ($/MMBtu)	1,417,500			$	3.25
Year ending December 31, 2021:
NYMEX ($/MMBtu)	710,000			$	3.00
Year ending December 31, 2022:
NYMEX ($/MMBtu)	850,000			$	3.00
Year ending December 31, 2023:
NYMEX ($/MMBtu)	90,000			$	2.91

(b)Marketing Derivatives

In 2017, due to delay of the in-service date for a pipeline on which the Company is to be an anchor shipper, the Company realized it would not be able to fulfill its delivery obligations under a 2018 natural gas sales contract. In order to acquire gas to fulfill its delivery obligations, the Company entered into several natural gas purchase agreements with index-based pricing to purchase gas for resale under this sales contract. Subsequently, the Company and the counterparty to the sales contract came to an agreement that the Company’s delivery obligations under the contract would not begin until the earlier of (1) the in-service date of the pipeline and (2) January 1, 2019. Consequently, in December 2017, the Company entered into natural gas sales agreements with index-based pricing to resell the purchased gas for delivery during the period from February to October 2018. The natural gas that it had purchased for January was sold on the spot market during January. As a result of severe cold weather in the local area in January resulting in wide basis premiums at the index for these contracts, the Company realized a cash gain on these contracts of $78.1 million during the nine months ended September 30, 2018.

The Company determined that these gas purchase and sales agreements should be accounted for as derivatives and measured at fair value at the end of each period. The Company recognized a loss in the fourth quarter of 2017 of $21.4 million. For the three and nine months ended September 30, 2018, the Company recognized a net gain (loss) of less than ($0.1) million and $94.1 million, respectively. The estimated fair value of these contracts of $5.4 million at September 30, 2018 is included in current Derivative liabilities on the Company’s unaudited condensed consolidated balance sheet, and will be recognized as cash settled losses in October 2018.

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ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2017 and September 30, 2018

(c)Summary

The following table presents a summary of the fair values of the Company’s derivative instruments and where such values are recorded in the consolidated balance sheets as of December 31, 2017 and September 30, 2018. None of the Company’s derivative instruments are designated as hedges for accounting purposes.


	December 31, 2017			September 30, 2018
	Balance sheet location	Fair value		Balance sheet location	Fair value
		(In thousands)			(In thousands)
Asset derivatives not designated as hedges for accounting purposes:
Commodity derivatives - current	Derivative instruments	$	460,685	Derivative instruments	$	493,354
Commodity derivatives - noncurrent	Derivative instruments		841,257	Derivative instruments		672,768

Total asset derivatives			1,301,942			1,166,122

Liability derivatives not designated as hedges for accounting purposes:
Marketing derivatives - current	Derivative instruments		21,394	Derivative instruments		5,411
Commodity derivatives - current	Derivative instruments		7,082	Derivative instruments		5,045
Commodity derivatives - noncurrent	Derivative instruments		207	Derivative instruments		—

Total liability derivatives			28,683			10,456

Net derivatives		$	1,273,259		$	1,155,666

The following table presents the gross values of recognized derivative assets and liabilities, the amounts offset under master netting arrangements with counterparties, and the resulting net amounts presented in the consolidated balance sheets as of the dates presented, all at fair value (in thousands):


	December 31, 2017						September 30, 2018
	Gross amounts on balance sheet		Gross amounts offset on balance sheet		Net amounts of assets on balance sheet		Gross amounts on balance sheet		Gross amounts offset on balance sheet		Net amounts of assets (liabilities) on balance sheet
Commodity derivative assets	$	1,367,554		(65,612)		1,301,942	$	1,214,248		(48,126)		1,166,122
Commodity derivative liabilities	$	(72,901)		65,612		(7,289)	$	(53,171)		48,126		(5,045)
Marketing derivative assets	$	311,083		(311,083)		—	$	—		—		—
Marketing derivative liabilities	$	(332,477)		311,083		(21,394)	$	(5,411)		—		(5,411)

The following is a summary of derivative fair value gains and losses and where such values are recorded in the unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2017 and 2018 (in thousands):


	Statement of operations	Three months ended September 30,				Nine months ended September 30,
	location	2017		2018		2017		2018
Commodity derivative fair value gains (losses)	Revenue	$	(65,957)		57,019	$	458,459		134,793
Marketing derivative fair value gains (losses)	Revenue	$	—		(42)	$	—		94,081

The fair value of derivative instruments was determined using Level 2 inputs.

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ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2017 and September 30, 2018

(12) Commitments

The table below is a schedule of future minimum payments for firm transportation, drilling rig and completion services, processing, gathering and compression, and office and equipment agreements, as well as leases that have remaining lease terms in excess of one year as of September 30, 2018 (in millions).


	Firm transportation		Processing, gathering and compression		Drilling rigs and completion services		Office and equipment
(in millions)	(a)		(b)		(c)		(d)		Total
Remainder of 2018	$	230		155		29		4		418
2019		1,087		360		92		14		1,553
2020		1,107		397		30		13		1,547
2021		1,086		382		5		11		1,484
2022		1,034		378		—		9		1,421
2023		1,022		369		—		7		1,398
Thereafter		8,690		1,670		—		49		10,409
Total	$	14,256		3,711		156		107		18,230

(a) Firm Transportation

The Company has entered into firm transportation agreements with various pipelines in order to facilitate the delivery of its production to market. These contracts commit the Company to transport minimum daily natural gas or NGLs volumes at negotiated rates, or pay for any deficiencies at specified reservation fee rates. The amounts in this table are based on the Company’s minimum daily volumes at the reservation fee rate. The values in the table represent the gross amounts that the Company is committed to pay; however, the Company will record in the consolidated financial statements its proportionate share of costs based on its working interest.

(b) Processing, Gathering, and Compression Service Commitments

The Company has entered into various long‑term gas processing agreements for certain of its production that will allow it to realize the value of its NGLs. The minimum payment obligations under the agreements are presented in the table.

The Company has various gathering and compression service agreements with third parties that provide for payments based on volumes gathered or compressed. The minimum payment obligations under these agreements are presented in the table.

The values in the table represent the gross amounts that the Company is committed to pay; however, the Company will record in the consolidated financial statements its proportionate share of costs based on its working interest. The values in the table also include minimum processing fees to be paid to the Joint Venture owned by Antero Midstream and MarkWest, and Antero Midstream’s commitments for the construction of its advanced wastewater treatment facility, which was placed in service in May 2018 but has not yet had a significant impact on the financial results of the water handling and treatment segment as a result of delays in reaching contracted treatment capacity. The table does not include intracompany commitments. Future capital contributions to unconsolidated affiliates are excluded from the table as neither the amounts nor the timing of the obligations can be determined in advance.

The Company has obligations under agreements with service providers to procure drilling rigs and completion services. The values in the table represent the gross amounts that the Company is committed to pay; however, the Company will record in the consolidated financial statements its proportionate share of costs based on its working interest.

(d) Office and Equipment Leases

The Company leases various office space and equipment under capital and operating lease arrangements.

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ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2017 and September 30, 2018

(13) Contingencies

SJGC

The Company is the plaintiff in two lawsuits against South Jersey Gas Company and South Jersey Resources Group, LLC (collectively, “SJGC”) pending in United States District Court in Colorado. In March 2015, the Company filed suit against SJGC seeking relief for breach of contract and damages in the amounts that SJGC had short paid, and continued to short pay, the Company in connection with two nearly identical long term gas contracts. Under those contracts, SJGC are long term purchasers of 80,000 MMBtu/day of the Company’s natural gas production. Deliveries under the contracts began in October 2011 and the term of the contracts continues through October 2019. The price for gas was based on specified indices in the contracts. Beginning in October 2014, SJGC began short paying the Company based on price indices unilaterally selected by SJGC and not the applicable index specified in the contracts. SJGC claimed that the index price specified in the contracts, and the index at which SJGC paid for deliveries from 2011 through September 2014, was no longer appropriate under the contracts because a market disruption event (as defined by the contract) had occurred and, as a result, a new index price was required to be determined by the parties. The Company rejected SJGC’s contention that a market disruption event occurred. SJGC’s actions constituted a breach of the contracts by failing to pay the Company based on the express price terms of the contracts and paying the Company based on unilaterally selected price indices in violation of the contracts’ remedial provisions. On May 8, 2017, a jury in the United States District Court in Colorado returned a unanimous verdict finding in favor of Antero’s positions in the lawsuit against SJGC. On July 21, 2017, final judgment on the jury’s unanimous verdict was entered by the court. On August 18, 2017, SJGC filed post-judgment motions with the court. On March 23, 2018, the court denied SJGC’s post-judgment motions. On April 20, 2018, SJGC appealed the final judgment to the United States Court of Appeals for the Tenth Circuit and the appeal remains pending.

Subsequent to the entry of judgment, SJGC has continued to short pay the Company on the basis of unilaterally selected price indices and not the index specified in the contract. Accordingly, on December 21, 2017, Antero filed suit against SJGC to recover for its damages since March of 2017. The second lawsuit remains pending.

Through September 30, 2018, the Company estimates that it is owed approximately $82 million (gross damages, including interest) more than SJGC has paid using the indices unilaterally selected by them. Substantially all of this amount has not been accrued in the Company’s financial statements. The Company will vigorously seek recovery from SJGC of all underpayments and damages, including interest, based on the contracted price.

WGL

The Company and Washington Gas Light Company and WGL Midstream, Inc. (collectively, “WGL”) were involved in a pricing dispute involving firm gas sales contracts executed June 20, 2014 (the “Contracts”) that the Company began delivering gas under in January 2016. From January 2016 through July 2017 and from December 2017 through January 2018, the aggregate daily gas volumes contracted for under the Contracts was 500,000 MMBtu/day, with the aggregate daily contracted volumes having increased to 600,000 MMBtu/day from August through November 2017. The Company invoiced WGL based on the natural gas index price specified in the Contracts and WGL paid the Company based on that invoice price. However, WGL asserted that the index price was no longer appropriate under the Contracts and claimed that an undefined alternative index was more appropriate for the delivery point of the gas. In July 2016, the matter was referred to arbitration by the Colorado district court. In January 2017, the arbitration panel ruled in the Company’s favor. As a result, the index price has remained as specified in the Contracts and there will be no adjustments to the invoices that have been paid by WGL, nor will future invoices to WGL be adjusted based on the same claim rejected by the arbitration panel. The arbitration panel’s award was confirmed by the Colorado district court on April 14, 2017.

In March of 2017, WGL filed a second legal proceeding against the Company in Colorado district court alleging breach of contract and seeking damages of more than $30 million. In this lawsuit, WGL claimed that the Company breached its contractual obligations under the Contracts by failing to deliver “TCO pool” gas. In subsequent filings, WGL explained that its claims were based on an alleged obligation that the Company must deliver gas to the Columbia IPP Pool (“IPP Pool”). WGL asserted this exact same issue in the arbitration and it was rejected by the arbitration panel. The arbitration panel specifically found that the Delivery Point under the Contracts was at a specific point in Braxton, West Virginia, not the IPP Pool. On August 24, 2017, the Colorado district court dismissed with prejudice WGL’s claims against the Company in its new lawsuit and found that the Company had not breached its Contracts with WGL by allegedly failing to deliver to the IPP Pool. The Court also reaffirmed the arbitration panel’s finding that the delivery point under the Contracts was not the IPP Pool. The Court dismissed WGL’s lawsuit because WGL had not adequately

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ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2017 and September 30, 2018

pled a claim against Antero for the alleged failure to deliver “TCO pool” gas under the Contracts. WGL appealed this decision to the Colorado Court of Appeals and on October 11, 2018 the Colorado Court of Appeals reversed the Colorado district court’s decision finding that WGL had adequately pled a claim for relief and remanded the case back to the district court for further proceedings. The Colorado Court of Appeals did not address the issue of whether WGL’s claims were independently barred by the prior arbitration’s findings.

The Company is also actively engaged in pursuing cover damages against WGL based on WGL’s failure to take receipt of all of the agreed quantities of gas required under the Contracts. WGL’s failure to take the gas volumes specified in the Contracts is directly related to WGL’s lack of primary firm transportation rights at the Delivery Point. The failures by WGL to take the full contracted volumes gas began in April 2017 and continued each month through December 2017 in varying quantities. In defense of its conduct, WGL has asserted to the Company that their failure to receive gas is excused by (1) the Company’s failure to deliver gas to the IPP Pool or (2) alleged instances of Force Majeure under the Contracts. However, as stated above, the alleged obligation that the Company must deliver gas to the IPP Pool was already rejected by the arbitration panel. Further, the Contracts expressly prohibit a Force Majeure claim in circumstances in which the gas purchaser does not have primary firm transportation agreements in place to transport the purchased gas. In each instance that WGL has failed to receive the quantity of gas required under the Contracts, the Company has resold the quantities not taken and invoiced WGL for cover damages pursuant to the terms of the Contracts. WGL has refused to pay for the invoiced cover damages as required by the Contracts and has also short paid the Company for, among other things, certain amounts of gas received by WGL. Through September 30, 2018, these damages amounted to approximately $105 million (gross damages, including interest). This amount has not been accrued in the Company’s financial statements. The Company is currently pursuing its cover damages in a lawsuit filed in Colorado district court on October 24, 2017. The Company will continue to vigorously seek recovery of its cover damages and other unpaid amounts, including interest, as part of its claims against WGL.

Effective February 1, 2018, as a result of a recent amendment to its firm gas sales contract with WGL Midstream, Inc. that was executed on December 28, 2017, the total aggregate volumes to be delivered to WGL at the delivery point in Braxton, West Virginia were reduced from 500,000 MMBtu/day to 200,000 MMBtu/day. Upon both (1) the in service of the Dominion Cove Point LNG facility and (2) the earlier of in service of the WB East expansion and January 1, 2019, the aggregate contract volumes to be delivered to WGL will increase by 330,000 MMBtu/day. The additional 330,000 MMBtu/day will be delivered to WGL at a delivery point in Loudoun County, Virginia. This increase will be in effect for the remaining term of our gas sale contract with WGL Midstream, which expires in 2038, and these increased volumes will be subject to NYMEX-based pricing. Following the increase of 330,000 MMBtu/day, the aggregate contract volumes to be delivered to WGL will total 530,000 MMBtu/day.

Other

The Company is party to various other legal proceedings and claims in the ordinary course of its business. The Company believes that certain of these matters will be covered by insurance and that the outcome of other matters will not have a material adverse effect on the Company’s consolidated financial position, results of operations, or cash flows.

(14) Related Parties

Certain of the Company’s shareholders, including members of its executive management group, own a significant interest in the Company and, either through their representatives or directly, serve as members of the Board of Directors of Antero and the Boards of Directors of the general partners of Antero Midstream and AMGP. These same groups or individuals own limited partner interests in Antero Midstream and common shares and other interests in AMGP, which indirectly owns the incentive distribution rights in Antero Midstream. Antero’s executive management group also manages the operations and business affairs of Antero Midstream and AMGP.

Antero Midstream’s operations comprise substantially all of the operations of our gathering and processing segment and our water handling and treatment segment. Substantially all of the revenues for those segments in the three and nine months ended September 30, 2017 and 2018 were derived from transactions with Antero. See Note 15 for the operating results of the Company’s reportable segments.

(15) Segment Information

See Note 2(i) for a description of the Company’s determination of its reportable segments. Revenues from gathering and processing and water handling and treatment operations are primarily derived from intersegment transactions for services provided to

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ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2017 and September 30, 2018

the Company’s exploration and production operations. Marketing revenues are primarily derived from activities to purchase and sell third-party natural gas and NGLs and to market excess firm transportation capacity to third parties.

Operating segments are evaluated based on their contribution to consolidated results, which is primarily determined by the respective operating income of each segment. General and administrative expenses are allocated to the gathering and processing and water handling and treatment segments based on the nature of the expenses and on a combination of the segments’ proportionate share of the Company’s consolidated property and equipment, capital expenditures, and labor costs, as applicable. General and administrative expenses related to the marketing segment are not allocated because they are immaterial. Other income, income taxes, and interest expense are primarily managed and evaluated on a consolidated basis. Intersegment sales are transacted at prices which approximate market. Accounting policies for each segment are the same as the Company’s accounting policies described in Note 2 to the unaudited condensed consolidated financial statements.

The operating results and assets of the Company’s reportable segments were as follows for the three months ended September 30, 2017 and 2018 (in thousands):


	Exploration and production		Gathering and processing	Water handling and treatment	Marketing	Elimination of intersegment transactions	Consolidated total
Three months ended September 30, 2017:
Sales and revenues:
Third-party	$	594,244	2,609	260	50,767	—	647,880
Intersegment		3,070	97,909	92,851	—	(193,830)	—
Total	$	597,314	100,518	93,111	50,767	(193,830)	647,880

Operating expenses:
Lease operating	$	24,060	—	51,569	—	(52,138)	23,491
Gathering, compression, processing, and transportation		369,538	10,468	—	—	(97,872)	282,134
Impairment of unproved properties		41,000	—	—	—	—	41,000
Depletion, depreciation, and amortization		176,188	22,027	8,753	—	—	206,968
General and administrative		48,289	9,336	4,980	—	(402)	62,203
Other		24,259	92	3,457	78,884	(2,556)	104,136
Total		683,334	41,923	68,759	78,884	(152,968)	719,932
Operating income (loss)	$	(86,020)	58,595	24,352	(28,117)	(40,862)	(72,052)
Equity in earnings of unconsolidated affiliates	$	—	7,033	—	—	—	7,033
Segment assets	$	12,751,606	2,158,107	752,982	15,807	(829,288)	14,849,214
Capital expenditures for segment assets	$	413,742	99,254	48,019	—	(39,358)	521,657

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ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2017 and September 30, 2018


	Exploration and production		Gathering and processing	Water handling and treatment	Marketing	Elimination of intersegment transactions	Consolidated total
Three months ended September 30, 2018:
Sales and revenues:
Third-party	$	982,131	4,441	404	89,556	—	1,076,532
Intersegment		5,197	128,761	132,599	—	(266,557)	—
Total	$	987,328	133,202	133,003	89,556	(266,557)	1,076,532

Operating expenses:
Lease operating	$	35,124	—	67,608	—	(66,463)	36,269
Gathering, compression, processing, and transportation		442,602	12,131	570	—	(128,799)	326,504
Impairment of unproved properties		221,094	—	—	—	—	221,094
Impairment of gathering systems and facilities		—	1,157	—	—	—	1,157
Depletion, depreciation, and amortization		204,465	26,095	12,626	—	—	243,186
General and administrative		45,474	11,783	3,235	—	(632)	59,860
Other		30,695	186	5,033	151,764	(4,020)	183,658
Total		979,454	51,352	89,072	151,764	(199,914)	1,071,728
Operating income (loss)	$	7,874	81,850	43,931	(62,208)	(66,643)	4,804
Equity in earnings of unconsolidated affiliates	$	—	10,705	—	—	—	10,705
Segment assets	$	13,484,457	2,367,855	1,043,641	20,481	(1,113,899)	15,802,535
Capital expenditures for segment assets	$	485,219	130,695	19,258	—	(67,951)	567,221

The operating results and assets of the Company’s reportable segments were as follows for the nine months ended September 30, 2017 and 2018 (in thousands):


	Exploration and production		Gathering and processing	Water handling and treatment	Marketing	Elimination of intersegment transactions	Consolidated total
Nine months ended September 30, 2017:
Sales and revenues:
Third-party	$	2,458,524	7,472	1,193	166,659	—	2,633,848
Intersegment		11,421	283,467	270,033	—	(564,921)	—
Total	$	2,469,945	290,939	271,226	166,659	(564,921)	2,633,848

Operating expenses:
Lease operating	$	56,991	—	131,635	—	(132,592)	56,034
Gathering, compression, processing, and transportation		1,070,522	28,492	—	—	(283,304)	815,710
Impairment of unproved properties		83,098	—	—	—	—	83,098
Depletion, depreciation, and amortization		521,603	64,445	24,831	—	—	610,879
General and administrative		148,876	30,179	13,383	—	(1,438)	191,000
Other		75,030	104	12,333	246,298	(9,672)	324,093
Total		1,956,120	123,220	182,182	246,298	(427,006)	2,080,814
Operating income (loss)	$	513,825	167,719	89,044	(79,639)	(137,915)	553,034
Equity in earnings of unconsolidated affiliates	$	—	12,887	—	—	—	12,887
Segment assets	$	12,751,606	2,158,107	752,982	15,807	(829,288)	14,849,214
Capital expenditures for segment assets	$	1,455,168	254,619	143,470	—	(135,718)	1,717,539

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ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2017 and September 30, 2018


	Exploration and production		Gathering and processing	Water handling and treatment	Marketing	Elimination of intersegment transactions	Consolidated total
Nine months ended September 30, 2018:
Sales and revenues:
Third-party	$	2,590,409	12,849	2,450	488,270	—	3,093,978
Intersegment		16,251	347,249	384,224	—	(747,724)	—
Total	$	2,606,660	360,098	386,674	488,270	(747,724)	3,093,978

Operating expenses:
Lease operating	$	98,698	—	184,698	—	(190,241)	93,155
Gathering, compression, processing, and transportation		1,236,655	35,899	570	—	(346,896)	926,228
Impairment of unproved properties		406,068	—	—	—	—	406,068
Impairment of gathering systems and facilities		—	9,658	—	—	—	9,658
Depletion, depreciation, and amortization		601,446	74,215	33,819	—	—	709,480
General and administrative		138,555	34,140	10,827	—	(1,946)	181,576
Other		85,067	204	14,925	560,924	(11,841)	649,279
Total		2,566,489	154,116	244,839	560,924	(550,924)	2,975,444
Operating income (loss)	$	40,171	205,982	141,835	(72,654)	(196,800)	118,534
Equity in earnings of unconsolidated affiliates	$	—	27,832	—	—	—	27,832
Segment assets	$	13,484,457	2,367,855	1,043,641	20,481	(1,113,899)	15,802,535
Capital expenditures for segment assets	$	1,464,041	337,448	77,385	—	(202,629)	1,676,245

(16) Subsidiary Guarantors

Each of Antero’s wholly-owned subsidiaries has fully and unconditionally guaranteed Antero’s senior notes. Antero Midstream and its subsidiaries have been designated as unrestricted subsidiaries under the Credit Facility and the indentures governing Antero’s senior notes, and do not guarantee any of Antero’s obligations (see Note 7). In the event a subsidiary guarantor is sold or disposed of (whether by merger, consolidation, the sale of a sufficient amount of its capital stock so that it no longer qualifies as a “Subsidiary” of the Company (as defined in the indentures governing the notes) or the sale of all or substantially all of its assets (other than by lease)) and whether or not the subsidiary guarantor is the surviving entity in such transaction to a person which is not Antero or a restricted subsidiary of Antero, such subsidiary guarantor will be released from its obligations under its subsidiary guarantee if the sale or other disposition does not violate the covenants set forth in the indentures governing the notes.

In addition, a subsidiary guarantor will be released from its obligations under the indentures and its guarantee, upon the release or discharge of the guarantee of other Indebtedness (as defined in the indentures governing the notes) that resulted in the creation of such guarantee, except a release or discharge by or as a result of payment under such guarantee; if Antero designates such subsidiary as an unrestricted subsidiary and such designation complies with the other applicable provisions of the indentures governing the notes or in connection with any covenant defeasance, legal defeasance or satisfaction and discharge of the notes.

The following Condensed Consolidating Balance Sheets at December 31, 2017 and September 30, 2018, and the related Condensed Consolidating Statements of Operations and Comprehensive Income (Loss) for the three and nine months ended September 30, 2017 and 2018 and Condensed Consolidating Statements of Cash Flows for the nine months ended September 30, 2017 and 2018 present financial information for Antero on a stand-alone basis (carrying its investment in subsidiaries using the equity method), financial information for the subsidiary guarantors, financial information for the non-guarantor subsidiaries, and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis. Antero’s wholly-owned subsidiaries are not restricted from making distributions to the Parent.

Distributions received by Antero from Antero Midstream have been reclassified from investing activities to operating activities on the Condensed Consolidating Statement of Cash Flows for the nine months ended September 30, 2017. The reclassification is a result of the adoption of ASU No. 2016-05, Classification of Certain Cash Receipts and Cash Payments, which

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ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2017 and September 30, 2018

provides for an accounting policy election to account for distributions received from equity method investees under the “nature of distribution” approach.

Condensed Consolidating Balance Sheet

December 31, 2017

(In thousands)


	Parent (Antero)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries (Antero Midstream)		Eliminations		Consolidated
Assets
Current assets:
Cash and cash equivalents	$	20,078		—		8,363		—		28,441
Accounts receivable, net		33,726		—		1,170		—		34,896
Intercompany receivables		6,459		—		110,182		(116,641)		—
Accrued revenue		300,122		—		—		—		300,122
Derivative instruments		460,685		—		—		—		460,685
Other current assets		8,273		—		670		—		8,943
Total current assets		829,343		—		120,385		(116,641)		833,087
Property and equipment:
Natural gas properties, at cost (successful efforts method):
Unproved properties		2,266,673		—		—		—		2,266,673
Proved properties		11,460,615		—		—		(364,153)		11,096,462
Water handling and treatment systems		—		—		942,361		4,309		946,670
Gathering systems and facilities		17,929		—		2,032,561		—		2,050,490
Other property and equipment		57,429		—		—		—		57,429
		13,802,646		—		2,974,922		(359,844)		16,417,724
Less accumulated depletion, depreciation, and amortization		(2,812,851)		—		(369,320)		—		(3,182,171)
Property and equipment, net		10,989,795		—		2,605,602		(359,844)		13,235,553
Derivative instruments		841,257		—		—		—		841,257
Investments in subsidiaries		(573,926)		—		—		573,926		—
Contingent acquisition consideration		208,014		—		—		(208,014)		—
Investments in unconsolidated affiliates		—		—		303,302		—		303,302
Other assets		35,371		—		12,920		—		48,291
Total assets	$	12,329,854		—		3,042,209		(110,573)		15,261,490

Liabilities and Equity
Current liabilities:
Accounts payable	$	54,340		—		8,642		—		62,982
Intercompany payable		110,182		—		6,459		(116,641)		—
Accrued liabilities		338,819		—		106,006		(1,600)		443,225
Revenue distributions payable		209,617		—		—		—		209,617
Derivative instruments		28,476		—		—		—		28,476
Other current liabilities		17,587		—		209		—		17,796
Total current liabilities		759,021		—		121,316		(118,241)		762,096
Long-term liabilities:
Long-term debt		3,604,090		—		1,196,000		—		4,800,090
Deferred income tax liability		779,645		—		—		—		779,645
Contingent acquisition consideration		—		—		208,014		(208,014)		—
Derivative instruments		207		—		—		—		207
Other liabilities		42,906		—		410		—		43,316
Total liabilities		5,185,869		—		1,525,740		(326,255)		6,385,354
Equity:
Stockholders' equity:
Partners' capital		—		—		1,516,469		(1,516,469)		—
Common stock		3,164		—		—		—		3,164
Additional paid-in capital		5,565,756		—		—		1,005,196		6,570,952
Accumulated earnings		1,575,065		—		—		—		1,575,065
Total stockholders' equity		7,143,985		—		1,516,469		(511,273)		8,149,181
Noncontrolling interests in consolidated subsidiary		—		—		—		726,955		726,955
Total equity		7,143,985		—		1,516,469		215,682		8,876,136
Total liabilities and equity	$	12,329,854		—		3,042,209		(110,573)		15,261,490

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ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2017 and September 30, 2018

Condensed Consolidating Balance Sheet

September 30, 2018

(In thousands)


	Parent (Antero)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries (Antero Midstream)		Eliminations		Consolidated
Assets
Current assets:
Accounts receivable, net		—		—		115,905		(115,905)		—
Intercompany receivables		30,018		—		16,586		—		46,604
Accrued revenue		354,010		—		—		—		354,010
Derivative instruments		493,354		—		—		—		493,354
Other current assets		11,190		—		1,474		—		12,664
Total current assets		888,572		—		133,965		(115,905)		906,632
Property and equipment:
Natural gas properties, at cost (successful efforts method):
Unproved properties		1,928,990		—		—		—		1,928,990
Proved properties		12,871,199		—		—		(565,001)		12,306,198
Water handling and treatment systems		—		—		984,225		9,060		993,285
Gathering systems and facilities		17,824		—		2,366,217		—		2,384,041
Other property and equipment		62,666		—		73		—		62,739
		14,880,679		—		3,350,515		(555,941)		17,675,253
Less accumulated depletion, depreciation, and amortization		(3,414,193)		—		(476,641)		—		(3,890,834)
Property and equipment, net		11,466,486		—		2,873,874		(555,941)		13,784,419
Derivative instruments		672,768		—		—		—		672,768
Investments in subsidiaries		(756,785)		—		—		756,785		—
Contingent acquisition consideration		219,855		—		—		(219,855)		—
Investments in unconsolidated affiliates		—		—		392,893		—		392,893
Other assets		31,727		—		14,096		—		45,823
Total assets	$	12,522,623		—		3,414,828		(134,916)		15,802,535

Liabilities and Equity
Current liabilities:
Accounts payable	$	76,284		—		15,656		—		91,940
Intercompany payable		112,147		—		3,758		(115,905)		—
Accrued liabilities		368,958		—		88,258		—		457,216
Revenue distributions payable		245,832		—		—		—		245,832
Derivative instruments		10,456		—		—		—		10,456
Other current liabilities		6,735		—		215		1,477		8,427
Total current liabilities		820,412		—		107,887		(114,428)		813,871
Long-term liabilities:
Long-term debt		3,970,150		—		1,516,854		—		5,487,004
Deferred income tax liability		782,145		—		—		—		782,145
Contingent acquisition consideration		—		—		219,855		(219,855)		—
Other liabilities		42,693		—		5,670		—		48,363
Total liabilities		5,615,400		—		1,850,266		(334,283)		7,131,383
Equity:
Stockholders' equity:
Partners' capital		—		—		1,564,562		(1,564,562)		—
Common stock		3,171		—		—		—		3,171
Additional paid-in capital		5,604,958		—		—		1,006,390		6,611,348
Accumulated earnings		1,299,094		—		—		—		1,299,094
Total stockholders' equity		6,907,223		—		1,564,562		(558,172)		7,913,613
Noncontrolling interests in consolidated subsidiary		—		—		—		757,539		757,539
Total equity		6,907,223		—		1,564,562		199,367		8,671,152
Total liabilities and equity	$	12,522,623		—		3,414,828		(134,916)		15,802,535

Table of Contents

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2017 and September 30, 2018

Condensed Consolidating Statement of Operations and Comprehensive Income

Three Months Ended September 30, 2017

(In thousands)


	Parent (Antero)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries (Antero Midstream)		Eliminations		Consolidated
Revenue and other:
Natural gas sales	$	409,141		—		—		—		409,141
Natural gas liquids sales		224,533		—		—		—		224,533
Oil sales		26,527		—		—		—		26,527
Commodity derivative fair value losses		(65,957)		—		—		—		(65,957)
Gathering, compression, water handling and treatment		—		—		193,629		(190,760)		2,869
Marketing		50,767		—		—		—		50,767
Other income		3,070		—		—		(3,070)		—
Total revenue		648,081		—		193,629		(193,830)		647,880
Operating expenses:
Lease operating		24,060		—		51,569		(52,138)		23,491
Gathering, compression, processing, and transportation		369,538		—		10,468		(97,872)		282,134
Production and ad valorem taxes		22,002		—		993		—		22,995
Marketing		78,884		—		—		—		78,884
Exploration		1,599		—		—		—		1,599
Impairment of unproved properties		41,000		—		—		—		41,000
Depletion, depreciation, and amortization		176,412		—		30,556		—		206,968
Accretion of asset retirement obligations		658		—		—		—		658
General and administrative		48,289		—		14,316		(402)		62,203
Accretion of contingent acquisition consideration		—		—		2,556		(2,556)		—
Total operating expenses		762,442		—		110,458		(152,968)		719,932
Operating income (loss)		(114,361)		—		83,171		(40,862)		(72,052)
Other income (expenses):
Equity in earnings of unconsolidated affiliates		—		—		7,033		—		7,033
Interest		(60,906)		—		(9,311)		158		(70,059)
Equity in earnings (loss) of consolidated subsidiaries		(4,874)		—		—		4,874		—
Total other expenses		(65,780)		—		(2,278)		5,032		(63,026)
Income (loss) before income taxes		(180,141)		—		80,893		(35,830)		(135,078)
Provision for income tax benefit		45,078		—		—		—		45,078
Net income (loss) and comprehensive income (loss) including noncontrolling interests		(135,063)		—		80,893		(35,830)		(90,000)
Net income and comprehensive income attributable to noncontrolling interests		—		—		—		45,063		45,063
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$	(135,063)		—		80,893		(80,893)		(135,063)

Table of Contents

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2017 and September 30, 2018

Condensed Consolidating Statement of Operations and Comprehensive Income

Three Months Ended September 30, 2018

(In thousands)


	Parent (Antero)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries (Antero Midstream)		Eliminations		Consolidated
Revenue and other:
Natural gas sales	$	527,122		—		—		—		527,122
Natural gas liquids sales		338,269		—		—		—		338,269
Oil sales		59,722		—		—		—		59,722
Commodity derivative fair value gains		57,019		—		—		—		57,019
Gathering, compression, water handling and treatment		—		—		266,205		(261,361)		4,844
Marketing		89,598		—		—		—		89,598
Marketing derivative losses		(42)		—		—		—		(42)
Other income		5,327		—		—		(5,327)		—
Total revenue		1,077,015		—		266,205		(266,688)		1,076,532
Operating expenses:
Lease operating		35,124		—		67,608		(66,463)		36,269
Gathering, compression, processing, and transportation		442,602		—		12,701		(128,799)		326,504
Production and ad valorem taxes		29,352		—		1,166		—		30,518
Marketing		151,764		—		—		—		151,764
Exploration		666		—		—		—		666
Impairment of unproved properties		221,094		—		—		—		221,094
Impairment of gathering systems and facilities		—		—		1,157		—		1,157
Depletion, depreciation, and amortization		204,730		—		38,456		—		243,186
Accretion of asset retirement obligations		677		—		33		—		710
General and administrative		45,477		—		15,015		(632)		59,860
Accretion of contingent acquisition consideration		—		—		4,020		(4,020)		—
Total operating expenses		1,131,486		—		140,156		(199,914)		1,071,728
Operating income (loss)		(54,471)		—		126,049		(66,774)		4,804
Other income (expenses):
Equity in earnings of unconsolidated affiliates		—		—		10,705		—		10,705
Interest		(57,632)		—		(16,989)		93		(74,528)
Equity in earnings (loss) of consolidated subsidiaries		(23,363)		—		—		23,363		—
Total other expenses		(80,995)		—		(6,284)		23,456		(63,823)
Income (loss) before income taxes		(135,466)		—		119,765		(43,318)		(59,019)
Provision for income tax expense		(18,953)		—		—		—		(18,953)
Net income (loss) and comprehensive income (loss) including noncontrolling interests		(154,419)		—		119,765		(43,318)		(77,972)
Net income and comprehensive income attributable to noncontrolling interests		—		—		—		76,447		76,447
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$	(154,419)		—		119,765		(119,765)		(154,419)

Table of Contents

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2017 and September 30, 2018

Condensed Consolidating Statement of Operations and Comprehensive Income

Nine Months Ended September 30, 2017

(In thousands)


	Parent (Antero)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries (Antero Midstream)		Eliminations		Consolidated
Revenue and other:
Natural gas sales	$	1,330,062		—		—		—		1,330,062
Natural gas liquids sales		590,004		—		—		—		590,004
Oil sales		79,999		—		—		—		79,999
Commodity derivative fair value gains		458,459		—		—		—		458,459
Gathering, compression, water handling and treatment		—		—		562,165		(553,500)		8,665
Marketing		166,659		—		—		—		166,659
Other income		11,421		—		—		(11,421)		—
Total revenue and other		2,636,604		—		562,165		(564,921)		2,633,848
Operating expenses:
Lease operating		56,991		—		131,635		(132,592)		56,034
Gathering, compression, processing, and transportation		1,070,522		—		28,492		(283,304)		815,710
Production and ad valorem taxes		67,576		—		2,765		—		70,341
Marketing		246,298		—		—		—		246,298
Exploration		5,510		—		—		—		5,510
Impairment of unproved properties		83,098		—		—		—		83,098
Depletion, depreciation, and amortization		522,275		—		88,604		—		610,879
Accretion of asset retirement obligations		1,944		—		—		—		1,944
General and administrative		148,876		—		43,562		(1,438)		191,000
Accretion of contingent acquisition consideration		—		—		9,672		(9,672)		—
Total operating expenses		2,203,090		—		304,730		(427,006)		2,080,814
Operating income		433,514		—		257,435		(137,915)		553,034
Other income (expenses):
Equity in earnings of unconsolidated affiliates		—		—		12,887		—		12,887
Interest		(178,644)		—		(27,162)		495		(205,311)
Equity in earnings (loss) of consolidated subsidiaries		(21,582)		—		—		21,582		—
Total other expenses		(200,226)		—		(14,275)		22,077		(192,424)
Income before income taxes		233,288		—		243,160		(115,838)		360,610
Provision for income tax expense		(105,087)		—		—		—		(105,087)
Net income and comprehensive income including noncontrolling interests		128,201		—		243,160		(115,838)		255,523
Net income and comprehensive income attributable to noncontrolling interests		—		—		—		127,322		127,322
Net income and comprehensive income attributable to Antero Resources Corporation	$	128,201		—		243,160		(243,160)		128,201

Table of Contents

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2017 and September 30, 2018

Condensed Consolidating Statement of Operations and Comprehensive Income

Nine Months Ended September 30, 2018

(In thousands)


	Parent (Antero)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries (Antero Midstream)		Eliminations		Consolidated
Revenue and other:
Natural gas sales	$	1,498,324		—		—		—		1,498,324
Natural gas liquids sales		828,424		—		—		—		828,424
Oil sales		128,869		—		—		—		128,869
Commodity derivative fair value gains		134,793		—		—		—		134,793
Gathering, compression, water handling and treatment		—		—		746,188		(730,890)		15,298
Marketing		394,189		—		—		—		394,189
Marketing derivative gains		94,081		—		—		—		94,081
Gain on sale of assets		—		—		583		(583)		—
Other income		16,381		—		—		(16,381)		—
Total revenue and other		3,095,061		—		746,771		(747,854)		3,093,978
Operating expenses:
Lease operating		98,698		—		184,698		(190,241)		93,155
Gathering, compression, processing, and transportation		1,236,655		—		36,469		(346,896)		926,228
Production and ad valorem taxes		79,045		—		3,187		—		82,232
Marketing		560,924		—		—		—		560,924
Exploration		4,022		—		—		—		4,022
Impairment of unproved properties		406,068		—		—		—		406,068
Impairment of gathering systems and facilities		4,470		—		5,771		(583)		9,658
Depletion, depreciation, and amortization		602,159		—		107,321		—		709,480
Accretion of asset retirement obligations		2,000		—		101		—		2,101
General and administrative		138,555		—		44,967		(1,946)		181,576
Accretion of contingent acquisition consideration		—		—		11,841		(11,841)		—
Total operating expenses		3,132,596		—		394,355		(551,507)		2,975,444
Operating income (loss)		(37,535)		—		352,416		(196,347)		118,534
Other income (expenses):
Equity in earnings of unconsolidated affiliates		—		—		27,832		—		27,832
Interest		(165,519)		—		(42,913)		129		(208,303)
Equity in earnings (loss) of consolidated subsidiaries		(70,417)		—		—		70,417		—
Total other expenses		(235,936)		—		(15,081)		70,546		(180,471)
Income (loss) before income taxes		(273,471)		—		337,335		(125,801)		(61,937)
Provision for income tax expense		(2,500)		—		—		—		(2,500)
Net income (loss) and comprehensive income (loss) including noncontrolling interests		(275,971)		—		337,335		(125,801)		(64,437)
Net income and comprehensive income attributable to noncontrolling interests		—		—		—		211,534		211,534
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$	(275,971)		—		337,335		(337,335)		(275,971)

Table of Contents

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2017 and September 30, 2018

Condensed Consolidating Statement of Cash Flows

Nine Months Ended September 30, 2017

(In thousands)


	Parent (Antero)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries (Antero Midstream)		Eliminations		Consolidated
Cash flows provided by (used in) operating activities:
Net income including noncontrolling interests	$	128,201		—		243,160		(115,838)		255,523
Adjustment to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, amortization, and accretion		524,219		—		88,604		—		612,823
Accretion of contingent acquisition consideration		(9,672)		—		9,672		—		—
Impairment of unproved properties		83,098		—		—		—		83,098
Commodity derivative fair value gains		(458,459)		—		—		—		(458,459)
Gains on settled commodity derivatives		137,392		—		—		—		137,392
Proceeds from derivative monetizations		749,906		—		—		—		749,906
Deferred income tax expense		105,087		—		—		—		105,087
Equity-based compensation expense		58,489		—		20,436		—		78,925
Equity in earnings of unconsolidated affiliates		21,582		—		—		(21,582)		—
Equity in (earnings) loss of consolidated subsidiaries		—		—		(12,887)		—		(12,887)
Distributions of earnings from unconsolidated affiliates		—		—		10,120		—		10,120
Distributions from Antero Midstream		97,984		—		—		(97,984)		—
Other		(715)		—		1,906		—		1,191
Changes in current assets and liabilities		145,131		—		(16,744)		1,702		130,089
Net cash provided by operating activities		1,582,243		—		344,267		(233,702)		1,692,808
Cash flows used in investing activities:
Additions to proved properties		(179,318)		—		—		—		(179,318)
Additions to unproved properties		(182,207)		—		—		—		(182,207)
Drilling and completion costs		(1,082,226)		—		—		135,718		(946,508)
Additions to water handling and treatment systems		—		—		(143,470)		—		(143,470)
Additions to gathering systems and facilities		—		—		(254,619)		—		(254,619)
Additions to other property and equipment		(11,417)		—		—		—		(11,417)
Investments in unconsolidated affiliates		—		—		(216,776)		—		(216,776)
Change in other assets		(10,271)		—		(5,877)		—		(16,148)
Proceeds from contribution of assets to non-guarantor subsidiary		2,156		—		—		—		2,156
Net cash used in investing activities		(1,463,283)		—		(620,742)		135,718		(1,948,307)
Cash flows provided by (used in) financing activities:
Issuance of common stock		—		—		—		—		—
Issuance of common units by Antero Midstream		—		—		248,949		—		248,949
Sale of common units in Antero Midstream by Antero Resources Corporation		311,100		—		—		—		311,100
Borrowings (repayments) on bank credit facility, net		(415,000)		—		217,000		—		(198,000)
Distributions		—		—		(200,037)		97,984		(102,053)
Employee tax withholding for settlement of equity compensation awards		(7,568)		—		(932)		—		(8,500)
Other		(3,861)		—		(52)		—		(3,913)
Net cash provided by (used in) financing activities		(115,329)		—		264,928		97,984		247,583
Net increase (decrease) in cash and cash equivalents		3,631		—		(11,547)		—		(7,916)
Cash and cash equivalents, beginning of period		17,568		—		14,042		—		31,610
Cash and cash equivalents, end of period	$	21,199		—		2,495		—		23,694

Table of Contents

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2017 and September 30, 2018

Condensed Consolidating Statement of Cash Flows

Nine Months Ended September 30, 2018

(In thousands)


	Parent (Antero)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries (Antero Midstream)		Eliminations		Consolidated
Cash flows provided by (used in) operating activities:
Net income (loss) including noncontrolling interests	$	(275,971)		—		337,335		(125,801)		(64,437)
Adjustment to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, amortization, and accretion		604,159		—		107,422		—		711,581
Accretion of contingent acquisition consideration		(11,841)		—		11,841		—		—
Impairment of unproved properties		406,068		—		—		—		406,068
Impairment of gathering systems and facilities		4,470		—		5,771		(583)		9,658
Commodity derivative fair value gains		(134,793)		—		—		—		(134,793)
Gains on settled commodity derivatives		268,369		—		—		—		268,369
Marketing derivative fair value gains		(94,081)		—		—		—		(94,081)
Gains on settled marketing derivatives		78,098		—		—		—		78,098
Deferred income tax expense		2,500		—		—		—		2,500
Gain on sale of assets		—		—		(583)		583		—
Equity-based compensation expense		39,823		—		16,606		—		56,429
Equity in (earnings) loss of consolidated subsidiaries		70,417		—		—		(70,417)		—
Equity in earnings of unconsolidated affiliates		—		—		(27,832)		—		(27,832)
Distributions of earnings from unconsolidated affiliates		—		—		29,660		—		29,660
Distributions from Antero Midstream		115,678		—		—		(115,678)		—
Other		862		—		2,083		—		2,945
Changes in current assets and liabilities		20,015		—		(10,901)		7,119		16,233
Net cash provided by operating activities		1,093,773		—		471,402		(304,777)		1,260,398
Cash flows used in investing activities:
Additions to unproved properties		(130,381)		—		—		—		(130,381)
Drilling and completion costs		(1,328,289)		—		—		202,629		(1,125,660)
Additions to water handling and treatment systems		—		—		(68,325)		(9,060)		(77,385)
Additions to gathering systems and facilities		175		—		(337,623)		—		(337,448)
Additions to other property and equipment		(5,371)		—		—		—		(5,371)
Investments in unconsolidated affiliates		—		—		(91,419)		—		(91,419)
Change in other assets		(1,810)		—		(865)		—		(2,675)
Other		—		—		4,470		(4,470)		—
Net cash used in investing activities		(1,465,676)		—		(493,762)		189,099		(1,770,339)
Cash flows provided by (used in) financing activities:
Borrowings (repayments) on bank credit facility, net		362,000		—		320,000		—		682,000
Distributions		—		—		(304,453)		115,678		(188,775)
Employee tax withholding for settlement of equity compensation awards		(6,806)		—		(1,399)		—		(8,205)
Other		(3,369)		—		(151)		—		(3,520)
Net cash provided by financing activities		351,825		—		13,997		115,678		481,500
Net decrease in cash and cash equivalents		(20,078)		—		(8,363)		—		(28,441)
Cash and cash equivalents, beginning of period		20,078		—		8,363		—		28,441
Cash and cash equivalents, end of period	$	—		—		—		—		—

Table of Contents

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2017 and September 30, 2018

(17) Subsequent Events

Simplification Agreement

On October 9, 2018, we announced that AMGP, Antero Midstream and certain of their affiliates entered into a Simplification Agreement (as may be amended from time to time, the “Simplification Agreement”), pursuant to which, among other things, (1) AMGP will be converted from a limited partnership to a corporation under the laws of the State of Delaware, to be named Antero Midstream Corporation (which is referred to as “New AM” and the conversion, the “Conversion”); (2) an indirect, wholly owned subsidiary of New AM will be merged with and into Antero Midstream, with Antero Midstream surviving the merger as an indirect, wholly owned subsidiary of New AM (the “Merger”) and (3) all the issued and outstanding Series B Units representing limited liability company interests of Antero IDR Holdings LLC (“IDR Holdings”), a subsidiary of AMGP and the holder of all of Antero Midstream’s incentive distribution rights, will be exchanged for an aggregate of approximately 17.35 million shares of New AM’s common stock (the “Series B Exchange”). The Conversion, the Merger, the Series B Exchange and the other transactions contemplated by the Simplification Agreement are collectively referred to as the “Transactions”. As a result of the Transactions, Antero Midstream will be a wholly owned subsidiary of New AM and former shareholders of AMGP and unitholders of Antero Midstream, including Antero Resources, will each own New AM’s common stock.

We currently own 98,870,335 of Antero Midstream’s common units and will be entitled to receive consideration of $3.00 in cash and 1.6023 shares of New AM’s common stock per Antero Midstream common unit. Public unitholders of Antero Midstream will be entitled to receive a combination of $3.415 in cash and 1.635 shares of New AM’s common stock per Antero Midstream common unit. All public unitholders of Antero Midstream will be entitled to elect to receive their merger consideration in all cash, all stock, or a combination of cash and stock, and we will have the ability to elect to take a larger portion of our merger consideration in cash if the public unitholders of Antero Midstream disproportionately elect to receive stock consideration, subject in each case to proration to ensure that the aggregate amount of cash consideration paid to all Antero Midstream unitholders is an amount equal to the aggregate amount of cash that would have been paid and issued if all public unitholders of Antero Midstream received $3.415 in cash per Antero Midstream common unit and we received $3.00 in cash per unit, which is approximately $598 million and the aggregate amount of equity issuable to all Antero Midstream unitholders is a number of shares of New AM’s common stock equal to the aggregate number of shares that would be issued if all public unitholders of Antero Midstream received 1.635 shares per Antero Midstream common unit and we received 1.6023 shares of New AM’s common stock per Antero Midstream common unit. If we elect to receive only $3.00 in cash per Antero Midstream common unit, we are expected to own approximately 31% of New AM’s common stock following the completion of the Transactions.

The closing of the Transactions is expected in the first quarter of 2019, subject to the satisfaction or waiver of customary closing conditions, including the approval of the Simplification Agreement, the Merger and the other Transactions contemplated thereby, as applicable, by Antero Midstream’s common unitholders and AMGP’s shareholders. AMGP and the Partnership expect to fund the cash portion of the merger consideration with borrowings under Antero Midstream’s revolving credit facility.

Also on October 9, 2018, in connection with the entry into the Simplification Agreement, (1) Antero Midstream entered into a voting agreement with AMGP’s shareholders owning a majority of the outstanding AMGP common shares, pursuant to which, among other things, such shareholders agreed to vote in favor of the Transactions, (2) AMGP entered into a voting agreement with us, pursuant to which, among other things, we agreed to vote in favor of the Transactions and (3) we, AMGP, certain funds affiliated with Warburg Pincus LLC and Yorktown Partners LLC (together, the “Sponsor Holders”), Paul M. Rady and Glen C. Warren, Jr. (Messrs. Rady and Warren together, the “Management Stockholders”) entered into a Stockholders’ Agreement, pursuant to which, among other things, we, the Sponsor Holders and the Management Holders will have the ability to designate members of the New AM board of directors under certain circumstances, effective as the closing of the Transactions.

Share Repurchase Program

Also on October 9, 2018, we announced that our board of directors authorized a share repurchase program under which we may repurchase up to $600 million of our outstanding common stock from time to time through March 31, 2020. This program is expected to be fully funded with cash proceeds from the Merger, as well as free cash flow to be generated over the next 12 to 18 months. The ultimate source of funding for the program, however, will depend on a number of factors, some of which are beyond our control, including but not limited to the timing of completion of the Merger, maintaining our desired leverage targets and our financial conditions and results of operations. If there are significant delays in completing the Transactions, or if we otherwise determine that it

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ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2017 and September 30, 2018

is advisable in light of any of the foregoing factors, we may choose to fund all or a portion of the repurchase program from other sources.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our unaudited condensed consolidated financial statements and related notes included elsewhere in this report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results, and the differences can be material. Some of the key factors that could cause actual results to vary from our expectations include changes in natural gas, NGLs, and oil prices, the timing of planned capital expenditures, our ability to fund our development programs, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Statement Regarding Forward-Looking Statements.” Also, see the risk factors and other cautionary statements described under the heading “Item 1A. Risk Factors.” We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law. For more information, please refer to the Annual Report on Form 10-K for the year ended December 31, 2017 on file with the SEC.

In this section, references to “Antero Resources,” “the Company,” “we,” “us,” and “our” refer to Antero Resources Corporation and its subsidiaries, unless otherwise indicated or the context otherwise requires.

Our Company

Antero Resources Corporation is an independent oil and natural gas company engaged in the exploration, development, and production of natural gas, NGLs, and oil properties located in the Appalachian Basin. We focus on unconventional reservoirs, which can generally be characterized as fractured shale formations. Our management team has worked together for many years and has a successful track record of reserve and production growth as well as significant expertise in unconventional resource plays. Our strategy is to leverage our team’s experience delineating and developing natural gas resource plays to profitably grow our reserves and production, primarily on our existing multi-year inventory of drilling locations.

We have assembled a portfolio of long-lived properties that are characterized by what we believe to be low geologic risk and repeatability. Our drilling opportunities are focused in the Marcellus Shale and Utica Shale of the Appalachian Basin. As of September 30, 2018, we held approximately 610,000 net acres of rich gas and dry gas properties located in the Appalachian Basin in West Virginia and Ohio. Our corporate headquarters are in Denver, Colorado.

We operate in the following industry segments: (i) the exploration, development, and production of natural gas, NGLs, and oil; (ii) gathering and processing; (iii) water handling and treatment; and (iv) marketing and utilization of excess firm transportation capacity. All of our operations are conducted in the United States.

Address, Internet Website and Availability of Public Filings

Our principal executive offices are located at 1615 Wynkoop Street, Denver, Colorado 80202, and our telephone number is (303) 357-7310. Our website is located at www.anteroresources.com.

We furnish or file with the SEC our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, and our Current Reports on Form 8-K. We make these documents available free of charge at www.anteroresources.com under the “Investors Relations” link as soon as reasonably practicable after they are furnished or filed with the SEC.

Information on our website is not incorporated into this Quarterly Report on Form 10-Q or our other filings with the SEC and is not a part of them.

2018 Developments and Highlights

Simplification Agreement

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AMGP will be converted from a limited partnership to a corporation under the laws of the State of Delaware, to be named Antero Midstream Corporation (which is referred to as “New AM” and the conversion, the “Conversion”); (2) an indirect, wholly owned subsidiary of New AM will be merged with and into Antero Midstream, with Antero Midstream surviving the merger as an indirect, wholly owned subsidiary of New AM (the “Merger”) and (3) all the issued and outstanding Series B Units representing limited liability company interests of Antero IDR Holdings LLC (“IDR Holdings”), a subsidiary of AMGP and the holder of all of Antero Midstream’s incentive distribution rights, will be exchanged for an aggregate of approximately 17.35 million shares of New AM’s common stock (the “Series B Exchange”). The Conversion, the Merger, the Series B Exchange and the other transactions contemplated by the Simplification Agreement are collectively referred to as the “Transactions”. As a result of the Transactions, Antero Midstream will be a wholly owned subsidiary of New AM and former shareholders of AMGP and unitholders of Antero Midstream, including Antero Resources, will each own New AM’s common stock.

Share Repurchase Program

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Production and Financial Results

For the three months ended September 30, 2018, our net production totaled 250 Bcfe, or 2,718 MMcfe per day, a 17% increase compared to 213 Bcfe, or 2,317 MMcfe per day, for the three months ended September 30, 2017. Production increases resulted from an increase in the number of producing wells as a result of our drilling and completion activity, offset by some curtailment of production due to oil hauling constraints. Our average price received for production, before the effects of gains on settled commodity derivatives, for the three months ended September 30, 2018 was $3.70 per Mcfe compared to $3.10 per Mcfe for the three months ended September 30, 2017. Our average realized price after the effects of gains on settled commodity derivatives was $3.98 per Mcfe for the three months ended September 30, 2018 compared to $3.39 per Mcfe for the three months ended September 30, 2017.

For the three months ended September 30, 2018, we generated consolidated cash flows from operations of $421 million, a consolidated net loss of $154 million, Adjusted EBITDAX of $498 million, and Stand-Alone Adjusted EBITDAX of $419 million. This compares to consolidated cash flows from operations of $1.0 billion, a consolidated net loss of $135 million, Adjusted EBITDAX of $336 million, and Stand-Alone Adjusted EBITDAX of $284 million for the three months ended September 30, 2017. Consolidated cash flows from operation of $1.0 billion for the three months ended September 30, 2017 included $750 million from hedge monetizations. See “—Non-GAAP Financial Measures” for a definition of Adjusted EBITDAX (a non-GAAP measure) and a reconciliation of Adjusted EBITDAX to net income. See “—Stand-Alone Exploration and Production (E&P) Information” for a definition of Stand-Alone Adjusted EBITDAX and a reconciliation of Stand-Alone Adjusted EBITDAX to Antero’s stand-alone net income. “Stand-Alone” data represents information for Antero on an unconsolidated basis, reflecting Antero’s investment in Antero Midstream under the equity method of accounting.

The consolidated net loss of $154 million for the three months ended September 30, 2018 included (i) commodity derivative fair value gains of $57 million, comprised of gains on settled derivatives of $71 million and a non-cash loss of $14 million on changes in the fair value of unsettled commodity derivatives, (ii) a non-cash charge of $16 million for equity-based compensation, (iii) a non-cash charge of $221 million for impairments of unproved properties, and (iv) a non-cash deferred tax expense of $19 million.

Adjusted EBITDAX increased from $336 million for the three months ended September 30, 2017 to $498 million for the three months ended September 30, 2018, an increase of 48% driven by increased production and realized prices. Stand-Alone Adjusted EBITDAX increased from $284 million for the three months ended September 30, 2017 to $419 million for the three months ended September 30, 2018, an increase of 48%.

Consolidated cash flows from operations decreased from $1.0 billion for the three months ended September 30, 2017 to $421 million for the three months ended September 30, 2018, and stand-alone cash flows from operations decreased from $1.0 billion for the three months ended September 30, 2017 to $367 billion for the three months ended September 30, 2018. The decreases in consolidated and stand-alone cash flows from operations were primarily due to $750 million of proceeds from the partial monetization of certain of our natural gas hedges in 2017.

For the nine months ended September 30, 2018, our net production totaled 693 Bcfe, or 2,539 MMcfe per day, a 14% increase compared to 606 Bcfe, or 2,221 MMcfe per day, for the nine months ended September 30, 2017. Production increases resulted from an increase in the number of producing wells as a result of our drilling and completion activity, offset by some curtailment of production due to oil hauling constraints. Our average price received for production, before the effects of gains on settled commodity derivatives, for the nine months ended September 30, 2018 was $3.54 per Mcfe compared to $3.30 per Mcfe for the nine months ended September 30, 2017. Our average realized price after the effects of gains on settled commodity derivatives was $3.93 per Mcfe for the nine months ended September 30, 2018 compared to $3.53 per Mcfe for the nine months ended September 30, 2017.

For the nine months ended September 30, 2018, we generated consolidated cash flows from operations of $1.3 billion, a consolidated net loss of $276 million, Adjusted EBITDAX of $1.5 billion, and Stand-Alone Adjusted EBITDAX of $1.2 billion. This compares to consolidated cash flows from operations of $1.7 billion, consolidated net income of $128 million, Adjusted EBITDAX of $1.0 billion, and Stand-Alone Adjusted EBITDAX of $872 million for the nine months ended September 30, 2017. See “—Non-GAAP Financial Measures” for a definition of Adjusted EBITDAX (a non-GAAP measure) and a reconciliation of Adjusted EBITDAX to net income. See “—Stand-Alone Exploration and Production (E&P) Information” for a definition of Stand-Alone Adjusted EBITDAX and a reconciliation of Stand-Alone Adjusted EBITDAX to Antero’s stand-alone net income. “Stand-Alone” data represents information for Antero on an unconsolidated basis, reflecting Antero’s investment in Antero Midstream under the equity method of accounting.

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The consolidated net loss of $276 million for the nine months ended September 30, 2018 included (i) commodity derivative fair value gains of $135 million, comprised of gains on settled derivatives of $268 million and a non-cash loss of $133 million on changes in the fair value of unsettled commodity derivatives, (ii) a non-cash charge of $56 million for equity-based compensation, (iii) a non-cash charge of $406 million for impairments of unproved properties, and (iv) a non-cash deferred tax expense of $3 million.

Adjusted EBITDAX increased from $1.0 billion for the nine months ended September 30, 2017 to $1.5 billion for the nine months ended September 30, 2018, an increase of 42% driven by increased production and average realized price for production after gains on settled derivatives. Stand-Alone Adjusted EBITDAX increased from $872 million for the nine months ended September 30, 2017 to $1.2 billion for the nine months ended September 30, 2018, an increase of 42%.

Consolidated cash flows from operations decreased from $1.7 billion for the nine months ended September 30, 2017 to $1.3 billion for the nine months ended September 30, 2018, a decrease of 24%. Stand-alone cash flows from operations decreased from $1.6 billion for the nine months ended September 30, 2017 to $1.1 billion for the nine months ended September 30, 2018, a decrease of 31%. The decreases in consolidated and stand-alone cash flows from operations were primarily due to $750 million of cash realized in the prior year, net of increases in total realized revenues from production and settled commodity derivatives and $78 million in settled marketing derivative gains during 2018, net of increases in cash operating costs.

2018 Capital Budget and Capital Spending

Our consolidated capital budget for 2018 is $2.1 billion, and includes: $1.3 billion for drilling and completion, $150 million for leasehold expenditures, and $650 million for capital expenditures by Antero Midstream, which includes $215 million for investments in unconsolidated affiliates. We do not budget for acquisitions. Drilling and completion efficiency gains during 2018 have allowed a reduction in the number of drilling rigs and completion crews and, as a result, capital spending is expected to substantially decline during the fourth quarter of 2018 compared to average capital spending in the previous three quarters. We periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, drilling results, leasehold acquisition opportunities, and commodity prices.

For the nine months ended September 30, 2018, our consolidated capital expenditures were approximately $1.7 billion, including drilling and completion costs of $1.1 billion, leasehold additions of $130 million, gathering and compression expenditures of $337 million, water handling and treatment expenditures of $77 million, and other capital expenditures of $5 million. Antero Midstream also invested $91 million in its gas processing and fractionation joint venture with MarkWest Energy Partners L.P. (the “Joint Venture”).

Hedge Position

As of September 30, 2018, we had entered into fixed price hedging contracts for approximately 2.2 Tcf of our projected natural gas production at a weighted average index price of $3.30 per MMBtu for the period from October 1, 2018 through December 31, 2023, 100 million gallons of propane at a weighted average index price of $0.77 per gallon for the period from October 1, 2018 through December 31, 2018, and 552,000 Bbls of oil at a weighted average index price of $56.99 per Bbl for the period from October 1, 2018 through December 31, 2018. These hedging contracts include contracts for the remainder of 2018 of approximately 184 Bcf of natural gas at a weighted average index price of $3.53 per MMBtu. At September 30, 2018, the estimated fair value of our commodity derivative instruments was a net asset of $1.2 billion comprised of current assets and liabilities and noncurrent assets.

Credit Facilities

As of September 30, 2018, Antero’s borrowing base under its senior secured revolving bank credit facility (the “Credit Facility”) was $4.5 billion and lender commitments were $2.5 billion. Each of these amounts were reaffirmed in the annual redetermination in April 2018. The next redetermination of the borrowing base is scheduled to occur in April 2019. The borrowing base under the Credit Facility is redetermined annually and is based on the collateral value of Antero’s assets. The maturity date of the Credit Facility is the earlier of (i) October 26, 2022 and (ii) the date that is 91 days prior to the earliest stated redemption date of any series of Antero’s senior notes, unless such series of notes is refinanced. At September 30, 2018, we had $547 million of borrowings and $692 million of letters of credit outstanding under the Credit Facility. See “—Debt Agreements and Contractual Obligations—Senior Secured Revolving Credit Facility” for a description of the Credit Facility.

Antero Midstream has a revolving credit facility that provides for lender commitments of $2.0 billion (the “Midstream Credit Facility”). At September 30, 2018, Antero Midstream had $875 million of borrowings outstanding under the Midstream Credit Facility. The Midstream Credit Facility will mature on October 26, 2022. See “—Debt Agreements and Contractual Obligations—Midstream Credit Facility” for a description of the Midstream Credit Facility.

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Results of Operations

Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2018

The Company has four operating segments: (1) the exploration, development and production of natural gas, NGLs, and oil; (2) gathering and processing; (3) water handling and treatment; and (4) marketing and utilization of excess firm transportation capacity. Revenues from the gathering and processing and water handling and treatment operations are primarily derived from intersegment transactions for services provided to our exploration and production operations by Antero Midstream. All intersegment transactions are eliminated upon consolidation, including revenues from water handling and treatment services provided by Antero Midstream which are capitalized as proved property development costs by Antero. Marketing revenues are primarily derived from activities to purchase and sell third-party natural gas and NGLs and to market and utilize excess firm transportation capacity.

The operating results of the Company’s reportable segments were as follows for the three months ended September 30, 2017 and 2018 (in thousands):


	Exploration and production		Gathering and processing	Water handling and treatment	Marketing	Elimination of intersegment transactions	Consolidated total
Three months ended September 30, 2017:
Operating revenues and other:
Natural gas sales	$	409,141	—	—	—	—	409,141
Natural gas liquids sales		224,533	—	—	—	—	224,533
Oil sales		26,527	—	—	—	—	26,527
Commodity derivative fair value losses		(65,957)	—	—	—	—	(65,957)
Gathering, compression, and water handling and treatment		—	100,518	93,111	—	(190,760)	2,869
Marketing		—	—	—	50,767	—	50,767
Other income		3,070	—	—	—	(3,070)	—
Total	$	597,314	100,518	93,111	50,767	(193,830)	647,880

Operating expenses:
Lease operating	$	24,060	—	51,569	—	(52,138)	23,491
Gathering, compression, processing, and transportation		369,538	10,468	—	—	(97,872)	282,134
Production and ad valorem taxes		22,002	92	901	—	—	22,995
Marketing		—	—	—	78,884	—	78,884
Exploration		1,599	—	—	—	—	1,599
Impairment of unproved properties		41,000	—	—	—	—	41,000
Accretion of asset retirement obligations		658	—	—	—	—	658
Depletion, depreciation, and amortization		176,188	22,027	8,753	—	—	206,968
General and administrative (before equity-based compensation)		29,041	4,225	2,892	—	(402)	35,756
Equity-based compensation		19,248	5,111	2,088	—	—	26,447
Change in fair value of contingent acquisition consideration		—	—	2,556	—	(2,556)	—
Total		683,334	41,923	68,759	78,884	(152,968)	719,932
Operating income (loss)	$	(86,020)	58,595	24,352	(28,117)	(40,862)	(72,052)

Equity in earnings of unconsolidated affiliates	$	—	7,033	—	—	—	7,033

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	Exploration and production		Gathering and processing	Water handling and treatment	Marketing	Elimination of intersegment transactions	Consolidated total
Three months ended September 30, 2018:
Operating revenues and other
Natural gas sales	$	527,122	—	—	—	—	527,122
Natural gas liquids sales		338,269	—	—	—	—	338,269
Oil sales		59,722	—	—	—	—	59,722
Commodity derivative fair value gains		57,019	—	—	—	—	57,019
Gathering, compression, and water handling and treatment		—	133,202	133,003	—	(261,361)	4,844
Marketing		—	—	—	89,598	—	89,598
Marketing derivative fair value losses		—	—	—	(42)	—	(42)
Other income		5,197	—	—	—	(5,197)	—
Total	$	987,329	133,202	133,003	89,556	(266,558)	1,076,532

Operating expenses:
Lease operating	$	35,124	—	67,608	—	(66,463)	36,269
Gathering, compression, processing, and transportation		442,602	12,131	570	—	(128,799)	326,504
Production and ad valorem taxes		29,352	186	980	—	—	30,518
Marketing		—	—	—	151,764	—	151,764
Exploration		666	—	—	—	—	666
Impairment of unproved properties		221,094	—	—	—	—	221,094
Impairment of gathering systems and facilities		—	1,157	—	—	—	1,157
Accretion of asset retirement obligations		677	—	33	—	—	710
Depletion, depreciation, and amortization		204,465	26,095	12,626	—	—	243,186
General and administrative (before equity-based compensation)		33,800	8,117	2,373	—	(632)	43,658
Equity-based compensation		11,674	3,666	862	—	—	16,202
Change in fair value of contingent acquisition consideration		—	—	4,020	—	(4,020)	—
Total		979,454	51,352	89,072	151,764	(199,914)	1,071,728
Operating income (loss)	$	7,875	81,850	43,931	(62,208)	(66,644)	4,804

Equity in earnings of unconsolidated affiliates	$	—	10,705	—	—	—	10,705

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Exploration and Production Segment Results for the Three Months Ended September 30, 2017 Compared to the Three Months Ended September 30, 2018

The following tables set forth selected operating data of the exploration and production segment for the three months ended September 30, 2017 compared to the three months ended September 30, 2018:


	Three Months Ended September 30,				Amount of Increase		Percent
(Exploration and Production segment)	2017		2018		(Decrease)		Change
Production data:
Natural gas (Bcf)		151		179		28	18	%
C2 Ethane (MBbl)		2,789		3,579		790	28	%
C3+ NGLs (MBbl)		6,927		7,343		416	6	%
Oil (MBbl)		624		978		354	57	%
Combined (Bcfe)		213		250		37	17	%
Daily combined production (MMcfe/d)		2,317		2,718		401	17	%
Average prices before effects of derivative settlements(1):
Natural gas (per Mcf)	$	2.71	$	2.95	$	0.24	9	%
C2 Ethane (per Bbl)	$	8.68	$	15.70	$	7.02	81	%
C3+ NGLs (per Bbl)	$	28.92	$	38.41	$	9.49	33	%
Oil (per Bbl)	$	42.50	$	61.06	$	18.56	44	%
Weighted Average Combined (per Mcfe)	$	3.10	$	3.70	$	0.60	19	%
Average realized prices after effects of derivative settlements(1):
Natural gas (per Mcf)	$	3.37	$	3.51	$	0.14	4	%
C2 Ethane (per Bbl)	$	8.53	$	15.70	$	7.17	84	%
C3+ NGLs (per Bbl)	$	23.15	$	35.32	$	12.17	53	%
Oil (per Bbl)	$	45.40	$	54.00	$	8.60	19	%
Weighted Average Combined (per Mcfe)	$	3.39	$	3.98	$	0.59	17	%
Average Costs (per Mcfe):
Lease operating	$	0.11	$	0.14	$	0.03	27	%
Gathering, compression, processing, and transportation	$	1.73	$	1.77	$	0.04	2	%
Production and ad valorem taxes	$	0.10	$	0.12	$	0.02	20	%
Depletion, depreciation, amortization, and accretion	$	0.83	$	0.82	$	(0.01)	(1)	%
General and administrative (before equity-based compensation)	$	0.14	$	0.14	$	—	—	%

(1)

Average sales prices shown in the table reflect both the before and after effects of our settled commodity derivatives. Our calculation of such after effects includes gains on settlements of commodity derivatives, which do not qualify for hedge accounting because we do not designate or document them as hedges for accounting purposes. Oil and NGLs production was converted at 6 Mcf per Bbl to calculate total Bcfe production and per Mcfe amounts. This ratio is an estimate of the equivalent energy content of the products and does not necessarily reflect their relative economic value.

Natural gas sales. Revenues from production of natural gas increased from $409 million for the three months ended September 30, 2017 to $527 million for the three months ended September 30, 2018, an increase of $118 million, or 29%. Increased natural gas production volumes accounted for an approximate $76 million increase in year-over-year product natural gas revenues (calculated as the change in year-to-year volumes times the prior year average price), and changes in our prices, excluding the effects of derivative settlements, accounted for an approximate $42 million increase in year-over-year product revenues (calculated as the change in the year-to-year average price times current year production volumes).

NGLs sales. Revenues from production of NGLs increased from $225 million for the three months ended September 30, 2017 to $338 million for the three months ended September 30, 2018, an increase of $114 million, or 51%. Increased NGL production volumes accounted for an approximate $19 million increase in year-over-year product NGL revenues (calculated as the change in year-to-year volumes times the prior year average price), and changes in our prices, excluding the effects of derivative settlements, accounted for an approximate $95 million increase in year-over-year product revenues (calculated as the change in the year-to-year average price times current year production volumes).

Oil sales. Revenues from production of oil increased from $27 million for the three months ended September 30, 2017 to $60 million for the three months ended September 30, 2018, an increase of $33 million, or 125%.

During the three months ended September 30, 2017 and 2018, our natural gas prices and revenues were negatively affected by contractual issues with certain of our customers. For more information on these disputes, please see Note 13 to the unaudited condensed consolidated financial statements or “Item 1. Legal Proceedings” included elsewhere in this Quarterly Report on Form 10-Q.

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Commodity derivative fair value gains. To achieve more predictable cash flows, and to reduce our exposure to price fluctuations, we enter into fixed for variable price swap contracts when management believes that favorable future sales prices for our production can be secured. Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment. Consequently, all mark-to-market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our statements of operations. For the three months ended September 30, 2017 and 2018, our commodity hedges resulted in derivative fair value gains (losses) of $(66) million and $57 million, respectively. The commodity derivative fair value gains (losses) included $61 million and $71 million of gains on cash settled derivatives for the three months ended September 30, 2017 and 2018, respectively. Commodity derivative fair value gains (losses) for the three months ended September 30, 2017 also include gains of $750 million related to derivatives which were partially monetized prior to their settlement dates.

Commodity derivative gains or losses vary based on future commodity prices and have no cash flow impact until the derivative contracts are settled or monetized prior to settlement. Derivative asset or liability positions at the end of any accounting period may reverse to the extent future commodity prices increase or decrease from their levels at the end of the accounting period, or as gains or losses are realized through settlement. We expect continued volatility in commodity prices and the related fair value of our derivative instruments in the future.

Other income. Other income increased from $3 million for the three months ended September 30, 2017 to $5 million for the three months ended September 30, 2018. Other income primarily relates to increases in the fair value of our exploration and production segment’s contingent acquisition consideration that was received in connection with Antero’s sale of its water handling and treatment assets to Antero Midstream in 2015. In conjunction with the acquisition of the water handling and treatment assets, Antero Midstream agreed to pay Antero (a) $125 million in cash if Antero Midstream delivers 176,295,000 barrels or more of fresh water during the period between January 1, 2017 and December 31, 2019 and (b) an additional $125 million in cash if Antero Midstream delivers 219,200,000 barrels or more of fresh water during the period between January 1, 2018 and December 31, 2020. The contingent acquisition consideration asset is recorded at its discounted net present value of the payout to be received by Antero, and is re-measured each period end. As the net present value of the contingent acquisition consideration asset increases, we recognize income in the E&P segment for the change in fair value. Other income is eliminated upon consolidation.

Lease operating expense. Lease operating expense increased from $24 million for the three months ended September 30, 2017 to $35 million for the three months ended September 30, 2018, an increase of 46%. This increase is partly due to a 17% increase in production. On a per unit basis, lease operating expenses increased from $0.11 per Mcfe for the three months ended September 30, 2017 to $0.14 for the three months ended September 30, 2018. The increase in lease operating expenses on a per Mcfe basis is primarily due to the increase in produced water, which is attributable to an increase in water used in our advanced well completions.

Gathering, compression, processing, and transportation expense. Gathering, compression, processing, and transportation expense increased from $370 million for the three months ended September 30, 2017 to $443 million for the three months ended September 30, 2018. The increase in these expenses is a result of the increase in production and the related firm transportation, gathering, compression, and processing expenses. On a per Mcfe basis, total gathering, compression, processing and transportation expenses increased from $1.73 per Mcfe for the three months ended September 30, 2017 to $1.77 per Mcfe for the three months ended September 30, 2018, primarily as a result of increases in fuel costs as compared to the prior year due to higher natural gas prices. Transportation expenses increased due to the Rover Pipeline that was placed in service in late 2017, which has higher per-unit transportation costs than the average of our transportation portfolio, but in turn results in higher realized prices for our natural gas production. In addition, the increases were due to increased fuel costs as compared to the prior year due to higher natural gas prices. These increases were partially offset by decreases in processing costs on a per Mcfe basis.

Production and ad valorem tax expense. Total production and ad valorem taxes increased from $22 million for the three months ended September 30, 2017 to $29 million for the three months ended September 30, 2018 as a result of an increase in production revenues. On a per Mcfe basis, production and ad valorem taxes increased from $0.10 per Mcfe for the three months ended September 30, 2017 to $0.12 per Mcfe for the for the three months ended September 30, 2018. Production and ad valorem taxes as a percentage of natural gas, NGLs, and oil revenues before the effects of hedging decreased slightly from 3.5% for the three months ended September 30, 2017 to 3.3% for the three months ended September 30, 2018.

Exploration expense. Exploration expense decreased from $2 million for the three months ended September 30, 2017 to $1 million for the three months ended September 30, 2018. These amounts represent expenses incurred for unsuccessful lease acquisition efforts.

Impairment of unproved properties. Impairment of unproved properties increased from $41 million for the three months ended September 30, 2017 to $221 million for the three months ended September 30, 2018. The increase was primarily due to the

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impairment of acreage in the Ohio Utica Shale expiring in the next 12 month outside of our primary area of development and that are not in our current development plan. We also charge impairment expense for expired or soon-to-be expired leases when we determine they are impaired based on factors such as remaining lease terms, reservoir performance, commodity price outlooks, and future plans to develop the acreage.

Depletion, depreciation, and amortization expense (“DD&A”). DD&A increased from $176 million for the three months ended September 30, 2017 to $204 million for the three months ended September 30, 2018, primarily because of increased production. DD&A per Mcfe decreased from $0.83 per Mcfe for the three months ended September 30, 2017 to $0.82 per Mcfe for the three months ended September 30, 2018.

We evaluate the carrying amount of our proved natural gas, NGLs, and oil properties for impairment on a geological reservoir basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying amount exceeded the estimated undiscounted future net cash flows (measured using futures prices at the end of a quarter), we would further evaluate our proved properties and record an impairment charge if the carrying amount of our proved properties exceeded the estimated fair value of the properties. At September 30, 2018, estimated future net cash flows were higher than the carrying values of our proved properties at September 30, 2018, we did not further evaluate our proved properties for impairment.

General and administrative expense. General and administrative expense (before equity-based compensation expense) increased from $29 million for the three months ended September 30, 2017 to $34 million for the three months ended September 30, 2018, primarily due to increases in employee compensation and benefits expenses as well as other expenses related to the growth of the Company. On a per-unit basis, general and administrative expense before equity-based compensation remained consistent at $0.14 per Mcfe for the three months ended September 30, 2017 and 2018 as the increase in expenses from 2017 to 2018 was offset by a 17% increase in production. We had 583 employees as of September 30, 2017 and 607 employees as of September 30, 2018.

Equity-based compensation expense. Noncash equity-based compensation expense decreased from $19 million for the three months ended September 30, 2017 to $12 million for the three months ended September 30, 2018 as a result of equity award forfeitures, as well as a decrease in the total value of awards granted to officers and employees in 2018 as compared to 2017. When an equity award is forfeited, expense previously recognized for the award is reversed. See Note 9 to the unaudited condensed consolidated financial statements included elsewhere in this report for more information on equity-based compensation awards.

Discussion of Gathering and Processing, Water Handling and Treatment, and Marketing Segment Results for the Three Months Ended September 30, 2017 Compared to the Three Months Ended September 30, 2018

Gathering and Processing. Revenue for the gathering and processing segment increased from $101 million for the three months ended September 30, 2017 to $133 million for the three months ended September 30, 2018, an increase of $32 million, or 33%. Gathering revenues increased by $23 million from the prior year period and compression revenues increased by $9 million as additional wells on production increased throughput volumes. Total operating expenses related to the gathering and processing segment increased from $42 million for the three months ended September 30, 2017 to $51 million for the three months ended September 30, 2018 primarily as a result of increases in direct operating and depreciation expenses due to a larger base of gathering and compression assets.

Antero Midstream has two investments accounted for under the equity method: a 15% interest in a regional gathering pipeline purchased in May 2016, and a 50% interest in the Joint Venture with MarkWest entered into in February 2017. Equity in earnings of unconsolidated affiliates of $7 million and $11 million for the three months ended September 30, 2017 and 2018, respectively, represents the portion of the net income from these investments which was allocated to Antero Midstream based on its equity interests. The increase was due to the commencement of operations by two additional processing plants which are owned by the Joint Venture.

Water Handling and Treatment. Revenue for the water handling and treatment segment increased from $93 million for the three months ended September 30, 2017 to $133 million for the three months ended September 30, 2018, an increase of $40 million, or 43%. The increase was due to an increase in the volume of water used per well in our advanced completions during 2018 as compared to 2017, as well as an increase in other fluid handling services as a result of the increase in the amount of water used. The volume of water delivered through the systems increased from 13.0 MMBbls for the three months ended September 30, 2017 to 18.0 MMBbls for the three months ended September 30, 2018. Operating expenses for the water handling and treatment segment increased from $69 million for the three months ended September 30, 2017 to $89 million for the three months ended September 30, 2018, primarily due to the increase in other fluid handling services.

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Marketing. Where feasible, we purchase and sell third-party natural gas and NGLs and market our excess firm transportation capacity, or engage third parties to conduct these activities on our behalf, in order to optimize the revenues from these transportation agreements. We have entered into long-term firm transportation agreements for a significant portion of our current and expected future production in order to secure guaranteed capacity to favorable markets.

Operating losses on our marketing activities were $28 million and $62 million for the three months ended September 30, 2017 and 2018, respectively. See Note 11 to the unaudited condensed consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for more information on marketing derivative fair value losses during the three months ended September 30, 2018.

Marketing expenses include firm transportation costs related to current excess capacity as well as the cost of third-party purchased gas and NGLs. This includes firm transportation costs of $27 million and $49 million for the three months ended September 30, 2017 and 2018, respectively, related to unutilized excess capacity which increased due to the Rover Pipeline that was placed in service in late 2017.

Discussion of Items Not Allocated to Segments for the Three Months Ended September 30, 2017 Compared to the Three Months Ended September 30, 2018

Interest expense. Interest expense increased from $70 million for the three months ended September 30, 2017 to $75 million for the three months ended September 30, 2018, primarily due to increased average balances outstanding under revolving credit facilities.

Income tax (expense) benefit. Income tax (expense) benefit changed from a deferred tax benefit of $45 million for the three months ended September 30, 2017 to a deferred tax expense of $19 million for the three months ended September 30, 2018. Deferred tax expense for the three months ended September 30, 2018 was primarily caused from the recording of a valuation allowance on certain state net operating loss carryforwards (NOLs”) which are no longer expected to be used due to changes in apportionment rules. The change in year-over-year tax provisions also reflects the reduction in the federal corporate tax rate from 35% to 21%. For the three months ended September 30, 2018, the Company’s overall effective tax rate was different than the statutory rate of 21% primarily due to the effects of noncontrolling interests, state tax rates, and permanent differences on vested equity compensation awards.

At December 31, 2017, we had approximately $3.0 billion of net operating loss carryforwards (“NOLs”) for U.S. federal income tax purposes that expire at various dates from 2024 through 2037 and approximately $2.3 billion of state NOLs that expire at various dates from 2018 through 2037. Future interpretations relating to the passage of the Tax Cuts and Jobs Act which vary from our current interpretation, and possible changes to state tax laws in response to the recently enacted federal legislation, may have a significant effect on our future taxable position. The impact of any such change would be recorded in the period in which such interpretation is received or legislation is enacted.

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2018

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The operating results of the Company’s reportable segments were as follows for the nine months ended September 30, 2017 and 2018 (in thousands):


	Exploration and production		Gathering and processing	Water handling and treatment	Marketing	Elimination of intersegment transactions	Consolidated total
Nine months ended September 30, 2017:
Operating revenues and other:
Natural gas sales	$	1,330,062	—	—	—	—	1,330,062
Natural gas liquids sales		590,004	—	—	—	—	590,004
Oil sales		79,999	—	—	—	—	79,999
Commodity derivative fair value gains		458,459	—	—	—	—	458,459
Gathering, compression, and water handling and treatment		—	290,939	271,226	—	(553,500)	8,665
Marketing		—	—	—	166,659	—	166,659
Other income		11,421	—	—	—	(11,421)	—
Total	$	2,469,945	290,939	271,226	166,659	(564,921)	2,633,848

Operating expenses:
Lease operating	$	56,991	—	131,635	—	(132,592)	56,034
Gathering, compression, processing, and transportation		1,070,522	28,492	—	—	(283,304)	815,710
Production and ad valorem taxes		67,576	104	2,661	—	—	70,341
Marketing		—	—	—	246,298	—	246,298
Exploration		5,510	—	—	—	—	5,510
Impairment of unproved properties		83,098	—	—	—	—	83,098
Accretion of asset retirement obligations		1,944	—	—	—	—	1,944
Depletion, depreciation, and amortization		521,603	64,445	24,831	—	—	610,879
General and administrative (before equity-based compensation)		90,387	15,242	7,884	—	(1,438)	112,075
Equity-based compensation		58,489	14,937	5,499	—	—	78,925
Change in fair value of contingent acquisition consideration		—	—	9,672	—	(9,672)	—
Total		1,956,120	123,220	182,182	246,298	(427,006)	2,080,814
Operating income (loss)	$	513,825	167,719	89,044	(79,639)	(137,915)	553,034

Equity in earnings of unconsolidated affiliates	$	—	12,887	—	—	—	12,887

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	Exploration and production		Gathering and processing	Water handling and treatment	Marketing	Elimination of intersegment transactions	Consolidated total
Nine months ended September 30, 2018:
Operating revenues and other:
Natural gas sales	$	1,498,324	—	—	—	—	1,498,324
Natural gas liquids sales		828,424	—	—	—	—	828,424
Oil sales		128,869	—	—	—	—	128,869
Commodity derivative fair value gains		134,793	—	—	—	—	134,793
Gathering, compression, and water handling and treatment		—	359,514	386,674	—	(730,890)	15,298
Marketing		—	—	—	394,189	—	394,189
Marketing derivative fair value gains		—	—	—	94,081	—	94,081
Gain on sale of assets		—	583	—	—	(583)	—
Other income		16,251	—	—	—	(16,251)	—
Total	$	2,606,661	360,097	386,674	488,270	(747,724)	3,093,978

Operating expenses:
Lease operating	$	98,698	—	184,698	—	(190,241)	93,155
Gathering, compression, processing, and transportation		1,236,655	35,899	570	—	(346,896)	926,228
Production and ad valorem taxes		79,045	204	2,983	—	—	82,232
Marketing		—	—	—	560,924	—	560,924
Exploration		4,022	—	—	—	—	4,022
Impairment of unproved properties		406,068	—	—	—	—	406,068
Impairment of gathering systems and facilities		—	9,658	—	—	—	9,658
Accretion of asset retirement obligations		2,000	—	101	—	—	2,101
Depletion, depreciation, and amortization		601,446	74,215	33,819	—	—	709,480
General and administrative (before equity-based compensation)		98,732	21,062	7,299	—	(1,946)	125,147
Equity-based compensation		39,823	13,078	3,528	—	—	56,429
Change in fair value of contingent acquisition consideration		—	—	11,841	—	(11,841)	—
Total		2,566,489	154,116	244,839	560,924	(550,924)	2,975,444
Operating income	$	40,172	205,981	141,835	(72,654)	(196,800)	118,534

Equity in earnings of unconsolidated affiliates	$	—	27,832	—	—	—	27,832

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Exploration and Production Segment Results for the Nine Months Ended September 30, 2018 Compared to the Nine Months Ended September 30, 2017

The following tables set forth selected operating data of the exploration and production segment for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2018:


	Nine Months Ended September 30,				Amount of Increase		Percent
(Exploration and Production segment)	2017		2018		(Decrease)		Change
Production data:
Natural gas (Bcf)		435		504		69	16	%
C2 Ethane (MBbl)		7,648		9,899		2,251	29	%
C3+ NGLs (MBbl)		19,085		19,450		365	2	%
Oil (MBbl)		1,880		2,139		259	14	%
Combined (Bcfe)		606		693		87	14	%
Daily combined production (MMcfe/d)		2,221		2,539		318	14	%
Average prices before effects of derivative settlements(1):
Natural gas (per Mcf)	$	3.06	$	2.97	$	(0.09)	(3)	%
C2 Ethane (per Bbl)	$	8.38	$	11.71	$	3.33	40	%
C3+ NGLs (per Bbl)	$	27.56	$	36.63	$	9.07	33	%
Oil (per Bbl)	$	42.56	$	60.23	$	17.67	42	%
Weighted Average Combined (per Mcfe)	$	3.30	$	3.54	$	0.24	7	%
Average realized prices after effects of derivative settlements(1):
Natural gas (per Mcf)	$	3.59	$	3.62	$	0.03	1	%
C2 Ethane (per Bbl)	$	8.62	$	11.71	$	3.09	36	%
C3+ NGLs (per Bbl)	$	22.37	$	34.54	$	12.17	54	%
Oil (per Bbl)	$	44.87	$	52.73	$	7.86	18	%
Weighted Average Combined (per Mcfe)	$	3.53	$	3.93	$	0.40	11	%
Average Costs (per Mcfe):
Lease operating	$	0.09	$	0.14	$	0.05	56	%
Gathering, compression, processing, and transportation	$	1.77	$	1.78	$	0.01	1	%
Production and ad valorem taxes	$	0.11	$	0.11	$	—	—	%
Depletion, depreciation, amortization, and accretion	$	0.86	$	0.87	$	0.01	1	%
General and administrative (before equity-based compensation)	$	0.15	$	0.14	$	(0.01)	(7)	%

(1)

Natural gas sales. Revenues from production of natural gas increased from $1.3 billion for the nine months ended September 30, 2017 to $1.5 billion for the nine months ended September 30, 2018, an increase of $168 million, or 13%. Increased natural gas production volumes accounted for an approximate $211 million increase in year-over-year product natural gas revenues (calculated as the change in year-to-year volumes times the prior year average price), and changes in our prices, excluding the effects of derivative settlements, accounted for an approximate $43 million decrease in year-over-year product revenues (calculated as the change in the year-to-year average price times current year production volumes).

NGLs sales. Revenues from production of NGLs increased from $590 million for the nine months ended September 30, 2017 to $828 million for the nine months ended September 30, 2018, an increase of $238 million, or 40%. Increased NGL production volumes accounted for an approximate $29 million increase in year-over-year product NGL revenues (calculated as the change in year-to-year volumes times the prior year average price), and changes in our prices, excluding the effects of derivative settlements, accounted for an approximate $209 million increase in year-over-year product revenues (calculated as the change in the year-to-year average price times current year production volumes).

Oil sales. Revenues from production of oil increased from $80 million for the nine months ended September 30, 2017 to $129 million for the nine months ended September 30, 2018, an increase of $49 million, or 61%.

During the nine months ended September 30, 2017 and 2018, our natural gas prices and revenues were negatively affected by contractual issues with certain of our customers. For more information on these disputes, please see Note 13 to the unaudited condensed consolidated financial statements or “Item 1. Legal Proceedings” included elsewhere in this Quarterly Report on Form 10-Q.

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Commodity derivative fair value gains. To achieve more predictable cash flows, and to reduce our exposure to price fluctuations, we enter into fixed for variable price swap contracts when management believes that favorable future sales prices for our production can be secured. Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment. Consequently, all mark-to-market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our statements of operations. For the nine months ended September 30, 2017 and 2018, our commodity hedges resulted in derivative fair value gains of $458 million and $135 million, respectively. The commodity derivative fair value gains included $137 million and $268 million of gains on cash settled derivatives for the nine months ended September 30, 2017 and 2018, respectively. Commodity derivative fair value gains for the nine months ended September 30, 2017 includes gains of $750 million related to derivatives which were partially monetized prior to their settlement dates.

Other income. Other income increased from $11 million for the nine months ended September 30, 2017 to $16 million for the nine months ended September 30, 2018. Other income primarily relates to increases in the fair value of our exploration and production segment’s contingent acquisition consideration that was received in connection with Antero’s sale of its water handling and treatment assets to Antero Midstream in 2015. In conjunction with the acquisition of the water handling and treatment assets, Antero Midstream agreed to pay Antero (a) $125 million in cash if Antero Midstream delivers 176,295,000 barrels or more of fresh water during the period between January 1, 2017 and December 31, 2019 and (b) an additional $125 million in cash if Antero Midstream delivers 219,200,000 barrels or more of fresh water during the period between January 1, 2018 and December 31, 2020. The contingent acquisition consideration asset is recorded at its discounted net present value of the payout to be received by Antero, and is re-measured each period end. As the net present value of the contingent acquisition consideration asset increases, we recognize income in the E&P segment for the change in fair value. Other income is eliminated upon consolidation.

Lease operating expense. Lease operating expense increased from $57 million for the nine months ended September 30, 2017 to $99 million for the nine months ended September 30, 2018, an increase of 73%. This increase is partly due to a 14% increase in production. On a per unit basis, lease operating expenses increased from $0.09 per Mcfe for the nine months ended September 30, 2017 to $0.14 for the nine months ended September 30, 2018. The increase in lease operating expenses on a per Mcfe basis is due to the increase in produced water, which is attributable to an increase in water used in our advanced well completions.

Gathering, compression, processing, and transportation expense. Gathering, compression, processing, and transportation expense increased from $1.1 billion for the nine months ended September 30, 2017 to $1.2 billion for the nine months ended September 30, 2018. The increase in these expenses is a result of the increase in production and the related firm transportation, gathering, compression, and processing expenses. On a per Mcfe basis, total gathering, compression, processing and transportation expenses remained relatively consistent at $1.77 per Mcfe for the nine months ended September 30, 2017 and $1.78 per Mcfe for the nine months ended September 30, 2018. Transportation expenses increased due to the Rover Pipeline that was placed in service in late 2017, which has higher per-unit transportation costs than the average of our transportation portfolio, but in turn results in higher realized prices for our natural gas production. This increase was partially offset by decreases in processing costs on a per Mcfe basis.

Production and ad valorem tax expense. Total production and ad valorem taxes increased from $68 million for the nine months ended September 30, 2017 to $79 million for the nine months ended September 30, 2018 as a result of an increase in production revenues. On a per Mcfe basis, production and ad valorem taxes remained consistent at $0.11 for the nine months ended September 30, 2017 and 2018. Production and ad valorem taxes as a percentage of natural gas, NGLs, and oil revenues before the effects of hedging decreased from 3.5% for the nine months ended September 30, 2017 to 3.3% for the nine months ended September 30, 2018.

Exploration expense. Exploration expense decreased from $6 million for the nine months ended September 30, 2017 to $4 million for the nine months ended September 30, 2018. These amounts represent expenses incurred for unsuccessful lease acquisition efforts.

Impairment of unproved properties. Impairment of unproved properties increased from $83 million for the nine months ended September 30, 2017 to $406 million for the nine months ended September 30, 2018. The increase was primarily due to the impairment of acreage in the Utica Shale expiring in the next 12 month outside of our primary area of development and that are not in our current development plan. We charge impairment expense for expired or soon-to-be expired leases when we determine they are

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impaired based on factors such as remaining lease terms, reservoir performance, commodity price outlooks, and future plans to develop the acreage.

Depletion, depreciation, and amortization expense (“DD&A”). DD&A increased from $522 million for the nine months ended September 30, 2017 to $601 million for the nine months ended September 30, 2018, primarily because of increased production. DD&A per Mcfe increased from $0.86 per Mcfe for the nine months ended September 30, 2017 to $0.87 per Mcfe for the nine months ended September 30, 2018.

General and administrative expense. General and administrative expense (before equity-based compensation expense) increased from $90 million for the nine months ended September 30, 2017 to $99 million for the nine months ended September 30, 2018, primarily due to increases in employee compensation and benefits expenses. On a per-unit basis, general and administrative expense before equity-based compensation decreased from $0.15 per Mcfe for the nine months ended September 30, 2017 to $0.14 per Mcfe for the nine months ended September 30, 2018 as the increase in expenses from 2017 to 2018 were offset by a 14% increase in production. We had 583 employees as of September 30, 2017 and 607 employees as of September 30, 2018.

Equity-based compensation expense. Noncash equity-based compensation expense decreased from $58 million for the nine months ended September 30, 2017 to $40 million for the nine months ended September 30, 2018 as a result of equity award forfeitures, as well as a decrease in the total value of awards granted to officers and employees in 2018 as compared to 2017. When an equity award is forfeited, expense previously recognized for the award is reversed. See Note 9 to the unaudited condensed consolidated financial statements included elsewhere in this report for more information on equity-based compensation awards.

Discussion of Gathering and Processing, Water Handling and Treatment, and Marketing Segment Results for the Nine Months Ended September 30, 2017 Compared to the Nine Months Ended September 30, 2018

Gathering and Processing. Revenue for the gathering and processing segment increased from $291 million for the nine months ended September 30, 2017 to $360 million for the nine months ended September 30, 2018, an increase of $69 million, or 24%. Gathering revenues increased by $46 million from the prior year period and compression revenues increased by $23 million as additional wells on production increased throughput volumes. Total operating expenses related to the gathering and processing segment increased from $123 million for the nine months ended September 30, 2017 to $154 million for the nine months ended September 30, 2018 primarily as a result of increases in direct operating and depreciation expenses due to a larger base of gathering and compression assets.

Antero Midstream has two investments accounted for under the equity method: a 15% interest in a regional gathering pipeline purchased in May 2016, and a 50% interest in the Joint Venture with MarkWest entered into in February 2017. Equity in earnings of unconsolidated affiliates of $13 million and $28 million for the nine months ended September 30, 2017 and 2018, respectively, represents the portion of the net income from these investments which was allocated to Antero Midstream based on its equity interests. The increase was due to the commencement of operations by two additional processing plants which are owned by the Joint Venture.

Water Handling and Treatment. Revenue for the water handling and treatment segment increased from $271 million for the nine months ended September 30, 2017 to $387 million for the nine months ended September 30, 2018, an increase of $116 million, or 43%. The increase was due to an increase in the volume of water used per well in our advanced completions during 2018 as compared to 2017, as well as an increase in other fluid handling services as a result of the increase in the amount of water used. The volume of water delivered through the systems increased from 42.1 MMBbls for the nine months ended September 30, 2017 to 58.7 MMBbls for the nine months ended September 30, 2018. Operating expenses for the water handling and treatment segment increased from $182 million for the nine months ended September 30, 2017 to $245 million for the nine months ended September 30, 2018, primarily due to the increase in other fluid handling services. Antero Midstream’s wastewater treatment facility was placed in service in May 2018, but has not yet had a significant impact on the financial results of the water handling and treatment segment as a result of delays in reaching contracted treatment capacity.

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Operating losses on our marketing activities were $79 million and $73 million for the nine months ended September 30, 2017 and 2018, respectively. See note 11 to the unaudited condensed consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for more information on marketing derivative fair value gains during the nine months ended September 30, 2018.

Marketing expenses include firm transportation costs related to current excess capacity as well as the cost of third-party purchased gas and NGLs. This includes firm transportation costs of $74 million and $126 million for the nine months ended September 30, 2017 and 2018, respectively, related to unutilized excess capacity which increased due to the Rover Pipeline that was placed in service in late 2017.

Discussion of Items Not Allocated to Segments for the Nine Months Ended September 30, 2017 Compared to the Nine Months Ended September 30, 2018

Interest expense. Interest expense increased from $205 million for the nine months ended September 30, 2017 to $208 million for the nine months ended September 30, 2018. Interest expense includes approximately $8.8 million and $9.5 million of non-cash amortization of deferred financing costs for the nine months ended September 30, 2017 and 2018, respectively.

Income tax expense. Income tax expense decreased from a deferred tax expense of $105 million for the nine months ended September 30, 2017 to a deferred tax expense of $3 million for the nine months ended September 30, 2018. The decrease in deferred tax expense is attributable to the decrease in income before income taxes from $361 million during the nine months ended September 30, 2017 to a loss before income taxes of $62 million during the three months ended September 30, 2018. The change in year-over-year tax provisions also reflects the reduction in the federal corporate tax rate from 35% to 21%. For the nine months ended September 30, 2018, the Company’s overall effective tax rate was different than the statutory rate of 21% primarily due to the effects of noncontrolling interests, state tax rates, and permanent differences on vested equity compensation awards.

At December 31, 2017, we had approximately $3.0 billion of NOLs for U.S. federal income tax purposes that expire at various dates from 2024 through 2037 and approximately $2.3 billion of state NOLs that expire at various dates from 2018 through 2037. Future interpretations relating to the passage of the Tax Cuts and Jobs Act which vary from our current interpretation, and possible changes to state tax laws in response to the recently enacted federal legislation, may have a significant effect on our future taxable position. The impact of any such change would be recorded in the period in which such interpretation is received or legislation is enacted.

Capital Resources and Liquidity

Historically, our primary sources of liquidity have been through issuances of debt and equity securities, borrowings under our revolving credit facilities, asset sales, and net cash provided by operating activities. Historically, our primary use of cash has been for the exploration, development, and acquisition of oil and natural gas properties, as well as for development of gathering and compression systems and facilities, and fresh water handling and wastewater treatment infrastructure. As we pursue the development of our reserves, we continually monitor what capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities, and liquidity requirements. Our future success in growing our proved reserves and production will be highly dependent on the capital resources available to us.

Based on strip pricing at September 30, 2018, we believe that funds from operating cash flows and available borrowings under the Credit Facility and Midstream Credit Facility, or capital market transactions, will be sufficient to meet our cash requirements, including normal operating needs, debt service obligations, capital expenditures, and commitments and contingencies for at least the next 12 months. For more information on our outstanding indebtedness, see Note 7 to the unaudited condensed consolidated financial statements included in this Quarterly Report on Form 10-Q.

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The following table summarizes our cash flows for the nine months ended September 30, 2017 and 2018:


	Nine Months Ended September 30,				Increase
(in thousands)	2017		2018		(Decrease)
Net cash provided by operating activities	$	1,692,808		1,260,398		(432,410)
Net cash used in investing activities		(1,948,307)		(1,770,339)		177,968
Net cash provided by financing activities		247,583		481,500		233,917
Net decrease in cash and cash equivalents	$	(7,916)		(28,441)

Cash Flows Provided by Operating Activities

Net cash provided by operating activities was $1.7 billion and $1.3 billion for the nine months ended September 30, 2017 and 2018, respectively. The decrease in cash flows from operations from the nine months ended September 30, 2017 to the nine months ended September 30, 2018 was primarily due to $750 million of proceeds from the partial monetization of certain of our natural gas hedges during the nine months ended September 30, 2017 partially offset by the net effect of revenues and costs from the increases in prices and production in 2018 over 2017 levels.

Our net operating cash flows are sensitive to many variables, the most significant of which is the volatility of natural gas, NGLs, and oil prices, as well as volatility in the cash flows attributable to settlement of our commodity derivatives. Prices for natural gas, NGLs, and oil are primarily determined by prevailing market conditions. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets, and other variables influence the market conditions for these products. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

Cash Flows Used in Investing Activities

Cash flows used in investing activities decreased from $1.9 billion for the nine months ended September 30, 2017 to $1.8 billion for the nine months ended September 30, 2018, primarily due to an acreage acquisition that we made during the nine months ended September 30, 2017 whereas no acquisitions took place in 2018, and decreases in investments in the Joint Venture by Antero Midstream during the nine months ended September 30, 2018 as compared to the nine months ended September 30, 2017. During the nine months ended September 30, 2018, our cash flows used in investing activities included $1.1 billion for drilling and completion costs, $130 million for undeveloped leasehold additions, $77 million for water handling and treatment systems, $337 million for gathering and compression systems, $91 million for investments in the Joint Venture, and $5 million for other property and equipment. During the nine months ended September 30, 2017, our cash flows used in investing activities included $947 million for drilling and completion costs, $182 million for undeveloped leasehold additions, $179 million for acquisitions, $143 million for water handling and treatment systems, $255 million for gathering and compression systems, $217 million for investments in the Joint Venture, $11 million for other property and equipment, and $14 million for other items.

Our capital budget for 2018 is $1.45 billion, which does not include the capital budget of $650 million for Antero Midstream, our consolidated subsidiary. Our capital budget may be adjusted as business conditions warrant as the amount, timing, and allocation of capital expenditures is largely discretionary and within our control. If natural gas, NGLs, and oil prices decline to levels that do not generate an acceptable level of corporate returns, or costs increase to levels that do not generate an acceptable level of corporate returns, we could choose to defer a significant portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity, and to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in commodity prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flows, and other factors both within and outside our control.

We expect 2018 drilling and completion capital expenditures to remain consistent with prior guidance of $1.3 billion on a consolidated basis. Drilling and completion efficiency gains during 2018 have allowed a reduction in the number of drilling rigs and completion crews and, as a result, capital spending is expected to substantially decline during the fourth quarter of 2018 compared to average capital spending in the previous three quarters.

Cash Flows Provided by Financing Activities

Net cash flows provided by financing activities increased from $248 million for the nine months ended September 30, 2017 to $482 million for the nine months ended September 30, 2018. Net cash provided by financing activities of $482 million during the

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nine months ended September 30, 2018 was primarily the result of (i) additional net borrowing on our credit facilities of $682 million, net of (ii) $189 million for distributions to noncontrolling interest owners in Antero Midstream and (iii) other items totaling $11 million. Net cash provided by financing activities of $248 million during the nine months ended September 30, 2017 included proceeds of $311 million from the sale of Antero Midstream common units owned by Antero and net proceeds from the issuance of common units in Antero Midstream of $249 million (including $26 million issued under the Distribution Agreement), partially offset by net repayments on our revolving credit facilities of $198 million, distributions of $102 million to noncontrolling interest owners in Antero Midstream and other items totaling $12 million.

Stand-Alone Exploration and Production (E&P) Information

As explained in Note 16 to the Consolidated Financial Statements included elsewhere in this Quarterly Report on Form 10-Q, each of the wholly-owned subsidiaries of Antero Resources Corporation has guaranteed Antero’s senior notes. Antero Midstream and its subsidiaries do not guarantee Antero’s senior notes or any of its other obligations. Note 16 to the Condensed Consolidated Financial Statements includes the condensed consolidating balance sheets, statements of operations and comprehensive income (loss), and statements of cash flows on a consolidating basis for Antero (the Parent) and Antero Midstream (Antero’s non-guarantor subsidiaries). Antero (Parent) includes the assets, liabilities, results of operations, and cash flows for the exploration and production and marketing operations of the Company, including cash flows related to Antero’s ownership of common units in Antero Midstream and Antero’s stand-alone debt obligations not guaranteed by Antero Midstream.

We believe the Antero (Parent) information is useful to investors as a means to evaluate Antero’s operations on a stand-alone basis and its ability to service its debt obligations that are not guaranteed by Antero Midstream or to incur additional debt. We believe that funds from stand-alone operating cash flows, available borrowings under the Credit Facility, and future capital market transactions by Antero, will be sufficient to meet Antero’s cash requirements, including normal operating needs, debt service obligations, capital expenditures, and commitments and contingencies for at least the next 12 months.

“Stand-Alone Adjusted EBITDAX” is a non-GAAP financial measure that we define as net income or loss on a stand-alone basis for Antero (Parent) before interest expense, interest income, gains or losses from commodity derivatives and marketing derivatives, but including net cash receipts or payments on derivative instruments included in derivative gains or losses, income taxes, impairment, depletion, depreciation, amortization, and accretion, exploration expense, franchise taxes, equity-based compensation, gain or loss on early extinguishment of debt, gain or loss on sale of assets, equity in earnings or loss of Antero Midstream, and gain or loss on changes in the fair value of contingent acquisition consideration. Stand-Alone Adjusted EBITDAX also includes distributions received from limited partner interests in Antero Midstream common units.

Stand-Alone Adjusted EBITDAX, as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. Stand-Alone Adjusted EBITDAX should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by operating, investing, and financing activities, or other income or cash flows statement data prepared in accordance with GAAP. Stand-Alone Adjusted EBITDAX provides no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, working capital movement, or tax position. Stand-Alone Adjusted EBITDAX does not represent funds available for discretionary use because those funds may be required for debt services, capital expenditures, working capital, income taxes, exploration expenses, and other commitments and obligations. However, our management team believes Stand-Alone Adjusted EBITDAX is useful to an investor in evaluating our financial performance because this measure:

is used by investors in the oil and natural gas industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, which may vary substantially from company to company depending upon accounting methods and the book value of assets, capital structure and the method by which assets were acquired, among other factors;

helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital and legal structure from our consolidated operating structure; and

is used by our management team for various purposes, including as a measure of our operating performance, in presentations to our Board of Directors, and as a basis for strategic planning and forecasting. EBITDAX, as defined under the Credit Facility, is used by our lenders pursuant to covenants under the Credit Facility and the indentures governing our senior notes, and is used as one of several evaluation metrics during the annual redetermination process for the Credit Facility.

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There are significant limitations to using Stand-Alone Adjusted EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations of different companies, and the different methods of calculating Adjusted EBITDAX reported by different companies.

The following table presents a reconciliation of Antero’s stand-alone net income to Stand-Alone Adjusted EBITDAX, and a reconciliation of Stand-Alone Adjusted EBITDAX to Antero’s stand-alone net cash provided by operating activities per our unaudited condensed consolidating statements of cash flows (see Note 16 to our Consolidated Financial Statements), in each case, for the periods presented:


	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2017		2018		2017		2018
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$	(135,063)		(154,419)		128,201		(275,971)
Commodity derivative fair value (gains) losses (1)		65,957		(57,020)		(458,459)		(134,793)
Gains on settled commodity derivatives(1)		61,479		71,144		137,392		268,369
Marketing derivative fair value (gains) losses(1)		—		43		—		(94,081)
Gains (losses) on settled marketing derivatives(1)		—		(16,060)		—		78,098
Interest expense		60,906		57,633		178,644		165,519
Income tax expense (benefit)		(45,078)		18,953		105,087		2,500
Depletion, depreciation, amortization, and accretion		177,070		205,408		524,219		604,159
Impairment of unproved properties		41,000		221,095		83,098		406,068
Impairment of gathering systems and facilities		—		—		—		4,470
Exploration expense		1,599		666		5,510		4,022
Gain on change in fair value of contingent acquisition consideration		(2,556)		(4,020)		(9,672)		(11,841)
Equity-based compensation expense		19,248		11,674		58,489		39,823
Equity in loss of Antero Midstream Partners LP		4,874		23,363		21,582		70,417
Distributions from Antero Midstream Partners LP		34,839		41,031		97,984		115,678
Stand-Alone E&P Adjusted EBITDAX		284,275		419,491		872,075		1,242,437
Interest expense		(60,906)		(57,633)		(178,644)		(165,519)
Exploration expense		(1,599)		(666)		(5,510)		(4,022)
Changes in current assets and liabilities		38,129		5,505		144,926		20,015
Proceeds from derivative monetizations		749,906		—		749,906		—
Other non-cash items		101		315		(694)		862
Net cash provided by operating activities	$	1,009,906		367,012		1,582,059		1,093,773

(1)

The adjustments for the derivative gains and losses and gains on settled commodity and marketing derivatives have the effect of adjusting net income from operations for changes in the fair value of unsettled derivatives, which are recognized at the end of each accounting period. As a result, Stand-Alone Adjusted EBITDAX only reflects derivatives which settled, or were monetized, during the period.

Stand-Alone Adjusted EBITDAX. Stand-Alone Adjusted EBITDAX increased from $284 million for the three months ended September 30, 2017 to $419 million for the three months ended September 30, 2018, an increase of 48% and Stand-Alone Adjusted EBITDAX increased from $872 million for the nine months ended September 30, 2017 to $1.2 billion for the nine months ended September 30, 2018, an increase of 42%. The increase in Adjusted EBITDAX and Stand-Alone Adjusted EBITDAX was primarily due to increases in our average realized price for liquids and increased production, net of increased costs related to higher production levels.

Debt Agreements and Contractual Obligations

Antero Senior Secured Revolving Credit Facility. Antero’s Credit Facility is with a consortium of bank lenders. Borrowings under the Credit Facility are subject to borrowing base limitations based on the collateral value of our assets and are subject to regular annual redeterminations. At September 30, 2018, the borrowing base was $4.5 billion and lender commitments were $2.5 billion. The next redetermination of the borrowing base is scheduled to occur by the end of April 2018. At September 30, 2018, we had $547 million of borrowings and $692 million of letters of credit outstanding under the Credit Facility, with a weighted average interest rate of 3.75%. At December 31, 2017, we had $185 million of borrowings and $705 million of letters of credit outstanding under the

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Credit Facility, with a weighted average interest rate of 2.96%. The maturity date of the Credit Facility is the earlier of (i) October 26, 2022 and (ii) the date that is 91 days prior to the earliest stated redemption date of any series of Antero’s senior notes, unless such series of senior notes is refinanced.

Under the Credit Facility, “Investment Grade Period” is a period that, as long as no event of default has occurred, commences when Antero elects to give notice to the Administrative Agent that Antero has received at least one of either (i) a BBB- or better rating from Standard and Poor’s or (ii) a Baa3 or better rating from Moody’s (an “Investment Grade Rating”). An Investment Grade Period can end at Antero’s election. During any period that is not an Investment Grade Period, the Credit Facility requires Antero and its restricted subsidiaries to maintain the following two financial ratios as of the end of each fiscal quarter:

a current ratio, which is the ratio of our current assets (including any unused borrowing base under the facilities and excluding derivative assets) to our current liabilities (excluding derivative liabilities), of not less than 1.0 to 1.0; and

an interest coverage ratio, which is the ratio of EBITDAX (as defined by the credit facility agreement) to interest expense over the most recent four quarters, of not less than 2.5 to 1.0.

During an Investment Grade Period, the Credit Facility requires Antero and its restricted subsidiaries to maintain the following three financial ratios as of the end of each fiscal quarter

a ratio of total Indebtedness (as defined by the credit facility agreement) to EBITDAX (as defined by the credit facility agreement) of not more than 4.25 to 1.00; and

a ratio of PV-9 reflected in the most recently delivered reserve report to its total Indebtedness of not less than 1.50 to 1.00, but only if Antero does not have both (i) an unsecured rating from Moody’s of Baa3 or better and (ii) an unsecured rating from S&P of BBB- or better.

We were in compliance with the applicable covenants and ratios as of December 31, 2017 and September 30, 2018. The actual borrowing capacity available to us may be limited by the financial ratio covenants. At September 30, 2018, our current ratio was 4.51 to 1.0 (based on the $4.5 billion borrowing base under the Credit Facility) and our interest coverage ratio was 7.74 to 1.0.

Midstream Credit Facility. Antero Midstream has a secured revolving credit facility among Antero Midstream, certain lenders party thereto, and Wells Fargo Bank, National Association, as administrative agent, letter of credit issuer, and swing line lender. The Midstream Credit Facility provides for lender commitments of $2.0 billion and for a letter of credit sublimit of $150 million. At September 30, 2018, Antero Midstream had $875 million of borrowings and no letters of credit outstanding under the Midstream Credit Facility, with a weighted average interest rate of 3.39%. At December 31, 2017, Antero Midstream had a total outstanding balance under the Midstream Credit Facility of $555 million, with a weighted average interest rate of 2.81%. The Midstream Credit Facility matures on October 26, 2022.

Senior Notes. Please refer to Note 7 to the unaudited condensed consolidated financial statements included in this Quarterly Report on Form 10-Q and to “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Annual Report on Form 10-K for the year ended December 31, 2017 for information on our senior notes.

We may, from time to time, seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for equity securities, in open market purchases, privately negotiated transactions, or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions, and other factors. The amounts involved could be material.

For more information on the terms, conditions, and restrictions under the Credit Facility, the Midstream Credit Facility, and senior unsecured notes, please refer to our Annual Report on Form 10-K for the year ended December 31, 2017 on file with the SEC.

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Contractual Obligations. A summary of our contractual obligations as of September 30, 2018 is provided in the table below. Contractual obligations listed exclude minimum fees that we will pay to Antero Midstream, our consolidated subsidiary, under gathering and compression and water services agreements. Future capital contributions to unconsolidated affiliates are excluded from the table as neither the amounts nor the timing of the obligations can be determined in advance.


	Remainder		Year Ended December 31,
(in millions)	of 2018		2019		2020		2021		2022		2023		Thereafter		Total
Credit Facility(1)	$	—		—		—		547		—		—		—		547
Midstream Credit Facility(1)		—		—		—		—		875		—		—		875
Antero senior notes—principal(2)		—		—		—		1,000		1,100		750		600		3,450
Antero senior notes—interest(2)		76		182		182		155		129		51		60		835
Antero Midstream senior notes—principal(2)		—		—		—		—		—		—		650		650
Antero Midstream senior notes—interest(2)		—		35		35		35		35		35		35		210
Drilling rig and completion service commitments(3)		29		92		31		5		—		—		—		157
Firm transportation (4)		230		1,087		1,107		1,087		1,034		1,022		8,689		14,256
Processing, gathering, and compression services (5)		155		360		396		382		378		369		1,671		3,711
Office and equipment leases		4		14		13		11		9		7		49		107
Asset retirement obligations(6)		—		—		—		1		—		—		41		42
Total	$	494		1,770		1,764		3,223		3,560		2,234		11,795		24,840

(1)

Includes outstanding principal amounts at September 30, 2018. This table does not include future commitment fees, interest expense, or other fees on our Credit Facility or the Midstream Credit Facility because they are floating rate instruments and we cannot determine with accuracy the timing of future loan advances, repayments, or future interest rates to be charged. The maturity date of the Credit Facility is the earlier of (i) October 26, 2022 and (ii) the date that is 91 days prior to the earliest stated redemption of any series of Antero’s senior notes, unless such series of notes is refinanced. The maturity date of the Midstream Credit Facility is October 26, 2022

(2)

Antero senior notes include the 5.375% notes due 2021, the 5.125% notes due 2022, the 5.625% notes due 2023, and the 5.00% notes due 2025. Antero Midstream senior notes include the 5.375% notes due 2024.

(3)

Includes contracts for services provided by drilling rigs and completion fleets which expire at various dates from February 2019 through November 2021. The values in the table represent the gross amounts that we are committed to pay; however, we will record in our financial statements our proportionate share of costs based on our working interests.

(4)

Includes firm transportation agreements with various pipelines in order to facilitate the delivery of our production to market. These contracts commit us to transport minimum daily natural gas or NGLs volumes at negotiated rates, or pay for any deficiencies at specified reservation fee rates. The amounts in this table reflect our minimum daily volumes at the reservation fee rates. The values in the table represent the gross amounts that we are committed to pay; however, we will record in our financial statements our proportionate share of costs based on our working interests.

(5)

Contractual commitments for processing, gathering, and compression services agreements represent minimum commitments under long-term agreements. This includes fees to be paid to the Joint Venture owned by Antero Midstream and MarkWest, as well as Antero Midstream’s remaining commitments for the construction of its advanced wastewater treatment complex, which was placed in service in May 2018. The values in the table represent the gross amounts that we are committed to pay; however, we will record in our financial statements our proportionate share of costs based on our working interests. The table does not include intracompany commitments.

(6)

Represents the present value of our estimated asset retirement obligations. Neither the ultimate settlement amounts nor the timing of our asset retirement obligations can be precisely determined in advance; however, we believe it is likely that a very small amount of these obligations will be settled within the next five years.

Non-GAAP Financial Measures

“Adjusted EBITDAX” is a non-GAAP financial measure that we define as net income or loss, including noncontrolling interests, before interest expense, interest income, derivative fair value gains or losses, but including net cash receipts or payments on derivative instruments included in derivative fair value gains or losses, taxes, impairment, depletion, depreciation, amortization, and accretion, exploration expense, franchise taxes, equity-based compensation, gain or loss on early extinguishment of debt, and gain or

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loss on sale of assets. Adjusted EBITDAX also includes distributions from unconsolidated affiliates and excludes equity in earnings or losses of unconsolidated affiliates.

“Adjusted EBITDAX,” as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. Adjusted EBITDAX should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by operating, investing, and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. Adjusted EBITDAX provides no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, working capital movement, or tax position. Adjusted EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, exploration expenses, and other commitments and obligations. However, our management team believes Adjusted EBITDAX is useful to an investor in evaluating our financial performance because this measure:

is widely used by investors in the oil and natural gas industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, which may vary substantially from company to company depending upon accounting methods and the book value of assets, capital structure, and the method by which assets were acquired, among other factors;

helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and

is used by our management team for various purposes, including as a measure of our operating performance, in presentations to our Board or Directors, and as a basis for strategic planning and forecasting. Adjusted EBITDAX is also used by our Board of Directors as a performance measure in determining executive compensation. Consolidated EBITDAX, as defined under the Credit Facility, is used by our lenders pursuant to covenants under the Credit Facility and the indentures governing our senior notes.

There are significant limitations to using Adjusted EBITDAX as a measure of performance, including the inability to analyze the effects of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations of different companies, and the different methods of calculating Adjusted EBITDAX reported by different companies.

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The following table represents a reconciliation of our net income, including noncontrolling interest, to Adjusted EBITDAX and a reconciliation of Adjusted EBITDAX to net cash provided by operating activities per our consolidated statements of cash flows for the three and nine months ended September 30, 2017 and 2018:


	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2017		2018		2017		2018
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$	(135,063)		(154,419)	$	128,201		(275,971)
Net income and comprehensive income attributable to noncontrolling interests		45,063		76,447		127,322		211,534
Commodity derivative fair value gains (losses) (1)		65,957		(57,020)		(458,459)		(134,793)
Gains on settled commodity derivatives(1)		61,479		71,144		137,392		268,369
Marketing derivative fair value (gains) losses(1)		—		43		—		(94,081)
Gains (losses) on settled marketing derivatives(1)		—		(16,060)		—		78,098
Interest expense		70,059		74,528		205,311		208,303
Income tax expense (benefit)		(45,078)		18,953		105,087		2,500
Depletion, depreciation, amortization, and accretion		207,626		243,897		612,823		711,581
Impairment of unproved properties		41,000		221,095		83,098		406,068
Impairment of gathering systems and facilities		—		1,157		—		9,658
Exploration expense		1,599		666		5,510		4,022
Equity-based compensation expense		26,447		16,202		78,925		56,429
Equity in earnings of unconsolidated affiliates		(7,033)		(10,706)		(12,887)		(27,832)
Distributions from unconsolidated affiliates		4,300		11,765		10,120		29,660
Adjusted EBITDAX		336,356		497,692		1,022,443		1,453,545
Interest expense		(70,059)		(74,528)		(205,311)		(208,303)
Exploration expense		(1,599)		(666)		(5,510)		(4,022)
Changes in current assets and liabilities		29,899		(2,053)		130,089		16,233
Proceeds from derivative monetizations		749,906		—		749,906		—
Other non-cash items		719		1,013		1,191		2,945
Net cash provided by operating activities	$	1,045,222		421,458	$	1,692,808		1,260,398

(1)

The adjustments for the derivative gains and losses and gains on settled commodity and marketing derivatives have the effect of adjusting net income from operations for changes in the fair value of unsettled derivatives, which are recognized at the end of each accounting period. As a result, Adjusted EBITDAX only reflects derivatives which settled, or were monetized, during the period.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. Our more significant accounting policies and estimates include the successful efforts method of accounting for our production activities, estimates of natural gas, NGLs, and oil reserve quantities and standardized measures of future cash flows, and impairment of proved properties. We provide an expanded discussion of our more significant accounting policies, estimates and judgments in our 2017 Form 10-K. We believe these accounting policies reflect our more significant estimates and assumptions used in the preparation of our consolidated financial statements. Also, see Note 2 of the notes to our audited consolidated financial statements, included in our 2017 Form 10-K, for a discussion of additional accounting policies and estimates made by management.

We evaluate the carrying amount of our proved natural gas, NGLs, and oil properties for impairment on a geological reservoir basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. Under GAAP for successful efforts accounting, if the carrying amount exceeded the estimated undiscounted future net cash flows

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(measured using futures prices), we would estimate the fair value of our proved properties and record an impairment charge for any excess of the carrying amount of the properties over the estimated fair value of the properties. We compared estimated undiscounted future net cash flows using futures pricing for our Utica and Marcellus Shale properties to the carrying values of those properties. Estimated undiscounted future net cash flows exceeded the carrying values at September 30, 2018 and thus, no further evaluation of our proved properties for impairment is required under GAAP. As a result, we have not recorded any impairment expenses associated with our Utica and Marcellus Basin proved properties during the three and nine months ended September 30, 2018. Additionally, we did not record any impairment expenses for proved properties during the years ended December 31, 2015, 2016, and 2017.

New Accounting Pronouncements

On February 25, 2016, the FASB issued ASU No. 2016-02, Leases, which requires lessees to present nearly all leasing arrangements on the balance sheet as liabilities along with a corresponding right-of-use asset. The ASU will replace most existing lease guidance in GAAP when it becomes effective. The new standard becomes effective for the Company on January 1, 2019. Although early application is permitted, the Company does not plan to early adopt the ASU. The standard requires the use of the modified retrospective transition method. The Company is evaluating the effect that ASU 2016-02 will have on its consolidated financial statements and related disclosures. Currently, the Company is evaluating the standard’s applicability to our various contractual arrangements. We believe that adoption of the standard will result in increases to our assets and liabilities on our consolidated balance sheet as well as changes to the presentation of certain operating expenses on our consolidated statement of operations, including the accelerated recognition of expenses attributable to certain of our leasing arrangements. However, we have not yet determined the extent of the adjustments that will be required upon implementation of the standard. We continue to monitor relevant industry guidance regarding the implementation of ASU 2016-02 and will adjust our implementation strategies as necessary. We do not believe that adoption of the standard will impact our operational strategies, growth prospects, or cash flows.

Off-Balance Sheet Arrangements

As of September 30, 2018, we did not have any off-balance sheet arrangements other than operating leases and contractual commitments for drilling rig and completion services, firm transportation, gas processing and fractionation, gathering, and compression services. See “—Debt Agreements and Contractual Obligations—Contractual Obligations” for our commitments under these agreements.

Item 3.Quantitative and Qualitative Disclosures About Market Risk.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas, NGLs, and oil prices, as well as interest rates. These disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures.

Commodity Hedging Activities

Our primary market risk exposure is in the price we receive for our natural gas, NGLs, and oil production. Pricing is primarily driven by spot regional market prices applicable to our U.S. natural gas production and the prevailing worldwide price for crude oil. Pricing for natural gas, NGLs, and oil has, historically, been volatile and unpredictable, and we expect this volatility to continue in the future. The prices we receive for our production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price.

To mitigate some of the potential negative impact on our cash flows caused by changes in commodity prices, we enter into financial derivative instruments to receive fixed prices for a portion of our natural gas, NGLs, and oil production when management believes that favorable future prices can be secured.

Our financial hedging activities are intended to support natural gas, NGLs, and oil prices at targeted levels and to manage our exposure to natural gas, NGLs, and oil price fluctuations. These contracts may include commodity price swaps whereby we will receive a fixed price and pay a variable market price to the contract counterparty, cashless price collars that set a floor and ceiling price for the hedged production, or basis differential swaps. These contracts are financial instruments, and do not require or allow for physical delivery of the hedged commodity. At September 30, 2018, all of our commodity derivatives were fixed price swaps at index-based pricing.

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At September 30, 2018, we had in place NGLs and oil swaps covering portions of our projected production through 2018, and natural gas swaps covering portions of our projected production through 2023. Our commodity hedge position as of September 30, 2018 is summarized in Note 11(a) to our unaudited condensed consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q. Under the Credit Facility, we are permitted to hedge up to 75% of our projected production for the next 60 months. We may enter into hedge contracts with a term greater than 60 months, and for no longer than 72 months, for up to 65% of our estimated production. Based on our production and our fixed price swap contracts which settled during the nine months ended September 30, 2018, our revenues would have decreased by approximately 18.7 million for each $0.10 decrease per MMBtu in natural gas prices and $1.00 decrease per Bbl in oil and NGLs prices, excluding the effects of changes in the fair value of our derivative positions which remain open at September 30, 2018.

All derivative instruments, other than those that meet the normal purchase and normal sale scope exception, are recorded at fair market value in accordance with GAAP and are included in our consolidated balance sheets as assets or liabilities. The fair values of our derivative instruments are adjusted for non-performance risk. Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment; therefore, all mark-to-market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our statements of operations. We present total gains or losses on commodity derivatives (for both settled derivatives and derivative positions which remain open) within operating revenues as “Commodity derivative fair value gains (losses).”

Mark-to-market adjustments of derivative instruments cause earnings volatility but have no cash flow impact relative to changes in market prices until the derivative contracts are settled or monetized prior to settlement. We expect continued volatility in the fair value of our derivative instruments. Our cash flows are only impacted when the associated derivative contracts are settled or monetized by making or receiving payments to or from the counterparty. At September 30, 2018, the estimated fair value of our commodity derivative instruments was a net asset of $1.2 billion comprised of current assets and liabilities and noncurrent assets. At December 31, 2017, the estimated fair value of our commodity derivative instruments was a net asset of $1.3 billion comprised of current and noncurrent assets and liabilities.

By removing price volatility from a portion of our expected production through December 2023, we have mitigated, but not eliminated, the potential negative effects of changing prices on our operating cash flows for those periods. While mitigating the negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices above the fixed hedge prices.

Counterparty and Customer Credit Risk

Our principal exposures to credit risk are through receivables resulting from the following: commodity derivative contracts ($1.2 billion at September 30, 2018); the sale of our oil and gas production ($334 million at September 30, 2018) which we market to energy companies, end users, and refineries; the marketing of our excess firm transportation capacity ($20 million at September 30, 2018); and joint interest receivables ($14 million at September 30, 2018).

By using derivative instruments that are not traded on an exchange to hedge our exposures to changes in commodity prices, we expose ourselves to the credit risk of our counterparties. Credit risk is the potential failure of a counterparty to perform under the terms of a derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe us, which creates credit risk. To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions which management deems to be competent and competitive market makers. The creditworthiness of our counterparties is subject to periodic review. We have commodity hedges in place with fifteen different counterparties, thirteen of which are lenders under our Credit Facility. The fair value of our commodity derivative contracts of approximately $1.2 billion at September 30, 2018 included the following derivative assets by bank counterparty: JP Morgan - $263 million; Morgan Stanley - $261 million; Citigroup - $223 million; Scotiabank - $151 million; Wells Fargo - $101 million; Canadian Imperial Bank of Commerce - $78 million; BNP Paribas - $27 million; Bank of Montreal - $18 million; Toronto Dominion - $15 million; Natixis - $9 million; PNC $9 million; SunTrust - $5 million; Capital One - $4 million; and Fifth Third - $3 million. The credit ratings of certain of these banks were downgraded several years ago because of their exposure to the sovereign debt crisis in Europe or various other economic factors. The estimated fair value of our commodity derivative assets has been risk-adjusted using a discount rate based upon the counterparties’ respective published credit default swap rates (if available, or if not available, a discount rate based on the applicable Reuters bond rating) at September 30, 2018 for each of the European and American banks. We believe that all of these institutions, currently, are acceptable credit risks. Other than as provided by the Credit Facility, we are not required to provide credit support or collateral to any of our counterparties under our derivative contracts, nor are they required to provide credit support to us. As of September 30, 2018, we did not have any past-due receivables from, or payables to, any of the counterparties to our derivative contracts.

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We are also subject to credit risk due to the concentration of our receivables from several significant customers for sales of natural gas, NGLs, and oil. Marketing receivables primarily result from sales of third-party natural gas and NGLs. We, generally, do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us, or their insolvency or liquidation, may adversely affect our financial results.

Joint interest receivables arise from our billing of entities who own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leased properties on which we drill. We have minimal control over deciding who participates in our wells.

Interest Rate Risks

Our primary exposure to interest rate risk results from outstanding borrowings under our Credit Facility and the Midstream Credit Facility of our consolidated subsidiary, Antero Midstream. Each of these credit facilities has a floating interest rate. The average annualized interest rate incurred on the Credit Facility and the Midstream Credit Facility during the nine months ended September 30, 2018 was approximately 3.45%. We estimate that a 1.0% increase in each of the applicable average interest rates for the nine months ended September 30, 2018 would have resulted in an estimated $7.8 million increase in interest expense.

Item 4.Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report on Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures and is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of September 30, 2018 at a level of reasonable assurance.

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the three months ended September 30, 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1.Legal Proceedings.

Environmental

In March 2011, we received orders for compliance from federal regulatory agencies, including the U.S. Environmental Protection Agency (“EPA”), relating to certain of our activities in West Virginia. The orders allege that certain of our operations at several well sites are in non-compliance with certain environmental regulations, such as unpermitted discharges of fill material into wetlands or waters of the United States that are potentially in violation of the Clean Water Act. We have responded to all pending orders and are actively cooperating with the relevant agencies. We believe that these actions will result in monetary sanctions exceeding $100,000. We have had ongoing settlement discussions with the relevant agencies to resolve the orders for compliance, but we are unable to estimate the total amount of monetary sanctions to resolve such orders or costs to remediate these locations in order to bring them into compliance with applicable environmental laws and regulations. Our operations at these locations are not suspended, and management does not expect these matters to have a material adverse effect on our financial condition, results of operations, or cash flows.

In June 2018, following site inspections conducted in September 2017 at certain of our facilities located in Doddridge County, Tyler County, and Ritchie County, West Virginia, we received a Notice of Violation (“NOV”) from the EPA Region III for alleged violations of the federal Clean Air Act and the West Virginia State Implementation Plan relating to permitting and control

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requirements for emissions of regulated pollutants at several of our natural gas production facilities. The NOV alleges that combustion devices at these facilities did not meet applicable air permitting requirements. Separately, in June 2018, we received an information request from EPA Region III pursuant to Section 114(a) of the Clean Air Act relating to the facilities that were inspected in September 2017 as well as additional Antero facilities for the purpose of determining if the additional facilities have the same alleged compliance issues that were identified during the September 2017 inspections. We are preparing a response to the NOV and the information request. Since receipt of the NOV and information request, we have met with the EPA to discuss the alleged compliance issues but do not yet have any indication with respect to whether, and to what extent, the NOV and information request will result in monetary sanctions; however we believe that there is a reasonable possibility that these actions may result in monetary sanctions exceeding $100,000. Our operations at these facilities are not suspended, and management does not expect these matters to have a material adverse effect on our financial condition, results of operations, or cash flows.

SJGC

Through September 30, 2018, the Company estimates $82 million (gross damages, including interest) more than SJGC has paid using the indices unilaterally selected by them. Substantially all of this amount has not been accrued in the Company’s financial statements. The Company will vigorously seek recovery from SJGC of all underpayments and damages, including interest, based on the contracted price.

WGL

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issue in the arbitration and it was rejected by the arbitration panel. The arbitration panel specifically found that the Delivery Point under the Contracts was at a specific point in Braxton, West Virginia, not the IPP Pool. On August 24, 2017, the Colorado district court dismissed with prejudice WGL’s claims against the Company in its new lawsuit and found that the Company had not breached its Contracts with WGL by allegedly failing to deliver to the IPP Pool. The Court also reaffirmed the arbitration panel’s finding that the delivery point under the Contracts was not the IPP Pool. The Court dismissed WGL’s lawsuit because WGL had not adequately pled a claim against Antero for the alleged failure to deliver “TCO pool” gas under the Contracts. WGL appealed this decision to the Colorado Court of Appeals and on October 11, 2018 the Colorado Court of Appeals reversed the Colorado district court’s decision finding that WGL had adequately pled a claim for relief and remanded the case back to the district court for further proceedings. The Colorado Court of Appeals did not address the issue of whether WGL’s claims were independently barred by the prior arbitration’s findings.

Other

Item 1A. Risk Factors.

We are subject to certain risks and hazards due to the nature of the business activities we conduct. For a discussion of these risks, see “Item 1A. Risk Factors” in our 2017 Form 10-K. The risks described in our 2017 Form 10-K could materially and adversely affect our business, financial condition, cash flows, and results of operations. There have been no material changes to the risks described in our 2017 Form 10-K. We may experience additional risks and uncertainties not currently known to us; or, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also materially and adversely affect our business, financial condition, cash flows, and results of operations.

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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

Issuer Purchases of Equity Securities

The following table sets forth our share purchase activity for each period presented:


Period	Total Number of Shares Purchased		Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans		Maximum Number of Shares that May Yet be Purchased Under the Plan
July 1, 2018 - July 31, 2018		7,119	$	21.76		—		N/A
August 1, 2018 - August 31, 2018		—	$	—		—		N/A
September 1, 2018 - September 30, 2018		—	$	—		—		N/A

Shares purchased represent shares of our common stock transferred to us in order to satisfy tax withholding obligations incurred upon the vesting of Antero equity awards held by our employees.

Item 6.Exhibits.


Exhibit Number		Description of Exhibit
3.1		Amended and Restated Certificate of Incorporation of Antero Resources Corporation (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K (Commission File No. 001-36120) filed on October 17, 2013).
3.2		Amended and Restated Bylaws of Antero Resources Corporation (incorporated by reference to Exhibit 3.2 to Current Report on Form 8-K (Commission File No. 001-36120) filed on October 17, 2013).
10.1		Voting Agreement, dated as of October 9, 2018, by and between Antero Midstream GP LP and Antero Resources Corporation (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (Commission File No. 001-36120) filed on October 10, 2018).
10.2		Stockholders’ Agreement, dated as of October 9, 2018, by and among Antero Midstream GP LP, Arkrose Subsidiary Holdings LLC, Warburg Pincus Private Equity X O&G, L.P., Warburg Pincus X Partners, L.P., Warburg Pincus Private Equity VIII, LP, Warburg Pincus Netherlands Private Equity VIII C.V.I, WP-WPVIII Investors, L.P., Yorktown Energy Partners V, L.P., Yorktown Energy Partners VI, L.P., Yorktown Energy Partners VII, L.P., Yorktown Energy Partners VIII, L.P., Paul M. Rady, Mockingbird Investment, LLC, Glen C. Warren, Jr. and Canton Investment Holdings LLC (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (Commission File No. 001-36120) filed on October 10, 2018).
31.1*		Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 7241).
31.2*		Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 7241).
32.1*		Certification of the Company’s Chief Executive Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 1350).
32.2*		Certification of the Company’s Chief Financial Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 1350).
101*		The following financial information from this Quarterly Report on Form 10-Q of Antero Resources Corporation for the quarter ended September 30, 2018 formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations and Comprehensive Income (Loss), (iii) Condensed Consolidated Statements of Equity, (iv) Condensed Consolidated Statements of Cash Flows, and (v) Notes to the Condensed Consolidated Financial Statements, tagged as blocks of text.

The exhibits marked with the asterisk symbol (*) are filed or furnished with this Quarterly Report on Form 10-Q.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


ANTERO RESOURCES CORPORATION

By:	/s/ GLEN C. WARREN, JR.
	Glen C. Warren, Jr.
	President, Chief Financial Officer and Secretary

Date:	October 31, 2018