Antero Resources (AR) 10-Q 2019 Q3 Quarterly report

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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, 2019

OR

☐ 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)

Securities registered pursuant to section 12(b) of the Act:
Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, par value $0.01	AR	New York Stock Exchange

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 304,270,444 shares of common stock outstanding as of October 25, 2019.

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	48
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	70
Item 4.	Controls and Procedures	72
PART II—OTHER INFORMATION		73
Item 1.	Legal Proceedings	73
Item 1A.	Risk Factors	73
Item 2.	Unregistered Sales of Equity Securities	73
Item 6.	Exhibits	74
SIGNATURES		75

1

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this Quarterly Report on Form 10-Q includes “forward looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward looking statements. 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, although not all forward-looking statements contain such identifying words. These forward looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering these forward-looking statements, investors should keep in mind the risk factors and other cautionary statements in this Quarterly Report on Form 10-Q. These forward-looking statements are management’s belief, based on currently available information, as to the outcome and timing of future events.

Forward looking statements may include statements about:

● 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;

● our ability to successfully complete our share repurchase program;

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

● future drilling plans;

● projected well costs and cost savings initiatives, including with respect to water handling and treatment services provided by Antero Midstream Corporation;

● 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 Corporation;

● general economic conditions;

● credit markets;

● expectations regarding the amount and timing of jury awards;

● uncertainty regarding our future operating results; and

● plans, objectives, expectations, and intentions.

2

We caution investors that these forward-looking statements are subject to all of the risks and uncertainties incidental to our business, most of which are difficult to predict and many of which are beyond our control. 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, 2018 (the “2018 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 Quarterly Report on Form 10-Q 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 Quarterly Report on Form 10-Q 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 to reflect events or circumstances after the date of this Quarterly Report on Form 10-Q.

3

PART I—FINANCIAL INFORMATION

ANTERO RESOURCES CORPORATION

Condensed Consolidated Balance Sheets

December 31, 2018 and September 30, 2019

(In thousands, except per share amounts)

			(Unaudited)
	December 31, 2018		September 30, 2019
Assets
Current assets:
Accounts receivable	$	51,073		29,207
Accrued revenue		474,827		281,177
Derivative instruments		245,263		411,774
Other current assets		35,450		7,342
Total current assets		806,613		729,500
Property and equipment:
Oil and gas properties, at cost (successful efforts method):
Unproved properties		1,767,600		1,406,464
Proved properties		12,705,672		11,568,285
Water handling and treatment systems		1,013,818		—
Gathering systems and facilities		2,470,708		5,802
Other property and equipment		65,842		70,965
		18,023,640		13,051,516
Less accumulated depletion, depreciation, and amortization		(4,153,725)		(3,136,767)
Property and equipment, net		13,869,915		9,914,749
Operating leases right-of-use assets		—		3,230,148
Derivative instruments		362,169		405,180
Investments in unconsolidated affiliates		433,642		1,819,323
Other assets		47,125		21,388
Total assets	$	15,519,464		16,120,288
Liabilities and Equity
Current liabilities:
Accounts payable	$	66,289		32,496
Accounts payable, related parties		—		100,437
Accrued liabilities		465,070		392,726
Revenue distributions payable		310,827		231,152
Derivative instruments		532		—
Short-term lease liabilities		2,459		409,990
Other current liabilities		8,363		4,367
Total current liabilities		853,540		1,171,168
Long-term liabilities:
Long-term debt		5,461,688		3,703,828
Deferred income tax liability		650,788		916,031
Long-term lease liabilities		2,873		2,823,197
Other liabilities		63,098		59,366
Total liabilities		7,031,987		8,673,590
Commitments and contingencies (Notes 13 and 14)
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; 308,594 shares and 304,161 shares issued and outstanding at December 31, 2018 and September 30, 2019, respectively		3,086		3,041
Additional paid-in capital		6,485,174		6,124,042
Accumulated earnings		1,177,548		1,319,615
Total stockholders' equity		7,665,808		7,446,698
Noncontrolling interests in consolidated subsidiary		821,669		—
Total equity		8,487,477		7,446,698
Total liabilities and equity	$	15,519,464		16,120,288

See accompanying notes to the unaudited condensed consolidated financial statements.

4

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Operations and Comprehensive Loss

Three Months Ended September 30, 2018 and 2019

(Unaudited)

(In thousands, except per share amounts)

	Three Months Ended September 30,
	2018		2019
Revenue and other:
Natural gas sales	$	527,122		524,448
Natural gas liquids sales		338,269		284,958
Oil sales		59,722		40,561
Commodity derivative fair value gains		57,019		220,788
Gathering, compression, water handling and treatment		4,844		—
Marketing		89,598		46,645
Marketing derivative fair value losses		(42)		—
Other income		—		1,481
Total revenue		1,076,532		1,118,881
Operating expenses:
Lease operating		36,269		35,928
Gathering, compression, processing, and transportation		326,504		603,860
Production and ad valorem taxes		30,518		28,863
Marketing		151,764		108,216
Exploration		666		208
Impairment of oil and gas properties		221,094		1,041,469
Impairment of midstream assets		1,157		7,800
Depletion, depreciation, and amortization		243,186		241,503
Accretion of asset retirement obligations		710		927
General and administrative (including equity-based compensation expense of $16,202 and $3,875 in 2018 and 2019, respectively)		59,860		35,923
Contract termination and rig stacking		—		62
Total operating expenses		1,071,728		2,104,759
Operating income (loss)		4,804		(985,878)
Other income (expenses):
Equity in earnings (loss) of unconsolidated affiliates		10,705		(117,859)
Interest expense, net		(74,528)		(47,754)
Total other expenses		(63,823)		(165,613)
Loss before income taxes		(59,019)		(1,151,491)
Provision for income tax (expense) benefit		(18,953)		272,627
Net loss and comprehensive loss including noncontrolling interests		(77,972)		(878,864)
Net income and comprehensive income attributable to noncontrolling interests		76,447		—
Net loss and comprehensive loss attributable to Antero Resources Corporation	$	(154,419)		(878,864)
Loss per common share—basic and diluted	$	(0.49)		(2.86)
Weighted average number of shares outstanding:
Basic and diluted		317,082		307,781

See accompanying notes to the unaudited condensed consolidated financial statements.

5

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)

Nine Months Ended September 30, 2018 and 2019

(Unaudited)

(In thousands, except per share amounts)

	Nine Months Ended September 30,
	2018		2019
Revenue and other:
Natural gas sales	$	1,498,324		1,735,086
Natural gas liquids sales		828,424		902,606
Oil sales		128,869		137,675
Commodity derivative fair value gains		134,793		471,847
Gathering, compression, water handling and treatment		15,298		4,479
Marketing		394,189		200,911
Marketing derivative fair value gains		94,081		—
Other income		—		3,348
Total revenue and other		3,093,978		3,455,952
Operating expenses:
Lease operating		93,155		118,517
Gathering, compression, processing, and transportation		926,228		1,595,223
Production and ad valorem taxes		82,232		95,509
Marketing		560,924		408,839
Exploration		4,022		648
Impairment of oil and gas properties		406,068		1,253,712
Impairment of midstream assets		9,658		14,782
Depletion, depreciation, and amortization		709,480		724,006
Loss on sale of assets		—		951
Accretion of asset retirement obligations		2,101		2,821
General and administrative (including equity-based compensation expense of $56,429 and $19,327 in 2018 and 2019, respectively)		181,576		146,507
Contract termination and rig stacking		—		14,026
Total operating expenses		2,975,444		4,375,541
Operating income (loss)		118,534		(919,589)
Other income (expenses):
Equity in earnings (loss) of unconsolidated affiliates		27,832		(90,193)
Interest expense, net		(208,303)		(173,868)
Gain on deconsolidation of Antero Midstream Partners LP		—		1,406,042
Total other income (expenses)		(180,471)		1,141,981
Income (loss) before income taxes		(61,937)		222,392
Provision for income tax expense		(2,500)		(33,332)
Net income (loss) and comprehensive income (loss) including noncontrolling interests		(64,437)		189,060
Net income and comprehensive income attributable to noncontrolling interests		211,534		46,993
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$	(275,971)		142,067
Earnings (loss) per common share—basic	$	(0.87)		0.46
Earnings (loss) per common share—assuming dilution	$	(0.87)		0.46
Weighted average number of shares outstanding:
Basic		316,850		308,509
Diluted		316,850		308,646

6

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Equity

Three and 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.

7

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Equity

Three and Nine Months Ended September 30, 2019

(Unaudited)

(In thousands)

	Common Stock				Additional paid-		Accumulated		Noncontrolling		Total
	Shares		Amount		in capital		earnings		interests		equity
Balances, December 31, 2018		308,594	$	3,086		6,485,174		1,177,548		821,669		8,487,477
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		147		1		(451)		—		—		(450)
Issuance of common units in Antero Midstream Partners LP upon vesting of equity-based compensation awards, net of units withheld for income taxes		—		—		(85)		—		56		(29)
Equity-based compensation		—		—		7,801		—		1,102		8,903
Net income and comprehensive income		—		—		—		978,763		46,993		1,025,756
Distributions to noncontrolling interests		—		—		—		—		(85,076)		(85,076)
Effect of deconsolidation of Antero Midstream Partners LP		—		—		(359,039)		—		(784,744)		(1,143,783)
Balances, March 31, 2019		308,741	$	3,087		6,133,400		2,156,311		—		8,292,798
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		382		4		(1,819)		—		—		(1,815)
Equity-based compensation		—		—		6,549		—		—		6,549
Net income and comprehensive income		—		—		—		42,168		—		42,168
Balances, June 30, 2019		309,123	$	3,091		6,138,130		2,198,479		—		8,339,700
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		99		1		(86)		—		—		(85)
Repurchases and retirements of common stock		(5,061)		(51)		(17,877)		—		—		(17,928)
Equity-based compensation		—		—		3,875		—		—		3,875
Net loss and comprehensive loss		—		—		—		(878,864)		—		(878,864)
Balances, September 30, 2019		304,161	$	3,041		6,124,042		1,319,615		—		7,446,698

See accompanying notes to the unaudited condensed consolidated financial statements.

8

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Cash Flows

Nine Months Ended September 30, 2018 and 2019

(Unaudited)

(In thousands)

	Nine Months Ended September 30,
	2018		2019
Cash flows provided by (used in) operating activities:
Net income (loss) including noncontrolling interests	$	(64,437)		189,060
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, amortization, and accretion		711,581		726,827
Impairment of oil and gas properties		406,068		1,253,712
Impairment of midstream assets		9,658		14,782
Commodity derivative fair value gains		(134,793)		(471,847)
Gains on settled commodity derivatives		268,369		261,794
Marketing derivative fair value gains		(94,081)		—
Gains on settled marketing derivatives		78,098		—
Deferred income tax expense		2,500		32,019
Loss on sale of assets		—		951
Equity-based compensation expense		56,429		19,327
Equity in earnings (loss) of unconsolidated affiliates		(27,832)		90,193
Distributions/dividends of earnings from unconsolidated affiliates		29,660		109,241
Gain on deconsolidation of Antero Midstream Partners LP		—		(1,406,042)
Other		2,945		8,179
Changes in current assets and liabilities:
Accounts receivable		4,653		14,236
Accrued revenue		(53,888)		193,650
Other current assets		(3,721)		2,365
Accounts payable including related parties		8,177		(971)
Accrued liabilities		27,446		(11,169)
Revenue distributions payable		36,215		(72,176)
Other current liabilities		(2,649)		1,387
Net cash provided by operating activities		1,260,398		955,518
Cash flows provided by (used in) investing activities:
Additions to unproved properties		(130,381)		(69,796)
Drilling and completion costs		(1,125,660)		(957,931)
Additions to water handling and treatment systems		(77,385)		(24,416)
Additions to gathering systems and facilities		(337,448)		(48,239)
Additions to other property and equipment		(5,371)		(5,980)
Investments in unconsolidated affiliates		(91,419)		(25,020)
Proceeds from the Antero Midstream Partners LP Transactions		—		296,611
Change in other assets		(2,675)		7,461
Proceeds from asset sales		—		1,983
Net cash used in investing activities		(1,770,339)		(825,327)
Cash flows provided by (used in) financing activities:
Repurchases of common stock		—		(17,924)
Issuance of senior notes		—		650,000
Borrowings (repayments) on bank credit facilities, net		682,000		(45,000)
Payments of deferred financing costs		—		(8,259)
Distributions to noncontrolling interests in Antero Midstream Partners LP		(188,775)		(85,076)
Employee tax withholding for settlement of equity compensation awards		(8,205)		(2,379)
Other		(3,520)		(2,021)
Net cash provided by financing activities		481,500		489,341
Effect of deconsolidation of Antero Midstream Partners LP		—		(619,532)
Net decrease in cash and cash equivalents		(28,441)		—
Cash and cash equivalents, beginning of period		28,441		—
Cash and cash equivalents, end of period	$	—		—
Supplemental disclosure of cash flow information:
Cash paid during the period for interest	$	179,489		142,288
Increase (decrease) in accounts payable and accrued liabilities for additions to property and equipment	$	7,325		(22,103)

See accompanying notes to the unaudited condensed consolidated financial statements.

9

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

(1) Organization

Antero Resources Corporation (individually referred to as “Antero”) and its consolidated subsidiaries (collectively referred to as the “Company,” “we,” “us” or “our”) 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. 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, 2018 consolidated financial statements and notes thereto for a more complete understanding of the Company’s operations, financial position, and accounting policies. The December 31, 2018 consolidated financial statements have been filed with the Securities and Exchange Commission (“SEC”) in Antero’s 2018 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, 2018 and September 30, 2019, and the results of its operations and its cash flows for the three and nine months ended September 30, 2018 and 2019. The Company has 0 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, 2019 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.

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.

(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.

Through March 12, 2019, Antero Midstream Partners LP (“Antero Midstream Partners”), a publicly traded limited partnership, was included in the consolidated financial statements of Antero. Prior to the Closing (defined in Note 3 to the unaudited condensed consolidated financial statements), our ownership of Antero Midstream Partners common units represented approximately a 53% limited partner interest in Antero Midstream Partners, and we consolidated Antero Midstream Partners’ financial position and results of operations into our consolidated financial statements. The Transactions (defined in Note 3 to the unaudited condensed consolidated financial statements) resulted in the exchange of the limited partner interest we owned in Antero Midstream Partners for common stock of Antero Midstream Corporation representing an approximate 31% interest. As a result, we no longer hold a controlling interest in Antero Midstream Partners and we now have an interest in Antero Midstream Corporation that provides significant influence, but not control, over Antero Midstream Corporation. Thus, effective March 13, 2019, Antero no longer consolidates Antero Midstream Partners in its consolidated financial statements and accounts for its interest in Antero Midstream Corporation using the equity method of accounting. See Note 3 to the unaudited condensed consolidated financial statements for further discussion on the Transactions.

All significant intercompany accounts and transactions have been eliminated in the Company’s unaudited condensed consolidated financial statements. The noncontrolling interest in the Company’s unaudited condensed consolidated financial statements represents the interests in Antero Midstream Partners, which were owned by the public prior to the Transactions, and the incentive distribution rights in Antero Midstream Partners, in both cases during the periods prior to the Transactions. Noncontrolling

10

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

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. The Company’s judgment regarding the level of influence over its equity investments includes considering key factors such as Antero’s ownership interest, representation on the board of directors, and participation in the policy-making decisions of equity method investees. 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. When Antero records its proportionate share of net income, it increases equity income in the statements of operations and comprehensive income (loss) and the carrying value of that investment on the Company’s balance sheet. When a distribution is received, it is recorded as a reduction to the carrying value of that investment on the balance sheet. Our equity in earnings of unconsolidated affiliates is adjusted for intercompany transactions and the basis differences recognized due to the difference between the cost of the equity investment in Antero Midstream Corporation and the amount of underlying equity in the net assets of Antero Midstream Partners as of the date of deconsolidation.

The Company accounts for distributions received from equity method investees under the “nature of the distribution” approach. Under this approach, distributions received from equity method investees are classified on the basis of the nature of the activity or activities of the investee that generated the distribution as either a return on investment (classified as cash inflows from operating activities) or a return of investment (classified as cash inflows from investing activities).

(c) Use of Estimates

The preparation of the unaudited condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that 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 that involve the use of significant estimates include derivative assets and liabilities, accrued revenue, deferred and current income taxes, equity-based compensation, asset retirement obligations, depreciation, amortization, and commitments and contingencies.

(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 in 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, 2019, the book overdraft included within accounts payable and revenue distributions payable were $8 million and $34 million, respectively. As of December 31, 2018, the book overdraft included within accounts payable and revenue distributions payable were $10 million and $28 million, respectively.

11

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

(f) Oil and Gas Properties

The Company accounts for its natural gas, NGLs, and oil exploration and development activities under the successful efforts method of accounting. Under the successful efforts method, the costs incurred to acquire, drill, and complete productive wells, development wells, and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel and other internal costs, geological and geophysical expenses, delay rentals for gas and oil leases, and costs associated with unsuccessful lease acquisitions are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if the Company determines that the well does not contain reserves in commercially viable quantities. The Company reviews exploration costs related to wells-in-progress at the end of each quarter and makes a determination, based on known results of drilling at that time, whether the costs should continue to be capitalized pending further well testing and results, or charged to expense. The Company incurred 0 such charges to expense during the nine months ended September 30, 2018 and 2019. During the nine months ended September 30, 2019, we recorded an impairment charge of $26 million for design and initial costs related to pads that are no longer planned to be placed into service. The sale of a partial interest in a proved property is accounted for as a cost recovery, and no gain or loss is recognized as long as this treatment does not significantly affect the units-of-production amortization rate. A gain or loss is recognized for all other sales of producing properties.

Unproved properties are assessed for impairment on a property-by-property basis, and any impairment in value is charged to expense. Impairment is assessed based on remaining lease terms, commodity price outlooks, and future plans to develop acreage, as well as drilling results, and reservoir performance of wells in the area. Unproved properties and the related costs are transferred to proved properties when reserves are discovered on, or otherwise attributed to, the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of cost without recognition of any gain or loss until the cost has been recovered. Impairment of unproved properties was $406 million and $347 million for the nine months ended September 30, 2018 and 2019, respectively.

The Company evaluates the carrying amount of its 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 exceeds the estimated undiscounted future cash flows, the Company would estimate the fair value of its properties and record an impairment charge for any excess of the carrying amount of the properties over the estimated fair value of the properties. Factors used to estimate fair value may include estimates of proved reserves, estimated future commodity prices, future production estimates, and anticipated capital expenditures, using a commensurate discount rate.

As estimated undiscounted future net cash flows based on future commodity prices at September 30, 2019 exceeded the carrying amount of our proved properties in the Marcellus Shale at September 30, 2019, we did not further evaluate our Marcellus proved properties for impairment. However, the carrying amount of the Utica Shale exceeded the estimated undiscounted future cash flows based on future commodity prices at September 30, 2019. We estimated the fair value of the Utica Shale assets based on sales of other properties, estimates of proved reserves, estimated future commodity prices, and future production estimates. As a result, the Company recorded an impairment charge of $881 million related to proved properties in the Utica Shale during the three months ended September 30, 2019. The Company did not record any impairment expenses associated with its proved properties in the Marcellus Shale during the nine months ended September 30, 2018 and 2019.

During the three months ended September 30, 2019, Antero completed a non-cash exchange of acreage and ownership interest in certain properties in West Virginia whereby the Company received 20,770 net acres primarily in Tyler and Wetzel Counties and delivered 18,857 net acres primarily in Wetzel and Marion Counties. In conjunction with the non-cash exchange, the Company also assumed certain gas gathering and processing obligations related to a portion of some of the properties. This exchange did not have a material impact on the timing and amount of future cash flows and 0 gain or loss was recorded related to this transaction.

(g) 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.

12

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

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.

(h) 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. 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.

(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) marketing and utilization of excess firm transportation capacity and (3) our equity method investment in Antero Midstream Corporation. Through March 12, 2019, the results of Antero Midstream Partners were included in the consolidated financial statements of Antero. Effective March 13, 2019, the results of Antero Midstream Partners are no longer consolidated in Antero’s results; however, the Company’s segment disclosures include our equity method investment in Antero Midstream Corporation due to its significance to the Company’s operations. See Note 3 to the unaudited condensed consolidated financial statements for further discussion on the Transactions and Note 17 to the unaudited condensed consolidated financial statements for disclosures on the Company’s reportable segments.

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 then transport the Company’s production to foreign countries for resale or consumption. Our revenues received from these customers are denominated in U.S. dollars and are based on pricing in foreign markets.

(j) Earnings (loss) Per Common Share

Earnings (loss) per common share—basic for each period is computed by dividing net income (loss) attributable to Antero by the basic weighted average number of shares outstanding during the period. Earnings (loss) 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 anti-dilutive.

13

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

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,
	2018	2019	2018	2019
Basic weighted average number of shares outstanding	317,082	307,781	316,850	308,509
Add: Dilutive effect of restricted stock units	—	—	—	27
Add: Dilutive effect of outstanding stock options	—	—	—	—
Add: Dilutive effect of performance stock units	—	—	—	110
Diluted weighted average number of shares outstanding	317,082	307,781	316,850	308,646
Weighted average number of outstanding equity awards excluded from calculation of diluted earnings per common share (1):
Restricted stock units	2,813	2,356	2,996	2,008
Outstanding stock options	619	514	637	541
Performance stock units	1,880	2,676	1,665	2,141

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

(k) Treasury Share Retirement

The Company retires treasury shares acquired through share repurchases and returns those shares to the status of authorized but unissued. When treasury shares are retired, the Company’s policy is to allocate the excess of the repurchase price over the par value of shares acquired first, to additional paid-in capital, and then to accumulated earnings. The portion allocable to additional paid-in capital is determined by applying a percentage, determined by dividing the number of shares to be retired by the number of shares outstanding, to the balance of additional paid-in capital as of retirement.

(l) Adoption of New Accounting Principle

The Company adopted ASU No. 2016-02, Leases, (“Topic 842”) as of January 1, 2019, using the effective date method.  The effective date method allows the Company to report its leases under Topic 842 prospectively as of the date of adoption, and no retrospective adjustments were required for prior periods.

The Company elected the available practical expedients and updated internal controls to enable the preparation of financial information on adoption.

The standard had a material impact on our consolidated balance sheets, but did not have a material impact on our consolidated statements of operations.  The most significant impact was the recognition of operating leases right-of-use assets and short-term and long-term lease liabilities for operating leases, while our accounting for finance leases remained substantially unchanged.  See Note 12 to the unaudited condensed consolidated financial statements for a description of the Company’s leases.

(3) Deconsolidation of Antero Midstream Partners LP

In 2014, the Company formed Antero Midstream Partners to own, operate, and develop midstream energy assets that service Antero’s production. Antero Midstream Partners’ 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.

On March 12, 2019, Antero Midstream GP LP and Antero Midstream Partners completed (the “Closing”) the transactions contemplated by the Simplification Agreement (the “Simplification Agreement”), dated as of October 9, 2018, by and among Antero Midstream GP LP, Antero Midstream Partners and certain of their affiliates, pursuant to which (i) Antero Midstream GP LP was converted from a limited partnership to a corporation under the laws of the State of Delaware and changed its name to Antero Midstream Corporation, and (ii) an indirect, wholly owned subsidiary of Antero Midstream Corporation was merged with and into Antero Midstream Partners, with Antero Midstream Partners surviving the merger as an indirect, wholly owned subsidiary of Antero Midstream Corporation (together, along with the other transactions contemplated by the Simplification Agreement, the

14

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

“Transactions”). In connection with the Closing, Antero received $297 million in cash and 158.4 million shares of Antero Midstream Corporation’s common stock, par value $0.01 per share, in consideration for 98,870,335 common units representing limited partnership interests in Antero Midstream Partners.

Prior to the Closing, the Company’s ownership of Antero Midstream Partners common units represented approximately a 53% limited partner interest in Antero Midstream Partners, and the Company consolidated Antero Midstream Partners’ financial position and results of operations into its consolidated financial statements. The Transactions resulted in the exchange of limited partner interests in Antero Midstream Partners owned by Antero for common stock of Antero Midstream Corporation representing an approximate 31% interest. As a result, the Company no longer holds a controlling interest in Antero Midstream Partners and the Company now has an interest in Antero Midstream Corporation that provides significant influence, but not control, over Antero Midstream Corporation. Thus, effective March 13, 2019, the Company no longer consolidates Antero Midstream Partners in our consolidated financial statements and accounts for its interest in Antero Midstream Corporation using the equity method of accounting. In addition, the Company recorded a gain on deconsolidation of $1.4 billion calculated as the sum of (i) the cash proceeds received, (ii) the fair value of the Antero Midstream Corporation common stock received at the Closing, and (iii) the elimination of the noncontrolling interest, less the carrying amount of the investment in Antero Midstream Partners. The fair value of Antero’s retained equity method investment on March 13, 2019 in Antero Midstream Corporation was $2.0 billion based on the market price of the shares received on March 12, 2019. See Note 5 to the unaudited condensed consolidated financial statements for further discussion on equity method investments.

Antero Midstream Partners’ results of operations are no longer consolidated in the Company’s consolidated statement of operations and comprehensive income (loss) beginning March 13, 2019. Because Antero Midstream Partners does not meet the requirements of a discontinued operation, Antero Midstream Partners’ results of operations continue to be included in the Company’s consolidated statement of operations and comprehensive income (loss) through March 12, 2019.

Summarized Financial Information of Antero Midstream Partners

The following table presents a summary of assets and liabilities of Antero Midstream Partners as of March 12, 2019, the date of deconsolidation.

(in thousands)	March 12, 2019
Current assets	$	763,109
Property and equipment, net		3,003,693
Other noncurrent assets		501,208
Total assets	$	4,268,010
Current liabilities	$	123,473
Long-term debt		2,359,084
Other noncurrent liabilities		123,523
Total liabilities	$	2,606,080
Net assets	$	1,661,930

(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 sale.

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

15

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

Midstream Partners 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 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 purchasers 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 a purchaser.

Gathering, compression, water handling and treatment revenue

Substantially all revenues from the gathering, compression, water handling and treatment operations were derived from transactions for services Antero Midstream Partners provided to our exploration and production operations through March 12, 2019 and were eliminated in consolidation. Effective March 13, 2019, Antero Midstream Partners is no longer consolidated in Antero’s results. See Note 3 to the unaudited condensed consolidated financial statements for further discussion on the Transactions and Note 17 to the unaudited condensed consolidated financial statements for disclosures on the Company’s reportable segments. The portion of such fees shown in our consolidated financial statements prior to March 13, 2019 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 Partners or usage of Antero Midstream Partners’ gathering and compression systems. For gathering and compression revenue, Antero Midstream Partners 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 Partners in accordance with the gathering and compression agreement. For water handling and treatment revenue, Antero Midstream Partners 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 Partners’ 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 Partners 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. We have 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. Fees generated from the sale of excess firm transportation marketed to third parties are included in revenue.

16

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

(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 17— Segment Information.

	Three months ended September 30,				Nine months ended September 30,				Segment to which
	2018		2019		2018		2019		revenues relate
Revenues from contracts with customers:
Natural gas sales	$	527,122		524,448	$	1,498,324		1,735,086	Exploration and production
Natural gas liquids sales (ethane)		56,185		26,488		115,947		92,378	Exploration and production
Natural gas liquids sales (C3+ NGLs)		282,084		258,470		712,477		810,228	Exploration and production
Oil sales		59,722		40,561		128,869		137,675	Exploration and production
Gathering and compression (1)		4,439		—		12,848		3,972	Equity method investment in AMC
Water handling and treatment (1)		405		—		2,450		507	Equity method investment in AMC
Marketing		89,598		46,645		394,189		200,911	Marketing
Total		1,019,555		896,612		2,865,104		2,980,757
Income from derivatives and other sources		56,977		222,269		228,874		475,195
Total revenue and other	$	1,076,532		1,118,881	$	3,093,978		3,455,952

(1) Gathering and compression and water handling and treatment revenues were included through March 12, 2019. See Note 3 to the unaudited condensed consolidated financial statements for further discussion on the Transactions.

(c)   Transaction Price Allocated to Remaining Performance Obligations

For our product sales that have a contract term greater than one year, we have utilized the practical expedient in ASC 606, which does not require the disclosure of 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 does not require the disclosure of 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, 2018 and September 30, 2019, our receivables from contracts with customers were $475 million and $281 million, respectively.

(5) Equity Method Investments

At September 30, 2019, Antero owned approximately 31.5% of Antero Midstream Corporation’s common stock, which is reflected in Antero’s consolidated financial statements using the equity method of accounting. See Note 3 to the unaudited condensed consolidated financial statements for further discussion on the Transactions.

Prior to March 13, 2019, our consolidated results included 2 equity method investments held by Antero Midstream Partners: a 15% equity interest in Stonewall Gas Gathering LLC (“Stonewall”), which operates a regional gathering pipeline on which Antero is an anchor shipper, and a 50% interest in the joint venture entered into on February 6, 2017 between Antero Midstream Partners and MarkWest Energy Partners, L.P. (“MarkWest”), a wholly owned subsidiary of MPLX, LP, to develop processing and fractionation assets in Appalachia (the “Joint Venture”). Effective March 13, 2019, the equity in earnings of these investments are accounted for in the equity in earnings of Antero Midstream Corporation.

17

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

The following table is a reconciliation of investments in unconsolidated affiliates for the nine months ended September 30, 2019 (in thousands):

	Stonewall (1)		MarkWest Joint Venture		Antero Midstream Corporation (2)		Total
Balance at December 31, 2018	$	68,103		365,539		—		433,642
Investments (3)		—		25,020		—		25,020
Equity in net income of unconsolidated affiliates		1,894		10,370		(102,457)		(90,193)
Distributions/dividends from unconsolidated affiliates		(3,000)		(9,605)		(96,636)		(109,241)
Elimination of intercompany profit		—		—		30,621		30,621
Effects of deconsolidation (4)		(66,997)		(391,324)		1,987,795		1,529,474
Balance at September 30, 2019	$	—		—		1,819,323		1,819,323

(1) Distributions are net of operating and capital requirements retained by Stonewall.

(2) As adjusted for the amortization of the difference between the cost of the equity investment in Antero Midstream Corporation and the amount of underlying equity in the net assets of Antero Midstream Partners as of the date of deconsolidation.

(3) Investments in the Joint Venture during the nine months ended September 30, 2019 relate to capital contributions for construction of additional processing facilities.

(4) Effective March 13, 2019, the equity in earnings of Stonewall and the Joint Venture are accounted for in the equity in earnings of Antero Midstream Corporation.

Summarized Financial Information of Antero Midstream Corporation

The following tables present summarized financial information of Antero Midstream Corporation. Summarized financial information is presented from March 13, 2019.

Balance Sheet

(in thousands)	September 30, 2019
Current assets	$	109,224
Noncurrent assets		6,336,280
Total assets	$	6,445,504
Current liabilities	$	259,628
Noncurrent liabilities		2,662,846
Stockholders' equity		3,523,030
Total liabilities and equity	$	6,445,504

Statement of Operations

	For the period
		March 13, 2019 through
(in thousands)	September 30, 2019
Revenues	$	553,521
Operating expenses		745,940
Loss from operations	$	(192,419)
Net loss attributable to the equity method investments	$	(197,006)

18

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

(6) Accrued Liabilities

Accrued liabilities as of December 31, 2018 and September 30, 2019 consisted of the following items (in thousands):

	December 31, 2018		September 30, 2019
Capital expenditures	$	113,237		83,963
Gathering, compression, processing, and transportation expenses		148,032		141,036
Marketing expenses		67,082		47,763
Interest expense, net		43,444		62,255
Other		93,275		57,709
	$	465,070		392,726

(7) Long-Term Debt

Long-term debt was as follows at December 31, 2018 and September 30, 2019 (in thousands):

	December 31, 2018		September 30, 2019
Antero Resources:
Credit Facility (a)	$	405,000		275,000
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		1,241		1,021
Net unamortized debt issuance costs		(26,700)		(22,193)
Long-term debt		3,829,541		3,703,828
Antero Midstream Partners:
Midstream Credit Facility (1)		990,000		—
5.375% senior notes due 2024 (1)		650,000		—
Net unamortized debt issuance costs (1)		(7,853)		—
Long-term debt		1,632,147		—
Consolidated long-term debt	$	5,461,688		3,703,828

(1) At December 31, 2018, Antero Midstream Partners’ indebtedness was included in the consolidated financial statements of Antero. At September 30, 2019, following the deconsolidation, Antero Midstream Partners’ outstanding indebtedness is no longer reflected in Antero’s consolidated financial statements. See Note 3 to the unaudited condensed consolidated financial statements for further discussion on the Transactions.

(a) Senior Secured Revolving Credit Facility

Antero has a senior secured revolving credit facility (the “Credit Facility”) 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, 2019, 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 2019. The next redetermination of the borrowing base is scheduled to occur in April 2020. 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.

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 (i) a BBB- or better rating from Standard and Poor’s and (ii) a Baa3 or better rating from Moody’s (an “Investment Grade Rating”). An Investment Grade Period can end at Antero’s election.

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ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

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, Antero’s and Antero Subsidiary Holdings LLC’s ownership interests in Antero Midstream Corporation, 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, 2018 and September 30, 2019.

At September 30, 2019, Antero had an outstanding balance under the Credit Facility of $275 million and outstanding letters of credit of $703 million. At December 31, 2018, Antero had an outstanding balance under the Credit Facility of $405 million and outstanding letters of credit of $685 million. The average annualized interest rate incurred on the Credit Facility during the nine months ended September 30, 2019 was approximately 4.39%. 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 101.344% currently to 100.00% on or after November 1, 2019. If Antero undergoes a change of control followed by a rating decline, 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.

(c) 5.125% Senior Notes Due 2022

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 101.281% currently to 100.00% on or after June 1, 2020. If Antero undergoes a change of control followed by a rating decline, 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 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 102.813% to 100.00% on or after June 1, 2021. If Antero undergoes a change of control followed by a rating decline, 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.

20

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

(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 followed by a rating decline, 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 that is also part of the Credit Facility lending consortium that 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, 2020. At December 31, 2018, there was $5.4 million in outstanding borrowings under the revolving note included in “Other current liabilities” on the Company’s Consolidated Balance Sheet. At September 30, 2019, there were 0 outstanding borrowings under the revolving note.

(8) Asset Retirement Obligations

The following is a reconciliation of the Company’s asset retirement obligations for the nine months ended September 30, 2019 (in thousands):

Asset retirement obligations—December 31, 2018	$	58,979
Obligations settled		(153)
Obligations incurred		1,361
Revisions to prior estimates		—
Accretion expense		2,821
Effect of deconsolidation of Antero Midstream Partners LP (1)		(7,518)
Asset retirement obligations—September 30, 2019	$	55,490

(1)Effective March 13, 2019, Antero Midstream Partners is no longer consolidated in Antero’s results.

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 6,046,007 shares were available for future grant under the Plan as of September 30, 2019.

Antero Midstream Partners’ general partner was authorized to grant up to 10,000,000 common units representing limited partner interests in Antero Midstream Partners under the Antero Midstream Partners LP Long-Term Incentive Plan (the “AMP Plan”) to non-employee directors of its general partner and certain officers, employees, and consultants of Antero Midstream Partners and its affiliates (which include Antero). As part of the Transactions, each of the outstanding phantom units in the AMP Plan, whether vested

21

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

or unvested, were assumed by Antero Midstream Corporation and converted into restricted stock units under the Antero Midstream Corporation Long Term Incentive Plan (the “AMC Plan”) representing a right to receive 1.8926 shares of Antero Midstream Corporation’s Common Stock, par value $0.01 per share (“Antero Midstream Corporation Common Stock”), for each converted phantom unit.

On March 12, 2019, the Board of Antero Midstream Corporation adopted the AMC Plan under which awards may be granted to employees, directors and other service providers of Antero and its affiliates. The AMC Plan provides for the grant of stock options, stock appreciation rights, restricted stock, restricted stock units, dividend equivalents, other stock-based awards, cash awards and substitute awards.

The Company’s equity-based compensation expense, by type of award, was as follows for the three and nine months ended September 30, 2018 and 2019 (in thousands):

	Three months ended September 30,				Nine months ended September 30,
	2018		2019		2018		2019
Restricted stock unit awards	$	10,001		2,229	$	33,676		8,829
Stock options		452		—		1,428		389
Performance share unit awards		1,017		399		7,018		6,027
Antero Midstream Partners phantom unit awards (1)		4,193		867		12,752		2,942
Equity awards issued to directors		539		380		1,555		1,140
Total expense	$	16,202		3,875	$	56,429		19,327

(1)Antero recognized compensation expense for equity awards granted under both the Plan and the AMP Plan because the awards under the AMP Plan are accounted for as if they are distributed by Antero Midstream Partners to Antero. Antero allocates a portion of equity-based compensation expense related to grants prior to the Transactions to Antero Midstream Partners based on its proportionate share of Antero’s labor costs. Through March 12, 2019, the total amount of equity-based compensation is included in the consolidated financial statements of Antero; and effective March 13, 2019 (date of deconsolidation), the amount allocated to Antero Midstream Partners is no longer reflected in Antero’s consolidated financial statements. See Note 3 to the unaudited condensed consolidated financial statements for further discussion on the Transactions.

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 Antero’s common stock on the date of the grant.

A summary of restricted stock unit award activity for the nine months ended September 30, 2019 is as follows:

		Weighted average		Aggregate
	Number of shares	grant date fair value		intrinsic value (in thousands)
Total awarded and unvested—December 31, 2018	1,712,485	$	24.57	$	16,080
Granted	1,610,690	$	8.60
Vested	(718,192)	$	27.70
Forfeited	(307,938)	$	16.56
Total awarded and unvested—September 30, 2019	2,297,045	$	13.47	$	6,937

Intrinsic values are based on the closing price of Antero’s common stock on the referenced dates. As of September 30, 2019, there was $25 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 2.6 years.

22

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

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 Antero’s common stock on the dates of grant.

A summary of stock option activity for the nine months ended September 30, 2019 is as follows:

				Weighted
		Weighted average		average remaining	Intrinsic
	Stock options	exercise price		contractual life	value (in thousands)
Outstanding at December 31, 2018	579,617	$	50.55	5.81	$	—
Granted	—	$	—
Exercised	—	$	—
Forfeited	(79,484)	$	50.25
Expired	—	$	—
Outstanding at September 30, 2019	500,133	$	50.60	4.98	$	—
Vested or expected to vest as of September 30, 2019	500,133	$	50.60	4.98	$	—
Exercisable at September 30, 2019	500,133	$	50.60	4.98	$	—

Intrinsic values are based on the exercise price of the options and the closing price of Antero’s common stock on the referenced dates.

A Black Scholes option pricing model is used to determine the grant-date fair value of stock options. Expected volatility was derived from the volatility of the historical stock prices of a peer group of similar publicly traded companies’ stock prices as Antero’s common stock had traded for a relatively short period of time at the dates the options were granted. The risk free interest rate was determined using the implied yield available for zero coupon U.S. government issues with a remaining term approximating the expected life of the options. A dividend yield of zero was assumed.

As of September 30, 2019, there was 0 unamortized equity-based compensation expense because all stock options were fully vested.

Performance Share Unit Awards

Performance Share Unit Awards Based on Stock Price Targets

In 2016, the Company granted performance share unit awards (“PSUs”) to certain of its executive officers that are based on stock price targets. The vesting of these PSUs is conditioned on the closing price of Antero’s common stock achieving specific price thresholds over 10-day periods, subject to the following vesting restrictions: 0 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. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period.

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 Antero’s common stock relative to the TSR of a peer group of companies over a three-year performance period. The number of shares of common stock which may ultimately be earned ranges from 0 to 200% of the PSUs granted. Expense related to these PSUs is recognized on a straight-line basis over three years. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period.

23

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

In 2019, the Company granted PSUs to certain of its employees and executive officers that vest based on Antero’s absolute TSR, with target payout achieved if the price per share of Antero’s common stock reaches 125% of the beginning price (as defined in the award agreement) at the end of a three-year performance period. The number of shares of common stock which may ultimately be earned ranges from 0 to 200% of the PSUs granted. Expense related to these PSUs is recognized on a straight-line basis over three years. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period.

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 absolute TSR, with target payout achieved if the price per share of Antero’s common stock reaches 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 Antero’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 0 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. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period.

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 0 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.

Summary Information for Performance Share Unit Awards

A summary of PSU activity for the nine months ended September 30, 2019 is as follows:

	Number of units	Weighted average grant date fair value
Total awarded and unvested—December 31, 2018	1,767,299	$	26.36
Granted	1,416,378	$	9.26
Vested	(31,944)	$	27.38
Forfeited	(614,450)	$	26.61
Total awarded and unvested—September 30, 2019	2,537,283	$	16.74

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 Antero’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, 2018 and 2019, and the assumptions used to determine the fair values:

	Nine months ended September 30,
	2018			2019
Dividend yield		—	%		—	%
Volatility		41	%		36	%
Risk-free interest rate		2.49	%		2.35	%
Weighted average fair value of awards granted	$	24.85		$	9.26

24

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

As of September 30, 2019, there was $20 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 1.9 years.

Antero Midstream Partners Phantom Unit Awards and Antero Midstream Corporation Restricted Stock Unit Awards

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

In connection with the closing of the Transactions, the Board of Antero Midstream Corporation adopted the AMC Plan. In accordance with the terms of the Transactions, each of the outstanding units in the AMP Plan, whether vested or unvested, was assumed by Antero Midstream Corporation and converted into restricted stock units under the AMC Plan at 1.8926 shares of Antero Midstream Corporation Common Stock LTIP for each converted phantom unit.

A summary of phantom unit awards activity for the nine months ended September 30, 2019 is as follows:

	Number of units	Weighted average grant date fair value		Aggregate intrinsic value (in thousands)
Total awarded and unvested—December 31, 2018	583,000	$	27.63	$	12,470
Granted	5,972	$	23.44
Vested	(3,853)	$	32.44
Forfeited	(20,338)	$	26.73
AMP Plan Units awarded and unvested—March 12, 2019	564,781	$	27.59	$	13,476
Effect of conversion (1)	504,119	$	14.58
Vested	(358,831)	$	14.34
Forfeited	(45,803)	$	14.58
Total awarded and unvested—September 30, 2019	664,266	$	14.70	$	4,916

(1)Effective March 12, 2019, all outstanding units in the AMP Plan, whether vested or unvested, were assumed by Antero Midstream Corporation and converted into restricted stock units under the AMC Plan.

Intrinsic values are based on the closing price of shares of Antero Midstream Corporation’s common stock or Antero

Midstream Partners’ common units, as applicable, on the referenced dates. As of September 30, 2019, there was $7.6 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 1.9 years.

(10) Financial Instruments

The carrying values of accounts receivable and accounts payable at December 31, 2018 and September 30, 2019 approximated market values because of their short-term nature. The carrying values of the amounts outstanding under the Credit Facility and Antero Midstream Partners’ credit facility at December 31, 2018 and the Credit Facility at September 30, 2019 approximated fair value because the variable interest rates are reflective of current market conditions.

25

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

Based on Level 2 market data inputs, the fair value of senior notes was approximately $3.9 billion and $3.1 billion at December 31, 2018 and September 30, 2019, respectively.

See Note 11 to the unaudited condensed consolidated financial statements 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, 2018 and 2019. 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. In addition, the Company has entered into basis swap contracts in order to hedge the difference between the New York Mercantile Exchange (“NYMEX”) index price and a local index price.

The Company also entered into NGL contracts, which establish a contractual price for the settlement month as a fixed percentage of the West Texas Intermediate Crude Oil index (“WTI”) price for the settlement month. When the percentage of the contractual price is above the contracted percentage, the Company pays the difference to the counterparty. When it is below the contracted percentage, the Company receives the difference from the counterparty.

In addition, the Company has entered into natural gas collar contracts, which establish ceiling and floor prices for the sale of notional volumes of natural gas as specified in the collar contracts. Under these contracts, the Company pays the difference between the ceiling price and the published index price in the event the published index price is above the ceiling price. When the published index price is below the floor price, the Company receives the difference between the floor price and the published index price. No amounts are paid or received if the index price is between the floor and the ceiling prices. The index prices in our collars are consistent with the index prices used to sell our production.

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

26

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

As of September 30, 2019, the Company’s fixed price natural gas, oil and NGL swap positions from October 1, 2019 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; NYMEX-WTI=West Texas Intermediate; ARA Butane =European Butane CIF ARA; FEI Butane = Butane Far East Asia Index; ARA Propane =European Propane CIF ARA; FEI Propane = Propane Far East Asia Index; Mont Belvieu Propane Non-TET=Mont Belvieu Propane; Mont Belvieu Butane Non-TET=Mont Belvieu Butane; Mont Belvieu Natural Gasoline Non-TET=Mont Belvieu Natural Gasoline):

	Natural gas MMBtu/day	Natural Gas Liquids Bbls/day	Oil Bbls/day	Weighted average index price
Three months ending December 31, 2019:
NYMEX ($/MMBtu)	996,766	—	—	$	3.23
ARA Propane ($/Gal)	—	10,113	—		0.68
FEI Propane ($/Gal)	—	9,809	—		0.81
Mont Belvieu Propane Non-TET ($/Gal)	—	8,000	—		0.50
Mont Belvieu Butane Non-TET ($/Gal)	—	4,000	—		0.59
Mont Belvieu Natural Gasoline Non-TET ($/Gal)	—	3,500	—		1.14
NYMEX-WTI ($/Bbl)	—	—	18,000		59.05
Total	996,766	35,422	18,000
Year ending December 31, 2020:
NYMEX ($/MMBtu)	2,227,500		—	$	2.87
ARA Propane ($/Gal)	—	9,761	—		0.65
FEI Propane ($/Gal)	—	2,045	—		0.81
Mont Belvieu Butane Non-TET ($/Gal)	—	2,000	—		0.57
NYMEX-WTI ($/Bbl)	—		12,000		56.60
Total	2,227,500	13,806	12,000
Year ending December 31, 2021:
NYMEX ($/MMBtu)	2,110,000			$	2.79
Year ending December 31, 2022:
NYMEX ($/MMBtu)	290,000			$	2.96
Year ending December 31, 2023:
NYMEX ($/MMBtu)	90,000			$	2.91

27

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

As of September 30, 2019, the Company’s natural gas basis swap positions, which settle on the pricing index to basis differential of TCO to the NYMEX Henry Hub natural gas price, and NGL basis swap positions, which settle on the pricing index to basis differential of Mont Belvieu Butane to the European Butane CIF ARA natural gas liquids price, were as follows:

	Natural gas MMBtu/day	Natural Gas Liquids Bbls/day	Weighted average hedged differential
Three months ending December 31, 2019:
ARA to Mont Belvieu Non-TET ($/Gal)	—	4,050	$	0.25
Year ending December 31, 2020:
NYMEX to TCO ($/MMBtu)	60,000	—		0.353
ARA to Mont Belvieu Non-TET ($/Gal)	—	4,273	$	0.23
Total	60,000	4,273
Year ending December 31, 2021:
NYMEX to TCO ($/MMBtu)	40,000	—	$	0.414
Year ending December 31, 2022:
NYMEX to TCO ($/MMBtu)	60,000	—	$	0.515
Year ending December 31, 2023:
NYMEX to TCO ($/MMBtu)	50,000	—	$	0.525
Year ending December 31, 2024:
NYMEX to TCO ($/MMBtu)	50,000	—	$	0.530

As of September 30, 2019, the Company had natural gas and NGL contracts for October 1, 2019 through December 31, 2021 that fix the Mont Belvieu index price to percentages of WTI as follows:

	Natural Gas Liquids Bbls/day	Weighted average payout ratio
Three months ending December 31, 2019:
Mont Belvieu Propane to NYMEX-WTI	500		50	%
Mont Belvieu Natural Gasoline to NYMEX-WTI	13,900		81	%
Total	14,400
Year ending December 31, 2020:
Mont Belvieu Propane to NYMEX-WTI	500		50	%
Mont Belvieu Natural Gasoline to NYMEX-WTI	15,000		79	%
Total	15,500
Year ending December 31, 2021:
Mont Belvieu Natural Gasoline to NYMEX-WTI	13,000		78	%

As of September 30, 2019, the Company’s fixed price natural gas collar positions from October 1, 2019 through December 31, 2019 were as follows (abbreviations in the table refer to the index to which the collar position is tied, as follows (NYMEX=Henry Hub):

	Natural gas (MMBtu/day)				Weighted average index price
	Ceiling		Floor		Ceiling price		Floor price
Three months ending December 31, 2019:
NYMEX ($/MMBtu)		1,575,000		1,333,234	$	3.52	$	2.50

An initial premium of $13 million was paid at the inception of natural gas collar contracts with one counterparty, and is recorded as a derivative asset measured at fair value. As of September 30, 2019, the unamortized portion of the premium was $4.5 million.

28

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

(b) Marketing Derivatives

In 2017, due to delay of the in-service date for a pipeline on which the Company is 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.

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. For the three and nine months ended September 30, 2018, the Company recognized a fair value loss of less than $1 million and a gain of $94 million, respectively. There were 0 marketing derivative fair value gains or losses during the three or nine months ended September 30, 2019.

(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, 2018 and September 30, 2019. NaN of the Company’s derivative instruments are designated as hedges for accounting purposes.

	December 31, 2018			September 30, 2019
	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	$	245,263	Derivative instruments	$	411,774
Commodity derivatives - noncurrent	Derivative instruments		362,169	Derivative instruments		405,180
Total asset derivatives			607,432			816,954
Liability derivatives not designated as hedges for accounting purposes:
Commodity derivatives - current	Derivative instruments		532	Derivative instruments		—
Commodity derivatives - noncurrent	Derivative instruments		—	Derivative instruments		—
Total liability derivatives			532			—
Net derivatives		$	606,900		$	816,954

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, 2018						September 30, 2019
	Gross amounts on balance sheet		Gross amounts offset on balance sheet		Net amounts of assets (liabilities) 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	$	658,830		(51,398)		607,432	$	838,795		(21,841)		816,954
Commodity derivative liabilities	$	(51,930)		51,398		(532)	$	(21,841)		21,841		—

29

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

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 (in thousands):

	Statement of operations	Three months ended September 30,				Nine months ended September 30,
	location	2018		2019		2018		2019
Commodity derivative fair value gains	Revenue	$	57,019		220,788		134,793		471,847
Marketing derivative fair value gains (losses)	Revenue	$	(42)		—		94,081		—

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

(12) Leases

On February 25, 2016, the FASB issued Accounting Standard Update (“ASU”) No. 2016-02, Leases, which requires lessees to record lease liabilities and right-of-use assets as of the date of adoption and was incorporated into GAAP as Accounting Standards Codification (“ASC”) Topic 842.  The new lease standard does not substantially change accounting by lessors.  The Company adopted the new standard effective January 1, 2019. The Company is a lessee to both operating and finance lease arrangements. The standard resulted in an increased in assets and liabilities related to our operating leases.

The Company leases certain office space, processing plants, drilling rigs and completion services, gas gathering lines, compressor stations, and other office and field equipment. Leases with an initial term of 12 months or less are considered short-term and are not recorded on the balance sheet. Instead, the short-term leases are recognized in expense on a straight-line basis over the lease term.

Most leases include one or more options to renew, with renewal terms that can extend the lease from one to 20 years or more. The exercise of the lease renewal options are at the Company’s sole discretion. The depreciable lives of the leased assets are limited by the expected lease term, unless there is a transfer of title or purchase option reasonably certain of exercise.

Certain of the Company’s lease agreements include minimum payments based on a percentage of produced volumes over contractual levels and others include rental payments adjusted periodically for inflation.

The Company has elected the effective date method for adoption of the new leasing standard under Topic 842. This method allows the Company to not make retrospective adjustments for leases that were in effect prior to the adoption date of January 1, 2019 when disclosing comparable prior periods, but instead, account for the prior period leases under Topic 840, which was the guidance in place at the time of the original reporting.

The Company considers all contracts that have assets specified in the contract, either explicitly or implicitly, that the Company has substantially all of the capacity of the asset, and has the right to obtain substantially all of the economic benefits of that asset, without the lessor’s ability to have a substantive right to substitute that asset, as leased assets under Topic 842. For any contract deemed to include a leased asset, that asset is capitalized on the balance sheet as a right-of-use asset and a corresponding lease liability is recorded at the present value of the known future minimum payments of the contract using a discount rate on the date of commencement. The leased asset classification is determined at the date of recording as either operating or financing, depending upon certain criteria of the contract.

The discount rate used for present value calculations is the discount rate implicit in the contract. If an implicit rate is not determinable, a collateralized incremental borrowing rate is used at the date of commencement. The Company used the collateralized incremental borrowing rate, adjusted for length of lease term, for all of its present value calculations at the initial adoption of Topic 842.

The Company has made an accounting policy election to adopt the practical expedient for combining lease and non-lease components on an asset class basis. This expedient allows the Company to combine non-lease components such as real estate taxes, insurance, maintenance, and other operating expenses associated with the leased premises with the lease component of a lease agreement on an asset class basis when the non-lease components of the agreement cannot be easily bifurcated from the lease payment. Currently, the Company is only applying this expedient to certain office space agreements.

30

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

Supplemental Balance Sheet Information Related to Leases

The Company’s lease assets as of September 30, 2019 consisted of the following items (in thousands):

	September 30, 2019
	Operating Leases		Finance Leases
Right-of-use Assets:
Processing plants	$	1,554,601		—
Drilling rigs and completion services		93,846		—
Gas gathering lines and compressor stations (1)		1,535,146		—
Office space		41,285		—
Vehicles		4,971		2,591
Other office and field equipment		299		448
Total right-of-use assets	$	3,230,148		3,039	(2)

(1) Gas gathering lines and compressor stations leases includes $1.3 billion related to Antero Midstream Corporation.

(2) Financing lease assets are recorded net of accumulated amortization of $9 million as of September 30, 2019.

The Company’s lease liabilities as of September 30, 2019 consisted of the following items (in thousands):

	September 30, 2019
	Operating Leases		Finance Leases
Location on the balance sheet:
Short-term lease liabilities	$	408,814		1,176
Long-term lease liabilities		2,821,334		1,863
Total lease liabilities	$	3,230,148		3,039

The processing plants, gathering lines and compressor stations that are classified as lease liabilities are classified as such under ASC 842 because Antero is the sole customer of the assets and because Antero makes the decisions that most impact the economic performance of the assets.

Supplemental Information Related to Leases

Costs associated with operating leases were included in the statement of operations and comprehensive income (loss) for the three and nine months ended September 30, 2019 (in thousands):

Statement of Operations Location	Three months ended September 30, 2019		Nine months ended September 30, 2019
Gathering, compression, processing, and transportation	$	237,618	$	644,007
General and administrative		2,859		8,395
Contract termination and rig stacking		—		10,692
Total Lease Expense	$	240,477	$	663,094

Costs associated with finance leases of less than $1 million for each of the three and nine months ended September 30, 2019 were included in interest expense.

We capitalized $53 million and $161 million, respectively, of costs related to operating leases and less than $1 million of costs related to finance leases during each of the three and nine months ended September 30, 2019, respectively.

Short-term lease costs that are more than one month but less than 12 months are excluded from the above amounts and total $115 million at September 30, 2019.

31

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

Supplemental Cash Flow Information Related to Leases

The following is the Company’s supplemental cash flow information related to leases for the three and nine months ended September 30, 2019 (in thousands):

	Three months ended September 30, 2019				Nine months ended September 30, 2019
	Operating Leases		Finance Leases		Operating Leases		Finance Leases
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash out flows related to operating leases	$	234,399		—	$	591,963		—
Investing cash out flows related to operating leases		47,417		—		146,315		—
Financing cash out flows related to financing leases		—		303		—		1,967
		281,816		303		738,278		1,967
Noncash activities:
Right of use assets obtained in exchange for operating lease liabilities		—		—		3,345,549		—
Right of use assets obtained in exchange for financing lease liabilities		—		—		—		—

Maturities of Lease Liabilities

The table below is a schedule of future minimum payments for operating and financing lease liabilities as of September 30, 2019 (in thousands):

(in thousands)	Operating Leases		Financing Leases		Total
Remainder of 2019	$	151,345		21		151,366
2020		578,615		523		579,138
2021		506,402		1,152		507,554
2022		495,694		1,298		496,992
2023		491,513		45		491,558
2024		482,745		—		482,745
Thereafter		1,447,537		—		1,447,537
Total lease payments		4,153,851		3,039		4,156,890
Less: imputed interest		(923,703)		—		(923,703)
Total	$	3,230,148		3,039		3,233,187

As of December 31, 2018, the following future minimum payments were required for office and equipment leases:

(in thousands)	Office Leases		Equipment Leases		Total
2019	$	8,630		6,042		14,672
2020		8,471		4,517		12,988
2021		8,450		2,410		10,860
2022		8,427		274		8,701
2023		7,495		—		7,495
Thereafter		49,367		—		49,367
Total	$	90,840		13,243		104,083

32

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

Lease Term and Discount Rate

The table below is the Company’s weighted-average remaining lease term and discount rate as of September 30, 2019:

	September 30, 2019
	Operating Leases			Finance Leases
Weighted-average remaining lease term:		8.4 years			2.1 years
Weighted-average discount rate:		6.1	%		5.7	%

As of September 30, 2019, the Company had requested additional processing capacity which will be accounted for as lease modifications when the processing capacity becomes available in 2019 and 2020.

Related party lease disclosure

The Company has a gathering and compression agreement with Antero Midstream Corporation, whereby Antero Midstream Corporation receives a low-pressure gathering fee per Mcf, a high-pressure gathering fee per Mcf, and a compression fee per Mcf, in each case subject to adjustments based on the consumer price index. If and to the extent we request that Antero Midstream Corporation construct new high pressure lines and compressor stations, the gathering and compression agreement contains minimum volume commitments that require Antero Resources to utilize or pay for 75% and 70%, respectively, of the requested capacity of such new construction for 10 years. For the three and nine months ended September 30, 2019, gathering and compression fees paid by Antero related to this agreement were $171 million and $486 million, respectively. As of September 30, 2019, $60 million was included within accounts payable, related parties on the Condensed Balance Sheet as due to Antero Midstream Corporation related to this agreement.

(13) 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, which include leases that have remaining lease terms in excess of one year as of September 30, 2019 (in thousands).

	Firm transportation		Processing, gathering and compression		Land payment obligations		Operating and Financing Leases		Imputed Interest for Leases
	(a)		(b)		(c)		(d)		(d)		Total
Remainder of 2019	$	282,571		13,667		4,653		102,808		48,558		452,257
2020		1,123,782		54,425		5,557		399,881		179,257		1,762,902
2021		1,100,079		54,093		3,177		350,364		157,190		1,664,903
2022		1,047,162		53,606		259		361,057		135,935		1,598,019
2023		1,034,641		58,565		—		377,836		113,722		1,584,764
2024		994,534		58,687		—		392,323		90,422		1,535,966
Thereafter		7,816,594		152,523		—		1,248,918		198,619		9,416,654
Total	$	13,399,363		445,566		13,646		3,233,187		923,703		18,015,465

(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. None of these agreements were determined to be leases.

33

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

(b) Processing, Gathering, and Compression Service Commitments

The Company has entered into various long-term gas processing, gathering and compression service agreements. Certain of these agreements were determined to be leases. The minimum payment obligations under the agreements that are not leases are presented in this column.

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 Partners and MarkWest.

(c) Land Payment Obligations

The Company has entered into various land acquisition agreements. Certain of these agreements contain minimum payment obligations over various terms. The values in the table represent the minimum payments due under these arrangements. None of these agreements were determined to be leases.

(d)  Leases, including imputed interest

The Company has obligations under contracts for services provided by drilling rigs and completion fleets, processing, gathering, and compression services agreements, and office and equipment leases. 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. Refer to Note 12 to the unaudited condensed consolidated financial statements for more information on the Company’s operating and finance leases.

(14) Contingencies

Environmental

As disclosed previously in our 2018 10-K, 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 U.S. Environmental Protection Agency (“EPA”) Region III for alleged violations of the federal Clean Air Act and the West Virginia State Implementation Plan relating to permitting and control 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 have separately received an NOV from West Virginia Department of Environmental Protection (“WVDEP”) alleging violations relating to the same issues being investigated by the EPA. We continue to negotiate with EPA and WVDEP to resolve the issues alleged in the NOVs and the information request; 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

In March 2015, the Company filed suit against South Jersey Gas Company and South Jersey Resources Group, LLC (collectively, “SJGC”) in United States District Court in Colorado 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 2 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

34

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

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. On August 6, 2019, the Tenth Circuit Court of Appeals affirmed the judgment of the trial court, and SJGC declined further appeal.

Subsequent to the entry of judgment on July 21, 2017, SJGC 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. After the judgment in the first lawsuit was affirmed, SJGC and Antero filed a joint motion for entry of judgment with the court on September 27, 2019 in which SJGC stipulated to liability and damages in the second lawsuit.

The Company received $59 million during the quarter and $23 million subsequent to the quarter for an aggregate payment of $82 million from SJGC, which was in full satisfaction and discharge of judgments entered in favor of the Company in the above described lawsuits. Antero recognized $54 million in natural gas sales, $3 million in production taxes, and $8 million in interest in the Company’s statement of operations for the three and nine months ended September 30, 2019, related to these lawsuits. The $23 million was included in accrued revenue on the Company’s consolidated balance sheet at September 30, 2019.

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 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 has 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 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 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 failed to receive the quantity of gas required under the Contracts, the

35

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

Company resold the quantities not taken and invoiced WGL for cover damages pursuant to the terms of the Contracts. WGL refused to pay for the invoiced cover damages as required by the Contracts and also short paid the Company for, among other things, certain amounts of gas received by WGL. The Company filed a lawsuit against WGL in Colorado district court on October 24, 2017 to recover its cover damages, other unpaid amounts, and interest. WGL’s claims have been consolidated with Antero’s claims in the same district court and trial began on June 10, 2019. WGL quantified its damages claim for the alleged failure to deliver TCO Pool gas and sought approximately $40 million from Antero.

On June 20, 2019, the Company was awarded a jury verdict of approximately $96 million in damages after the jury found that WGL breached the Contracts with the Company. In addition, the jury rejected WGL’s claim against the Company, finding that the Company did not breach the Contracts by allegedly failing to deliver TCO Pool gas and awarding no damages in favor of WGL. On August 16, 2019, WGL filed a notice of appeal of the judgment.

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 and in November 2018, the total aggregate contract volumes to be delivered to WGL at a delivery point in Loudoun County, Virginia increased by 330,000 MMBtu/day. This increase of 330,000 MMBtu/day is in effect for the remaining term of our gas sale contract with WGL Midstream, which expires in 2038, and these increased volumes are subject to NYMEX-based pricing. Following this increase, the aggregate contract volumes delivered to WGL 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.

(15) Contract Termination and Rig Stacking

During the  three and nine months ended September 30, 2019, the Company incurred less than $1 million and $14 million, respectively, of costs for the delay or cancelation of drilling and completion contracts with third-party contractors.

(16) Related Parties

Antero Midstream Partners’ operations comprised substantially all of the operations reflected in the gathering and processing, and water handling and treatment, results through March 12, 2019. Effective March 13, 2019, Antero accounts for Antero Midstream Corporation as an equity method investment. See Note 3 to the unaudited condensed consolidated financial statements for more discussion on the Transactions. Substantially all of the revenues for gathering and processing and water handling and treatment were derived from transactions with Antero. See Note 17 to the unaudited condensed consolidated financial statements for the operating results of the Company’s reportable segments.

(17) Segment Information

See Note 2(i) to the unaudited condensed consolidated financial statements for a description of the Company’s determination of its reportable segments. Revenues from gathering and processing and water handling and treatment operations were primarily derived from intersegment transactions for services provided to the Company’s exploration and production operations prior to the closing of the Transactions. Through March 12, 2019, the results of Antero Midstream Partners were included in the consolidated financial statements of Antero. Effective March 13, 2019, the results of Antero Midstream Partners are no longer consolidated in Antero’s result; however, the Company’s segment disclosures include the results of our unconsolidated affiliates due to their significance to the Company’s operations. See Note 3 to the unaudited condensed consolidated financial statements for further discussion on the Transactions. 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 (loss) of each segment. General and administrative expenses were 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.

36

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

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 were 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, 2018 and 2019 (in thousands):

	Exploration and production		Marketing	Midstream	Elimination of intersegment transactions	Consolidated total
Three months ended September 30, 2018:
Sales and revenues:
Third-party	$	982,131	89,556	4,845	—	1,076,532
Intersegment		5,197	—	261,360	(266,557)	—
Total	$	987,328	89,556	266,205	(266,557)	1,076,532
Operating expenses:
Lease operating	$	35,124	—	67,608	(66,463)	36,269
Gathering, compression, processing, and transportation		442,602	—	12,701	(128,799)	326,504
Impairment of oil and gas properties		221,094	—	—	—	221,094
Impairment of midstream assets		—	—	1,157	—	1,157
Depletion, depreciation, and amortization		204,465	—	38,721	—	243,186
General and administrative		45,474	—	15,018	(632)	59,860
Other		30,695	151,764	5,219	(4,020)	183,658
Total		979,454	151,764	140,424	(199,914)	1,071,728
Operating income (loss)	$	7,874	(62,208)	125,781	(66,643)	4,804
Equity in earnings of unconsolidated affiliates	$	—	—	10,705	—	10,705
Segment assets	$	13,484,457	20,481	3,411,496	(1,113,899)	15,802,535
Capital expenditures for segment assets	$	485,219	—	149,953	(67,951)	567,221

37

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

	Exploration and production		Marketing	Equity Method Investment in Antero Midstream Corporation	Elimination of intersegment transactions and unconsolidated affiliates	Consolidated total
Three months ended September 30, 2019:
Sales and revenues:
Third-party	$	1,070,755	46,645	—	—	1,117,400
Intersegment		1,481	—	243,795	(243,795)	1,481
Total	$	1,072,236	46,645	243,795	(243,795)	1,118,881
Operating expenses:
Lease operating	$	35,928	—	49,050	(49,050)	35,928
Gathering, compression, processing, and transportation		603,860	—	13,091	(13,091)	603,860
Impairment of oil and gas properties		1,041,469	—	—	—	1,041,469
Impairment of midstream assets		—	—	465,278	(457,478)	7,800
Depletion, depreciation, and amortization		241,503	—	24,460	(24,460)	241,503
General and administrative		35,923	—	30,595	(30,595)	35,923
Other		30,060	108,216	3,210	(3,210)	138,276
Total		1,988,743	108,216	585,684	(577,884)	2,104,759
Operating loss	$	(916,507)	(61,571)	(341,889)	334,089	(985,878)
Equity in earnings (loss) of unconsolidated affiliates	$	(117,859)	—	18,478	(18,478)	(117,859)
Investments in unconsolidated affiliates	$	1,819,323	—	672,310	(672,310)	1,819,323
Segment assets	$	16,094,927	25,361	6,445,504	(6,445,504)	16,120,288
Capital expenditures for segment assets	$	292,176	—	120,875	(120,875)	292,176

The operating results and assets of the Company’s reportable segments were as follows for the nine months ended September 30, 2018 and 2019 (in thousands):

	Exploration and production		Marketing	Midstream	Elimination of intersegment transactions	Consolidated total
Nine months ended September 30, 2018:
Sales and revenues:
Third-party	$	2,590,409	488,270	15,299	—	3,093,978
Intersegment		16,251	—	731,473	(747,724)	—
Total	$	2,606,660	488,270	746,772	(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	—	36,469	(346,896)	926,228
Impairment of oil and gas properties		406,068	—	—	—	406,068
Impairment of midstream assets		—	—	9,658	—	9,658
Depletion, depreciation, and amortization		601,446	—	108,034	—	709,480
General and administrative		138,555	—	44,967	(1,946)	181,576
Other		85,067	560,924	15,129	(11,841)	649,279
Total		2,566,489	560,924	398,955	(550,924)	2,975,444
Operating income (loss)	$	40,171	(72,654)	347,817	(196,800)	118,534
Equity in earnings of unconsolidated affiliates	$	—	—	27,832	—	27,832
Segment assets	$	13,484,457	20,481	3,411,496	(1,113,899)	15,802,535
Capital expenditures for segment assets	$	1,464,041	—	414,833	(202,629)	1,676,245

38

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

	Exploration and production		Marketing	Equity Method Investment in Antero Midstream Corporation	Elimination of intersegment transactions and unconsolidated affiliates	Consolidated total
Nine months ended September 30, 2019:
Sales and revenues:
Third-party	$	3,247,214	200,911	50	—	3,448,175
Intersegment		4,999	—	553,471	(550,693)	7,777
Total	$	3,252,213	200,911	553,521	(550,693)	3,455,952
Operating expenses:
Lease operating	$	119,754	—	111,427	(112,664)	118,517
Gathering, compression, processing, and transportation		1,705,709	—	28,324	(138,810)	1,595,223
Impairment of oil and gas properties		1,253,712	—	—	—	1,253,712
Impairment of midstream assets		—	—	472,854	(458,072)	14,782
Depletion, depreciation, and amortization		702,299	—	68,557	(46,850)	724,006
General and administrative		128,213	—	85,026	(66,732)	146,507
Other		112,952	408,839	8,005	(7,002)	522,794
Total		4,022,639	408,839	774,193	(830,130)	4,375,541
Operating income (loss)	$	(770,426)	(207,928)	(220,672)	279,437	(919,589)
Equity in earnings (loss) of unconsolidated affiliates	$	(102,457)	—	34,981	(22,717)	(90,193)
Investments in unconsolidated affiliates	$	1,819,323	—	672,310	(672,310)	1,819,323
Segment assets	$	16,094,927	25,361	6,445,504	(6,445,504)	16,120,288
Capital expenditures for segment assets	$	1,053,210	—	262,065	(208,913)	1,106,362

(18) Subsidiary Guarantors

Each of Antero’s wholly owned subsidiaries has fully and unconditionally guaranteed Antero’s senior notes.  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 Antero (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 that 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, 2018 and September 30, 2019, and the related Condensed Consolidating Statements of Operations and Comprehensive Income (Loss) for the three and nine months ended September 30, 2018 and 2019, and Condensed Consolidating Statements of Cash Flows for the nine months ended September 30, 2018 and 2019 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 Antero.

39

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

Condensed Consolidating Balance Sheet
December 31, 2018
(In thousands)

	Parent (Antero)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations		Consolidated
Assets
Current assets:
Accounts receivable, net	$	49,529		—		1,544		—		51,073
Intercompany receivables		383		—		115,378		(115,761)		—
Accrued revenue		474,827		—		—		—		474,827
Derivative instruments		245,263		—		—		—		245,263
Other current assets		13,937		—		21,513		—		35,450
Total current assets		783,939		—		138,435		(115,761)		806,613
Property and equipment:
Oil and gas properties, at cost (successful efforts method):
Unproved properties		1,767,600		—		—		—		1,767,600
Proved properties		13,306,585		—		—		(600,913)		12,705,672
Water handling and treatment systems		—		—		1,004,793		9,025		1,013,818
Gathering systems and facilities		17,825		—		2,452,883		—		2,470,708
Other property and equipment		65,770		—		72		—		65,842
		15,157,780		—		3,457,748		(591,888)		18,023,640
Less accumulated depletion, depreciation, and amortization		(3,654,392)		—		(499,333)		—		(4,153,725)
Property and equipment, net		11,503,388		—		2,958,415		(591,888)		13,869,915
Derivative instruments		362,169		—		—		—		362,169
Investment in Antero Midstream Partners		(740,031)		—		—		740,031		—
Contingent acquisition consideration		114,995		—		—		(114,995)		—
Investments in unconsolidated affiliates		—		—		433,642		—		433,642
Other assets		31,200		—		15,925		—		47,125
Total assets	$	12,055,660		—		3,546,417		(82,613)		15,519,464
Liabilities and Equity
Current liabilities:
Accounts payable	$	44,917		—		21,372		—		66,289
Intercompany payable		111,620		—		4,141		(115,761)		—
Accrued liabilities		392,949		—		72,121		—		465,070
Revenue distributions payable		310,827		—		—		—		310,827
Derivative instruments		532		—		—		—		532
Short-term lease liabilities		2,459		—		—		—		2,459
Other current liabilities		2,162		—		2,052		4,149		8,363
Total current liabilities		865,466		—		99,686		(111,612)		853,540
Long-term liabilities:
Long-term debt		3,829,541		—		1,632,147		—		5,461,688
Deferred income tax liability		650,788		—		—		—		650,788
Contingent acquisition consideration		—		—		114,995		(114,995)		—
Long-term lease liabilities		2,873		—		—		—		2,873
Other liabilities		55,017		—		8,081		—		63,098
Total liabilities		5,403,685		—		1,854,909		(226,607)		7,031,987
Equity:
Stockholders' equity:
Partners' capital		—		—		1,691,508		(1,691,508)		—
Common stock		3,086		—		—		—		3,086
Additional paid-in capital		5,471,341		—		—		1,013,833		6,485,174
Accumulated earnings		1,177,548		—		—		—		1,177,548
Total stockholders' equity		6,651,975		—		1,691,508		(677,675)		7,665,808
Noncontrolling interests in consolidated subsidiary		—		—		—		821,669		821,669
Total equity		6,651,975		—		1,691,508		143,994		8,487,477
Total liabilities and equity	$	12,055,660		—		3,546,417		(82,613)		15,519,464

40

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

Condensed Consolidating Balance Sheet
September 30, 2019
(In thousands)

	Parent (Antero)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations		Consolidated
Assets
Current assets:
Accounts receivable, net		29,207		—		—		—		29,207
Intercompany receivables		—		131,135		—		(131,135)		—
Accrued revenue		281,177		—		—		—		281,177
Derivative instruments		411,774		—		—		—		411,774
Other current assets		7,342		—		—		—		7,342
Total current assets		729,500		131,135		—		(131,135)		729,500
Property and equipment:
Oil and gas properties, at cost (successful efforts method):
Unproved properties		1,406,464		—		—		—		1,406,464
Proved properties		11,568,285		—		—		—		11,568,285
Gathering systems and facilities		5,802		—		—		—		5,802
Other property and equipment		70,965		—		—		—		70,965
		13,051,516		—		—		—		13,051,516
Less accumulated depletion, depreciation, and amortization		(3,136,767)		—		—		—		(3,136,767)
Property and equipment, net		9,914,749		—		—		—		9,914,749
Operating leases right-of-use assets		3,230,148		—		—		—		3,230,148
Derivative instruments		405,180		—		—		—		405,180
Investments in unconsolidated affiliates		481,474		1,337,849		—		—		1,819,323
Investments in consolidated affiliates		1,337,849		—		—		(1,337,849)		—
Other assets		21,388		—		—		—		21,388
Total assets	$	16,120,288		1,468,984		—		(1,468,984)		16,120,288
Liabilities and Equity
Current liabilities:
Accounts payable	$	32,496		—		—		—		32,496
Accounts payable, related parties		300,774		—		—		(200,337)		100,437
Accrued liabilities		392,726		—		—		—		392,726
Revenue distributions payable		231,152		—		—		—		231,152
Short-term lease liabilities		409,990				—				409,990
Other current liabilities		4,367		—		—		—		4,367
Total current liabilities		1,371,505		—		—		(200,337)		1,171,168
Long-term liabilities:
Long-term debt		3,703,828		—		—		—		3,703,828
Deferred income tax liability		916,031		—		—		—		916,031
Long-term lease liabilities		2,823,197				—				2,823,197
Other liabilities		59,366		—		—		—		59,366
Total liabilities		8,873,927		—		—		(200,337)		8,673,590
Equity:
Stockholders' equity:
Partners' capital		—		—		—		—		—
Common stock		3,041		—		—		—		3,041
Additional paid-in capital		6,124,042		1,337,849		—		(1,337,849)		6,124,042
Accumulated earnings		1,119,278		131,135		—		69,202		1,319,615
Total equity		7,246,361		1,468,984		—		(1,268,647)		7,446,698
Total liabilities and equity	$	16,120,288		1,468,984		—		(1,468,984)		16,120,288

41

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss)
Three Months Ended September 30, 2018
(In thousands)

	Parent (Antero)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		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 fair value losses		(42)		—		—		—		(42)
Other income		5,327		—		—		(5,327)		—
Total revenue and other		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 oil and gas properties		221,094		—		—		—		221,094
Impairment of midstream assets		—		—		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 expense, net		(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)

42

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss)
Three Months Ended September 30, 2019
(In thousands)

	Parent (Antero)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations		Consolidated
Revenue and other:
Natural gas sales	$	524,448		—		—		—		524,448
Natural gas liquids sales		284,958		—		—		—		284,958
Oil sales		40,561		—		—		—		40,561
Commodity derivative fair value gains		220,788		—		—		—		220,788
Marketing		46,645		—		—		—		46,645
Other income		1,481		—		—		—		1,481
Total revenue and other		1,118,881		—		—		—		1,118,881
Operating expenses:
Lease operating		35,928		—		—		—		35,928
Gathering, compression, processing, and transportation		603,860		—		—		—		603,860
Production and ad valorem taxes		28,863		—		—		—		28,863
Marketing		108,216		—		—		—		108,216
Exploration		208		—		—		—		208
Impairment of oil and gas properties		1,041,469		—		—		—		1,041,469
Impairment of midstream assets		7,800		—		—		—		7,800
Depletion, depreciation, and amortization		241,503		—		—		—		241,503
Accretion of asset retirement obligations		927		—		—		—		927
General and administrative		35,923		—		—		—		35,923
Contract termination and rig stacking		62		—		—		—		62
Total operating expenses		2,104,759		—		—		—		2,104,759
Operating loss		(985,878)		—		—		—		(985,878)
Other income (expenses):
Equity in earnings of unconsolidated affiliates		(38,255)		(79,604)		—		—		(117,859)
Interest expense, net		(47,754)		—		—		—		(47,754)
Total other expenses		(86,009)		(79,604)		—		—		(165,613)
Loss before income taxes		(1,071,887)		(79,604)		—		—		(1,151,491)
Provision for income tax benefit		272,627		—		—		—		272,627
Net loss and comprehensive loss attributable to Antero Resources Corporation	$	(799,260)		(79,604)		—		—		(878,864)

43

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss)
Nine Months Ended September 30, 2018
(In thousands)

	Parent (Antero)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		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 fair value 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 oil and gas properties		406,068		—		—		—		406,068
Impairment of midstream assets		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 expense, net		(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)

44

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

Condensed Consolidating Statement of Operations and Comprehensive Income
Nine Months Ended September 30, 2019
(In thousands)

	Parent (Antero)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations		Consolidated
Revenue and other:
Natural gas sales	$	1,735,086		—		—		—		1,735,086
Natural gas liquids sales		902,606		—		—		—		902,606
Oil sales		137,675		—		—		—		137,675
Commodity derivative fair value gains		471,847		—		—		—		471,847
Gathering, compression, water handling and treatment		—		—		218,360		(213,881)		4,479
Marketing		200,911		—		—		—		200,911
Other income		4,999		—		—		(1,651)		3,348
Total revenue and other		3,453,124		—		218,360		(215,532)		3,455,952
Operating expenses:
Lease operating		119,754		—		64,818		(66,055)		118,517
Gathering, compression, processing, and transportation		1,705,709		—		—		(110,486)		1,595,223
Production and ad valorem taxes		94,569		—		—		940		95,509
Marketing		408,839		—		—		—		408,839
Exploration		648		—		—		—		648
Impairment of oil and gas properties		1,253,712		—		—		—		1,253,712
Impairment of midstream assets		7,800		—		6,982		—		14,782
Depletion, depreciation, and amortization		702,299		—		21,707		—		724,006
Loss on sale of assets		951		—		—		—		951
Accretion of asset retirement obligations		2,758		—		63		—		2,821
General and administrative		128,213		—		18,793		(499)		146,507
Contract termination and rig stacking		14,026		—		—		—		14,026
Accretion of contingent acquisition consideration		—		—		1,928		(1,928)		—
Total operating expenses		4,439,278		—		114,291		(178,028)		4,375,541
Operating income (loss)		(986,154)		—		104,069		(37,504)		(919,589)
Other income (expenses):
Equity in earnings (loss) of unconsolidated affiliates		(33,255)		(69,202)		12,264		—		(90,193)
Interest expense, net		(157,053)		—		(16,815)		—		(173,868)
Equity in earnings of affiliates		15,021		—		—		(15,021)		—
Gain on deconsolidation of Antero Midstream Partners LP		1,205,705		200,337		—		—		1,406,042
Total other income (expenses)		1,030,418		131,135		(4,551)		(15,021)		1,141,981
Income before income taxes		44,264		131,135		99,518		(52,525)		222,392
Provision for income tax expense		(33,332)		—		—		—		(33,332)
Net income and comprehensive income including noncontrolling interests		10,932		131,135		99,518		(52,525)		189,060
Net income and comprehensive income attributable to noncontrolling interests		—		—		—		46,993		46,993
Net income and comprehensive income attributable to Antero Resources Corporation	$	10,932		131,135		99,518		(99,518)		142,067

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ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2018
(In thousands)

	Parent (Antero)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		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 oil and gas properties		406,068		—		—		—		406,068
Impairment of midstream assets		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 Partners LP		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 provided by (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 to noncontrolling interests in Antero Midstream Partners LP		—		—		(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	$	—		—		—		—		—

46

ANTERO RESOURCES CORPORATION

Notes to the Unaudited Condensed Consolidated Financial Statements

December 31, 2018 and September 30, 2019

Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2019
(In thousands)

	Parent (Antero)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations		Consolidated
Cash flows provided by (used in) operating activities:
Net income including noncontrolling interests	$	10,932		131,135		99,518		(52,525)		189,060
Adjustment to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, amortization, and accretion		705,057		—		21,770		—		726,827
Impairment of oil and gas properties		1,253,712		—		—		—		1,253,712
Impairment of midstream assets		7,800		—		6,982		—		14,782
Commodity derivative fair value gains		(471,847)		—		—		—		(471,847)
Gains on settled commodity derivatives		261,794		—		—		—		261,794
Deferred income tax expense		32,019		—		—		—		32,019
Loss on sale of assets		951		—		—		—		951
Equity-based compensation expense		16,850		—		2,477		—		19,327
Equity in earnings of affiliates		(15,021)		—		—		15,021		—
Equity in earnings (loss) of unconsolidated affiliates		33,255		69,202		(12,264)		—		90,193
Distributions/dividends of earnings from unconsolidated affiliates		96,636		—		12,605		—		109,241
Gain on deconsolidation of Antero Midstream Partners LP		(1,205,705)		(200,337)		—		—		(1,406,042)
Distributions from Antero Midstream Partners LP		94,391		—		—		(94,391)		—
Other		(40,493)		—		750		47,922		8,179
Changes in current assets and liabilities		121,087		—		(10,573)		16,808		127,322
Net cash provided by operating activities		901,418		—		121,265		(67,165)		955,518
Cash flows provided by (used in) investing activities:
Additions to unproved properties		(69,796)		—		—		—		(69,796)
Drilling and completion costs		(978,496)		—		—		20,565		(957,931)
Additions to water handling and treatment systems		—		—		(24,547)		131		(24,416)
Additions to gathering systems and facilities		—		—		(48,239)		—		(48,239)
Additions to other property and equipment		(4,918)		—		(1,062)		—		(5,980)
Investments in unconsolidated affiliates		—		—		(25,020)		—		(25,020)
Proceeds from the Antero Midstream Partners LP Transactions		296,611		—		—		—		296,611
Change in other assets		10,818		—		(3,357)		—		7,461
Proceeds from sale of assets		1,983		—		—		—		1,983
Net cash used in investing activities		(743,798)		—		(102,225)		20,696		(825,327)
Cash flows provided by (used in) financing activities:
Repurchases of common stock		(17,924)		—		—		—		(17,924)
Issuance of senior notes		—		—		650,000		—		650,000
Borrowings (repayments) on bank credit facility, net		(135,379)		—		90,379		—		(45,000)
Payments of deferred financing costs		(791)		—		(7,468)		—		(8,259)
Distributions to noncontrolling interests in Antero Midstream Partners LP		—		—		(131,545)		46,469		(85,076)
Employee tax withholding for settlement of equity compensation awards		(2,350)		—		(29)		—		(2,379)
Other		(1,176)		—		(845)		—		(2,021)
Net cash provided by (used in) financing activities		(157,620)		—		600,492		46,469		489,341
Effect of deconsolidation of Antero Midstream Partners LP		—		—		(619,532)		—		(619,532)
Net increase in cash and cash equivalents		—		—		—		—		—
Cash and cash equivalents, beginning of period		—		—		—		—		—
Cash and cash equivalents, end of period	$	—		—		—		—		—

47

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 Quarterly Report on Form 10-Q. 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 2018 Form 10-K.

In this section, references to “Antero,” 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 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, 2019, we held approximately 555,000 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) marketing of excess firm transportation capacity; and (iii) our equity method investment in Antero Midstream Corporation. All of our operations are conducted in the United States. As described below and elsewhere in this Quarterly Report on Form 10-Q, effective March 13, 2019, the results of Antero Midstream Partners are no longer consolidated in Antero’s results.

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–SEC Filings” section 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 any of our other filings with the SEC.

2019 Developments and Highlights

Closing of Simplification Transaction

On March 12, 2019, Antero Midstream Corporation and Antero Midstream Partners completed the Transactions contemplated by the Simplification Agreement, pursuant to which (i) Antero Midstream GP LP was converted from a limited partnership to a corporation under the laws of the State of Delaware and changed its name to Antero Midstream Corporation, and (ii) an indirect, wholly owned subsidiary of Antero Midstream Corporation was merged with and into Antero Midstream Partners, with Antero Midstream Partners surviving the merger as an indirect, wholly owned subsidiary of Antero Midstream Corporation. In

48

connection with the Transactions, we received $297 million in cash and 158.4 million shares of Antero Midstream Corporation’s common stock, par value $0.01 per share, in exchange for the 98,870,335 common units representing limited partner interests in Antero Midstream Partners owned immediately prior to the Closing.

Prior to the Transactions, our ownership of Antero Midstream Partners common units represented approximately a 53% limited partner interest in Antero Midstream Partners, and we consolidated Antero Midstream Partners’ financial position and results of operations into our consolidated financial statements. The Transactions resulted in the exchange of the limited partner interest we owned in Antero Midstream Partners for common stock of Antero Midstream Corporation representing an approximate 31% interest. Thus, effective March 13, 2019, we no longer consolidated Antero Midstream Corporation or Antero Midstream Partners in our consolidated financial statements and began accounting for our interest in Antero Midstream Corporation using the equity method of accounting starting with our financial statements for the first quarter of 2019. For more information, please see Note 3 to the unaudited condensed consolidated financial statements.

Production and Financial Results

For the three months ended September 30, 2019, our net production totaled 310 Bcfe, or 3,367 MMcfe per day, a 24% increase compared to 250 Bcfe, or 2,718 MMcfe per day, for the three months ended September 30, 2018. Production increases resulted from an increase in the number of producing wells as a result of our drilling and completion activity. Our average price received for production, before the effects of gains on settled commodity derivatives and including the proceeds related to the lawsuits against South Jersey Gas Company and South Jersey Resources Group LLC (together, “SJGC,” and such lawsuits collectively, the “South Jersey Litigation”), for the three months ended September 30, 2019 was $2.57 per Mcfe compared to $3.70 per Mcfe for the three months ended September 30, 2018. Our average realized price after the effects of gains on settled commodity derivatives was $3.13 per Mcfe for the three months ended September 30, 2019 compared to $3.98 per Mcfe for the three months ended September 30, 2018.

For the three months ended September 30, 2019, we generated consolidated cash flows from operations of $198 million, consolidated net loss attributable to Antero of $879 million and Adjusted EBITDAX of $258 million. This compares to consolidated cash flows from operations of $421 million, consolidated net loss attributable to Antero of $154 million and Adjusted EBITDAX of $419 million for the three months ended September 30, 2018. See “—Non-GAAP Financial Measures” for a definition of Adjusted EBITDAX and a reconciliation of Adjusted EBITDAX to net cash provided by operating activities and net loss.

Consolidated cash flows from operations decreased by $223 million for the three months ended September 30, 2019 compared to the prior year period primarily because of the deconsolidation of Antero Midstream Partners. Consolidated net loss attributable to Antero of $879 million for the three months ended September 30, 2019 decreased from consolidated net loss attributable to Antero of $154 million for the three months ended September 30, 2018 primarily because of changes in commodity derivative fair value gains.

Adjusted EBITDAX decreased from $419 million for the three months ended September 30, 2018 to $258 million for the three months ended September 30, 2019, a decrease of 39%, primarily because of the deconsolidation of Antero Midstream Partners.

For the nine months ended September 30, 2019, our net production totaled 882 Bcfe, or 3,232 MMcfe per day, a 27% increase compared to 693 Bcfe, or 2,539 MMcfe per day, for the nine months ended September 30, 2018. Production increases resulted from an increase in the number of producing wells as a result of our drilling and completion activity. Our average price received for production, before the effects of gains on settled commodity derivatives and including the proceeds related to the South Jersey Litigation, for the nine months ended September 30, 2019 was $3.15 per Mcfe compared to $3.54 per Mcfe for the nine months ended September 30, 2018. Our average realized price after the effects of gains on settled commodity derivatives was $3.44 per Mcfe for the nine months ended September 30, 2019 compared to $3.93 per Mcfe for the nine months ended September 30, 2018.

For the nine months ended September 30, 2019, we generated consolidated cash flows from operations of $956 million, consolidated net income attributable to Antero of $142 million, and Adjusted EBITDAX of $952 million. This compares to consolidated cash flows from operations of $1.3 billion, consolidated net loss attributable to Antero of $276 million, and Adjusted EBITDAX of $1.2 billion for the nine months ended September 30, 2018.

Consolidated cash flows from operations decreased by $305 million for the nine months ended September 30, 2019 compared to the prior year period primarily because of the deconsolidation of Antero Midstream Partners. Consolidated net income attributable to Antero of $142 million for the nine months ended September 30, 2019 increased from consolidated net loss attributable to Antero of $276 million for the nine months ended September 30, 2018 primarily because of the gain on deconsolidation of Antero Midstream Partners and changes in commodity derivative fair value gains.

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Adjusted EBITDAX decreased from $1.2 billion for the nine months ended September 30, 2018 to $952 million for the nine months ended September 30, 2019, a decrease of 23%, primarily because of the deconsolidation of Antero Midstream Partners.

Consolidated cash flows from operations decreased from $1.3 billion for the nine months ended September 30, 2018 to $956 million for the nine months ended September 30, 2019.

2019 Capital Budget and Capital Spending

Our exploration and production capital budget for 2019 is a range of $1.35 billion to $1.4 billion, which includes: $1.275 billion to $1.3 billion for drilling and completion and $75 million to $100 million for leasehold expenditures. We do not include acquisitions in our capital budget. 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, 2019, our deconsolidated capital expenditures were approximately $1.1 billion, including drilling and completion costs of $958 million, leasehold acquisitions of $70 million, and other capital expenditures of $6 million. In addition, capital expenditures for the nine months ended September 30, 2019, included gathering and compression expenditures of $48 million, water handling and treatment expenditures of $24 million and $25 million of costs invested by Antero Midstream Partners in its Joint Venture. These expenditures relate to the period prior to deconsolidation.

For the three months ended September 30, 2019, our exploration and production capital expenditures decreased significantly from the three month periods ended March 31, 2019 and June 30, 2019 from approximately $399 million and $342 million, respectively, to $292 million. Our consolidated capital expenditures for the three months ended September 30, 2019 of $292 million included drilling and completion costs of $278 million, leasehold acquisitions of $13 million, and other capital expenditures of $1.4 million, whereas, our capital expenditures for the three months ended June 30, 2019 of $342 million included drilling and completion costs of $311 million, leasehold acquisitions of $29 million, and other capital expenditures of $1.5 million. Our capital expenditures for the three months ended March 31, 2019 of $399 million included drilling and completion costs of $369 million, leasehold acquisitions of $27 million, and other capital expenditures of $3 million. This reduction in costs was a result of our well cost savings initiatives, which include savings as a result of service cost deflation, sand logistics optimization and operational efficiency gains. As a result, we anticipate our exploration and production capital expenditures for the remainder of the year to be more consistent with levels in the three months ended September 30, 2019 as opposed to the levels in the three months ended March 31, 2019 or June 30, 2019.

Well Cost Savings Update

Antero’s drilling and completion capital expenditures declined to $290 million during third quarter of 2019.  The reduced capital spending during the quarter showcased capital efficiency gains previously outlined that are trending ahead of schedule.  Some of the key contributions were (i) localized water blending operations that reduced flowback water costs by reducing trucking costs and (ii) the use of lower volumes of fresh water per foot in approximately 20% of stages completed during the quarter.  Additionally, Antero continued to see operational efficiency gains during the third quarter.  Completion stages per day exceeded six stages per day in August and September, an increase from 5.7 stages per day during the second quarter as lower water volume completions accelerated cycle times.  The Company expects further well cost savings moving forward as it transitions to using less water on all completions by 2020 and moves towards blending nearly all flowback and produced water from the Company’s Marcellus wells.

Net Marketing Expense Mitigation

Antero recently agreed to release capacity agreements with certain third parties to mitigate 250 MMcf/d of its excess firm transportation expenses for the period from September 2019 through March 2020 to certain third parties.  Antero estimates that the release will result in a $15 million reduction in net marketing expenses during such seven-month period.  Antero will continue to evaluate opportunities to monetize or otherwise release a portion of its excess firm transportation capacity given the recent widening of local basis and attractive spreads to the Midwest and Gulf Coast.

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Hedge Position

At September 30, 2019, we had fixed price natural gas swap contracts on NYMEX Henry Hub for the period from October 2019 through December 2023 for 1.8 Tcf of our projected natural gas production at a weighted average index price of $2.86 per MMBtu, including contracts for the remainder of 2019 of approximately 91.7 Bcf of natural gas at a weighted average index price of $3.23 per MMBtu. Additionally, we have collar agreements for the period from October 2019 through December 2019 for 144.9 Bcf of our projected natural gas production at a weighted average floor and ceiling of $2.50 and $3.52, respectively. We also had basis swaps for the period from January 2020 through December 2024 for 95.0 Bcf of our projected natural gas production with pricing differentials ranging from $0.353 to $0.530 per MMBtu that hedge the difference between TCO and the NYMEX Henry Hub.

We had fixed price propane swap contracts for 6 MMBbls of propane for the period from October 2019 through March 2020 at a weighted average index price of $0.67 per gallon. These fixed price propane swap contracts are a combination of fixed priced swaps based on Mont Belvieu, ARA (Europe) and FEI (Asia) indices as detailed in Note 17 to the unaudited condensed consolidated financial statements. In addition, we had propane contracts for 91,500 Bbls of propane for the period from October 2019 through March 2020 that fix the Mont Belvieu Propane index price at 50% of NYMEX WTI crude oil. We had fixed price normal butane swap contracts for 550,000 Bbls of normal butane for the period from October 2019 through December 2020 at a weighted average Mont Belvieu index price of $0.59 per gallon. We had basis swap contracts for 761,400 Bbls of normal butane for the period from October 2019 through June 2020 with pricing differentials ranging from $0.23 to $0.25 per gallon that hedge the difference between the ARA index price and Mont Belvieu index price. We had fixed price natural gasoline swap contracts for 322,000 Bbls of natural gasoline for the period from October 2019 through December 2020 at a weighted average Mont Belvieu index price $0.67 per gallon. In addition, we had natural gasoline contracts for 12 MMBbls of natural gasoline for the period from October 2019 through December 2021 that fix the Mont Belvieu Natural Gasoline index price at weighted average percentages of WTI ranging from 78% to 81%.

We had fixed price oil contracts for 6.0 MMBbls of projected oil production at a weighted average index price of $57.27 per Bbl for the period from October 2019 through December 2020, including contracts for the remainder of 2019 of approximately 1.7 MMBbls of oil at a weighted average index price of $59.05 per Bbl.

We believe our hedge position provides some certainty to cash flows supporting our future operations and capital spending plans. As of September 30, 2019, the estimated fair value of our commodity derivative contracts was approximately $817 million.

Credit Facility

As of September 30, 2019, our 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 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 our senior notes, unless such series of notes is refinanced. The borrowing base under our Credit Facility is redetermined annually and is based on the estimated future cash flows from our proved oil and gas reserves and our commodity derivative positions. The next redetermination is scheduled to occur in April 2020. At September 30, 2019, we had $275 million of borrowings and $703 million of letters of credit outstanding under the Credit Facility. The average annualized interest rate incurred on the Credit Facility during the nine months ended September 30, 2019 was approximately 4.39%. See “—Debt Agreements and Contractual Obligations—Senior Secured Revolving Credit Facility” for a description of the Credit Facility.

Share Repurchase Program

In October 2018, the Company’s Board of Directors authorized a $600 million share repurchase program. During the three and nine months ended September 30, 2019, we repurchased 5,060,946 shares of our common stock (approximately 2% of total shares outstanding at commencement of the program) at a total cost of approximately $18 million. At September 30, 2019, Antero had 304,161,046 shares outstanding.

Results of Operations

The Company has three operating segments: (1) the exploration, development and production of natural gas, NGLs, and oil; (2) marketing and utilization of excess firm transportation capacity gathering and processing; and (3) equity method investment in Antero Midstream Corporation. Revenues from Antero Midstream Corporation’s operations were primarily derived from intersegment transactions for services provided to our exploration and production operations by Antero Midstream Partners. All intersegment transactions were eliminated upon consolidation, including revenues from water handling and treatment services provided by Antero Midstream Partners, which were capitalized as proved property development costs by Antero. Through March 12, 2019, the results of Antero Midstream Partners were included in the consolidated financial statements of Antero. Effective March 13,

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2019, the results of Antero Midstream Partners are no longer consolidated in Antero’s results; however, the Company’s segment disclosures include the segments of our unconsolidated affiliates due to their significance to the Company’s operations. See Note 3 to the unaudited condensed consolidated financial statements for further discussion on the Transactions and Note 17 to the unaudited condensed consolidated financial statements for disclosures on the Company’s reportable segments. 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.

Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2019

The operating results of the Company’s reportable segments were as follows for the three months ended September 30, 2018 and 2019 (in thousands):

	Exploration and production		Marketing	Midstream	Elimination of intersegment transactions	Consolidated total
Three months ended September 30, 2018:
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, and water handling and treatment		—	—	266,205	(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	89,556	266,205	(266,558)	1,076,532
Operating expenses:
Lease operating	$	35,124	—	67,608	(66,463)	36,269
Gathering, compression, processing, and transportation		442,602	—	12,701	(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 oil and gas properties		221,094	—	—	—	221,094
Impairment of midstream assets		—	—	1,157	—	1,157
Accretion of asset retirement obligations		677	—	33	—	710
Depletion, depreciation, and amortization		204,465	—	38,721	—	243,186
General and administrative (excluding equity-based compensation)		33,800	—	10,490	(632)	43,658
Equity-based compensation		11,674	—	4,528	—	16,202
Change in fair value of contingent acquisition consideration		—	—	4,020	(4,020)	—
Total		979,454	151,764	140,424	(199,914)	1,071,728
Operating income (loss)	$	7,875	(62,208)	125,781	(66,644)	4,804
Equity in earnings of unconsolidated affiliates	$	—	—	10,705	—	10,705

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	Exploration and production		Marketing	Equity Method Investment in Antero Midstream Corporation	Elimination of intersegment transactions and unconsolidated affiliates	Consolidated total
Three months ended September 30, 2019:
Revenue and other:
Natural gas sales	$	524,448	—	—	—	524,448
Natural gas liquids sales		284,958	—	—	—	284,958
Oil sales		40,561	—	—	—	40,561
Commodity derivative fair value gains		220,788	—	—	—	220,788
Gathering, compression, and water handling and treatment		—	—	272,658	(272,658)	—
Marketing		—	46,645	—	—	46,645
Other income (loss)		1,481	—	(28,863)	28,863	1,481
Total	$	1,072,236	46,645	243,795	(243,795)	1,118,881
Operating expenses:
Lease operating	$	35,928	—	49,050	(49,050)	35,928
Gathering, compression, processing, and transportation		603,860	—	13,091	(13,091)	603,860
Production and ad valorem taxes		28,863	—	1,179	(1,179)	28,863
Marketing		—	108,216	—	—	108,216
Exploration		208	—	—	—	208
Impairment of oil and gas properties		1,041,469	—	—	—	1,041,469
Impairment of midstream assets		—	—	465,278	(457,478)	7,800
Depletion, depreciation, and amortization		241,503	—	24,460	(24,460)	241,503
Accretion of asset retirement obligations		927	—	54	(54)	927
General and administrative (excluding equity-based compensation)		32,048	—	10,466	(10,466)	32,048
Equity-based compensation		3,875	—	20,129	(20,129)	3,875
Change in fair value of contingent acquisition consideration		—	—	1,977	(1,977)	—
Contract termination and rig stacking		62	—	—	—	62
Total		1,988,743	108,216	585,684	(577,884)	2,104,759
Operating loss	$	(916,507)	(61,571)	(341,889)	334,089	(985,878)
Equity in earnings (loss) of unconsolidated affiliates	$	(117,859)	—	18,478	(18,478)	(117,859)

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Exploration and Production Segment Results for the Three Months Ended September 30, 2018 Compared to the Three Months Ended September 30, 2019

The following table sets forth selected operating data of the exploration and production segment for the three months ended September 30, 2018 compared to the three months ended September 30, 2019:

	Three months ended September 30,				Amount of Increase		Percent
	2018		2019		(Decrease)		Change
Production data:
Natural gas (Bcf)		179		210		31	17	%
C2 Ethane (MBbl)		3,579		4,307		728	20	%
C3+ NGLs (MBbl)		7,343		11,472		4,129	56	%
Oil (MBbl)		978		865		(113)	(12)	%
Combined (Bcfe)		250		310		60	24	%
Daily combined production (MMcfe/d)		2,718		3,367		649	24	%
Average prices before effects of derivative settlements (1):
Natural gas (per Mcf) (2)	$	2.95	$	2.50	$	(0.45)	(15)	%
C2 Ethane (per Bbl)	$	15.70	$	6.15	$	(9.55)	(61)	%
C3+ NGLs (per Bbl)	$	38.41	$	22.53	$	(15.88)	(41)	%
Oil (per Bbl)	$	61.06	$	46.86	$	(14.20)	(23)	%
Weighted Average Combined (per Mcfe)	$	3.70	$	2.74	$	(0.96)	(26)	%
Average realized prices after effects of derivative settlements (1):
Natural gas (per Mcf)	$	3.51	$	3.05	$	(0.46)	(13)	%
C2 Ethane (per Bbl)	$	15.70	$	6.15	$	(9.55)	(61)	%
C3+ NGLs (per Bbl)	$	35.32	$	22.67	$	(12.65)	(36)	%
Oil (per Bbl)	$	54.00	$	50.00	$	(4.00)	(7)	%
Weighted Average Combined (per Mcfe)	$	3.98	$	3.13	$	(0.85)	(21)	%
Average costs (per Mcfe):
Lease operating	$	0.14	$	0.12	$	(0.02)	(14)	%
Gathering, compression, processing, and transportation	$	1.77	$	1.95	$	0.18	10	%
Production and ad valorem taxes	$	0.12	$	0.09	$	(0.03)	(25)	%
Marketing expense, net	$	0.25	$	0.20	$	(0.05)	(20)	%
Depletion, depreciation, amortization, and accretion	$	0.82	$	0.78	$	(0.04)	(5)	%
General and administrative (excluding equity-based compensation)	$	0.14	$	0.10	$	(0.04)	(29)	%

(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 but does not include proceeds from derivative monetizations, 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.

(2) The average realized price for the three months ended September 30, 2019 includes $54 million of the proceeds related to the South Jersey Litigation. See Note 14 to the unaudited condensed consolidated financial statements for further discussion on the South Jersey Litigation. Excluding the effect of the proceeds of the South Jersey Litigation settlement, the average realized price would have been $2.24 per Mcf.

Natural gas sales. Revenues from production of natural gas decreased from $527 million for the three months ended September 30, 2018 to $524 million for the three months ended September 30, 2019, a decrease of $3 million, or 1%. Increased natural gas production volumes accounted for an approximate $91 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 $148 million decrease in year-over-year product revenues (calculated as the change in the year-to-year average price times current year production volumes). The South Jersey Litigation settlement accounted for an additional $54 million increase in year over year natural gas revenues.

NGLs sales. Revenues from production of NGLs decreased from $338 million for the three months ended September 30, 2018 to $285 million for the three months ended September 30, 2019, a decrease of $53 million, or 16%. Increased NGLs production volumes accounted for an approximate $170 million increase in year-over-year product NGLs 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 $223 million decrease in year-over-year product revenues (calculated as the change in the year-to-year average price times current year production volumes).

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Oil sales. Revenues from production of oil decreased from $60 million for the three months ended September 30, 2018 to $41 million for the three months ended September 30, 2019, a decrease of $19 million, or 32%. Decreased oil production volumes accounted for an approximate $7 million decrease in year-over-year product oil 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 $12 million decrease in year-over-year product revenues (calculated as the change in the year-to-year average price times current year production volumes).

During the three months ended September 30, 2018 and 2019, our natural gas prices and revenues included proceeds of $54 million from SJGC resulting from resolution of contractual issues. These disputes with SJGC negatively affected our natural gas prices and revenues for prior periods including the nine months ended September 30, 2018. For more information on these disputes, please see Note 14 to the unaudited condensed consolidated financial statements.

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, basis swap contracts and collar 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, 2018 and 2019, our commodity hedges resulted in derivative fair value gains of $57 million and $221 million, respectively. The commodity derivative fair value gains included $71 million and $120 million of gains on cash settled derivatives for the three months ended September 30, 2018 and 2019, respectively.

Commodity derivative fair value 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 decreased from $5 million for the three months ended September 30, 2018 to $1 million for the three months ended September 30, 2019.

Lease operating expense. Lease operating expense increased from $35 million for the three months ended September 30, 2018 to $36 million for the three months ended September 30, 2019, an increase of 2%. This increase is primarily due to a 24% increase in production. On a per unit basis, lease operating expenses decreased from $0.14 per Mcfe for the three months ended September 30, 2018 to $0.12 per Mcfe for the three months ended September 30, 2019. This decrease is mainly due to increased operational efficiencies related to produced water and the increase in production.

Gathering, compression, processing, and transportation expense. Gathering, compression, processing, and transportation expense increased from $443 million for the three months ended September 30, 2018 to $604 million for the three months ended September 30, 2019. This is primarily a result of the increase in production. On a per Mcfe basis, total gathering, compression, processing and transportation expenses increased from $1.77 per Mcfe for the three months ended September 30, 2018 to $1.95 per Mcfe for the three months ended September 30, 2019. Processing costs increased from $0.55 per Mcfe for the three months ended September 30, 2018 to $0.74 per Mcfe for the three months ended September 30, 2019, as NGL production has increased as a proportion of our Mcfe production. Processing costs on a per Bbl basis have increased from $18.89 for the three months ended September 30, 2018 per NGL barrel to $20.01 per NGL barrel for the three months ended September 30, 2019 due to the introduction of Mariner East 2 in 2019 and the costs associated with the NGL transportation and terminaling with that facility. Transportation costs increased from $0.48 per Mcfe for the three months ended September 30, 2018 to $0.53 per Mcfe for the three months ended September 30, 2019, primarily as a result of the Mountaineer Xpress pipeline being placed in service in February 2019. These increases were partially offset by a $0.06 per Mcfe decrease quarter over quarter in other gathering and compression expenses due to a decrease in the cost of natural gas converted to NGLs through processing as a result of decreased pricing between the respective periods.

Production and ad valorem tax expense.  Total production and ad valorem taxes remained relatively flat at $29 million for the three months ended September 30, 2018 three months ended September 30, 2019. On a per Mcfe basis, production and ad valorem taxes decreased from $0.12 per Mcfe for the three months ended September 30, 2018 to $0.09 per Mcfe for the three months ended September 30, 2019 due to due to lower average prices.

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Exploration expense. Exploration expense representing expenses incurred for unsuccessful lease acquisition efforts decreased from $0.7 million for the three months ended September 30, 2018 to $0.2 million for the three months ended September 30, 2019 as leasing activities declined.

Impairment of oil and gas properties. Impairment of oil and gas properties increased from $221 million for the three months ended September 30, 2018 to $1.0 billion for the three months ended September 30, 2019 due to expiring leases, impairment of design and initial costs related to pads that are no longer planned to be placed into service, and impairment of proved properties in the Ohio Utica Shale due to lower future commodity prices. We 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.

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 exceeds the estimated undiscounted future net cash flows (measured using futures prices at the end of a quarter), we 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. Because estimated undiscounted future net cash flows based on future commodity prices at September 30, 2019 exceeded the carrying value of our proved properties in the Marcellus Shale at September 30, 2019, we did not further evaluate our Marcellus proved properties for impairment. However, the carrying amount of the Utica Shale exceeded the estimated undiscounted future cash flows based on future strip commodity prices at September 30, 2019. We estimated the fair value of the Utica Shale assets based on sales of other properties in the Utica Shale, estimates of proved reserves, estimated future commodity prices, future production estimates, and anticipated capital expenditures, using a commensurate discount rate. As a result, the Company recorded an impairment charge of $881 million related to proved properties in the Utica Shale during the three months ended September 30, 2019.

Depletion, depreciation, and amortization expense (“DD&A”). DD&A expense increased from $204 million for the three months ended September 30, 2018 to $242 million for the three months ended September 30, 2019, primarily due to increased production, offset by a decrease in the DD&A per Mcfe. DD&A per Mcfe decreased from $0.82 per Mcfe during the three months ended September 30, 2018 to $0.78 per Mcfe during the three months ended September 30, 2019, as our net oil and gas reserve volumes increased more than our net costs. The Transactions and the associated deconsolidation of Antero Midstream Partners resulted in our oil and gas reserves being adjusted from a consolidated to a stand-alone basis.

General and administrative expense. General and administrative expense (excluding equity-based compensation expense) decreased from $34 million for the three months ended September 30, 2018 to $32 million for the three months ended September 30, 2019, primarily due to a decrease in employee costs. We had 607 employees as of September 30, 2018 and 569 employees as of September 30, 2019. On a per-unit basis, general and administrative expense excluding equity-based compensation decreased by 29%, from $0.14 per Mcfe during the three months ended September 30, 2018 to $0.10 per Mcfe during the three months ended September 30, 2019 as result of production increasing and costs decreasing.

Equity-based compensation expense. Noncash equity-based compensation expense decreased from $12 million for the three months ended September 30, 2018 to $4 million for the three months ended September 30, 2019 as a result of equity award forfeitures, as well as a decrease in the total value of awards to officers and employees in 2019 as compared to 2018. 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 Quarterly Report on Form 10-Q for more information on equity-based compensation awards.

Contract termination and rig stacking. We incurred contract termination and rig stacking costs of less than $1 million during the three months ended September 30, 2019, representing fees incurred upon the delay or cancellation of drilling and completion contracts with third-party contractors to align our drilling and completion activity level with our 2019 capital budget.

Discussion of Antero Midstream Corporation Segment for the Three Months Ended September 30, 2018 Compared to the Three Months Ended September 30, 2019

Through March 12, 2019, the results of Antero Midstream Partners were included in the consolidated financial statements of Antero. Effective March 13, 2019, the results of Antero Midstream Partners were no longer consolidated in Antero’s results. See Note 3 to the unaudited condensed consolidated financial statements for further discussion on the Transactions. The three months ended September 30, 2018 include the results of Antero Midstream Partners while the three months ended September 30, 2019 account for our interest in Antero Midstream Corporation as an equity method investment.

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Antero Midstream Corporation. Revenue from the Antero Midstream Corporation segment decreased from $266 million for the three months ended September 30, 2018 to $244 million for the three months ended September 30, 2019, a decrease of $22 million, or 8%. The increase in operating revenue of $7 million, which was due to an increase in wells serviced by Antero Midstream Partners’ system as well as an increase in fresh water delivery, was offset by $29 million in amortization of customer relationships. Total operating expenses related to the segment increased from $140 million for the three months ended September 30, 2018 to $586 million for the three months ended September 30, 2019 primarily due to impairment expense of $457 million on Antero Midstream Corporation’s wastewater treatment facility and related goodwill and customer relationships.

In addition, Antero Midstream Corporation had equity in earnings of unconsolidated affiliates of $11 million and $18 million for the three months ended September 30, 2018 and 2019, respectively.

Discussion of the Marketing Segment for the Three Months Ended September 30, 2018 Compared to the Three Months Ended September 30, 2019

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, to optimize the revenues and reduce our net costs related to the unused capacity under these transportation agreements. We have entered into long-term firm transportation agreements for a significant portion of our current and expected future production to secure guaranteed capacity to favorable markets.

Marketing revenues were $90 million and $47 million, and expenses were $152 million and $108 million, for the three months ended September 30, 2018 and 2019, respectively, related to these activities.

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 $49 million and $62 million for the three months ended September 30, 2018 and 2019, respectively, which increased due to increased excess capacity charges related to new firm transportation lines being placed into service in late 2018 and in the first quarter of 2019.

Operating losses on our marketing activities were $62 million for both periods, or $0.25 per Mcfe and $0.20 per Mcfe, for the three months ended September 30, 2018 and 2019, respectively.

Discussion of Items Not Allocated to Segments for the Three Months Ended September 30, 2018 Compared to the Three Months Ended September 30, 2019

Interest expense. Interest expense decreased from $75 million for the three months ended September 30, 2018 to $48 million for the three months ended September 30, 2019, due to decreased borrowings under the Credit Facility and the three months ended September 30, 2019 not including interest related to Antero Midstream Partners’ debt. The three months ended September 30, 2018 include the results of Antero Midstream Partners while the three months ended September 30, 2019 account for our interest in Antero Midstream Corporation as an equity method investment. Interest expense includes approximately $3.2 million and $2.6 million of non-cash amortization of deferred financing costs for the three months ended September 30, 2018 and 2019, respectively.

Income tax (expense) benefit. Income tax (expense) benefit changed from a deferred tax expense of $19 million, with an effective tax rate of 32%, for the three months ended September 30, 2018 to a deferred tax benefit of $273 million, with an effective tax rate of 24%, for the three months ended September 30, 2019. The change was primarily a result of the decrease in book income due to the impairment of proved properties in the Utica Shale.

At December 31, 2018, we had significant NOLs for U.S. federal and state income tax purposes. We will utilize a substantial portion of our NOLs to offset the taxable gain from the Transactions.  Future interpretations of existing tax laws that vary from our current interpretation, and possible changes to state tax laws in response to the U.S federal tax legislation enacted in Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act, 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.

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Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2019

The operating results of the Company’s reportable segments were as follows for the nine months ended September 30, 2018 and 2019 (in thousands):

	Exploration and production		Marketing	Midstream	Elimination of intersegment transactions	Consolidated total
Nine months ended September 30, 2018:
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, and water handling and treatment		—	—	746,188	(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	488,270	746,771	(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	—	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 oil and gas properties		406,068	—	—	—	406,068
Impairment of midstream assets		—	—	9,658	—	9,658
Accretion of asset retirement obligations		2,000	—	101	—	2,101
Depletion, depreciation, and amortization		601,446	—	108,034	—	709,480
General and administrative (excluding equity-based compensation)		98,732	—	28,361	(1,946)	125,147
Equity-based compensation		39,823	—	16,606	—	56,429
Change in fair value of contingent acquisition consideration		—	—	11,841	(11,841)	—
Total		2,566,489	560,924	398,955	(550,924)	2,975,444
Operating income (loss)	$	40,172	(72,654)	347,816	(196,800)	118,534
Equity in earnings of unconsolidated affiliates	$	—	—	27,832	—	27,832

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	Exploration and production		Marketing	Equity Method Investment in Antero Midstream Corporation	Elimination of intersegment transactions and unconsolidated affiliates	Consolidated total
Nine months ended September 30, 2019:
Revenue and other:
Natural gas sales	$	1,735,086	—	—	—	1,735,086
Natural gas liquids sales		902,606	—	—	—	902,606
Oil sales		137,675	—	—	—	137,675
Commodity derivative fair value gains		471,847	—	—	—	471,847
Gathering, compression, and water handling and treatment		—	—	592,699	(588,220)	4,479
Marketing		—	200,911	—	—	200,911
Other income (loss)		4,999	—	(39,178)	37,527	3,348
Total	$	3,252,213	200,911	553,521	(550,693)	3,455,952
Operating expenses:
Lease operating	$	119,754	—	111,427	(112,664)	118,517
Gathering, compression, processing, and transportation		1,705,709	—	28,324	(138,810)	1,595,223
Production and ad valorem taxes		94,569	—	2,549	(1,609)	95,509
Marketing		—	408,839	—	—	408,839
Exploration		648	—	—	—	648
Impairment of oil and gas properties		1,253,712	—	—	—	1,253,712
Impairment of midstream assets		—	—	472,854	(458,072)	14,782
Depletion, depreciation, and amortization		702,299	—	68,557	(46,850)	724,006
Loss on sale of assets		951	—	—	—	951
Accretion of asset retirement obligations		2,758	—	133	(70)	2,821
General and administrative (excluding equity-based compensation)		111,363	—	31,931	(16,114)	127,180
Equity-based compensation		16,850	—	53,095	(50,618)	19,327
Change in fair value of contingent acquisition consideration		—	—	5,323	(5,323)	—
Contract termination and rig stacking		14,026	—	—	—	14,026
Total		4,022,639	408,839	774,193	(830,130)	4,375,541
Operating income (loss)	$	(770,426)	(207,928)	(220,672)	279,437	(919,589)
Equity in earnings (loss) of unconsolidated affiliates	$	(102,457)	—	34,981	(22,717)	(90,193)

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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, 2019

The following table sets forth selected operating data of the exploration and production segment for the nine months ended September 30, 2018 compared to the nine months ended September 30, 2019:

	Nine months ended September 30,				Amount of Increase		Percent
	2018		2019		(Decrease)		Change
Production data:
Natural gas (Bcf)		504		617		113	22	%
C2 Ethane (MBbl)		9,899		11,536		1,637	17	%
C3+ NGLs (MBbl)		19,450		29,842		10,392	53	%
Oil (MBbl)		2,139		2,823		684	32	%
Combined (Bcfe)		693		882		189	27	%
Daily combined production (MMcfe/d)		2,539		3,232		693	27	%
Average prices before effects of derivative settlements (1):
Natural gas (per Mcf) (2)	$	2.97	$	2.81	$	(0.16)	(5)	%
C2 Ethane (per Bbl)	$	11.71	$	8.01	$	(3.70)	(32)	%
C3+ NGLs (per Bbl)	$	36.63	$	27.15	$	(9.48)	(26)	%
Oil (per Bbl)	$	60.23	$	48.77	$	(11.46)	(19)	%
Weighted Average Combined (per Mcfe)	$	3.54	$	3.15	$	(0.39)	(11)	%
Average realized prices after effects of derivative settlements (1):
Natural gas (per Mcf)	$	3.62	$	3.23	$	(0.39)	(11)	%
C2 Ethane (per Bbl)	$	11.71	$	8.01	$	(3.70)	(32)	%
C3+ NGLs (per Bbl)	$	34.54	$	27.24	$	(7.30)	(21)	%
Oil (per Bbl)	$	52.73	$	50.16	$	(2.57)	(5)	%
Weighted Average Combined (per Mcfe)	$	3.93	$	3.44	$	(0.49)	(12)	%
Average costs (per Mcfe):
Lease operating	$	0.14	$	0.14	$	—	—	%
Gathering, compression, processing, and transportation	$	1.78	$	1.93	$	0.15	8	%
Production and ad valorem taxes	$	0.11	$	0.11	$	—	—	%
Marketing expense (gain), net	$	0.24	$	0.24	$	—	—	%
Depletion, depreciation, amortization, and accretion	$	0.87	$	0.80	$	(0.07)	(8)	%
General and administrative (excluding equity-based compensation)	$	0.14	$	0.13	$	(0.01)	(7)	%

(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 but does not include proceeds from derivative monetizations, 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.

(2) The average realized price for the nine months ended September 30, 2019 includes $54 million of the proceeds related to the South Jersey Litigation. See Note 14 to the unaudited condensed consolidated financial statements for further discussion on the South Jersey Litigation. Excluding the effect of the proceeds of the South Jersey Litigation settlement, the average realized price would have been $2.72 per Mcf.

Natural gas sales. Revenues from production of natural gas increased from $1.5 billion for the nine months ended September 30, 2018 to $1.7 billion for the nine months ended September 30, 2019, an increase of $237 million, or 16%. Increased natural gas production volumes accounted for an approximate $335 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 $152 million decrease in year-over-year product revenues (calculated as the change in the year-to-year average price times current year production volumes). The South Jersey Litigation settlement accounted for an additional $54 million increase in year over year natural gas revenues.

NGLs sales. Revenues from production of NGLs increased from $828 million for the nine months ended September 30, 2018 to $903 million for the nine months ended September 30, 2019, an increase of $75 million, or 9%. Increased NGLs production volumes accounted for an approximate $400 million increase in year-over-year product NGLs 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 $325 million decrease in year-over-year product revenues (calculated as the change in the year-to-year average price times current year production volumes).

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Oil sales. Revenues from production of oil increased from $129 million for the nine months ended September 30, 2018 to $138 million for the nine months ended September 30, 2019, an increase of $9 million, or 7%. Increased oil production volumes accounted for an approximate $41 million increase in year-over-year product oil 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 $32 million decrease in year-over-year product revenues (calculated as the change in the year-to-year average price times current year production volumes).

During the nine months ended September 30, 2019, our natural gas prices and revenues included proceeds of $54 million from SJGC resulting from resolution of contractual issues. These disputes with SJGC negatively affected our natural gas prices and revenues for prior periods including the nine months ended September 30, 2018.  For more information on these disputes, please see Note 14 to the unaudited condensed consolidated financial statements.

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, basis swap contracts and collar 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, 2018 and 2019, our commodity hedges resulted in derivative fair value gains of $135 million and $472 million, respectively. The commodity derivative fair value gains included $268 million and $263 million of gains on cash settled derivatives for the nine months ended September 30, 2018 and 2019, respectively.

Commodity derivative fair value 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 decreased from $16 million for the nine months ended September 30, 2018 to $5 million for the nine months ended September 30, 2019.

Lease operating expense. Lease operating expense increased from $99 million for the nine months ended September 30, 2018 to $120 million for the nine months ended September 30, 2019, an increase of 21%. This increase is primarily due to a 27% increase in production. On a per unit basis, lease operating expenses remained flat at $0.14 for the nine months ended September 30, 2018 and 2019.

Gathering, compression, processing, and transportation expense. Gathering, compression, processing, and transportation expense increased from $1.2 billion for the nine months ended September 30, 2018 to $1.7 billion for the nine months ended September 30, 2019. This is primarily a result of the increase in production. On a per Mcfe basis, total gathering, compression, processing and transportation expenses increased from $1.78 per Mcfe for the nine months ended September 30, 2018 to $1.93 per Mcfe for the nine months ended September 30, 2019. Processing costs increased from $0.55 per Mcfe for the nine months ended September 30, 2018 to $0.67 per Mcfe for the nine months ended September 30, 2019, as NGL production has increased as a proportion of our Mcfe production. Processing costs on a per Bbl basis have remained relatively consistent. Transportation costs increased from $0.51 per Mcfe for the nine months ended September 30, 2018 to $0.54 per Mcfe for the nine months ended September 30, 2019, primarily as a result of the Mountaineer Xpress pipeline placed in service in February 2019. Other gathering and compression expenses remained relatively consistent at $0.73 per Mcfe for the nine months ended September 30, 2018 and $0.72 per Mcfe for the nine months ended September 30, 2019.

Production and ad valorem tax expense.  Total production and ad valorem taxes increased from $79 million for the nine months ended September 30, 2018 to $95 million for the nine months ended September 30, 2019 as a result of an increase in production revenues. On a per Mcfe basis, production and ad valorem taxes remained flat at $0.11 per Mcfe for the nine months ended September 30, 2018 and 2019.

Exploration expense. Exploration expense representing expenses incurred for unsuccessful lease acquisition efforts decreased from $4.0 million for the nine months ended September 30, 2018 to less than $1 million for the nine months ended September 30, 2019 as leasing activities declined.

Impairment of oil and gas properties. Impairment of oil and gas properties increased from $406 million for the nine months ended September 30, 2018 to $1.3 billion for the nine months ended September 30, 2019 due to expiring leases, impairment of design

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and initial costs related to pads that are no longer planned to be placed into service, and impairment of proved properties in the Ohio Utica Shale due to lower future commodity prices. We 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.

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 exceeds 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. Because estimated undiscounted future net cash flows based on future commodity prices at September 30, 2019 exceeded the carrying value of our proved properties in the Marcellus Shale at September 30, 2019, we did not further evaluate our Marcellus proved properties for impairment. However, the carrying amount of the Utica Shale exceeded the estimated undiscounted future cash flows based on future strip commodity prices at September 30, 2019. We estimated the fair value of the Utica Shale assets based on sales of other properties in the Utica Shale, estimates of proved reserves, estimated future commodity prices, future production estimates, and anticipated capital expenditures, using a commensurate discount rate. As a result, the Company recorded an impairment charge of $881 million related to proved properties in the Utica Shale during the three months ended September 30, 2019.

Depletion, depreciation, and amortization expense (“DD&A”). DD&A expense increased from $601 million for the nine months ended September 30, 2018 to $702 million for the nine months ended September 30, 2019, primarily due to increased production. DD&A per Mcfe decreased from $0.87 per Mcfe during the nine months ended September 30, 2018 to $0.80 per Mcfe during the nine months ended September 30, 2019, as our depletable reserve volumes increased more than our depletable base. The Transactions and the associated deconsolidation of Antero Midstream Partners resulted in our oil and gas reserves being adjusted from a consolidated to a stand-alone basis.

General and administrative expense. General and administrative expense (excluding equity-based compensation expense) increased from $99 million for the nine months ended September 30, 2018 to $111 million for the nine months ended September 30, 2019, primarily due to $6.3 million in legal and other expenses related to the Transactions, as well as an increase in other legal costs related to corporate matters. We had 607 employees as of September 30, 2018 and 569 employees as of September 30, 2019. On a per-unit basis, general and administrative expense excluding equity-based compensation decreased by 7%, from $0.14 per Mcfe during the nine months ended September 30, 2018 to $0.13 per Mcfe during the nine months ended September 30, 2019 as the increase in expenses was offset by a 27% increase in production.

Equity-based compensation expense. Noncash equity-based compensation expense decreased from $40 million for the nine months ended September 30, 2018 to $17 million for the nine months ended September 30, 2019 as a result of equity award forfeitures, as well as a decrease in the total value of awards to officers and employees in 2019 as compared to 2018. 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 Quarterly Report on Form 10-Q for more information on equity-based compensation awards.

Contract termination and rig stacking. We incurred contract termination and rig stacking costs of $14 million during the nine months ended September 30, 2019, representing fees incurred upon the delay or cancellation of drilling and completion contracts with third-party contractors in the first quarter of 2019 in order to align our drilling and completion activity level with our 2019 capital budget.

Discussion of Antero Midstream Corporation Segment for the Nine Months Ended September 30, 2018 Compared to the Nine Months Ended September 30, 2019

Through March 12, 2019, the results of Antero Midstream Partners were included in the consolidated financial statements of Antero. Effective March 13, 2019, the results of Antero Midstream Partners were no longer consolidated in Antero’s results. See Note 3 to the unaudited condensed consolidated financial statements for further discussion on the Transactions. The nine months ended September 30, 2018 include the results of Antero Midstream Partners while the nine months ended September 30, 2019 include partial results of Antero Midstream Partners through March 12, 2019.

Antero Midstream Corporation. Revenue from the Antero Midstream Corporation segment decreased from $747 million for the nine months ended September 30, 2018 to $554 million for the nine months ended September 30, 2019, a decrease of $193 million, or 26%. The decrease in operating revenue was primarily to a decrease in fresh water deliveries as well as waste water handling and treatment services and $39 million in amortization of customer relationships recognized in the nine months ended

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September 30, 2019. Total operating expenses related to the segment increased from $399 million for the nine months ended September 30, 2018 to $774 million for the nine months ended September 30, 2019. The increase was primarily due to the impairment of $457 million on Antero Midstream Corporation’s wastewater treatment facility and related goodwill and customer relationships, partially offset by decreases in the fresh water and waste water activities.

In addition, Antero Midstream Partners had equity in earnings of unconsolidated affiliates of $28 million and $35 million for the nine months ended September 30, 2018 and 2019, respectively.

Discussion of the Marketing Segment for the Nine Months Ended September 30, 2018 Compared to the Nine Months Ended September 30, 2019

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 and reduce our net costs related to the unused capacity under 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.

Marketing revenues were $488 million and $201 million and expenses of $561 million and $409 million for the nine months ended September 30, 2018 and 2019, respectively, related to these activities.

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 $126 million and $198 million for the nine months ended September 30, 2018 and 2019, respectively, which increased due to increased excess capacity charges related to new firm transportation lines being placed into service in late 2018 and in the first quarter of 2019. Additionally, the marketing segment recorded a fair value gain of $94 million in the nine months ended September 30, 2018 related to several natural gas purchase and sales contracts which were determined to be derivative instruments.

Operating losses on our marketing activities were $73 million and $208 million, or $0.24 per Mcfe and $0.24 per Mcfe, for the nine months ended September 30, 2018 and 2019, respectively.

Discussion of Items Not Allocated to Segments for the Nine Months Ended September 30, 2018 Compared to the Nine Months Ended September 30, 2019

Interest expense. Interest expense decreased from $208 million for the nine months ended September 30, 2018 to $174 million for the nine months ended September 30, 2019, due to decreased borrowings under the Credit Facility and due to the nine months ended September 30, 2019 including interest related to Antero Midstream Partners’ debt through March 12, 2019. Interest expense includes approximately $9.5 million and $8.3 million of non-cash amortization of deferred financing costs for the nine months ended September 30, 2018 and 2019, respectively. Interest expense related to stand-alone Antero was $157 million for the nine months ended September 30, 2019 compared to $166 million for the nine months ended September 30, 2018.

Income tax expense. Income tax expense increased from a deferred tax expense of $3 million, with an effective tax rate of 4%, for the nine months ended September 30, 2018 to a deferred tax expense of $32 million and $1.3 million of current tax expense, with an effective tax rate of 15%, for the nine months ended September 30, 2019. The change was primarily a result of the increase in book income due to the Transactions and the associated deconsolidation of Antero Midstream Partners, offset by the decrease in book income resulting from the impairment of proved properties in the Utica Shale.

At December 31, 2018, we had significant NOLs for U.S. federal and state income tax purposes. We will utilize a substantial portion of our NOLs to offset the taxable gain from the Transactions.  Future interpretations of existing tax laws that vary from our current interpretation, and possible changes to state tax laws in response to the U.S. federal tax legislation enacted in Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act, 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

Our primary sources of liquidity have been through net cash provided by operating activities including proceeds from derivatives, borrowings under the Credit Facility, issuances of debt and equity securities, and distributions/dividends of earnings from unconsolidated affiliates. 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 through March 12, 2019. As we pursue the development of our reserves, we continually monitor what capital

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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 net cash provided by operating activities and the capital resources available to us.

In addition, we may from time to time repurchase shares of our common stock under our share repurchase program. Under this program, we repurchased and retired 5,060,946 common shares for $18 million during the nine months ended September 30, 2019. We may also seek to retire or purchase our outstanding debt securities from time to time through cash purchases, in open market purchases, privately negotiated transactions or otherwise. Any such repurchases or exchanges will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors.

As of September 30, 2019, we believe that funds from operating cash flows and available borrowings under the Credit Facility, distributions/dividends of earnings from unconsolidated affiliates 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.

The following table summarizes our cash flows for the nine months ended September 30, 2018 and 2019:

	Nine Months Ended September 30,				Increase
(in thousands)	2018		2019		(Decrease)
Net cash provided by operating activities	$	1,260,398		955,518	(304,880)
Net cash used in investing activities		(1,770,339)		(825,327)	945,012
Net cash provided by financing activities		481,500		489,341	7,841
Effect of deconsolidation of Antero Midstream Partners LP		—		(619,532)	(619,532)
Net decrease in cash and cash equivalents	$	(28,441)		—	28,441

The Company's condensed consolidated cash flow statements for the nine months ended September 30, 2018 and 2019 includes the cash flows related to Antero Midstream Corporation for periods prior to March 13, 2019. Effective March 13, 2019, the Company's cash flows include only the operating, investing and financing activities related to Antero and; therefore, the cash flows for the nine months ended September 30, 2018 and 2019 are not representative of the expected future cash flows of the Company.

Cash Flows Provided by Operating Activities

Net cash provided by operating activities was $1.3 billion and $956 million for the nine months ended September 30, 2018 and 2019, respectively.

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.

Cash Flows Used in Investing Activities

During the nine months ended September 30, 2018 and 2019, we used cash flows in investing activities of $1.8 billion and $825 million, respectively, primarily as a result of our capital expenditures for drilling, development, and acquisitions. In addition, cash flows in investing activities included expenditures of Antero Midstream Partners related to construction of midstream and water handling and treatment infrastructure and investments in joint ventures through March 12, 2019. Effective March 13, 2019, these expenditures are no longer consolidated in Antero’s results. Excluding Antero Midstream Partners, capital expenditures were $1.3 billion and $1.0 billion for the nine months ended September 30, 2018 and 2019, respectively.

Cash flows used in investing activities decreased from $1.8 billion for the nine months ended September 30, 2018 to $825 million for the nine months ended September 30, 2019, primarily due to a decrease in capital expenditures of $570 million during the nine months ended September 30, 2019 as compared to the same period in 2018, and $297 million in proceeds received in connection with the Transactions. See Note 3 to the unaudited condensed consolidated financial statements for further discussion on the Transactions. Total capital expenditures for oil and gas properties decreased from $1.3 billion during the nine months ended September 30, 2018 to $1.0 billion during the nine months ended September 30, 2019 due to a decrease in drilling and completion activity. Capital expenditures for water handling and treatment systems decreased $53 million from $77 million for the nine months

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ended September 30, 2018 to $24 million for the nine months ended September 30, 2019, and capital expenditures for gathering and compression systems decreased $289 million from $337 million to $48 million for the nine months ended September 30, 2019. The decreases in capital expenditures for both the water handling and treatment systems, and the gathering and compression systems are due to the nine months ended September 30, 2019 only including Antero Midstream Partners’ activity through the deconsolidation date of March 12, 2019 as compared to the nine months ended September 30, 2018 including Antero Midstream Partners’ activity for the entire period. Additionally, investments in joint ventures by Antero Midstream Partners decreased $66 million from $91 million during the nine months ended September 30, 2018 to $25 million during the nine months ended September 30, 2019 due to the deconsolidation as of March 12, 2019.

Our exploration and production capital budget for 2019 is a range of $1.35 billion to $1.4 billion, which includes: $1.275 billion to $1.3 billion for drilling and completion and $75 million to $100 million for leasehold expenditures. 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 may 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.

For the three months ended September 30, 2019, our exploration and production capital expenditures decreased significantly from the three months ended March 31, 2019 and June 30, 2019 from approximately $399 million and $342 million, respectively, to $292 million. Our consolidated capital expenditures for the three months ended September 30, 2019 of $292 million included drilling and completion costs of $278 million, leasehold acquisitions of $13 million, and other capital expenditures of $1.4 million, whereas, our capital expenditures for the three months ended June 30, 2019 of $342 million included drilling and completion costs of $311 million, leasehold acquisitions of $29 million, and other capital expenditures of $1.5 million. Our capital expenditures for the three months ended March 31, 2019 of $399 million included drilling and completion costs of $369 million, leasehold acquisitions of $27 million, and other capital expenditures of $3 million. This reduction in costs was a result of our well cost savings initiatives, which include savings as a result of service cost deflation, sand logistics optimization and operational efficiency gains. As a result, we anticipate our exploration and production capital expenditures for the remainder of the year to be generally consistent with levels in the three months ended September 30, 2019 as opposed to the levels in the three months ended March 31, 2019 or June 30, 2019.

Cash Flows Provided by Financing Activities

During the nine months ended September 30, 2018 and 2019, net cash flows provided by financing activities increased from $482 million to $489 million primarily as a result of the issuance of senior notes by Antero Midstream Partners prior to the Transactions and the associated deconsolidation of Antero Midstream Partners, partially offset by net repayments on our Credit Facility and Antero Midstream Partners’ credit facility.

Net borrowings (repayments) on our Credit Facility and Antero Midstream Partners’ credit facility changed from net borrowings of $682 million during the nine months ended September 30, 2018 to net repayments of $45 million during the nine months ended September 30, 2019. In addition, under the share repurchase program launched in the fourth quarter of 2018, Antero repurchased and retired 5,060,946 common shares for $18 million during the nine months ended September 30, 2019.

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Debt Agreements and Contractual Obligations

Senior Secured Revolving Credit Facility. Our 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, 2019, the borrowing base was $4.5 billion and lender commitments were $2.5 billion. Each of these amounts were reaffirmed in the annual redetermination in April 2019. The next redetermination of the borrowing base is scheduled to occur by the end of April 2020. At December 31, 2018, we had $405 million of borrowings and $685 million of letters of credit outstanding under the Credit Facility, with a weighted average interest rate of 3.95%. At September 30, 2019, we had $275 million of borrowings and $703 million of letters of credit outstanding under the Credit Facility. The average annualized interest rate incurred on the Credit Facility during the nine months ended September 30, 2019 was approximately 4.39%. 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 our senior notes, unless such series of senior notes is refinanced. Our Credit Facility provides for borrowing under either LIBOR or an Alternative Rate of Interest.

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 and lease 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 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;

● 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, 2018 and September 30, 2019. The actual borrowing capacity available to us may be limited by the financial ratio covenants. At September 30, 2019, our current ratio was 5.05 to 1.0 (based on the $4.5 billion borrowing base under the Credit Facility) and our interest coverage ratio was 8.15 to 1.0.

For more information on the terms, conditions, and restrictions under the Credit Facility, please refer to our 2018 Form 10-K.

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, 2018 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.

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Contractual Obligations. A summary of our contractual obligations as of September 30, 2019 is provided in the table below. 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 2019		2020		2021		2022		2023		2024		Thereafter		Total
Recorded contractual obligations:
Credit Facility (1)	$	—		—		275		—		—		—		—		275
Antero senior notes—principal (2)		—		—		1,000		1,100		750		—		600		3,450
Antero senior notes—interest (2)		76		182		155		129		51		30		30		653
Operating leases (3)		103		399		349		359		377		392		1,251		3,230
Finance leases (3)		—		1		1		1		—		—		—		3
Imputed interest for leases (3)		49		179		157		136		114		90		199		924
Asset retirement obligations (4)		—		—		—		—		—		—		55		55
Unrecorded contractual obligations:
Firm transportation (5)		283		1,124		1,100		1,047		1,035		995		7,817		13,401
Processing, gathering, and compression services (6)		14		54		54		54		59		59		153		447
Land payment obligations (7)		5		6		3		—		—		—		—		14
Total	$	530		1,945		3,094		2,826		2,386		1,566		10,105		22,452

(1) Includes outstanding principal amounts at September 30, 2019. This table does not include future commitment fees, interest expense, or other fees on our 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.

(2) Our 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.

(3) Includes contracts for services provided by drilling rigs and completion fleets, processing, gathering and compression services agreements and office and equipment leases accounted for as leases. 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. See Note 12 to the unaudited condensed consolidated financial statements for more information on the Company’s operating and finance leases.

(4) 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.

(5) 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 and net of any fees for excess firm transportation marketed to third parties. None of these agreements were determined to be leases.

(6) Contractual commitments for processing, gathering, and compression services agreements represent minimum commitments under long-term agreements not accounted for as leases. This includes fees to be paid to the Joint Venture owned by Antero Midstream Partners and MarkWest. 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 obligations determined to be leases are included within finance and operating leases in the table above.

(7) Includes contractual commitments for land acquisition agreements. The values in the table represent the minimum payments due under these arrangements. None of these agreements were determined to be leases.

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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, 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 other than proceeds from derivative monetizations, income taxes, impairment, depletion, depreciation, amortization, and accretion, exploration expense, equity-based compensation, gain or loss on early extinguishment of debt, contract termination and rig stacking costs, simplification transaction fees, and gain or loss on sale of assets.

Through March 12, 2019, the financial results of Antero Midstream Partners were included in the consolidated results of Antero. Effective March 13, 2019, Antero no longer consolidates Antero Midstream Partners and accounts for its interest in Antero Midstream Corporation using the equity method of accounting (see Note 5 to the unaudited condensed consolidated financial statements). Adjusted EBITDAX also includes distributions received with respect to limited partner interests in Antero Midstream Partners common units through March 12, 2019.

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 or loss, 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 our 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 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. Adjusted EBITDAX is also used by our Board of Directors as a performance measure in determining executive compensation.

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 (loss), including noncontrolling interest, to Adjusted EBITDAX and a reconciliation of our Adjusted EBITDAX to net cash provided by operating activities per our consolidated statements of cash flows, in each case, for the three and nine months ended September 30, 2018 and 2019:

	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2018		2019		2018		2019
Reconciliation of net income (loss) to Adjusted EBITDAX:
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$	(154,419)		(878,864)	$	(275,971)		142,067
Net income and comprehensive income attributable to noncontrolling interests		76,447		—		211,534		46,993
Commodity derivative fair value gains (1)		(57,019)		(220,788)		(134,793)		(471,847)
Gains on settled commodity derivatives (1)		71,143		120,003		268,369		261,794
Marketing derivative fair value (gains) losses (1)		42		—		(94,081)		—
Gains (losses) on settled marketing derivatives (1)		(16,060)		—		78,098		—
Loss on sale of assets		—		—		—		951
Gain on deconsolidation of Antero Midstream Partners LP		—		—		—		(1,406,042)
Interest expense, net		74,528		47,754		208,303		173,868
Income tax expense		18,953		(272,627)		2,500		33,332
Depletion, depreciation, amortization, and accretion		243,897		242,430		711,581		726,827
Impairment of oil and gas properties		221,095		1,041,469		406,068		1,253,712
Impairment of midstream assets		1,157		7,800		9,658		14,782
Exploration expense		666		208		4,022		648
Equity-based compensation expense		16,202		3,875		56,429		19,327
Equity in earnings (loss) of unconsolidated affiliates		(10,705)		117,859		(27,832)		90,193
Distributions/dividends from unconsolidated affiliates		11,765		48,714		29,660		109,241
Contract termination and rig stacking		—		62		—		14,026
Simplification transaction fees		—		—		—		15,482
		497,692		257,895		1,453,545		1,025,354
Net income and comprehensive income attributable to noncontrolling interests		(76,447)		—		(211,534)		(46,993)
Antero Midstream Partners interest expense, net (2)		(16,895)		—		(42,784)		(16,815)
Antero Midstream Partners depreciation, accretion of ARO and accretion of contingent consideration (2)		(42,509)		—		(119,263)		(21,770)
Antero Midstream Partners impairment		(1,157)		—		(5,188)		(6,982)
Antero Midstream Partners equity-based compensation expense (2)		(4,528)		—		(16,606)		(2,477)
Antero Midstream Partners equity in earnings of unconsolidated affiliates (2)		10,705		—		27,832		12,264
Antero Midstream Partners distributions from unconsolidated affiliates (2)		(11,765)		—		(29,660)		(61,319)
Equity in earnings of Antero Midstream Partners (2)		23,363		—		70,417		(15,021)
Distributions from Antero Midstream Partners (2)		41,031		—		115,678		95,183
Antero Midstream Partners Simplification transaction fees		—		—		—		(9,185)
Antero Midstream Partners related adjustments		(78,202)		—		(211,108)		(73,115)
Adjusted EBITDAX	$	419,490		257,895	$	1,242,437		952,239
Reconciliation of our Adjusted EBITDAX to net cash provided by operating activities:
Adjusted EBITDAX	$	419,490		257,895	$	1,242,437		952,239
Antero Midstream Partners related adjustments		78,202		—		211,108		73,115
Interest expense, net		(74,528)		(47,754)		(208,303)		(173,868)
Exploration expense		(666)		(208)		(4,022)		(648)
Changes in current assets and liabilities		(2,053)		(13,653)		16,233		127,322
Simplification transaction fees		—		—		—		(15,482)
Other		—		(379)		—		(15,339)
Other non-cash items		1,013		2,509		2,945		8,179
Net cash provided by operating activities	$	421,458		198,410	$	1,260,398		955,518

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(1) The adjustments for the derivative fair value gains and losses and gains on settled derivatives have the effect of adjusting net income (loss) from operations for changes in the fair value of unsettled derivatives, which are recognized at the end of each accounting period. As a result, derivative gains included in the calculation Adjusted EBITDAX only reflect derivatives that settled during the period.

(2) Amounts reflected are net of any elimination adjustments for intercompany activity and include activity related to Antero Midstream Partners through March 12, 2019 (date of the Closing). Effective March 13, 2019, Antero accounts for its unconsolidated investment in Antero Midstream Corporation using the equity method of accounting. See Note 5 to the unaudited condensed consolidated financial statements for further discussion on equity method investments.

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 2018 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 to the consolidated financial statements, included in our 2018 Form 10-K, for a discussion of additional accounting policies and estimates made by management.

At September 30, 2019, estimated undiscounted future net cash flows based on future commodity prices exceeded the carrying values at September 30, 2019, for our Marcellus Shale properties and thus, no further evaluation of our Marcellus proved properties for impairment is required under GAAP. However, for the Utica Shale, the carrying amount exceeded the estimated undiscounted future cash flows based on future commodity prices at September 30, 2019. We estimated the fair value of the Utica Shale assets based on sales of other properties in the Utica Shale, estimates of proved reserves, estimated future commodity prices, future production estimates, and anticipated capital expenditures, using a commensurate discount rate. As a result, the Company recorded an impairment charges of $881 million related to proved properties in the Utica Shale during the three months ended September 30, 2019. Furthermore, the estimated future net cash flows decreased significantly from December 31, 2018 as a result of the deconsolidation of Antero Midstream, which resulted in an increase in capital and operating costs on a stand-alone basis, and further decreased throughout the year as future commodity prices declined. We have also seen costs decline as a result of reduced activity in the industry resulting from declining future commodity prices as well as our efforts to reduce costs, particularly in the area of wastewater management.

Off-Balance Sheet Arrangements

As of September 30, 2019, we did not have any off balance sheet arrangements other than contractual obligations for firm transportation and processing, 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.

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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 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 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, 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, 2019, our commodity derivatives included fixed price swaps, basis differential swaps and collars at index-based pricing.

At September 30, 2019, we had in place natural gas swaps and collars covering portions of our projected production through 2023. Our commodity hedge position as of September 30, 2019 is summarized in Note 11 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, 2019, our revenues would have decreased by approximately $51 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, 2019.

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.”

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, 2019, the estimated fair value of our commodity derivative instruments was a net asset of $817 million comprised of current assets and liabilities and noncurrent assets. At December 31, 2018, the estimated fair value of our commodity derivative instruments was a net asset of $607 million comprised of current assets and liabilities and noncurrent assets.

By reducing 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 ($817 million at September 30, 2019); and the sale of our natural gas, NGLs and oil production ($263 million at September 30, 2019), which we market to energy companies, end users, and refineries.

By using derivative instruments that are not traded on an exchange to hedge 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

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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 that 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 sixteen different counterparties, fourteen of which are lenders under our Credit Facility. The fair value of our commodity derivative contracts of approximately $817 million at September 30, 2019 included the following derivative assets by bank counterparty: Bank of Montreal - $10 million; BNP Paribas - $24 million; Capital One - $2 million; Canadian Imperial Bank of Commerce - $79 million; Citigroup - $150 million; DNB Bank - less than $1 million; Fifth Third - less than $1 million; JP Morgan - $123 million; Mitsui Ltd - $1 million; Morgan Stanley - $125 million; Natixis - $11 million; PNC – $21 million; Scotiabank - $79 million; SunTrust - $7 million; Toronto Dominion - $7 million; and Wells Fargo - $177 million. 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, 2019 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, 2019, we did not have any past-due receivables from, or payables to, any of the counterparties to our derivative contracts.

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. 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.

Interest Rate Risks

Our primary exposure to interest rate risk results from outstanding borrowings under our Credit Facility. The Credit Facility has a floating interest rate. The average annualized interest rate incurred on the Credit Facility during the nine months ended September 30, 2019 was approximately 4.39%. We estimate that a 1.0% increase in each of the applicable average interest rates for the nine months ended September 30, 2019 would have resulted in an estimated $1.6 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, 2019 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, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1.Legal Proceedings.

The information required by this item is included in Note 14 to our unaudited condensed consolidated financial statements and is incorporated herein.

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 2018 Form 10-K. The risks described in our 2018 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 2018 Form 10-K. We may experience additional risks and uncertainties not currently known to us. Furthermore, 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.

Item 2. Unregistered Sales of Equity Securities

Issuer Purchases of Equity Securities

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

Period	Total Number of Shares Purchased (1)		Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans (2)		Maximum Number of Shares that May Yet be Purchased Under the Plan
July 1, 2019 - July 31, 2019		16,405	$	5.11		—		N/A
August 1, 2019 - August 31, 2019		510,846	$	3.05		510,846		N/A
September 1, 2019 - September 30, 2019		4,550,100	$	3.60		4,550,100		N/A
Total		5,077,351	$	3.55		5,060,946		N/A

(1) The total number of shares purchased includes 16,405 shares repurchased in July representing shares of our common stock transferred to us in order to satisfy tax withholding obligations incurred upon the vesting of restricted stock and restricted stock units held by our employees. There were no share repurchases in August or September relating to shares transferred to satisfy tax withholding obligations.

(2) In October 2018, the Company’s Board of Directors authorized a $600 million share repurchase program. During the three months ended September 30, 2019, we repurchased 5,060,946 shares under this program for a total of $18 million, or a weighted average of $3.54 per share.

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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).
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, 2019 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations and Comprehensive 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.
104*	Cover Page Interactive Data File (embedded within the Inline XBRL document).

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 29, 2019

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