Antero Resources (AR) 10-Q 2020 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, 2020

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 268,671,945 shares of common stock outstanding as of October 23, 2020.

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	44
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	69
Item 4.	Controls and Procedures	70
PART II—OTHER INFORMATION		71
Item 1.	Legal Proceedings	71
Item 1A.	Risk Factors	71
Item 2.	Unregistered Sales of Equity Securities	72
Item 6.	Exhibits	73
SIGNATURES		74

1

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Some of the information in this Quarterly Report on Form 10-Q may contain “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. 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 based on management’s current beliefs, based on currently available information, as to the outcome and timing of future events. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

● our ability to execute our business strategy;

● our production and oil and gas reserves;

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

● our ability to obtain debt or equity financing on satisfactory terms to fund additional acquisitions, expansion projects, working capital requirements and the repayment or refinancing of indebtedness;

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

● impacts of world health events, including the coronavirus (“COVID-19”) pandemic;

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

● our hedging strategy and results;

● our ability to execute our debt repurchase program and/or our asset sale program;

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

● our future drilling plans;

● our projected well costs and cost savings initiatives, including with respect to water handling 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

2

● our other plans, objectives, expectations and intentions contained in this Quarterly Report on Form 10-Q.

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, impacts of world health events, including the COVID-19 pandemic, potential shut-ins of production due to lack of downstream demand or storage capacity, and the other risks described or referenced under the heading “Risk Factors” herein, including the risk factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2019 (the “2019 Form 10-K”) and in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, each of which is 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 or referenced 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, 2019 and September 30, 2020

(In thousands)

			(Unaudited)
	December 31,		September 30,
	2019		2020
Assets
Current assets:
Accounts receivable	$	46,419		88,062
Accounts receivable, related parties		125,000		—
Accrued revenue		317,886		338,729
Derivative instruments		422,849		83,057
Other current assets		10,731		11,934
Total current assets		922,885		521,782
Property and equipment:
Oil and gas properties, at cost (successful efforts method):
Unproved properties		1,368,854		1,265,255
Proved properties		11,859,817		12,149,941
Gathering systems and facilities		5,802		5,802
Other property and equipment		71,895		72,936
		13,306,368		13,493,934
Less accumulated depletion, depreciation, and amortization		(3,327,629)		(3,659,376)
Property and equipment, net		9,978,739		9,834,558
Operating leases right-of-use assets		2,886,500		2,660,188
Derivative instruments		333,174		44,070
Investment in unconsolidated affiliate		1,055,177		272,926
Other assets		21,094		16,215
Total assets	$	15,197,569		13,349,739
Liabilities and Equity
Current liabilities:
Accounts payable	$	14,498		55,173
Accounts payable, related parties		97,883		81,519
Accrued liabilities		400,850		344,606
Revenue distributions payable		207,988		148,917
Derivative instruments		6,721		107,933
Short-term lease liabilities		305,320		251,568
Deferred revenue, VPP		—		43,192
Other current liabilities		6,879		2,467
Total current liabilities		1,040,139		1,035,375
Long-term liabilities:
Long-term debt		3,758,868		3,158,225
Deferred income tax liability		781,987		381,233
Derivative instruments		3,519		149,222
Long-term lease liabilities		2,583,678		2,410,114
Deferred revenue, VPP		—		167,466
Other liabilities		58,635		64,223
Total liabilities		8,226,826		7,365,858
Commitments and contingencies (Notes 14 and 15)
Equity:
Stockholders' equity:
Preferred stock, $0.01 par value; authorized - 50,000 shares; NaN issued		—		—
Common stock, $0.01 par value; authorized - 1,000,000 shares; 295,941 shares and 268,549 shares issued and outstanding at December 31, 2019 and September 30, 2020, respectively		2,959		2,685
Additional paid-in capital		6,130,365		6,165,750
Accumulated earnings (deficit)		837,419		(500,308)
Total stockholders' equity		6,970,743		5,668,127
Noncontrolling interests		—		315,754
Total equity		6,970,743		5,983,881
Total liabilities and equity	$	15,197,569		13,349,739

See accompanying notes to unaudited condensed consolidated financial statements.

4

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Operations and Comprehensive Loss

Three Months Ended September 30, 2019 and 2020

(Unaudited)

(In thousands, except per share amounts)

	Three Months Ended September 30,
	2019		2020
Revenue and other:
Natural gas sales	$	524,448		436,304
Natural gas liquids sales		284,958		327,426
Oil sales		40,561		34,265
Commodity derivative fair value gains (losses)		220,788		(514,751)
Marketing		46,645		91,497
Amortization of deferred revenue, VPP		—		5,175
Other income		1,481		675
Total revenue		1,118,881		380,591
Operating expenses:
Lease operating		35,928		21,450
Gathering, compression, processing, and transportation		603,860		656,615
Production and ad valorem taxes		28,863		25,790
Marketing		108,216		128,580
Exploration		208		454
Impairment of oil and gas properties		1,041,469		29,392
Impairment of midstream assets		7,800		—
Depletion, depreciation, and amortization		241,503		238,418
Accretion of asset retirement obligations		927		1,115
General and administrative (including equity-based compensation expense of $3,875 and $5,699 in 2019 and 2020, respectively)		35,923		31,640
Contract termination and rig stacking		62		1,246
Total operating expenses		2,104,759		1,134,700
Operating loss		(985,878)		(754,109)
Other income (expense):
Equity in earnings (loss) of unconsolidated affiliates		(117,859)		24,419
Transaction expense		—		(524)
Interest expense, net		(47,754)		(48,043)
Gain on early extinguishment of debt		—		55,633
Total other income (expense)		(165,613)		31,485
Loss before income taxes		(1,151,491)		(722,624)
Provision for income tax benefit		272,627		168,778
Net loss and comprehensive income loss including noncontrolling interests		(878,864)		(553,846)
Less: net loss and comprehensive loss attributable to noncontrolling interests		—		(18,233)
Net loss and comprehensive loss attributable to Antero Resources Corporation	$	(878,864)		(535,613)
Loss per share—basic	$	(2.86)		(1.99)
Loss per share—diluted	$	(2.86)		(1.99)
Weighted average number of shares outstanding:
Basic		307,781		268,511
Diluted		307,781		268,511

See accompanying notes to unaudited condensed consolidated financial statements

5

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)

Nine Months Ended September 30, 2019 and 2020

(Unaudited)

(In thousands, except per share amounts)

	Nine Months Ended September 30,
	2019		2020
Revenue and other:
Natural gas sales	$	1,735,086		1,214,801
Natural gas liquids sales		902,606		797,296
Oil sales		137,675		78,233
Commodity derivative fair value gains (losses)		471,847		(116,933)
Gathering, compression, water handling and treatment		4,479		—
Marketing		200,911		201,855
Amortization of deferred revenue, VPP		—		5,175
Other income		3,348		2,180
Total revenue		3,455,952		2,182,607
Operating expenses:
Lease operating		118,517		71,836
Gathering, compression, processing, and transportation		1,595,223		1,877,084
Production and ad valorem taxes		95,509		71,481
Marketing		408,839		334,906
Exploration		648		895
Impairment of oil and gas properties		1,253,712		155,962
Impairment of midstream assets		14,782		—
Depletion, depreciation, and amortization		724,006		652,130
Loss on sale of assets		951		—
Accretion of asset retirement obligations		2,821		3,330
General and administrative (including equity-based compensation expense of $19,327 and $17,001 in 2019 and 2020, respectively)		146,507		101,264
Contract termination and rig stacking		14,026		12,317
Total operating expenses		4,375,541		3,281,205
Operating loss		(919,589)		(1,098,598)
Other income (expense):
Equity in loss of unconsolidated affiliates		(90,193)		(83,408)
Impairment of equity investment		—		(610,632)
Gain on deconsolidation of Antero Midstream Partners LP		1,406,042		—
Transaction expense		—		(6,662)
Interest expense, net		(173,868)		(152,956)
Gain on early extinguishment of debt		—		175,365
Total other income (expenses)		1,141,981		(678,293)
Income (loss) before income taxes		222,392		(1,776,891)
Provision for income tax (expense) benefit		(33,332)		421,167
Net income (loss) and comprehensive income (loss) including noncontrolling interests		189,060		(1,355,724)
Less: net income (loss) and comprehensive income (loss) attributable to noncontrolling interests		46,993		(17,997)
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$	142,067		(1,337,727)
Income (loss) per share—basic	$	0.46		(4.89)
Income (loss) per share—diluted	$	0.46		(4.89)
Weighted average number of shares outstanding:
Basic		308,509		273,689
Diluted		308,646		273,689

See accompanying notes to unaudited condensed consolidated financial statements.

6

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statement of Stockholders’ Equity

Nine Months Ended September 30, 2019

(Unaudited)

(In thousands)

					Additional		Accumulated
	Common Stock				paid-in		earnings		Noncontrolling		Total
	Shares		Amount		capital		(deficit)		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 unaudited condensed consolidated financial statements.

7

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statement of Stockholders’ Equity

Nine Months Ended September 30, 2020

(Unaudited)

(In thousands)

					Additional		Accumulated
	Common Stock				paid-in		earnings		Noncontrolling		Total
	Shares		Amount		capital		(deficit)		interests		equity
Balances, December 31, 2019		295,941	$	2,959		6,130,365		837,419		—		6,970,743
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		178		2		(34)		—		—		(32)
Repurchases and retirements of common stock		(27,193)		(272)		(42,418)		—		—		(42,690)
Equity-based compensation		—		—		3,329		—		—		3,329
Net loss and comprehensive loss		—		—		—		(338,810)		—		(338,810)
Balances, March 31, 2020		268,926		2,689		6,091,242		498,609		—		6,592,540
Issuance of common units in Martica Holdings, LLC		—		—		—		—		300,000		300,000
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		464		5		(305)		—		—		(300)
Distributions to noncontrolling interest		—		—		—		—		(3,413)		(3,413)
Repurchases and retirements of common stock		(1,000)		(10)		(743)		—		—		(753)
Equity-based compensation		—		—		7,973		—		—		7,973
Net loss and comprehensive loss		—		—		—		(463,304)		236		(463,068)
Balances, June 30, 2020		268,390	$	2,684		6,098,167		35,305		296,823		6,432,979
Issuance of common units in Martica Holdings, LLC		—		—		—		—		51,000		51,000
Equity component of 2026 Convertible Notes, net		—		—		61,926		—		—		61,926
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		159		1		(42)		—		—		(41)
Distributions to noncontrolling interest		—		—		—		—		(13,836)		(13,836)
Equity-based compensation		—		—		5,699		—		—		5,699
Net loss and comprehensive loss		—		—		—		(535,613)		(18,233)		(553,846)
Balances, September 30, 2020		268,549	$	2,685		6,165,750		(500,308)		315,754		5,983,881

See accompanying notes to unaudited condensed consolidated financial statements.

8

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Cash Flows

Nine Months Ended September 30, 2019 and 2020

(Unaudited)

(In thousands)

	Nine Months Ended September 30,
	2019		2020
Cash flows provided by (used in) operating activities:
Net income (loss) including noncontrolling interests	$	189,060		(1,355,724)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, amortization, and accretion		726,827		655,460
Impairment of oil and gas properties		1,253,712		155,962
Impairment of midstream assets		14,782		—
Commodity derivative fair value (gains) losses		(471,847)		116,933
Gains on settled commodity derivatives		261,794		740,805
Proceeds from derivative monetizations		—		18,073
Loss on sale of assets		951		—
Equity-based compensation expense		19,327		17,001
Deferred income tax expense (benefit)		32,019		(426,267)
Gain on early extinguishment of debt		—		(175,365)
Equity in loss of unconsolidated affiliates		90,193		83,408
Impairment of equity investment		—		610,632
Gain on deconsolidation of Antero Midstream Partners LP		(1,406,042)		—
Distributions/dividends of earnings from unconsolidated affiliates		109,241		128,267
Amortization of deferred revenue		—		(5,175)
Amortization of debt issuance costs, debt discount debt premium and other		8,179		7,391
Changes in current assets and liabilities:
Accounts receivable		14,236		(15,454)
Accrued revenue		193,650		(20,843)
Other current assets		2,365		(1,455)
Accounts payable including related parties		(971)		(2,198)
Accrued liabilities		(11,169)		15,522
Revenue distributions payable		(72,176)		(54,403)
Other current liabilities		1,387		(60)
Net cash provided by operating activities		955,518		492,510
Cash flows provided by (used in) investing activities:
Additions to unproved properties		(69,796)		(31,136)
Drilling and completion costs		(957,931)		(693,920)
Additions to water handling and treatment systems		(24,416)		—
Additions to gathering systems and facilities		(48,239)		—
Additions to other property and equipment		(5,980)		(1,346)
Settlement of water earnout		—		125,000
Investments in unconsolidated affiliates		(25,020)		—
Proceeds from the Antero Midstream Partners LP Transactions		296,611		—
Proceeds from asset sales		7,461		—
Proceeds from VPP sale, net		—		215,833
Change in other assets		1,983		1,506
Net cash used in investing activities		(825,327)		(384,063)
Cash flows provided by (used in) financing activities:
Repurchases of common stock		(17,924)		(43,443)
Issuance of senior notes		650,000		—
Issuance of convertible notes		—		287,500
Repayment of senior notes		—		(899,971)
Borrowings (repayments) on bank credit facilities, net		(45,000)		275,000
Payments of deferred financing costs		(8,259)		(8,907)
Sale of noncontrolling interest		—		300,000
Distributions to noncontrolling interests in Antero Midstream Partners LP		(85,076)		—
Distributions to noncontrolling interests in Martica Holdings LLC		—		(17,249)
Employee tax withholding for settlement of equity compensation awards		(2,379)		(373)
Other		(2,021)		(1,004)
Net cash provided by (used in) financing activities		489,341		(108,447)
Effect of deconsolidation of Antero Midstream Partners LP		(619,532)		—
Net decrease in cash and cash equivalents		0		0
Cash and cash equivalents, beginning of period		0		0
Cash and cash equivalents, end of period	$	0		0
Supplemental disclosure of cash flow information:
Cash paid during the period for interest	$	142,288		135,494
Decrease in accounts payable and accrued liabilities for additions to property and equipment	$	22,103		44,302

See accompanying notes to unaudited condensed consolidated financial statements.

9

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

(1) Organization

Antero Resources Corporation (individually referred to as “Antero”) and its consolidated subsidiaries (collectively referred to as “Antero Resources,” 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 Securities and Exchange Commission (the “SEC”) applicable to interim financial information and should be read in the context of the Company’s December 31, 2019 consolidated financial statements and notes thereto for a more complete understanding of the Company’s operations, financial position, and accounting policies. The Company’s December 31, 2019 consolidated financial statements were included in Antero Resources’ 2019 Annual Report on Form 10-K, which was filed with the SEC.

These 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, these 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, 2019 and September 30, 2020, its results of operations for the three and nine months ended September 30, 2019 and 2020 and its cash flows for the nine months ended September 30, 2019 and 2020. The Company has no items of other comprehensive income or loss; therefore, its net income or loss is equal to its comprehensive income or loss. Operating results for the period ended September 30, 2020 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, the impacts of COVID-19 and other factors.

(b) Principles of Consolidation

The accompanying unaudited condensed consolidated financial statements include the accounts of Antero Resources Corporation, 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—Deconsolidation of Antero Midstream Partners LP to the unaudited condensed consolidated financial statements), the Company’s ownership of Antero Midstream Partners common units represented approximately a 53% limited partner interest in Antero Midstream Partners, and Antero Resources consolidated Antero Midstream Partners’ financial position and results of operations into its consolidated financial statements. The Transactions (defined in Note 3—Deconsolidation of Antero Midstream Partners LP to the unaudited condensed consolidated financial statements) resulted in the exchange of the limited partner interest Antero Resources owned in Antero Midstream Partners for common stock of Antero Midstream Corporation, par value $0.01 per share (the “Antero Midstream Corporation common stock”), representing an approximate 31% interest in Antero Midstream Corporation. As a result, Antero Resources’ controlling interest in Antero Midstream Partners was converted to 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—Deconsolidation of Antero Midstream Partners LP to the unaudited condensed consolidated financial statements for further discussion on the Transactions.

For the three months and nine months ended September 30, 2020, the Company determined that Martica Holdings LLC (“Martica”) is a VIE for which Antero is the primary beneficiary.  Therefore, Martica’s accounts are consolidated in the Company’s consolidated financial statements.  Antero is the primary beneficiary of Martica based on its power to direct the activities that most

10

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

significantly impact Martica’s economic performance, and its obligation to absorb losses of, or right to receive benefits from, Martica that could be significant to Martica.  In reaching such determination that Antero is the primary beneficiary of Martica, the Company considered the following:

● Martica was formed to hold certain overriding royalty interests across the Company’s existing asset base;

● substantially all of Martica’s revenues are derived from production from the Company’s natural gas, NGLs, and oil properties in the Appalachian Basin in West Virginia and Ohio;

● Antero owns the Class B Units in Martica, which entitle Antero to receive distributions in respect of the Incremental Override (as defined in Note 4—Transactions); and

● Antero provides accounting, administrative and other services to Martica under a Management Services Agreement.

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 for the nine months ended September 30, 2019 represents the interests in Antero Midstream Partners that were owned by the public prior to the Transactions, and the incentive distribution rights in Antero Midstream Partners. The noncontrolling interest in the Company’s unaudited condensed consolidated financial statements for the three and nine months ended September 30, 2020 represents the interest in Martica owned by third parties. See Note 4—Transactions for more information on the sale of this noncontrolling interest. Martica is a discrete entity and the assets and credits of Martica are not available to satisfy the debts and obligations of the Company or its other subsidiaries.

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 Investment in unconsolidated affiliate on the Company’s unaudited condensed consolidated balance sheets. Income (loss) from investees that are accounted for under the equity method is included in Equity in earnings (loss) 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 or net loss, it is recorded in equity in earnings (loss) of unconsolidated affiliates in the statements of operations 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 Company’s balance sheet. The Company’s 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, which is classified as cash inflows from operating activities, or a return of investment, which is 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, liabilities and 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.

11

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

(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 storage capacity and transportation 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 December 31, 2019, the book overdraft included within accounts payable and revenue distributions payable was $7 million and $18 million, respectively. As of September 30, 2020, the book overdraft included within accounts payable and revenue distributions payable was $8 million and $13 million, respectively.

(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 three and nine months ended September 30, 2020. During the nine months ended September 30, 2019, the Company 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, future plans to develop acreage, 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. For the three months ended September 30, 2019 and 2020, impairment of unproved properties was $160 million and $29 million, respectively. For the nine months ended September 30, 2019 and 2020, impairment of unproved properties was $347 million and $156 million, 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 expense 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.

Because estimated undiscounted future net cash flows based on future commodity prices as of September 30, 2019 exceeded the carrying amount of our proved properties in the Marcellus Shale as of September 30, 2019, management did not further evaluate our Marcellus proved properties for impairment. However, the carrying amount of the Company’s proved properties in the Utica

12

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

Shale exceeded the estimated undiscounted future cash flows based on future commodity prices as of September 30, 2019. The Company 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 expense of $881 million related to proved properties in the Utica Shale during the three months ended September 30, 2019. The Company did not incur any impairment expenses related to proved properties in the Utica Shale for the nine months ended September 30, 2020. The Company did not record any impairment expenses associated with its proved properties in the Marcellus Shale during the nine months ended September 30, 2019 and 2020.

(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.

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) Deferred Revenue

Under the terms of the VPP (as defined below in Note 4—Transactions), the Company is obligated to deliver certain natural gas volumes from specified wells to an overriding royalty interest owner over the term of the arrangement. The Company has accounted for the VPP as a conveyance under Accounting Standard Codifications (“ASC”) Topic 932, Extractive Industries—Oil and Gas (“ASC 932”), which requires the net proceeds to be recognized as deferred revenue due to the Company’s future performance obligations. Deferred revenue is recognized as volumes are delivered using the units-of-production method over the term of the VPP in Amortization of deferred revenue on the Company’s unaudited condensed consolidated statements of operations. See Note 4—Transactions for further discussion of the VPP transaction.

(j) Natural Gas, NGLs, and Oil Revenues

The Company’s 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 the Company’s natural gas sales contracts, it delivers natural gas to the purchaser at an agreed upon delivery point. Natural gas is transported from the wellheads to delivery points specified under sales contracts. To deliver natural gas to these points, Antero Midstream Corporation or other third parties gather, compress, process and transport the Company’s natural gas. The Company maintains control of the natural gas during gathering, compression, processing, and transportation. The Company’s sales contracts provide that it receives a specific index price adjusted for pricing differentials. The Company transfers control of the product at the delivery point and recognizes revenue based on the contract price. The costs incurred to gather, compress, process and transport natural gas are recorded as Gathering, compression, processing and transportation expense.

13

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

NGLs, which are extracted from natural gas through processing, are either sold by the Company directly or by the processor under processing contracts. For NGLs sold by the Company directly, the sales contracts primarily provide that the Company delivers the product to the purchaser at an agreed upon delivery point and that it receives a specific index price adjusted for pricing differentials. The Company transfers control of the product to the purchaser at the delivery point and recognizes revenue based on the contract price. The costs incurred to process and transport NGLs are recorded as Gathering, compression, processing, and transportation expense. For NGLs sold by the processor, the Company’s processing contracts provide that the Company transfers control to the processor at the tailgate of the processing plant and it recognizes revenue based on the price received from the processor.

Under the Company’s oil sales contracts, Antero Resources’ generally sells oil to purchasers and collects a contractually agreed upon index price, net of pricing differentials. The Company recognizes revenue based on the contract price when it transfers control of the product to a purchaser. When applicable, the costs incurred to transport oil to a purchaser are recorded as Gathering, compression, processing and transportation expense.

(k) Marketing Revenues and Expenses

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. The Company retains control of the purchased natural gas and NGLs prior to delivery to the purchaser. The Company has concluded that it is the principal in these arrangements and therefore, the Company recognizes 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 the Company’s produced natural gas and NGLs. The Company satisfies performance obligations to the purchaser by transferring control of the product at the delivery point and recognizes revenue based on the contract price received from the purchaser. Fees generated from the sale of excess firm transportation marketed to third parties are included in Marketing revenue.

Marketing expenses include the cost of purchased third-party natural gas and NGLs. The Company classifies firm transportation costs related to capacity contracted for in advance of having sufficient production and infrastructure to fully utilize the capacity (excess capacity) as marketing expenses since it is marketing this excess capacity to third parties. Firm transportation for which the Company has sufficient production capacity (even though it may not use the transportation capacity because of alternative delivery points with more favorable pricing) is considered unutilized capacity and is charged to transportation expense.

(l) 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—Deconsolidation of Antero Midstream Partners LP to the consolidated financial statements for further discussion on the Transactions and Note 18—Segment information to the 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 satisfied its performance obligations and recognized revenue when low pressure volumes were delivered to a compressor station, high pressure volumes were delivered to a processing plant or transmission pipeline, and compression volumes were delivered to a high pressure line. Revenue was 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 satisfied its performance obligations and recognized revenue when the fresh water volumes were delivered to the hydration unit of a specified well pad and the wastewater volumes were delivered to its wastewater treatment facility. For services contracted through third-party providers, Antero Midstream Partners’ performance obligation was satisfied when the services performed by the third-party providers were completed. Revenue was 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.

(m) 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

14

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

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 unaudited 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—Deconsolidation of Antero Midstream Partners LP to the unaudited condensed consolidated financial statements for further discussion on the Transactions and Note 18—Segment Information 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.

(n) 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 and shares of common stock issuable upon conversion of the 2026 Convertible Notes (as defined below in Note 8—Long-Term Debt), calculated using the treasury stock method. The Company includes restricted stock unit (“RSUs”) awards, performance share unit (“PSUs”) awards and stock options 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.

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		Nine months ended
	September 30,		September 30,
	2019	2020	2019	2020
Basic weighted average number of shares outstanding	307,781	268,511	308,509	273,689
Add: Dilutive effect of RSUs	—	—	27	—
Add: Dilutive effect of outstanding stock options	—	—	—	—
Add: Dilutive effect of PSUs	—	—	110	—
Diluted weighted average number of shares outstanding	307,781	268,511	308,646	273,689
Weighted average number of outstanding securities excluded from calculation of diluted earnings per common share (1):
RSUs	2,356	10,129	2,008	7,397
Outstanding stock options	514	432	541	432
PSUs	2,676	1,988	2,141	1,808
2026 Convertible Notes (2)	—	—	—	—

(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.

(2) In August 2020 and September 2020, the Company issued $287.5 million in aggregate principal amount of 4.25% convertible senior notes due September 1, 20206 (the “2026 Convertible Notes”). The Company intends to settle the principal amount of the 2026 Convertible Notes in cash upon conversion. As a result, only the amount by which the conversion value exceeds the aggregate principal amount of the 2026 Convertible Notes is considered in the diluted earnings per share computation under the treasury stock method. As of September 30, 2020, the conversion value did not exceed the principal amount of the notes, and accordingly, there was no impact to diluted earnings per share for the periods presented. See Note 8—Long-Term Debt.

15

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

(o) 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.

(p) Recently Issued Accounting Standard

On August 5, 2020, the Financial Accounting Standards Board issued Accounting Standards Update No. 2020-06, Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity, which eliminates the cash conversion model in ASC 470-20, Debt with Conversion and Other Options, that require separate accounting for conversion features that is currently being applied to the 2026 Convertible Notes, and instead, allows the debt instrument and conversion features to be accounted for as a single debt instrument. The new standard becomes effective for the Company on January 1, 2022, and early adoption is permitted. The Company is evaluating its plans for adoption, including the adoption date and transition method.

Upon adoption of this new standard, the Company expects to reclassify $62 million, net of deferred income taxes and equity issuance costs, to long-term debt and deferred income tax liability, as applicable, from stockholders’ equity. Additionally, annual interest expense for the 2026 Convertible Notes will be based on an effective interest rate of 4.8% as compared to 11.7% for the three and nine months ended September 30, 2020 in the statement of operations and the weighted average diluted shares outstanding will increase from 0 as of September 30, 2020 under the treasury-stock method to 66 million under the if-converted method. The Company does not believe that adoption of the standard will impact its operational strategies or growth prospects.

(3) Deconsolidation of Antero Midstream Partners LP

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

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 6—Equity Method Investments 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 unaudited 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 unaudited statement of operations and comprehensive income (loss) through March 12, 2019.

16

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

(4) Transactions

Conveyance of Overriding Royalty Interest

On June 15, 2020, the Company announced the consummation of a transaction with an affiliate of Sixth Street Partners, LLC (“Sixth Street”) relating to certain overriding royalty interests across the Company’s existing asset base (the “ORRIs”). In connection with the transaction, the Company contributed the ORRIs to Martica and Sixth Street contributed $300 million in cash (subject to customary adjustments) and agreed to contribute up to an additional $102 million in cash if certain production thresholds attributable to the ORRIs are achieved in the third quarter of 2020 and first quarter of 2021. All cash contributed by Sixth Street at the initial closing was distributed to the Company. As of September 30, 2020, the Company determined it met the production threshold related to the third quarter of 2020 whereby it became entitled to receive a $51 million cash distribution that will be paid in the fourth quarter of 2020.

The ORRIs include an overriding royalty interest of 1.25% of the Company’s working interest in all of its proved operated developed properties in West Virginia and Ohio, subject to certain excluded wells (the “Initial PDP Override”), and an overriding royalty interest of 3.75% of the Company’s working interest in all of its undeveloped properties in West Virginia and Ohio (the “Development Override”). Wells turned to sales after April 1, 2020 and prior to the later of (a) the date on which the Company turns to sales 2.2 million lateral feet (net to the Company’s interest) of horizontal wells burdened by the Development Override and (b) the earlier of (i) April 1, 2023 and (ii) the date on which the Company turns to sales 3.82 million lateral feet (net to the Company’s interest) of horizontal wells are subject to the Development Override.

The ORRIs also include an additional overriding royalty interest of 2.00% of the Company’s working interest in the properties underlying the Initial PDP Override (the “Incremental Override”). The Incremental Override (or a portion thereof, as applicable) may be re-conveyed to the Company (at the Company’s election) if certain production targets attributable to the ORRIs are achieved through March 31, 2023. Any portion of the Incremental Override that may not be re-conveyed to the Company based on the Company failing to achieve such production volumes through March 31, 2023 will remain with Martica.

 Prior to Sixth Street achieving an internal rate of return of 13% and 1.5x cash-on-cash return (the “Hurdle”), Sixth Street will receive all distributions in respect of the Initial PDP Override and the Development Override, and the Company will receive all distributions in respect of the Incremental Override, unless certain production targets are not achieved, in which case Sixth Street will receive some or all of the distributions in respect of the Incremental Override. Following Sixth Street achieving the Hurdle, the Company will receive 85% of the distributions in respect of the ORRIs to which Sixth Street was entitled immediately prior to the Hurdle being achieved.

The conveyance of the ORRIs from the Company to Martica was accounted for as a transaction between entities under common control.  As a result, the contributed ORRIs have been recorded by Martica at their historical cost.  

Volumetric Production Payment Transaction

On August 10, 2020, the Company completed a volumetric production payment transaction and received net proceeds of approximately $215 million (the "VPP").  In connection with the VPP, the Company entered into a purchase and sale agreement, together with a conveyance agreement and production and marketing agreement, with J.P. Morgan Ventures Energy Corporation ("JPM-VEC") to convey, effective July 1, 2020, an overriding royalty interest in dry gas producing properties in West Virginia (the "VPP Properties") equal to 136,589,000 MMBtu over the expected seven-year term of the VPP.

The Company has accounted for the VPP as a conveyance under ASC 932, and the net proceeds were recognized as deferred revenue as of September 30, 2020. Deferred revenue is recognized as volumes are delivered using the units-of-production method over the term of the VPP. Under the production and marketing agreement, Antero and its affiliates provide certain marketing services as JPM-VEC’s agent, and any income or expenses related to these services will be recorded as marketing revenue or marketing expenses (as the case may be).

Contemporaneously with the VPP transaction, the Company executed a call option related to the production volumes associated with its retained interest in the VPP properties, which is collateralized by a mortgage on the VPP properties. Additionally, the production and marketing agreement contains an embedded put option related to the production volumes for the Company’s

17

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

retained interest in the VPP properties, which has been bifurcated from the production and marketing arrangement and accounted for as a derivative instrument recorded at fair value as of September 30, 2020. See Note 12—Derivative Instruments.

(5) Revenue

(a)Disaggregation of Revenue

Revenue is disaggregated by type in the following table. The table also identifies which reportable segment that the disaggregated revenues relate. For more information on reportable segments, see Note 18—Segment Information.

	Three months ended				Nine months ended
	September 30,				September 30,
(in thousands)	2019		2020		2019		2020		Reportable segment
Revenues from contracts with customers:
Natural gas sales	$	524,448		436,304	$	1,735,086		1,214,801	Exploration and production
Natural gas liquids sales (ethane)		26,488		32,444		92,378		85,884	Exploration and production
Natural gas liquids sales (C3+ NGLs)		258,470		294,982		810,228		711,412	Exploration and production
Oil sales		40,561		34,265		137,675		78,233	Exploration and production
Gathering and compression (1)		—		—		3,972		—	Equity method investment in Antero Midstream Corporation
Water handling and treatment (1)		—		—		507		—	Equity method investment in Antero Midstream Corporation
Marketing		46,645		91,497		200,911		201,855	Marketing
Total revenue from contracts with customers		896,612		889,492		2,980,757		2,292,185
Income (loss) from derivatives and other sources		222,269		(508,901)		475,195		(109,578)
Total revenue and other	$	1,118,881		380,591	$	3,455,952		2,182,607

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

(b)Transaction Price Allocated to Remaining Performance Obligations

For the Company’s product sales that have a contract term greater than one year, the Company utilized the practical expedient, 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 the Company’s 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 the Company’s product sales that have a contract term of one year or less, the Company utilized the practical expedient, 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.

(c)Contract Balances

Under the Company’s sales contracts, the Company invoices customers after the Company’s performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s contracts do not give rise to contract assets or liabilities. At December 31, 2019 and September 30, 2020, the Company’s receivables from contracts with customers were $318 million and $339 million, respectively.

(6) Equity Method Investments

As of September 30, 2020, the Company owned approximately 29.2% 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—Deconsolidation of Antero Midstream Partners to the unaudited condensed consolidated financial statements for further discussion on the Transactions.

18

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

The following table is a reconciliation of investments in unconsolidated affiliates for the nine months ended September 30, 2020 (in thousands):

	Antero Midstream
	Corporation
Balance as of December 31, 2019	$	1,055,177
Equity in loss of unconsolidated affiliates		(83,408)
Distributions/dividends from unconsolidated affiliates		(128,267)
Impairment (1)		(610,632)
Elimination of intercompany profit		40,056
Balance as of September 30, 2020	$	272,926

(1) Other-than-temporary impairment of investment in Antero Midstream Corporation.

Summarized Financial Information of Antero Midstream Corporation

The following tables present summarized financial information of Antero Midstream Corporation.

Balance Sheet

	December 31,		September 30,
(in thousands)	2019		2020
Current assets	$	108,558		108,008
Noncurrent assets		6,174,320		5,565,496
Total assets	$	6,282,878		5,673,504
Current liabilities	$	242,084		61,259
Noncurrent liabilities		2,897,380		3,126,754
Stockholders' equity		3,143,414		2,485,491
Total liabilities and stockholders' equity	$	6,282,878		5,673,504

Statement of Operations

	For the period
	March 13, 2019
	through		Nine months ended
(in thousands)	September 30, 2019		September 30, 2020
Revenues	$	553,521		696,859
Operating expenses		745,940		929,480
Loss from operations	$	(192,419)		(232,621)
Loss attributable to the equity method investment	$	(197,006)		(198,985)

(7) Accrued Liabilities

Accrued liabilities as of December 31, 2019 and September 30, 2020 consisted of the following items (in thousands):

	December 31,		September 30,
	2019		2020
Capital expenditures	$	105,706		46,122
Gathering, compression, processing, and transportation expenses		134,153		158,043
Marketing expenses		52,612		55,777
Interest expense, net		30,834		40,355
Accrued taxes		39,332		20,403
Other		38,213		23,906
Total accrued liabilities	$	400,850		344,606

19

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

(8) Long-Term Debt

Long-term debt as of December 31, 2019 and September 30, 2020 consisted of the following items (in thousands):

	December 31,		September 30,
	2019		2020
Credit Facility (a)	$	552,000		827,000
5.375% senior notes due 2021 (b)		952,500		315,279
5.125% senior notes due 2022 (c)		923,041		660,516
5.625% senior notes due 2023 (d)		750,000		579,232
5.00% senior notes due 2025 (e)		600,000		590,000
4.25% convertible senior notes due 2026 (f)		—		287,500
Total principal		3,777,541		3,259,527
Unamortized premium (discount), net		791		(83,658)
Unamortized debt issuance costs		(19,464)		(17,644)
Long-term debt	$	3,758,868		3,158,225

(a) Senior Secured Revolving Credit Facility

Antero Resources 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 Resources’ assets and are subject to regular semi-annual redeterminations. The borrowing base was re-affirmed in October 2020 at $2.85 billion and lender commitments are $2.64 billion. The next redetermination of the borrowing base is scheduled to occur in April 2021. 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 Resources’ senior notes then outstanding. The Company intends to extinguish the 2021 Notes on or prior to August 2, 2021 with proceeds from its asset sales program, cash flow from operations and available borrowings under the Credit Facility. Consequently, the Company has classified the Credit Facility as long-term debt. The classification of the Credit Facility does not impact any of the Company’s financial covenants.

As of September 30, 2020, Antero Resources had an outstanding balance under the Credit Facility of $827 million, with a weighted average interest rate of 3.28%, and outstanding letters of credit of $730 million. As of December 31, 2019, Antero Resources had an outstanding balance under the Credit Facility of $552 million, with a weighted average interest rate of 3.28%, and outstanding letters of credit of $623 million. Commitment fees on the unused portion of the Credit Facility are due quarterly at rates ranging from 0.300% to 0.375% (subject to certain exceptions) of the unused portion based on utilization.

(b) 5.375% Senior Notes Due 2021

On November 5, 2013, Antero Resources issued $1.0 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 Resources’ other outstanding senior notes. The 2021 Notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by Antero Resources’ 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 a redemption price of 100.00%. If Antero Resources undergoes a change of control followed by a rating decline, the holders of the 2021 Notes will have the right to require Antero Resources 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 Resources issued $600 million of 5.125% senior notes due December 1, 2022 (the “2022 Notes”) at par. On September 18, 2014, Antero Resources 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 Resources’ other outstanding senior notes. The 2022 Notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by Antero Resources’ wholly owned subsidiaries and certain of its

20

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

future restricted subsidiaries. Interest on the 2022 Notes is payable on June 1 and December 1 of each year. Antero Resources may redeem all or part of the 2022 Notes at any time at a redemption price of 100.00%. If Antero Resources undergoes a change of control followed by a rating decline, the holders of the 2022 Notes will have the right to require Antero Resources 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 Resources 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 Resources’ other outstanding senior notes. The 2023 Notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by Antero Resources’ 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 Resources may redeem all or part of the 2023 Notes at any time at redemption prices ranging from 101.406% currently to 100.00% on or after June 1, 2021. If Antero Resources undergoes a change of control followed by a rating decline, the holders of the 2023 Notes will have the right to require Antero Resources to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the 2023 Notes, plus accrued and unpaid interest.

(e) 5.00% Senior Notes Due 2025

On December 21, 2016, Antero Resources 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 Resources’ other outstanding senior notes. The 2025 Notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by Antero Resources’ 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 Resources may redeem all or part of the 2025 Notes at any time at redemption prices ranging from 103.75% currently to 100.00% on or after March 1, 2023. If Antero Resources undergoes a change of control followed by a rating decline, the holders of the 2025 Notes will have the right to require Antero Resources 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) 4.25% Convertible Senior Notes Due 2026

On August 21, 2020, Antero Resources issued $250 million in aggregate principal amount of 2026 Convertible Notes. On September 2, 2020, Antero Resources issued an additional $37.5 million of the 2026 Convertible Notes. The 2026 Convertible Notes were issued pursuant to an indenture and are senior, unsecured obligations of Antero Resources. The 2026 Convertible Notes bear interest at a fixed rate of 4.25% per annum, payable semi-annually in arrears on March 1 and September 1 of each year, commencing on March 1, 2021. Proceeds from the issuance of the 2026 Convertible Notes totaled $278.6 million, net of initial purchasers’ fees and issuance cost of $8.9 million. Each capitalized term used in this subsection but not otherwise defined in this Quarterly Report on Form 10-Q has the meaning as set forth in the indenture governing the 2026 Convertible Notes.

The initial conversion rate is 230.2026 shares of Antero Resources’ common stock per $1,000 principal amount of 2026 Convertible Notes, subject to adjustment upon the occurrence of specified events. The 2026 Convertible Notes will mature on September 1, 2026, unless earlier repurchased, redeemed or converted. Before May 1, 2026, note holders will have the right to convert their 2026 Convertible Notes only upon the occurrence of the following events:

● during any calendar quarter (and only during such calendar quarter) commencing after the calendar quarter ending on September 30, 2020, if the Last Reported Sale Price per share of Antero Resources’ common stock exceeds 130% of the Conversion Price for each of at least 20 Trading Days (whether or not consecutive) during the 30 consecutive Trading Days ending on, and including, the last Trading Day of the immediately preceding calendar quarter;

● during the 5 consecutive Business Days immediately after any 10 consecutive trading day period (such 10 consecutive Trading Day period, the “Measurement Period”) if the trading Price per $1,000 principal amount of 2026 Convertible Notes, as determined following a request by a noteholder in accordance with the procedures set forth below, for each trading day of the Measurement Period was less than 98% of the product of the last reported sale price per share of common stock on such trading day and the conversion rate on such trading day;

21

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

● if Antero Resources calls any or all of the 2026 Convertible Notes for redemption, at any time prior to the close of business on the scheduled trading day immediately preceding the redemption date; or

● upon the occurrence of certain specified corporate events as set forth in the indenture governing the 2026 Convertible Notes.

From and after May 1, 2026, noteholders may convert their 2026 Convertible Notes at any time at their election until the close of business on the second scheduled trading day immediately before the maturity date.

Upon conversion, Antero Resources may satisfy its conversion obligation by paying and/or delivering, as the case may be, cash, shares of Antero Resources’ common stock or a combination of cash and shares of Antero Resources’ common stock, at Antero Resources’ election, in the manner and subject to the terms and conditions provided in the indenture governing the 2026 Convertible Notes. Antero Resources’ current intent is to settle the principle amount of the 2026 Convertible Notes in cash upon conversion. Antero Resources’ current intent is to settle the principle amount of the 2026 Convertible Notes in cash upon conversion. At no point since issuance of the 2026 Convertible Notes has the conditions allowing holders of the 2026 Convertible Notes to exercise their conversion right been met.

The conversion rate is subject to adjustment under certain circumstances in accordance with the terms of the indenture governing the 2026 Convertible Notes. In addition, following certain corporate events, as described in the indenture governing the 2026 Convertible Notes, that occur prior to the maturity date, Antero Resources will increase the conversion rate for a holder who elects to convert its 2026 Convertible Notes in connection with such a corporate event.

If certain corporate events that constitute a Fundamental Change occur, then noteholders may require Antero Resources to repurchase their 2026 Convertible Notes at a cash repurchase price equal to the principal amount of the 2026 Convertible Notes to be repurchased, plus accrued and unpaid interest, if any, to, but excluding, the fundamental change repurchase date. The definition of Fundamental Change includes certain business combination transactions involving Antero Resources and certain de-listing events with respect to Antero Resources’ common stock.

Upon issuance, the Company separately accounted for the liability and equity components of the 2026 Convertible Notes.  The liability component was recorded at the estimated fair value of a similar debt instrument without the conversion feature.  The difference between the principal amount of the 2026 Convertible Notes and the estimated fair value of the liability component was recorded as a debt discount and will be amortized to interest expense over the term of the 2026 Convertible Notes using the effective interest method, with an effective interest rate of 10.8% per annum.  As of the issuance date, the fair value of the 2026 Convertible Notes was estimated at $203 million, resulting in a debt discount at inception of $85 million.  The equity component, representing the value of the conversion option, was computed by deducting the fair value of the liability component from the initial proceeds of the 2026 Convertible Notes issuance.  This equity component was recorded, net of deferred taxes and issuance costs, in additional paid-in capital within the unaudited consolidated statement of stockholders’ equity and will not be remeasured as long as it continues to meet the conditions for equity classification. 

Transaction costs related to the 2026 Convertible Notes issuance were allocated to the liability and equity components based on their relative fair values.  Issuance costs attributable to the liability component were recorded within debt issuance costs on the unaudited consolidated balance sheet and are amortized over the term of the 2026 Convertible Notes using the effective interest method.  Issuance costs attributable to the equity component were recorded as a charge to additional paid-in capital within the unaudited consolidated statement of stockholders’ equity.

22

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

The 2026 Convertible Notes consist of the following as of September 30, 2020 (in thousands):

Liability component:
Principal	$	287,500
Less: unamortized note discount		(84,084)
Less: unamortized debt issuance costs		(6,209)
Net carrying value	$	197,207
Equity component (1)	$	84,972

(1) Recorded in additional paid-in capital, net of $3 million of issuance costs and $20 million of deferred taxes.

Interest expense recognized on the 2026 Convertible Notes related to the stated interest rate and amortization of the debt discount totaled $2.3 million for the three months ended September 30, 2020.

(g)Debt Repurchase Program

During the three and nine months ended September 30, 2020, Antero Resources repurchased $461 million and $1.1 billion, respectively, principal amount of debt at a weighted average discount of 13% and 17%, respectively, which purchases included a portion of the 2021 Notes, 2022 Notes, 2023 Notes and 2025 Notes. The Company recognized a gain of $56 million and $175 million for the three and nine months ended September 30, 2020, respectively, on the early extinguishment of the debt repurchased. Repurchases of the principal amount of debt during the three and nine months ended September 30, 2020 include repurchases of $367 million on the 2021 Notes, 2022 Notes and 2023 Notes through previously disclosed tender offers at a weighted average discount of 10%.

(9) Asset Retirement Obligations

The following is a reconciliation of the Company’s asset retirement obligations for the nine months ended September 30, 2020 (in thousands):

Asset retirement obligations—December 31, 2019	$	54,845
Obligations incurred		1,529
Accretion expense		3,330
Settlement of obligations		(229)
Asset retirement obligations—September 30, 2020	$	59,475

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

(10) Equity-Based Compensation

On June 17, 2020, Antero Resources’ stockholders approved the Antero Resources Corporation 2020 Long-Term Incentive Plan (the “2020 Plan”), which replaced the Antero Resources Corporation Long-Term Incentive Plan (the “2013 Plan”), and the 2020 Plan became effective as of such date. The 2020 Plan provides for grants of stock options (including incentive stock options), stock appreciation rights, restricted stock awards, RSU awards, vested stock awards, dividend equivalent awards, and other stock-based and cash awards. The terms and conditions of the awards granted are established by the Compensation Committee of Antero Resources’ Board of Directors. Employees, officers, non-employee directors and other service providers of the Company and its affiliates are eligible to receive awards under the 2020 Plan. No further awards will be granted under the 2013 Plan on or after June 17, 2020.

The 2020 Plan provides for the reservation of 10,050,000 shares of the Company’s common stock, plus the number of certain shares that become available again for delivery from the 2013 Plan in accordance with the share recycling provisions described below. The share recycling provisions allow for all or any portion of an award (including an award granted under the 2013 Plan that was outstanding as of June 17, 2020) that expires or is cancelled, forfeited, exchanged, settled for cash, or otherwise terminated without actual delivery of the shares to be considered not delivered and thus available for new awards under the 2020 Plan. Further, any shares withheld or surrendered in payment of any taxes relating to awards that were outstanding under either the 2013 Plan as of June

23

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

17, 2020 or are granted under the 2020 Plan (other than stock options and stock appreciation rights) will again be available for new awards under the 2020 Plan.

A total of 7,149,371 shares were available for future grant under the 2020 Plan as of September 30, 2020.

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 includes Antero Resources). As part of the Transactions, each outstanding phantom unit award under the AMP Plan, was assumed by Antero Midstream Corporation and converted into 1.8926 RSUs under the Antero Midstream Corporation Long Term Incentive Plan (the “AMC Plan”). Each RSU award under the AMC Plan represents a right to receive 1 share of Antero Midstream Corporation common stock.

The Company’s equity-based compensation expense, by type of award, was as follows for the three and nine months ended September 30, 2019 and 2020 (in thousands):

	Three months ended September 30,				Nine months ended September 30,
	2019		2020		2019		2020
RSU awards	$	2,229		3,063	$	8,829		9,021
Stock options		—		—		389		—
PSU awards		399		1,827		6,027		5,380
Antero Midstream Partners phantom unit awards (1)		867		459		2,942		1,881
Equity awards issued to directors		380		350		1,140		719
Total expense	$	3,875		5,699	$	19,327		17,001

(1) Antero Resources recognized compensation expense for equity awards granted under both the 2013 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 Resources. Antero Resources 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 Resources’ labor costs. Through March 12, 2019, the total amount of equity-based compensation is included in the consolidated financial statements of Antero Resources; and effective March 13, 2019 (date of deconsolidation), the amount allocated to Antero Midstream Partners is no longer reflected in Antero Resources consolidated financial statements. See Note 3—Deconsolidation of Antero Midstream Partners LP to the unaudited condensed consolidated financial statements for further discussion on the Transactions.

Restricted Stock Unit Awards

A summary of RSU award activity for the nine months ended September 30, 2020 is as follows:

		Weighted
		average		Aggregate
	Number of	grant date		intrinsic value
	shares	fair value		(in thousands)
Total awarded and unvested—December 31, 2019	2,370,575	$	12.81	$	6,756
Granted	7,108,061	$	2.39
Vested	(1,045,771)	$	12.50
Forfeited	(119,679)	$	12.46
Total awarded and unvested—September 30, 2020	8,313,186	$	4.08	$	22,862

Intrinsic values are based on the closing price of Antero Resources’ common stock on the referenced dates. As of September 30, 2020, there was approximately $26 million of unamortized equity-based compensation expense related to unvested RSUs. That expense is expected to be recognized over a weighted average period of approximately 2.3 years.

24

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

Stock Options

A summary of stock option activity for the nine months ended September 30, 2020 is as follows:

				Weighted
		Weighted		average
		average		remaining	Intrinsic
	Stock	exercise		contractual	value
	options	price		life	(in thousands)
Outstanding as of December 31, 2019	467,633	$	50.64	5.05	$	—
Granted	—	$	—
Exercised	—	$	—
Forfeited	—	$	—
Expired	(35,172)	$	50.56
Outstanding at September 30, 2020	432,461	$	50.64	4.31	$	—
Vested or expected to vest as of September 30, 2020	432,461	$	50.64	4.31	$	—
Exercisable as of September 30, 2020	432,461	$	50.64	4.31	$	—

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

As of September 30, 2020, all stock options were fully vested resulting in 0 unamortized equity-based compensation expense.

Performance Share Unit Awards

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

In July 2020, the Company granted PSU awards to certain of its executive officers that vest based on Antero Resources’ absolute total shareholder return (“TSR”) determined as of the last day of each of 3 one-year performance periods ending on April 15, 2021, April 15, 2022, and April 15, 2023, and 1 cumulative three-year performance period ending on April 15, 2023, in each case, subject to the executive officer’s continued employment through April 15, 2023. The number of shares of common stock that may ultimately be earned following the end of the cumulative three-year performance period ranges from 0 to 150% of the target number of PSUs granted. Expense related to these PSUs is recognized on a graded-vested basis over approximately three years. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period.

Additionally, in July 2020, the Company granted PSUs to certain of its executive officers that vest based on Antero Resources’ TSR relative to the TSR of certain peer companies determined as of the last day of each of 3 one-year performance periods ending on April 15, 2021, April 15, 2022, and April 15, 2023, and 1 cumulative three-year performance period ending on April 15, 2023, in each case, subject to the executive officer’s continued employment through April 15, 2023. The number of shares of common stock that may ultimately be earned following the end of the cumulative three-year performance period ranges from 0 to 150% of the target number of PSUs granted. Expense related to these PSUs is recognized on a graded-vested basis over approximately three years. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period.

A summary of PSUs activity for the nine months ended September 30, 2020 is as follows:

		Weighted
	Number of	average grant
	units	date fair value
Total awarded and unvested—December 31, 2019	2,537,283	$	16.74
Granted	469,000	$	2.97
Forfeited	(29,316)	$	12.21
Cancelled (unearned)	(458,485)	$	25.32
Total awarded and unvested—September 30, 2020	2,518,482	$	11.94

25

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

The following table presents information regarding the weighted average fair values for market-based PSUs granted during the nine months ended September 30, 2019 and 2020, and the assumptions used to determine the fair values:

	Nine months ended
	September 30,
	2019			2020
Dividend yield		—	%		—	%
Volatility		36	%		80	%
Risk-free interest rate		2.35	%		0.17	%
Weighted average fair value of awards granted—Return on Capital Employed	$	9.26		$	—
Weighted average fair value of awards granted—Absolute TSR	$	—		$	2.63
Weighted average fair value of awards granted—Relative TSR	$	—		$	3.30

As of September 30, 2020, there was approximately $10 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 1.4 years.

Cash Awards

In January 2020, the Company granted cash awards of approximately $3.3 million to certain executives under the 2013 Plan, and compensation expense for these awards is recognized ratably over the vesting period for each of 3 tranches through January 20, 2023. In July 2020, the Company granted additional cash awards on the aggregate of $2.6 million to certain non-executive employees under the 2020 Plan that vest ratably over four years. As of September 30, 2020, the Company has accrued approximately $2.2 million in Other liabilities in the unaudited condensed consolidated balance sheet related to cash awards.

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

A summary of Antero Midstream Corporation RSU awards for the nine months ended September 30, 2020 is as follows:

		Weighted
		average		Aggregate
	Number of	grant date		intrinsic value
	units	fair value		(in thousands)
Total awarded and unvested—December 31, 2019	657,757	$	14.71	$	4,992
Granted	—	$	—
Vested	(335,051)	$	11.67
Forfeited	(22,577)	$	14.09
Total awarded and unvested—September 30, 2020	300,129	$	5.19	$	1,558

Intrinsic values are based on the closing price of shares of Antero Midstream Corporation common stock. As of September 30, 2020, there was approximately $3 million of unamortized equity-based compensation expense related to unvested phantom unit awards. That expense is expected to be recognized over a weighted average period of approximately 1.2 years.

(11) Financial Instruments

The carrying values of accounts receivable and accounts payable at December 31, 2019 and September 30, 2020 approximated market values because of their short-term nature. The carrying values of the amounts outstanding under the Credit Facility at December 31, 2019 and September 30, 2020 approximated fair value because the variable interest rates are reflective of current market conditions.

Based on Level 2 market data inputs, the fair value of senior notes was approximately $2.8 billion and $1.6 billion at December 31, 2019 and September 30, 2020, respectively. The fair value of the 2026 Convertible Notes was approximately $235 million as of September 30, 2020 based on Level 2 market data inputs.

See Note 12—Derivative Instruments to the unaudited condensed consolidated financial statements for information regarding the fair value of derivative financial instruments.

26

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

(12) Derivative Instruments

The Company is exposed to certain risks relating to its ongoing business operations, and it uses derivative instruments to manage its commodity price risk.  In addition, the Company periodically enters into contracts that contain embedded features that are required to be bifurcated and accounted for separately as derivatives.

(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, 2019 and 2020. 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 derivative 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 also entered into a call option agreement that gives the counterparty the right, but not the obligation, to enter into a fixed price swap agreement on a specified future date for a specific amount of production for a specified future period.

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.

27

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

As of September 30, 2020, the Company’s fixed price natural gas, oil and NGL swap positions from October 1, 2020 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 Propane =European Propane CIF ARA; OPIS Ethane Mt Belv=Mont Belvieu Purity Ethane-OPIS):

		Natural Gas		Weighted
	Natural gas	Liquids	Oil	average index
	MMBtu/day	Bbls/day	Bbls/day	price
Three months ending December 31, 2020:
NYMEX ($/MMBtu)	2,067,500	—	—	$	2.84
ARA Propane ($/Gal)	—	10,315	—		0.65
OPIS Ethane Mt Belv ($/Gal)	—	24,500	—		0.20
NYMEX-WTI ($/Bbl)	—	—	26,000		55.63
Total	2,067,500	34,815	26,000
Three months ending March 31, 2021
OPIS Ethane Mt Belv ($/Gal)		19,000		$	0.20
Year ending December 31, 2021:
NYMEX ($/MMBtu)	2,160,000		—	$	2.77
NYMEX-WTI ($/Bbl)	—		3,000		55.16
Total	2,160,000		3,000
Year ending December 31, 2022:
NYMEX ($/MMBtu)	905,897			$	2.43
Year ending December 31, 2023:
NYMEX ($/MMBtu)	43,000			$	2.37

A portion of the NYMEX-WTI ($/Bbl) in 2020 combined with the Mont Belvieu Natural Gasoline to NYMEX-WTI are intended to fix the price of Natural Gasoline.

In addition, the Company has a call option agreement, which entitles the holder the right, but not the obligation, to enter into a fixed price swap agreement on December 21, 2023 to purchase 427,500 MMBtu per day at a price of $2.77 per MMBtu for the year ending December 31, 2024.

As of September 30, 2020, the Company’s natural gas basis swap positions, which settle on the pricing index to basis differential of the Columbia Gas Transmission pipeline (“TCO”) to the NYMEX Henry Hub natural gas price were as follows:

		Weighted
	Natural gas	average hedged
	MMBtu/day	differential
Three months ending December 31, 2020:
NYMEX to TCO ($/MMBtu)	15,123	$	0.353
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

28

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

As of September 30, 2020, the Company had NGL contracts for January 1, 2021 through December 31, 2021 that fix the Mont Belvieu index price for natural gasoline to percentages of WTI as follows:

		Weighted
	Gas	average
	Liquids	Payout
	Bbls/day	Ratio
Year ending December 31, 2021:
Mont Belvieu Natural Gasoline to NYMEX-WTI	14,150	78	%

29

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

As of September 30, 2020, the Company’s fixed price natural gas, oil and NGL swap positions from October 1, 2020 through March 31, 2025 for Martica, the Company’s consolidated subsidiary, 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; OPIS Propane Mt Belv Non-TET = Mont Belvieu Propane-OPIS; OPIS Ethane Mt Belv=Mont Belvieu Purity Ethane-OPIS; OPIS Natural Gasoline Mt Belv Non-TET = Mont Belvieu Natural Gasoline-OPIS):

		Natural Gas		Weighted
	Natural gas	Liquids	Oil	average index
	MMBtu/day	Bbls/day	Bbls/day	price
Three months ending December 31, 2020:
NYMEX ($/MMBtu)	46,495	—	—	$	2.06
OPIS Propane Mt Belv Non-TET	—	982	—		0.49
OPIS Natural Gasoline Mt Belv Non-TET	—	298	—		0.67
OPIS Ethane Mt Belv ($/Gal)	—	633	—		0.20
NYMEX-WTI ($/Bbl)	—	—	128		37.78
Total	46,495	1,913	128
Year ending December 31, 2021:
NYMEX ($/MMBtu)	46,536	—	—	$	2.62
OPIS Propane Mt Belv Non-TET	—	932	—		0.43
OPIS Natural Gasoline Mt Belv Non-TET	—	282	—		0.71
OPIS Ethane Mt Belv ($/Gal)	—	987	—		0.17
NYMEX-WTI ($/Bbl)	—	—	117		39.94
Total	46,536	2,201	117
Three months ending March 31, 2022
OPIS Propane Mt Belv Non-TET	—	379	—	$	0.43
OPIS Natural Gasoline Mt Belv Non-TET	—	115	—		0.72
OPIS Ethane Mt Belv ($/Gal)	—	521	—		0.16
NYMEX-WTI ($/Bbl)	—	—	17		43.85
Total	—	1,015	17
Year ending December 31, 2022:
NYMEX ($/MMBtu)	38,356	—	—	$	2.39
OPIS Natural Gasoline Mt Belv Non-TET	—	254	—		0.83
NYMEX-WTI ($/Bbl)	—	—	66		40.92
Total	38,356	254	66
Year ending December 31, 2023:
NYMEX ($/MMBtu)	35,616	—	—	$	2.35
NYMEX-WTI ($/Bbl)	—	—	52		42.45
Total	35,616	—	52
Year ending December 31, 2024:
NYMEX ($/MMBtu)	23,885		—	$	2.33
NYMEX-WTI ($/Bbl)	—		43		44.02
Total	23,885		43
Three months ending March 31, 2025:
NYMEX ($/MMBtu)	18,021		—	$	2.53
NYMEX-WTI ($/Bbl)	—		39		45.06
Total	18,021		39

30

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

(b) Embedded Derivatives

The VPP includes an embedded put option tied to NYMEX pricing for the production volumes associated with the Company’s retained interest in the VPP properties of 120,667,000 MMBtu remaining through December 31, 2026 at a weighted average strike price of $2.60 per MMBtu that is not clearly and closely related to the host contract. Therefore, the Company bifurcated this embedded put option and reflected it at fair value in the unaudited condensed consolidated financial statements.

(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, 2019 and September 30, 2020. NaN of the Company’s derivative instruments are designated as hedges for accounting purposes and the fair value of derivative instruments was determined using Level 2 inputs.

	December 31, 2019			September 30, 2020
	Balance sheet	Fair value		Balance sheet	Fair value
	location	(In thousands)		location	(In thousands)
Asset derivatives not designated as hedges for accounting purposes:
Commodity derivatives—current (1)	Derivative instruments	$	422,849	Derivative instruments	$	75,776
Embedded derivatives—current	Derivative instruments		—	Derivative instruments		7,281
Commodity derivatives—noncurrent (1)	Derivative instruments		333,174	Derivative instruments		6,998
Embedded derivatives—noncurrent	Derivative instruments		—	Derivative instruments		37,072
Total asset derivatives			756,023			127,127
Liability derivatives not designated as hedges for accounting purposes:
Commodity derivatives—current	Derivative instruments		6,721	Derivative instruments		107,933
Commodity derivatives—noncurrent	Derivative instruments		3,519	Derivative instruments		149,222
Total liability derivatives			10,240			257,155
Net derivatives assets (liabilities)		$	745,783		$	(130,028)

(1) Approximately $16 million of commodity derivative liabilities, including $8 million of current commodity derivatives and $8 million of noncurrent commodity derivatives, are attributable to our consolidated VIE, Martica.

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, 2019						September 30, 2020
	Gross		Gross amounts		Net amounts of		Gross		Gross amounts		Net amounts of
	amounts on		offset on		assets (liabilities)		amounts on		offset on		assets (liabilities)
	balance sheet		balance sheet		on balance sheet		balance sheet		balance sheet		on balance sheet
Commodity derivative assets	$	882,817		(126,794)		756,023	$	212,335		(129,561)		82,774
Embedded derivative assets	$	—		—		—	$	44,353		—		44,353
Commodity derivative liabilities	$	(137,034)		126,794		(10,240)	$	(386,716)		129,561		(257,155)

31

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

The following is a summary of derivative fair value gains and losses and where such values are recorded in the unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2019 and 2020 (in thousands):

	Statement of	Three months ended				Nine months ended
	operations	September 30,				September 30,
	location	2019		2020		2019		2020
Commodity derivative fair value gains (losses)	Revenue	$	220,788		(558,979)	$	471,847		(161,161)
Embedded derivative fair value gains (losses)	Revenue	$	—		44,228	$	—		44,228

(13) 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 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. 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. As new leases commence or previous leases are modified the discount rate used in the present value calculation is the current period applicable discount rate.

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.

32

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

Supplemental Balance Sheet Information Related to Leases

The Company’s lease assets as of December 31, 2019 and September 30, 2020 consisted of the following items (in thousands):

	December 31, 2019				September 30, 2020
	Operating Leases		Finance Leases(2)		Operating Leases		Finance Leases(2)
Right-of-use Assets:
Processing plants	$	1,460,770		—	$	1,324,022		—
Drilling rigs and completion services		71,662		—		19,480		—
Gas gathering lines and compressor stations (1)		1,308,428		—		1,274,755		—
Office space		40,491		—		37,784		—
Vehicles		4,983		2,328		3,367		1,494
Other office and field equipment		166		170		780		—
Total right-of-use assets	$	2,886,500		2,498	$	2,660,188		1,494

(1) Gas gathering lines and compressor stations leases includes $1.1 billion related to Antero Midstream Corporation as of December 31, 2019 and September 30, 2020. See “—Related party lease disclosure” for additional discussion.

(2) Financing lease assets are recorded net of accumulated amortization of $9 million and $3 million as of December 31, 2019 and September 30, 2020, respectively.

The Company’s lease liabilities as of September 30, 2020 consisted of the following items (in thousands):

	December 31, 2019				September 30, 2020
	Operating Leases		Finance Leases		Operating Leases		Finance Leases
Location on the balance sheet:
Short-term lease liabilities	$	304,397		923	$	250,594		974
Long-term lease liabilities		2,582,103		1,575		2,409,594		520
Total lease liabilities	$	2,886,500		2,498	$	2,660,188		1,494

The processing plants, gathering lines and compressor stations that are classified as lease liabilities are classified as such under ASC Topic 842, Leases, 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, 2020 (in thousands):

	Three months ended				Nine months ended
	September 30,				September 30,
Statement of Operations Location	2019		2020		2019		2020
Gathering, compression, processing, and transportation	$	237,618		409,006	$	644,007		1,112,502
General and administrative		2,859		2,969		8,395		8,639
Contract termination and rig stacking		—		546		10,692		6,387
Total lease expense	$	240,477		412,521	$	663,094		1,127,528

Costs associated with finance leases of less than $1 million for each of the three months and nine months ended September 30, 2019 and 2020 were included in interest expense.

For the three months ended September 30, 2019 and 2020, the Company capitalized $53 million and $32 million, respectively, of costs related to operating leases and less than $1 million of costs related to finance leases. For the nine months ended September 30, 2019, and 2020, the Company capitalized $161 million and $91 million, respectively, of costs related to operating leases and less than $1 million of costs related to finance leases.

33

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

Short-term lease costs that are more than one month but less than 12 months are excluded from the above amounts and total $41 million and $16 million, respectively, for the three months ended September 30, 2019 and 2020 and $115 million and $108 million, respectively, for the nine months ended September 30, 2019 and 2020.

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				Nine months ended
	September 30, 2019				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	$	—		—	$	—		—

The following is the Company’s supplemental cash flow information related to leases for the three and nine months ended September 30, 2020 (in thousands):

	Three months ended				Nine months ended
	September 30, 2020				September 30, 2020
	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	$	485,692		—	$	1,147,489		—
Investing cash out flows related to operating leases		24,950		—		88,229		—
Financing cash out flows related to financing leases		—		287		—		1,004
	$	510,642		287	$	1,235,718		1,004
Noncash activities:
Right of use assets obtained in exchange for operating lease liabilities	$	64,586		—	$	178,348		—
Right of use assets obtained in exchange for financing lease liabilities	$	—		—	$	—		—

34

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

Maturities of Lease Liabilities

The table below is a schedule of future minimum payments for operating and financing lease liabilities as of September 30, 2020 (in thousands):

(in thousands)	Operating Leases		Financing Leases		Total
Remainder of 2020	$	156,878		317		157,195
2021		590,519		844		591,363
2022		578,305		321		578,626
2023		575,228		26		575,254
2024		566,460		—		566,460
2025		493,783		—		493,783
Thereafter		1,558,470		—		1,558,470
Total lease payments		4,519,643		1,508		4,521,151
Less: imputed interest		(1,859,455)		(14)		(1,859,469)
Total	$	2,660,188		1,494		2,661,682

Lease Term and Discount Rate

The table below is the Company’s weighted-average remaining lease term and discount rate as of September 30, 2020:

	September 30, 2020
	Operating Leases		Finance Leases
Weighted-average remaining lease term:	8.2 years		1.6 years
Weighted-average discount rate:	13.8	%	6.2	%

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 the Company requests 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. In December 2019, the Company and Antero Midstream Corporation agreed to extend the initial term of the gathering and compression agreement to 2038 and established a growth incentive fee program whereby low pressure gathering fees will be reduced from 2020 through 2023 to the extent the Company achieves certain volumetric targets at certain points during such time. Upon completion of the initial contract term, the gathering and compression agreement will continue in effect from year to year until such time as the agreement is terminated, effective upon an anniversary of the effective date of the agreement, by either the Company or Antero Midstream Corporation on or before the 180^th day prior to the anniversary of such effective date. The Company achieved the volumetric targets during each quarter in the three and nine months ended September 30, 2020, and Antero Midstream Corporation provided a rebate of $12 million in each such quarter. Antero Midstream Corporation has provided rebates of $36 million for the nine months ended September 30, 2020.

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. For the three and nine months ended September 30, 2020, gathering and compression fees paid by Antero related to this agreement were $181 million and $503 million, respectively. As of December 31, 2019 and September 30, 2020, $57 million and $56 million was included within Accounts payable, related parties, respectively, on the condensed consolidated balance sheet as due to Antero Midstream Corporation related to this agreement.

35

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

(14) 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, 2020 (in thousands).

			Processing,
	Firm		gathering and		Land payment		Operating and		Imputed Interest
	transportation		compression		obligations		Financing Leases		for Leases
	(a)		(b)		(c)		(d)		(d)		Total
Remainder of 2020	$	278,430		14,089		1,527		66,340		90,855		451,241
2021		1,076,424		55,780		2,859		247,159		344,204		1,726,426
2022		1,033,787		52,712		—		267,094		311,532		1,665,125
2023		1,061,265		58,565		—		300,989		274,265		1,695,084
2024		1,021,107		58,687		—		334,693		231,767		1,646,254
2025		981,271		47,385		—		306,918		186,865		1,522,439
Thereafter		6,941,177		105,977		—		1,138,489		419,981		8,605,624
Total	$	12,393,461		393,195		4,386		2,661,682		1,859,469		17,312,193

(a) Firm Transportation

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

(b) Processing, Gathering, and Compression Service Commitments

The Company has entered into various long-term gas processing, 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.

(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 Antero Resources is committed to pay; however, the Company will record in its financial statements its proportionate share of costs based on its working interests. Refer to Note 13—Leases to the unaudited condensed consolidated financial statements for more information on the Company’s operating and finance leases.

36

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

(15) Contingencies

Environmental

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 Resources facilities for the purpose of determining if the additional facilities have the same alleged compliance issues that were identified during the September 2017 inspections. Subsequently, West Virginia Department of Environmental Protection (“WVDEP”) conducted its own inspections, and we have received NOVs from WVDEP alleging violations relating to similar 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.

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 geographic point in Braxton County, 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 Resources 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 of 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

37

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

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 Resources’ 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 Resources.

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 appealed the judgment and the appeal is currently pending before the Colorado Court of Appeals. In the appeal, briefing has been completed and oral argument is scheduled for November 4, 2020.

Effective February 1, 2018, as a result of an 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 Braxton delivery point 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.

(16) Contract Termination and Rig Stacking

The Company incurs costs associated with the delay or cancellation of drilling and completion contracts with third-party contractors. These costs are recorded in Contract termination and rig stacking and included in the statement of operations and comprehensive income (loss) for the three and nine months ended September 30, 2019 and 2020 (in thousands):

	Three months ended September 30,				Nine months ended September 30,
	2019		2020		2019		2020
Contract termination and rig stacking	$	62		1,246	$	14,026		12,317

(17) 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 Resources accounts for Antero Midstream Corporation as an equity method investment. See Note 3—Deconsolidation of Antero Midstream Partners LP 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 Resources. See Note 18—Segment Information to the unaudited condensed consolidated financial statements for the operating results of the Company’s reportable segments.

(18) Segment Information

See Note 2(l)—Summary of Significant Accounting Policies, Industry Segments and Geographic Information, 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 Resources. Effective March 13, 2019, the results of Antero Midstream Partners are no longer consolidated in Antero Resources’

38

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

results; however, the Company’s segment disclosures include the results of the Company’s unconsolidated affiliates due to their significance to the Company’s operations. See Note 3—Deconsolidation of Antero Midstream Partners LP 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 midstream segment based on the nature of the expenses and on a combination of the segments’ proportionate share of the Company’s consolidated property and equipment, capital expenditures, and labor costs, as applicable. General and administrative expenses related to the marketing segment are not allocated because they are immaterial. Other income, income taxes, and interest expense are primarily managed and evaluated on a consolidated basis. Intersegment sales 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—Summary of Significant Accounting Policies to the unaudited condensed consolidated financial statements.

39

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

The operating results and assets of the Company’s reportable segments were as follows for the three months ended September 30, 2019 and 2020 (in thousands):

					Equity Method		Elimination of
					Investment in		intersegment
	Exploration				Antero		transactions and
	and				Midstream		unconsolidated		Consolidated
	production		Marketing		Corporation		affiliates		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 income (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

					Equity Method		Elimination of
					Investment in		intersegment
	Exploration				Antero		transactions and
	and				Midstream		unconsolidated		Consolidated
	production		Marketing		Corporation		affiliates		total
Three months ended September 30, 2020:
Sales and revenues:
Third-party	$	288,419		91,497		—		—		379,916
Intersegment		675		—		233,415		(233,415)		675
Total	$	289,094		91,497		233,415		(233,415)		380,591
Operating expenses:
Lease operating	$	21,450		—		—		—		21,450
Gathering, compression, processing, and transportation		656,615		—		38,052		(38,052)		656,615
Impairment of oil and gas properties		29,392		—		—		—		29,392
Depletion, depreciation, and amortization		238,418		—		26,801		(26,801)		238,418
General and administrative		31,640		—		13,232		(13,232)		31,640
Other		28,605		128,580		3,513		(3,513)		157,185
Total		1,006,120		128,580		81,598		(81,598)		1,134,700
Operating income (loss)	$	(717,026)		(37,083)		151,817		(151,817)		(754,109)
Equity in earnings of unconsolidated affiliates	$	24,419		—		23,173		(23,173)		24,419
Investments in unconsolidated affiliates	$	272,926		—		—		—		272,926
Segment assets	$	13,349,739		—		5,673,504		(5,673,504)		13,349,739
Capital expenditures for segment assets	$	151,269		—		41,851		(41,851)		151,269

40

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

The operating results and assets of the Company’s reportable segments were as follows for the nine months ended September 30, 2019 and 2020 (in thousands):

					Equity Method		Elimination of
					Investment in		intersegment
	Exploration				Antero		transactions and
	and				Midstream		unconsolidated		Consolidated
	production		Marketing		Corporation		affiliates		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

41

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

					Equity Method		Elimination of
					Investment in		intersegment
	Exploration				Antero		transactions and
	and				Midstream		unconsolidated		Consolidated
	production		Marketing		Corporation		affiliates		total
Nine months ended September 30, 2020:
Sales and revenues:
Third-party	$	1,978,572		201,855		—		—		2,180,427
Intersegment		2,180		—		696,859		(696,859)		2,180
Total	$	1,980,752		201,855		696,859		(696,859)		2,182,607
Operating expenses:
Lease operating	$	71,836		—		—		—		71,836
Gathering, compression, processing, and transportation		1,877,084		—		128,847		(128,847)		1,877,084
Impairment of oil and gas properties		155,962		—		—		—		155,962
Impairment of midstream assets		—		—		665,491		(665,491)		—
Depletion, depreciation, and amortization		652,130		—		81,889		(81,889)		652,130
General and administrative		101,264		—		39,191		(39,191)		101,264
Other		88,023		334,906		14,062		(14,062)		422,929
Total		2,946,299		334,906		929,480		(929,480)		3,281,205
Operating income (loss)	$	(965,547)		(133,051)		(232,621)		232,621		(1,098,598)
Equity in earnings (loss) of unconsolidated affiliates	$	(83,408)		—		63,197		(63,197)		(83,408)
Investments in unconsolidated affiliates	$	272,926		—		—		—		272,926
Segment assets	$	13,349,739		—		5,673,504		(5,673,504)		13,349,739
Capital expenditures for segment assets	$	726,402		—		165,265		(165,265)		726,402

(19) Subsidiary Guarantors

Each of the Company’s wholly owned subsidiaries has fully and unconditionally guaranteed Antero Resources’ 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 tables present summarized financial information of Antero and its guarantor subsidiaries. The Company’s wholly owned subsidiaries are not restricted from making distributions to the Company.

42

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and September 30, 2020

Balance Sheet

	Parent				Guarantor
	(Antero)				Subsidiaries
	December 31,		September 30,		December 31,		September 30,
(in thousands)	2019		2020		2019		2020
Accounts receivable, non-guarantor subsidiaries	$	—		51,000	$	—		—
Accounts receivable, related parties		125,000		—		299,450		398,158
Other current assets		797,885		446,889		—		35,028
Total current assets		922,885		497,889		299,450		433,186
Noncurrent assets		14,274,684		11,813,110		812,129		202,452
Total assets	$	15,197,569		12,310,999	$	1,111,579		635,638
Accounts payable, non-guarantor subsidiaries	$	—		—	$	—		—
Accounts payable, related parties		397,333		514,705		—		35,028
Other current liabilities		942,256		945,647		—		—
Total current liabilities		1,339,589		1,460,352		—		35,028
Noncurrent liabilities		7,186,687		6,322,233		—		—
Total liabilities	$	8,526,276		7,782,585		—		35,028
Noncontrolling interests	$	—		315,754		—		—

Statement of Operations

	Parent				Guarantor
	(Antero)				Subsidiaries
	Nine months ended				Nine months ended
	September 30,				September 30,
(in thousands)	2019		2020		2019		2020
Revenues	$	3,453,124		2,158,743		—		93,318
Operating expenses		4,439,278		2,789,119		—		560,102
Income (loss) from operations		(986,154)		(630,376)		—		(466,784)
Net income and comprehensive income including noncontrolling interests		10,932		(844,755)		131,135		(510,969)
Net income and comprehensive income attributable to Antero Resources Corporation	$	10,932		(826,758)		131,135		(510,969)

43

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, 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, impacts of world health events, including the COVID-19 pandemic, potential shut-ins of production due to lack of downstream demand or storage capacity, 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.

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

We are 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, 2020, we held approximately 522,000 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.

2020 Developments and Highlights

COVID-19 Pandemic

In March 2020, the World Health Organization declared the COVID-19 outbreak a pandemic. Governments have tried to slow the spread of the virus by imposing social distancing guidelines, travel restrictions and stay-at-home orders, which have caused a significant decrease in activity in the global economy and the demand for oil and, to a lesser extent, natural gas and NGLs. Also in March 2020, Saudi Arabia and Russia failed to agree to cut production of oil along with the Organization of the Petroleum Exporting Countries (“OPEC”), and Saudi Arabia significantly reduced the price at which it sells oil and announced plans to increase production, which contributed to a sharp drop in the price of oil. While OPEC, Russia and other allied producers reached an agreement in April 2020 to reduce production, oil prices have remained low. The imbalance between the supply of and demand for oil, as well as the uncertainty around the extent and timing of an economic recovery, have caused extreme market volatility and a substantial adverse effect on commodity prices.

As a producer of natural gas, NGLs and oil, we are recognized as an essential business under various federal, state and local regulations related to the COVID-19 pandemic. We have continued to operate as permitted under these regulations while taking steps to protect the health and safety of our employees and workers. We have implemented protocols to reduce the risk of an outbreak within our field operations, and these protocols have not reduced production or efficiency in a significant manner. A substantial

44

portion of our non-field level employees continue to operate in remote work from home arrangements, and we have been able to maintain a consistent level of effectiveness through these arrangements, including maintaining our day-to-day operations, our financial reporting systems and our internal control over financial reporting.

Our natural gas, NGLs and oil producing properties are located in the liquids-rich Appalachian Basin. Although the decline in oil prices has negatively impacted our oil revenue, oil sales represented approximately 4% of our total revenue for each of the nine months ended September 30, 2020 and the year ended December 31, 2019. While natural gas prices also declined during the first half of 2020, benchmark Henry Hub prices recovered during the third quarter and averaged $2.58/Mcf in September. Similarly, C3+ NGL prices also improved during the third quarter as gasoline demand increased, supporting prices for normal butane (nC4), isobutane (iC4), and pentane (C5), all of which are used for gasoline. The COVID-19 induced demand destruction on gasoline, which forced C5 prices below propane prices for much of April to under $0.40 per gallon, has since rebounded with benchmark C5 price in October in the range of $0.85 to $0.95 per gallon.

In addition, we have hedged through fixed price contracts the sale of 1.3 Bcf per day of natural gas at a weighted average price of $2.84 per MMBtu for the remainder of 2020. Our hedges cover a substantial majority of our expected natural gas production in 2020. We also have fixed priced contracts for the sale of 10,315 barrels per day of propane at a weighted average price of $0.65 per gallon, 24,500 barrels per day of ethane at a weighted average price of $0.20 per gallon and 26,000 barrels per day of oil at a weighted average price of $55.63 per barrel for the remainder of 2020. All of our hedges are financial hedges and do not have physical delivery requirements. As such, any decreases in anticipated production, whether as a result of decreased development activity, shut-ins, or through transactions under our asset sale plan, will not impact our ability to realize the benefits of the hedges.

Our natural gas and NGLs are primarily used in manufacturing, power generation and heating rather than transportation. While we have seen a decrease in the overall demand for these products, demand for natural gas and NGLs has not declined as much as demand for oil, and there has not been as substantial an oversupply of natural gas and NGLs as there has been of oil. Furthermore, the decrease in demand for oil has significantly reduced the number of rigs drilling for oil in the continental U.S. and, as a result, estimates of future gas supply associated with oil production have declined. Additionally, the restart of economic activity in Asia and Europe, coupled with lower LPG production from refineries in the U.S., Europe, and Asia during the second quarter, provided support for international LPG prices relative to oil. Further, reductions in OPEC+ and North American oil production and the associated NGL volumes are expected to have a supportive effect on propane and butane prices through the remainder of 2020 and into 2021.

During the third quarter of 2020, we shipped 54% of our total C3+ NGL net production on Mariner East 2 for export and realized a $0.04 per gallon premium to Mont Belvieu pricing on these volumes at Marcus Hook, PA. We sold the remaining 46% of C3+ NGL net production at a $0.12 per gallon discount to Mont Belvieu pricing at Hopedale, OH. We expect to sell at least 50% of our C3+ NGL full-year production in 2020 at Marcus Hook for export at a premium to Mont Belvieu.

Condensate differentials to WTI were approximately $15/Bbl during the third quarter. Pre-hedge oil realizations were negatively impacted during the second quarter and beginning of the third quarter as Antero sold volumes at a material discount to WTI in order to keep from shutting in production volumes. This period of weak condensate demand driven by the pandemic coincided with an active well completion period for Antero that brought on large condensate volumes. The negative impact from wider oil differentials was more than offset by the benefit of maintaining full natural gas and NGL volumes through this period. Antero expects its full year 2020 realized oil price differential to be at the high end of the $10.00/Bbl to $12.00/Bbl range, as the differential normalizes during the fourth quarter of 2020.

Our supply chain also has not experienced any significant interruptions. The industry continues to experience storage capacity constraints for oil and certain NGL products, and we may become subject to those constraints if we are not able to sell our production or certain components thereof, or enter into additional storage arrangements. The lack of a market or available storage for any one NGL product or oil could result in our having to delay or discontinue well completions and commercial production or shut in production for other products because we cannot curtail the production of individual products in a meaningful way without reducing production of other products. Potential impacts of these constraints may include partial shut-in of production, although we are not able to determine the extent of shut-ins or for how long they may last. However, because some of our wells produce rich gas, which is processed, and some produce dry gas, which does not require processing, we can change the mix of products that we produce and wells that we complete to adjust our production to address takeaway capacity constraints for certain products. For example, we can shut-in rich gas wells and still produce from our dry gas wells if processing or storage capacity of NGL products becomes further limited or constrained. Also, prior to the COVID-19 pandemic, we had developed a diverse set of buyers and destinations, as well as in-field and off-site storage capacity for our condensate volumes, and such capacity is still largely available to us.

During the third quarter of 2020, condensate differentials to WTI were notably wider as a result of COVID-19 demand destruction at both the Appalachia regional level and national level. To protect against production curtailments and shut-ins due to

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insufficient storage capacity, Antero expanded its customer base and its condensate storage capacity within the basin. In addition, Antero entered into transactions that required buyers to transport product to more distant markets and storage, which coincided with substantially weakened crack spreads for refined products. To date, Antero has not shut in or curtailed any production from its assets as a result of COVID-19 demand issues and does not expect to shut in any volumes during 2020.

In addition, as discussed below in “—2020 Capital Budget and Capital Spending,” in April 2020, we announced a 34% reduction in our drilling and completion capital budget for 2020. During the third quarter, our ongoing emphasis on completion efficiencies and drilling longer laterals resulted in material improvements in well costs. Well costs average $640 per lateral foot during the third quarter, benefiting from these efficiency improvements and lateral lengths that averaged over 15,000 feet. Well costs were $675 per foot when normalized for a 12,000 foot lateral length. We expect well costs to average $675 per foot during the fourth quarter of 2020, based on a 12,000 foot lateral. We continue to monitor our five-year drilling plan and will make further revisions as appropriate. Reducing the 2020 capital budget may impact production levels in 2021 and forward to the extent fewer wells are brought online.

During the first quarter of 2020 and the two preceding quarters, we recognized various impairment charges related to the decline in commodity prices and the value of our investment in Antero Midstream Corporation. At this time, we do not anticipate any further impairment charges in our equity method investment in Antero Midstream Corporation, as the value of our equity method investment has increased since the end of the first quarter of 2020. Additional impairment charges related to our assets may occur if we experience disruptions in production, additional or sustained declines in the forward commodity price strip from September 30, 2020, unresolved storage capacity restraints or other consequences caused by the COVID-19 pandemic.

In October 2020, the borrowing base supporting our Credit Facility was subject to its semi-annual redetermination and was re-affirmed our borrowing base at $2.85 billion. Lender commitments also remained unchanged at $2.64 billion, providing us with a consistent amount of available borrowings. Our next semi-annual borrowing base redetermination is in April 2021, which could impact our available borrowings and liquidity.

In addition, our borrowing capacity is directly impacted by the amount of financial assurance we are required to provide in the form of letters of credit to third parties, primarily pipeline capacity providers. The amount of financial assurance we must provide has not increased during the COVID-19 pandemic and, thus far, we have not experienced any losses due to counterparty risk. However, our ability to limit any additional financial assurance we are required to provide, as well as to protect ourselves from the counterparty risk of our financial hedges, may be limited in the future. Since the onset of the COVID-19 pandemic, we have timely serviced our debt and other obligations, and we have not implemented or requested any concessions or materially modified the terms of any agreements.

The COVID-19 pandemic, commodity market volatility and resulting financial market instability are variables beyond our control and may adversely impact our generation of funds from operating cash flows, distributions from unconsolidated affiliates, available borrowings under our Credit Facility and our ability to access the capital markets. We have announced $751 million in asset sales since December 2019, inclusive of up to $51 million of contingent consideration, with proceeds used for absolute debt reduction. Any additional asset sales or excess cash flows is expected to be used for further debt reduction. Instability in the financial markets and uncertainty in the general business environment resulting from the COVID-19 pandemic may impact our ability to further execute our asset sale program on the terms and the timeframe previously anticipated.

Volumetric Production Payment Transaction

On August 10, 2020, we completed a volumetric production payment transaction and received net proceeds of approximately $215 million (the "VPP").  In connection with the VPP, we entered into a purchase and sale agreement, together with a conveyance agreement and production and marketing agreement, with J.P. Morgan Ventures Energy Corporation ("JPM-VEC") to convey, effective July 1, 2020, an overriding royalty interest in dry gas producing properties in West Virginia (the "VPP Properties") equal to 136,589,000 MMBtu over the expected seven-year term of the VPP.

We accounted for the VPP as a conveyance under Accounting Standard Codifications (“ASC”) Topic 932, Extractive Industries—Oil and Gas, and the net proceeds were recognized as deferred revenue as of September 30, 2020. Deferred revenue is recognized as volumes are delivered using the units-of-production method over the term of the VPP. Under the production and marketing agreement, we and our affiliates provide certain marketing services as JPM-VEC’s agent, and any income or expenses related to these services will be recorded as marketing revenue or marketing expenses (as the case may be).

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Contemporaneously with the VPP transaction, we executed a call option related to the production volumes associated with our retained interest in the VPP properties, which is collateralized by a mortgage on the VPP properties. Additionally, the production and marketing agreement contains an embedded put option related to the production volumes for our retained interest in the VPP properties, which has been bifurcated from the production and marketing arrangement and accounted for as a derivative instrument recorded at fair value as of September 30, 2020. See Note 12—Derivative Instruments to the unaudited condensed consolidated financial statements for further discussion of such derivative instruments.

Conveyance of Overriding Royalty Interest

On June 15, 2020, we announced the consummation of a transaction with an affiliate of Sixth Street Partners, LLC (“Sixth Street”) relating to certain overriding royalty interests across our existing asset base (the “ORRIs”). In connection with the transaction, we contributed the ORRIs to a newly formed subsidiary, Martica Holdings LLC (“Martica”), and Sixth Street at the initial closing contributed $300 million in cash (subject to customary adjustments) and agreed to contribute up to an additional $102 million in cash if certain production targets attributable to the ORRIs are achieved in the third quarter of 2020 and first quarter of 2021. All cash contributed by Sixth Street was distributed to us. As of September 30, 2020, we determined we met the production threshold related to the third quarter of 2020 whereby we became entitled to receive a $51 million cash distribution that will be paid in the fourth quarter of 2020.

The ORRIs include an overriding royalty interest of 1.25% of our working interest in all of its proved developed operated properties in West Virginia and Ohio, subject to certain excluded wells (the “Initial PDP Override”), and an overriding royalty interest of 3.75% of our working interest in all of its undeveloped properties in West Virginia and Ohio (the “Development Override”). Wells turned to sales after April 1, 2020 and prior to the later of (a) the date on which we turn to sales 2.2 million lateral feet (net to our interest) of horizontal wells burdened by the Development Override and (b) the earlier of (i) April 1, 2023 and (ii) the date on which we turn to sales 3.82 million lateral feet (net to our interest) of horizontal wells are subject to the Development Override.

The ORRIs also include an additional overriding royalty interest of 2.00% of our working interest in the properties underlying the Initial PDP Override (the “Incremental Override”). The Incremental Override (or a portion thereof, as applicable) may be re-conveyed to us (at our election) if certain production targets attributable to the ORRIs are achieved through March 31, 2023. Any portion of the Incremental Override that may not be re-conveyed to us based on us achieving such production volumes through March 31, 2023 will remain with Martica.

Prior to Sixth Street achieving an internal rate of return of 13% and 1.5x cash-on-cash return (the “Hurdle”), Sixth Street will receive all distributions in respect of the Initial PDP Override and the Development Override, and we will receive all distributions in respect of the Incremental Override, unless certain production targets are not achieved, in which case Sixth Street will receive some or all of the distributions in respect of the Incremental Override. Following Sixth Street achieving the Hurdle, we will receive 85% of the distributions in respect of the ORRIs to which Sixth Street was entitled immediately prior to the Hurdle being achieved.

Production and Financial Results

Three months ended September 30, 2020. For the three months ended September 30, 2020 our net production totaled 347 Bcfe, or 3,772 MMcfe per day, a 12% increase in daily gas equivalent production compared to 310 Bcfe, or 3,367 MMcfe per day, for the three months ended September 30, 2019. 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 for the three months ended September 30, 2020 was $2.30 per Mcfe compared to $2.74 per Mcfe for the three months ended September 30, 2019. These prices are before the effects of gains on settled commodity derivatives in both periods and included the proceeds related to a certain lawsuit in the three months ended September 30, 2019. Our average realized price after the effects of gains on settled commodity derivatives was $2.92 per Mcfe for the three months ended September 30, 2020 compared to $3.13 per Mcfe for the three months ended September 30, 2019, a decrease of 7%.

We generated consolidated cash flows from operations of $176 million, net loss attributable to Antero Resources of $536 million, and Adjusted EBITDAX of $272 million for the three months ended September 30, 2020. This compares to consolidated cash flows from operations of $198 million, consolidated net loss attributable to Antero Resources of $879 million, and Adjusted EBITDAX of $258 million for the three months ended September 30, 2019. 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 income (loss).

Cash flows from operations decreased by $22 million for the three months ended September 30, 2020 compared to the prior year period primarily due to decreases in commodity prices both before and after the effects of settled commodity derivatives, increases in processing and transportation costs, and changes in current assets and liabilities. Consolidated net loss attributable to

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Antero Resources of $536 million for the three months ended September 30, 2020 decreased from consolidated net loss attributable to Antero Resources of $879 million for the three months ended September 30, 2019 primarily due to impairments of oil and gas properties in 2019, partially offset by decreases in commodity derivative fair value gains (losses) and commodity prices and expense increases in processing and transportation costs.

Adjusted EBITDAX increased from $258 million for the three months ended September 30, 2019 to $272 million for the three months ended September 30, 2020, an increase of 6%, primarily due to higher commodity derivative settlement gains and decreased operating expenses per Mcfe, partially offset by lower commodity prices between periods.

Nine months ended September 30, 2020. For the nine months ended September 30, 2020 our net production totaled 974 Bcfe, or 3,554 MMcfe per day, a 10% increase in daily combined production compared to 882 Bcfe, or 3,232 MMcfe per day, for the nine months ended September 30, 2019. 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 for the nine months ended September 30, 2020 was $2.15 per Mcfe compared to $3.15 per Mcfe for the nine months ended September 30, 2019. Our average realized price, after the effects of gains on settled commodity derivatives in both periods and including the proceeds related to a certain lawsuit in the three months ended September 30, 2019, was $2.91 per Mcfe for the nine months ended September 30, 2020 compared to $3.44 per Mcfe for the nine months ended September 30, 2019, a decrease of 15%.

We generated consolidated cash flows from operations of $493 million, net loss attributable to Antero of $1.3 billion, and Adjusted EBITDAX of $703 million for the nine months ended September 30, 2020. This compares to consolidated cash flows from operations of $956 million, consolidated net income attributable to Antero Resources of $142 million, and Adjusted EBITDAX of $952 million for the nine months ended September 30, 2019.

Cash flows from operations decreased by $463 million for the nine months ended September 30, 2020 compared to the prior year period primarily due to decreases in commodity prices both before and after the effects of settled commodity derivatives, increases in processing and transportation costs and changes in current assets and liabilities. Consolidated net loss attributable to Antero Resources of $1.3 billion for the nine months ended September 30, 2020 decreased from consolidated net income attributable to Antero Resources of $142 million for the nine months ended September 30, 2019 primarily due to lower commodity prices between periods as well as the gain on deconsolidation of Antero Midstream Partners in 2019 partially offset by impairment of oil and gas properties in 2019. The nine months ended September 30, 2020 was also impacted by an impairment of equity investment due to the decline in Antero Midstream Corporation’s fair value, Antero Midstream Corporation’s reporting a loss for such period, and the decreases in commodity prices both before and after the effects of settled commodity derivatives and increases in gathering, compression, processing and transportation costs.

Adjusted EBITDAX decreased from $982 million for the nine months ended September 30, 2019 to $703 million for the nine months ended September 30, 2020, a decrease of 26%, primarily due to the decrease in commodity prices of 32% per Mcfe before and 15% per Mcfe after the effects of settled commodity derivatives, and increased processing and transportation costs per Mcfe. A portion of the cost increases are the result of the deconsolidation of Antero Midstream Partners as costs that were previously eliminated in consolidation are now expensed.

2020 Capital Budget and Capital Spending

On April 20, 2020, we announced our revised 2020 drilling and completion capital budget of $750 million. We do not include acquisitions in our capital budget. We periodically review our capital expenditures and adjust our budget and its allocation based on commodity prices, takeaway constraints, operating cash flow and liquidity.

Three months ended September 30, 2020. For the three months ended September 30, 2020, our capital expenditures were approximately $151 million, including drilling and completion costs of $141 million, leasehold acquisitions of $9 million, and other capital expenditures of $1 million. Our capital expenditures for the three months ended September 30, 2019 of approximately $292 million included drilling and completion costs of $278 million, leasehold acquisitions of $13 million, and other capital expenditures of $1 million. This 48% reduction in capital costs was a result of our decreased activity levels during the third quarter of 2020 as well as well cost savings initiatives, which include savings resulting from service cost deflation, sand and water logistics optimization, and operational efficiency gains.

Nine months ended September 30, 2020. For the nine months ended September 30, 2020, our capital expenditures were approximately $726 million, including drilling and completion costs of $694 million, leasehold acquisitions of $31 million, and other capital expenditures of $1 million. Our exploration and production capital expenditures for the nine months ended September 30, 2019 of approximately $1.1 billion included drilling and completion costs of $958 million, leasehold acquisitions of $70 million, and

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other capital expenditures of $6 million. This 30% reduction in capital costs was a result of our decreased activity levels during 2020 as well as our well cost savings initiatives, which include savings resulting from service cost deflation, sand and water logistics optimization, and operational efficiency gains.

In addition, consolidated capital expenditures for the nine months ended September 30, 2019 included gathering and compression expenditures of $48 million and water handling and treatment expenditures of $24 million. Antero Midstream Partners also invested $25 million in a joint venture. These expenditures relate to the period prior to deconsolidation of Antero Midstream Partners on March 12, 2019.

Hedge Position (Excluding Martica)

As of September 30, 2020, we had fixed price natural gas swap contracts on NYMEX Henry Hub for the period from October 2020 through December 2023 covering 1.3 Tcf of our projected natural gas production at a weighted average index price of $2.69 per MMBtu, including contracts for the remainder of 2020 of approximately 190 Bcf of natural gas at a weighted average index price of $2.84 per MMBtu. As of September 30, 2020, we also had basis swaps for the period from October 2020 through December 2024 for approximately 78.6 Bcf of our projected natural gas production with pricing differentials ranging from $0.35 to $0.53 per MMBtu that hedge the difference between TCO and the NYMEX Henry Hub. In addition, we have a call option agreement, which entitles the holder, if exercised, to enter into a fixed price swap agreement for approximately 428 MMBtu per day at a price of $2.77 per MMBtu in 2024.

As of September 30, 2020, we had fixed price oil swap contracts on NYMEX-WTI for the period from October 2020 through December 2021 covering approximately 3.5 million barrels of our projected oil production at a weighted average index price of $55.48 per barrel. Additionally, we had fixed price propane swap contracts on ARA Propane for the period from October 2020 through December 2020 covering approximately 0.9 million barrels of our projected propane production at a weighted average index price of $0.65 per gallon. We also had fixed price ethane swap contracts on OPIS Ethane Mt Belv for the period from October 2020 through March 2021 covering approximately 4.0 million barrels of our projected ethane production at a weighted average index price of $0.20 per gallon.

As of September 30, 2020, we also had an embedded put option tied to NYMEX pricing for the production volumes associated with our retained interest in the VPP properties of 120,667,000 MMBtu remaining through December 31, 2026 at a weighted average strike price of $2.60 per MMBtu.

We believe our hedge position provides some certainty to cash flows supporting our future operations and capital spending plans. As of September 30, 2020, the estimated fair value of our commodity derivative contracts was a net liability of approximately $130 million.

Results of Operations

We have 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 we capitalized as proved property development costs. Through March 12, 2019, the results of Antero Midstream Partners were included in our consolidated financial statements. Effective March 13, 2019, the results of Antero Midstream Partners are no longer included in our results; however, our disclosures include the segments of our unconsolidated affiliates due to their significance to our operations. See Note 3—Deconsolidation of Antero Midstream Partners LP and Note 18—Segment Information to the unaudited condensed consolidated financial statements. 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.

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Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2020

The operating results of our reportable segments were as follows for the three months ended September 30, 2019 and 2020 (in thousands):

					Equity Method		Elimination of
					Investment in		intersegment
	Exploration				Antero		transactions and
	and				Midstream		unconsolidated		Consolidated
	production		Marketing		Corporation		affiliates		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, 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 and compression		209,752		—		13,091		(13,091)		209,752
Processing		230,377		—		—		—		230,377
Transportation		163,731		—		—		—		163,731
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 income (loss)	$	(916,507)		(61,571)		(341,889)		334,089		(985,878)
Equity in earnings of unconsolidated affiliates	$	(117,859)		—		18,478		(18,478)		(117,859)

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					Equity Method		Elimination of
					Investment in		intersegment
	Exploration				Antero		transactions and
	and				Midstream		unconsolidated		Consolidated
	production		Marketing		Corporation		affiliates		total
Three months ended September 30, 2020:
Revenue and other:
Natural gas sales	$	436,304		—		—		—		436,304
Natural gas liquids sales		327,426		—		—		—		327,426
Oil sales		34,265		—		—		—		34,265
Commodity derivative fair value losses		(514,751)		—		—		—		(514,751)
Gathering, compression, water handling and treatment		—		—		251,215		(251,215)		—
Marketing		—		91,497		—		—		91,497
Amortization of deferred revenue, VPP		5,175		—		—		—		5,175
Other income		675		—		(17,800)		17,800		675
Total	$	289,094		91,497		233,415		(233,415)		380,591
Operating expenses:
Lease operating	$	21,450		—		—		—		21,450
Gathering and compression		221,004		—		38,052		(38,052)		221,004
Processing		244,888		—		—		—		244,888
Transportation		190,723		—		—		—		190,723
Production and ad valorem taxes		25,790		—		—		—		25,790
Marketing		—		128,580		—		—		128,580
Exploration		454		—		—		—		454
Impairment of oil and gas properties		29,392		—		—		—		29,392
Impairment of midstream assets		—		—		947		(947)		—
Depletion, depreciation, and amortization		238,418		—		26,801		(26,801)		238,418
Accretion of asset retirement obligations		1,115		—		39		(39)		1,115
General and administrative (excluding equity-based compensation)		25,941		—		9,554		(9,554)		25,941
Equity-based compensation		5,699		—		3,678		(3,678)		5,699
Contract termination and rig stacking and other expenses		1,246		—		2,527		(2,527)		1,246
Total		1,006,120		128,580		81,598		(81,598)		1,134,700
Operating income (loss)	$	(717,026)		(37,083)		151,817		(151,817)		(754,109)
Equity in earnings of unconsolidated affiliates	$	24,419		—		23,173		(23,173)		24,419

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Exploration and Production Segment Results for the Three Months Ended September 30, 2019 Compared to the Three Months Ended September 30, 2020

The following table sets forth selected operating data of the exploration and production segment for the three months ended September 30, 2019 compared to the three months ended September 30, 2020:

	Three months ended				Amount of
	September 30,				Increase		Percent
	2019		2020		(Decrease)		Change
Production data (1):
Natural gas (Bcf)		210		226		16	8	%
C2 Ethane (MBbl)		4,307		5,459		1,152	27	%
C3+ NGLs (MBbl)		11,472		13,400		1,928	17	%
Oil (MBbl)		865		1,367		502	58	%
Combined (Bcfe)		310		347		37	12	%
Daily combined production (MMcfe/d)		3,367		3,772		405	12	%
Average prices before effects of derivative settlements (2):
Natural gas (per Mcf)	$	2.50	$	1.93	$	(0.57)	(23)	%
C2 Ethane (per Bbl)	$	6.15	$	5.94	$	(0.21)	(3)	%
C3+ NGLs (per Bbl)	$	22.53	$	22.01	$	(0.52)	(2)	%
Oil (per Bbl)	$	46.86	$	25.07	$	(21.79)	(47)	%
Weighted Average Combined (per Mcfe)	$	2.74	$	2.30	$	(0.44)	(16)	%
Average realized prices after effects of derivative settlements (2):
Natural gas (per Mcf)	$	3.05	$	2.73	$	(0.32)	(10)	%
C2 Ethane (per Bbl)	$	6.15	$	5.67	$	(0.48)	(8)	%
C3+ NGLs (per Bbl)	$	22.67	$	23.81	$	1.14	5	%
Oil (per Bbl)	$	50.00	$	34.96	$	(15.04)	(30)	%
Weighted Average Combined (per Mcfe)	$	3.13	$	2.92	$	(0.21)	(7)	%
Average costs (per Mcfe):
Lease operating	$	0.12	$	0.06	$	(0.06)	(50)	%
Gathering and compression	$	0.68	$	0.64	$	(0.04)	(6)	%
Processing	$	0.74	$	0.71	$	(0.03)	(4)	%
Transportation	$	0.53	$	0.55	$	0.02	4	%
Production taxes	$	0.09	$	0.07	$	(0.02)	(22)	%
Marketing, net	$	0.20	$	0.11	$	(0.09)	(45)	%
Depletion, depreciation, amortization and accretion	$	0.78	$	0.69	$	(0.09)	(12)	%
General and administrative (excluding equity-based compensation)	$	0.10	$	0.07	$	(0.03)	(30)	%

(1) Production data excludes volumes related to the VPP.

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

Natural gas sales. Revenues from production of natural gas decreased from $524 million for the three months ended September 30, 2019 to $436 million for the three months ended September 30, 2020, a decrease of $88 million, or 17% (calculated as the change in year-over-year volumes times the change in year-to-year average price). Higher natural gas production volumes during the three months ended September 30, 2020 accounted for an approximate $40 million increase in year-over-year 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 $128 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

NGLs sales. Revenues from production of NGLs increased from $285 million for the three months ended September 30, 2019 to $327 million for the three months ended September 30, 2020, an increase of $42 million, or 15% (calculated as the change in year-over-year volumes times the change in year-to-year average price). Increased NGLs production volumes accounted for an approximate $50 million increase in year-over-year NGL revenues (calculated as the change in year-to-year volumes times the prior year average price), and changes in our prices, excluding the effects of derivative settlements, accounted for an approximate $8

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million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

Oil sales. Revenues from production of oil decreased from $41 million for the three months ended September 30, 2019 to $34 million for the three months ended September 30, 2020, a decrease of $7 million, or 16% (calculated as the change in year-over-year volumes times the change in year-to-year average price). Increased oil production volumes accounted for an approximate $23 million increase in year-over-year 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 $30 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

Commodity derivative fair value gains (losses). 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. The commodity derivative fair value gains (losses) included $120 million and $234 million gains on cash settled derivatives for the three months ended September 30, 2019 and 2020, respectively. For the three months ended September 30, 2019 and 2020, our commodity hedges resulted in derivative fair value gains of $221 million and losses of $515 million, 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.

Amortization of deferred revenue, VPP. The three months ended September 30, 2020 include amortization of $5 million of deferred revenues associated with the VPP, which relate to the production volumes delivered under the terms of the agreement during such period at approximately $1.61 per MMBtu. See Note 4—Transactions to the unaudited condensed consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for more information on this transaction.

Other income. Other income remained relatively consistent at $1 million for the three months ended September 30, 2019 and 2020.

Lease operating expense. Lease operating expense decreased from $36 million for the three months ended September 30, 2019 to $21 million for the three months ended September 30, 2020, a decrease of $15 million, or 40%. On a per unit basis, lease operating expenses decreased from $0.12 for the three months ended September 30, 2019 to $0.06 for the three months ended September 30, 2020, primarily due to lower water handling costs resulting from improved operating efficiencies including the reuse of produced and flowback water in completion operations.

Gathering, compression, processing, and transportation expense. Gathering, compression, processing, and transportation expense increased by $53 million, or 9%, from $604 million for the three months ended September 30, 2019 to $657 million for the three months ended September 30, 2020 primarily due to a 12% increase in production, partially offset by lower costs between periods. Gathering and compression costs decreased from $0.68 per Mcfe to $0.64 per Mcfe primarily as a result of lower fuel costs as a result of decreased natural gas prices and a $12 million incentive fee rebate from Antero Midstream Corporation. Processing costs primarily decreased from $0.74 to $0.71 per Mcfe as a result of decreased terminal fees at Mariner East 2. Our transportation costs increased from $0.53 per Mcfe to $0.55 per Mcfe due to increased rates on the Rockies Express pipeline.

Production and ad valorem tax expense. Production and ad valorem taxes decreased from $29 million for the three months ended September 30, 2019 to $26 million for the three months ended September 30, 2020, a decrease of $3 million, or 11%. This decrease is primarily as a result of decreases in commodity prices. Production and ad valorem taxes as a percentage of natural gas revenues was relatively consistent at 6% in the three months ended September 30, 2019 and 2020.

Impairment of oil and gas properties. During the three months ended September 30, 2019, we recognized an $881 million impairment to write-down our Utica Shale proved properties to fair value because the carrying value of such properties exceeded the estimated undiscounted cash flows based on future strip commodity prices as of September 30, 2019. We also recorded $160 million of impairments for the three months ended September 30, 2019 related to expiring leases and the design and initial costs related to pads we no longer plan to place into service. During the three months ended September 30, 2020, we recognized impairment of $29 million primarily related to expiring leases and the design and initial costs related to pads we no longer plan to place into service.

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Depletion, depreciation, and amortization expense (“DD&A”). DD&A expense decreased from $242 million for the three months ended September 30, 2019 to $238 million for the three months ended September 30, 2020, a decrease of $4 million, or 1%. DD&A per Mcfe decreased from $0.78 per Mcfe during the three months ended September 30, 2019 to $0.69 per Mcfe during the three months ended September 30, 2020, primarily due to a lower depletable cost basis as a result of the Utica proved property impairment of $881 million in 2019, which was partially offset by downward reserve revisions that resulted from lower SEC prices between periods.

General and administrative expense. General and administrative expense (excluding equity-based compensation expense) was $32 million for the three months ended September 30, 2019 and $26 million for the three months ended September 30, 2020, a decrease of $6 million, or 19%. This decrease was primarily due to decreases in employee related expenses in the three months ended September 30, 2020 as a result of ongoing cost savings initiatives related to lower headcount in 2020. We had 569 employees as of September 30, 2019 and 520 employees as of September 30, 2020. On a per-unit basis, general and administrative expense excluding equity-based compensation decreased by 30%, from $0.10 per Mcfe during the three months ended September 30, 2019 to $0.07 per Mcfe during the three months ended September 30, 2020 as a result of higher production volumes and lower overall costs between periods.

Equity-based compensation expense. Noncash equity-based compensation expense was $4 million for the three months ended September 30, 2019 and $6 million for the three months ended September 30, 2020, an increase of $2 million, or 47%. This increases was primarily due to new equity-based compensation awards granted in the three months ended September 30, 2020. See Note 10—Equity Based Compensation 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 compared to $1 million for the three months ended September 30, 2020. Contract termination and rig stacking costs represent fees incurred upon the delay or cancellation of drilling and completion contracts with third-party contractors in order to align our drilling and completion activity level with our capital budget.

Discussion of the Marketing Segment for the Three Months Ended September 30, 2019 Compared to the Three Months Ended September 30, 2020

Marketing. We have entered into long-term firm transportation agreements for our current and expected future production to secure guaranteed capacity to favorable markets. Where feasible, we purchase and sell third-party natural gas and NGLs to utilize our excess firm transportation capacity, or release capacity to third parties to conduct these activities on our behalf, to reduce our net costs related to the unused capacity under these transportation agreements.

Operating losses on our marketing activities, or our net marketing expense, decreased from $62 million, or $0.20 per Mcfe, for the three months ended September 30, 2019 to $37 million, or $0.11 per Mcfe, for the three months ended September 30, 2020. The decrease was driven by higher volumes and the mitigation of some of our excess firm transportation expense.

Marketing revenues increased from $47 million for the three months ended September 30, 2019 to $92 million for the three months ended September 30, 2020, an increase of $45 million, or 96%. Marketing expenses increased from $108 million for the three months ended September 30, 2019 to $129 million for the three months ended September 30, 2020, an increase of $21 million, or 19%. Marketing expenses include firm transportation costs related to current excess firm capacity as well as the cost of third-party purchased gas and NGLs. Firm transportation costs included in the expenses above were $62 million and $32 million for the three months ended September 30, 2019 and 2020, respectively.

Discussion of Antero Midstream Corporation Segment for the Three Months Ended September 30, 2019 Compared to the Three Months Ended September 30, 2020

Antero Midstream Corporation. Revenue from the Antero Midstream Corporation segment decreased from $244 million for the three months ended September 30, 2019 to $235 million for the three months ended September 30, 2020, a decrease of $9 million, or 4%, primarily due to a reduction in water handling revenues. Total operating expenses related to the segment decreased from $586 million for the three months ended September 30, 2019 to $82 million for the three months ended September 30, 2020. The decrease was primarily due to impairment expense of $457 million on Antero Midstream Corporation’s wastewater treatment facility and related goodwill and customer relationships in the three months ended September 30, 2019.

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Discussion of Items Not Allocated to Segments for the Three Months Ended September 30, 2019 Compared to the Three Months Ended September 30, 2020

Interest expense. Our interest expense was relatively flat at $48 million for each of the three months ended September 30, 2019 and 2020 due to lower total indebtedness resulting from repurchases of our unsecured senior notes at prices below their stated value, partially offset by the interest that accrued on the newly issued 2026 Convertible Notes (as defined below). Interest expense included approximately $2.6 million and $3.1 million of non-cash amortization of deferred financing costs for the three months ended September 30, 2019 and 2020, respectively.

Transaction expense. We incurred transaction expense of less than $1 million in the three months ended September 30, 2020 and did not incur comparable costs in the three months ended September 30, 2019. These expenses included legal and transaction fees associated with the ORRI transaction. See Note 4—Transactions to the unaudited condensed consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for more information on this transaction.

Income tax benefit. Income tax benefit decreased from a deferred tax benefit of $273 million, with an effective tax rate of 24%, for the three months ended September 30, 2019 to a deferred tax benefit of $169 million, with an effective tax rate of 23%, for the three months ended September 30, 2020. The change was primarily a result of an increase in book income due to the impairment of proved properties in the Utica Shale in the prior period.

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Nine months ended September 30, 2019 Compared to Nine months ended September 30, 2020

The operating results of our reportable segments were as follows for the nine months ended September 30, 2019 and 2020 (in thousands):

					Equity Method		Elimination of
					Investment in		intersegment
	Exploration				Antero		transactions and
	and				Midstream		unconsolidated		Consolidated
	production		Marketing		Corporation		affiliates		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, water handling and treatment		—		—		592,699		(588,220)		4,479
Marketing		—		200,911		—		—		200,911
Other income		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 and compression		632,733		—		28,324		(138,810)		522,247
Processing		593,394		—		—		—		593,394
Transportation		479,582		—		—		—		479,582
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 of unconsolidated affiliates	$	(102,457)		—		34,981		(22,717)		(90,193)

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					Equity Method		Elimination of
					Investment in		intersegment
	Exploration				Antero		transactions and
	and				Midstream		unconsolidated		Consolidated
	production		Marketing		Corporation		affiliates		total
Nine months ended September 30, 2020:
Revenue and other:
Natural gas sales	$	1,214,801		—		—		—		1,214,801
Natural gas liquids sales		797,296		—		—		—		797,296
Oil sales		78,233		—		—		—		78,233
Commodity derivative fair value losses		(116,933)		—		—		—		(116,933)
Gathering, compression, water handling and treatment		—		—		749,870		(749,870)		—
Marketing		—		201,855		—		—		201,855
Amortization of deferred revenue, VPP		5,175		—		—		—		5,175
Other income		2,180		—		(53,011)		53,011		2,180
Total	$	1,980,752		201,855		696,859		(696,859)		2,182,607
Operating expenses:
Lease operating	$	71,836		—		—		—		71,836
Gathering and compression		616,785		—		128,847		(128,847)		616,785
Processing		697,716		—		—		—		697,716
Transportation		562,583		—		—		—		562,583
Production and ad valorem taxes		71,481		—		—		—		71,481
Marketing		—		334,906		—		—		334,906
Exploration		895		—		—		—		895
Impairment of oil and gas properties		155,962		—		—		—		155,962
Impairment of midstream assets		—		—		665,491		(665,491)		—
Depletion, depreciation, and amortization		652,130		—		81,889		(81,889)		652,130
Accretion of asset retirement obligations		3,330		—		142		(142)		3,330
General and administrative (excluding equity-based compensation)		84,263		—		29,478		(29,478)		84,263
Equity-based compensation		17,001		—		9,713		(9,713)		17,001
Contract termination and rig stacking and other expenses		12,317		—		13,920		(13,920)		12,317
Total		2,946,299		334,906		929,480		(929,480)		3,281,205
Operating loss	$	(965,547)		(133,051)		(232,621)		232,621		(1,098,598)
Equity in earnings (loss) of unconsolidated affiliates	$	(83,408)		—		63,197		(63,197)		(83,408)

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Exploration and Production Segment Results for the Nine months ended September 30, 2019 Compared to the Nine months ended September 30, 2020

The following table sets forth selected operating data of the exploration and production segment for the nine months ended September 30, 2019 compared to the nine months ended September 30, 2020:

	Nine months ended				Amount of
	September 30,				Increase		Percent
	2019		2020		(Decrease)		Change
Production data (1):
Natural gas (Bcf)		617		649		32	5	%
C2 Ethane (MBbl)		11,536		14,686		3,150	27	%
C3+ NGLs (MBbl)		29,842		36,167		6,325	21	%
Oil (MBbl)		2,823		3,308		485	17	%
Combined (Bcfe)		882		974		92	10	%
Daily combined production (MMcfe/d)		3,232		3,554		322	10	%
Average prices before effects of derivative settlements (2):
Natural gas (per Mcf)	$	2.81	$	1.87	$	(0.94)	(33)	%
C2 Ethane (per Bbl)	$	8.01	$	5.85	$	(2.16)	(27)	%
C3+ NGLs (per Bbl)	$	27.15	$	19.67	$	(7.48)	(28)	%
Oil (per Bbl)	$	48.77	$	23.65	$	(25.12)	(52)	%
Weighted Average Combined (per Mcfe)	$	3.15	$	2.15	$	(1.00)	(32)	%
Average realized prices after effects of derivative settlements (2):
Natural gas (per Mcf)	$	3.23	$	2.80	$	(0.43)	(13)	%
C2 Ethane (per Bbl)	$	8.01	$	5.72	$	(2.29)	(29)	%
C3+ NGLs (per Bbl)	$	27.24	$	22.25	$	(4.99)	(18)	%
Oil (per Bbl)	$	50.16	$	38.00	$	(12.16)	(24)	%
Weighted Average Combined (per Mcfe)	$	3.44	$	2.91	$	(0.53)	(15)	%
Average costs (per Mcfe):
Lease operating	$	0.14	$	0.07	$	(0.07)	(50)	%
Gathering and compression	$	0.72	$	0.63	$	(0.09)	(13)	%
Processing	$	0.67	$	0.72	$	0.05	7	%
Transportation	$	0.54	$	0.58	$	0.04	7	%
Production and ad valorem taxes	$	0.11	$	0.07	$	(0.04)	(36)	%
Marketing expense, net	$	0.24	$	0.14	$	(0.10)	(42)	%
Depletion, depreciation, amortization, and accretion	$	0.80	$	0.67	$	(0.13)	(16)	%
General and administrative (excluding equity-based compensation)	$	0.13	$	0.09	$	(0.04)	(31)	%

(1) Production data excludes volumes related to the VPP.

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

Natural gas sales. Revenues from production of natural gas decreased from $1.7 billion for the nine months ended September 30, 2019 to $1.2 billion for the nine months ended September 30, 2020, a decrease of $520 million, or 30% (calculated as the change in year-over-year volumes times the change in year-to-year average price). Higher natural gas production volumes during the nine months ended September 30, 2020 accounted for an approximate $90 million increase in year-over-year 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 $610 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

NGLs sales. Revenues from production of NGLs decreased from $903 million for the nine months ended September 30, 2019 to $797 million for the nine months ended September 30, 2020, a decrease of $106 million, or 12% (calculated as the change in year-over-year volumes times the change in year-to-year average price). Increased NGLs production volumes accounted for an approximate $196 million increase in year-over-year NGL revenues (calculated as the change in year-to-year volumes times the prior year average price), and changes in our prices, excluding the effects of derivative settlements, accounted for an approximate $302

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million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

Oil sales. Revenues from production of oil decreased from $138 million for the nine months ended September 30, 2019 to $78 million for the nine months ended September 30, 2020, a decrease of $59 million, or 43% (calculated as the change in year-over-year volumes times the change in year-to-year average price). Increased oil production volumes accounted for a $24 million increase in year-over-year 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 $83 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

Commodity derivative fair value gains (losses). 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. The commodity derivative fair value gains (losses) included $262 million and $759 million of gains on cash settled derivatives for the nine months ended September 30, 2019 and 2020, respectively. For the nine months ended September 30, 2019 and 2020, our commodity hedges resulted in derivative fair value gains of $472 million and losses of $117 million, 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.

Amortization of deferred revenue, VPP. The nine months ended September 30, 2020 include amortization of $5 million of deferred revenues associated with the VPP, which relate to the production volumes delivered under the terms of the agreement during such period at approximately $1.61 per MMBtu. See Note 4—Transactions to the unaudited condensed consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for more information on this transaction.

Other income. Other income remained relatively consistent at $3 million and $2 million for the nine months ended September 30, 2019 and 2020, respectively.

Lease operating expense. Lease operating expense decreased from $119 million for the nine months ended September 30, 2019 to $72 million for the nine months ended September 30, 2020, a decrease of $47 million, or 39%. On a per unit basis, lease operating expenses decreased from $0.14 per Mcfe for the nine months ended September 30, 2019 to $0.07 per Mcfe for the nine months ended September 30, 2020 primarily due to lower water handling costs resulting from improved operating efficiencies, including the reuse of produced and flowback water in completion operations.

Gathering, compression, processing, and transportation expense. Gathering, compression, processing, and transportation expense increased by $282 million, or 18%, from $1.6 billion for the nine months ended September 30, 2019 to $1.9 billion for the nine months ended September 30, 2020 primarily due to a 10% increase in production between periods as well as higher processing and transportation costs. Gathering and compression costs decreased from $0.72 per Mcfe for the nine months ended September 30, 2019 to $0.63 per Mcfe for the nine months ended September 30, 2020 primarily due to lower fuel costs as a result of decreased natural gas prices and $36 million in incentive fee rebates from Antero Midstream Corporation. Processing costs primarily increased from $0.67 per Mcfe to $0.72 per Mcfe for the nine months ended September 30, 2019 and 2020, respectively, due to increased NGL production in our production mix. Processing costs, however, remained relatively unchanged per NGL barrel. Transportation costs increased from $0.54 per Mcfe to $0.58 per Mcfe for the nine months ended September 30, 2019 and 2020, respectively, primarily due to increased rates on the Rockies Express pipeline and demand charges for Mountaineer Xpress pipeline, which came on-line in February 2019.

Production and ad valorem tax expense. Production and ad valorem taxes decreased from $96 million for the nine months ended September 30, 2019 to $72 million for the nine months ended September 30, 2020, a decrease of $24 million, or 25% primarily due to lower in commodity prices between periods. Production and ad valorem taxes as a percentage of natural gas revenues was relatively consistent at 6% in each of the nine months ended September 30, 2019 and 2020.

Impairment of oil and gas properties. During the nine months ended September 30, 2019, we recognized an $881 million impairment to write-down our Utica Shale proved properties to fair value because the carrying value of such properties exceeded the

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estimated undiscounted cash flows based on future strip commodity prices as of September 30, 2019. We also recorded $373 million of impairments for the nine months ended September 30, 2019 related to expiring leases and the design and initial costs related to pads we no longer plan to place into service. During the nine months ended September 30, 2020 we recognized impairment of $156 million primarily related to expiring leases and the design and initial costs related to pads we no longer plan to place into service.

Depletion, depreciation, and amortization expense. DD&A expense decreased from $724 million for the nine months ended September 30, 2019 to $652 million for the nine months ended September 30, 2020, a decrease of $72 million, or 10%. DD&A per Mcfe decreased from $0.80 per Mcfe during the nine months ended September 30, 2019 to $0.67 per Mcfe during the nine months ended September 30, 2020, primarily due to a lower depletable cost basis as a result of the Utica proved property impairment of $881 million in 2019, partially offset by downward reserve revisions that resulted from lower SEC prices between periods.

General and administrative expense. General and administrative expense (excluding equity-based compensation expense) was $127 million for the nine months ended September 30, 2019 and $84 million for the nine months ended September 30, 2020, a decrease of $43 million, or 34%. This decrease was primarily due to decreases in employee related expenses in the nine months ended September 30, 2020 as a result of ongoing cost savings initiatives related to lower headcount in 2020. We had 569 employees as of September 30, 2019 and 520 employees as of September 30, 2020. On a per-unit basis, general and administrative expense excluding equity-based compensation decreased by 31%, from $0.13 per Mcfe during the nine months ended September 30, 2019 to $0.09 per Mcfe during the nine months ended September 30, 2020 as a result of higher production volumes and lower overall costs between periods.

Equity-based compensation expense. Noncash equity-based compensation expense decreased from $19 million for the nine months ended September 30, 2019 to $17 million for the nine months ended September 30, 2020, a decrease of $2 million, or 12%. This decrease was the result of equity award forfeitures, as well as a decrease in the total value of awards to officers and employees in 2019, which impacts future expense recognition. When an equity award is forfeited, expense previously recognized for the award is reversed. See Note 10—Equity Based Compensation 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 compared to $12 million for the nine months ended September 30, 2020. Contract termination and rig stacking costs represent fees incurred upon the delay or cancellation of drilling and completion contracts with third-party contractors in order to align our drilling and completion activity level with our capital budget.

Discussion of the Marketing Segment for the Nine months ended September 30, 2019 Compared to the Nine months ended September 30, 2020

Marketing. We have entered into long-term firm transportation agreements for our current and expected future production to secure guaranteed capacity to favorable markets. Where feasible, we purchase and sell third-party natural gas and NGLs to utilize our excess firm transportation capacity, or release capacity to third parties to conduct these activities on our behalf, in order to reduce our net costs related to the unused capacity under these transportation agreements.

Our net marketing expense decreased from $208 million, or $0.24 per Mcfe, for the nine months ended September 30, 2019 to $133 million, or $0.14 per Mcfe, for the nine months ended September 30, 2020. The decrease was driven by higher volumes and the mitigation of some of our excess firm transportation expense.

Marketing revenues remained relatively flat at $201 million and $202 million for the nine months ended September 30, 2019 and 2020, respectively.

Marketing expenses decreased from $409 million for the nine months ended September 30, 2019 to $335 million for the nine months ended September 30, 2020, a decrease of $74 million, or 18%. Marketing expenses include firm transportation costs related to current excess firm capacity as well as the cost of third-party purchased gas and NGLs. Firm transportation costs included in the expenses above were $127 million and $122 million for the nine months ended September 30, 2019 and 2020, respectively.

Discussion of Antero Midstream Corporation Segment for the Nine months ended September 30, 2019 Compared to the Nine months ended September 30, 2020

Through March 12, 2019, the results of Antero Midstream Partners are included in our consolidated financial statements. Effective March 13, 2019, we no longer consolidate the results of Antero Midstream Partners in our results. As such, the nine months

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ended September 30, 2019 include the results of Antero Midstream Partners through March 12, 2019. See Note 3—Deconsolidation of Antero Midstream Partners LP to the unaudited condensed consolidated financial statements.

Antero Midstream Corporation. Revenue from the Antero Midstream Corporation segment increased from $554 million for the nine months ended September 30, 2019 to $697 million for the nine months ended September 30, 2020, an increase of $143 million, or 26%, primarily due to the nine months ended September 30, 2019 only including Antero Midstream Corporation’s results following the closing of the simplification transactions on March 12, 2019. Total operating expenses related to the segment increased from $774 million for the nine months ended September 30, 2019 to $929 million for the nine months ended September 30, 2020. The increase was primarily due to impairments by Antero Midstream Corporation of $89 million on its freshwater pipelines and equipment, and an impairment expense of $575 million on its goodwill.

Discussion of Items Not Allocated to Segments for the Nine months ended September 30, 2019 Compared to the Nine months ended September 30, 2020

Impairment of equity investment. At March 31, 2020, we determined that events and circumstances indicated that the carrying value of our equity method investment in Antero Midstream Corporation had experienced an other-than-temporary decline and we recorded an impairment of $611 million. The fair value of the equity method investment in Antero Midstream Corporation was based on the quoted market share price of Antero Midstream Corporation at March 31, 2020.

Interest expense. Our interest expense exclusive of interest expense related to Antero Midstream Partners’ indebtedness decreased from $157 million for the nine months ended September 30, 2019 to $153 million for the nine months ended September 30, 2020 primarily due to the reduction in debt as a result of our debt repurchases of our unsecured senior notes at prices below their stated value, partially offset by interest that accrued on the newly issued 2026 Convertible Notes.

Consolidated interest expense decreased from $174 million for the nine months ended September 30, 2019 to $153 million for the nine months ended September 30, 2020, a decrease of $21 million, or 12%. During the nine months ended September 30, 2019, interest related to Antero Midstream Partners’ debt through March 12, 2019 is included in consolidated interest expense. Interest expense includes approximately $8.3 million and $8.0 million of non-cash amortization of deferred financing costs for the nine months ended September 30, 2019 and 2020, respectively.

Transaction expense. We incurred transaction expense of $7 million in the nine months ended September 30, 2020 and did not incur comparable costs in the nine months ended September 30, 2019. These expenses included legal and transaction fees associated with the sale of our ORRI and the creation of Martica, as well as the VPP transaction. See Note 4—Transactions to the unaudited condensed consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for more information on these transactions.

Income tax expense/benefit. Income tax expense decreased from a deferred tax expense of $33 million, with an effective tax rate of 15%, for the nine months ended September 30, 2019 to a deferred tax benefit of $421 million, with an effective tax rate of 24%, for the nine months ended September 30, 2020. The change was primarily a result of an increase in book income due to the simplification transactions and the associated deconsolidation of Antero Midstream Partners for the nine months ended September 30, 2019, offset by a decrease in book income resulting from the impairment of our investment in Antero Midstream Corporation and reduced revenue due to commodity price decreases for the nine months ended September 30, 2020.

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, distributions/dividends from unconsolidated affiliates and proceeds from our asset sale program, including the sale of the overriding royalty interest. Our primary use of cash has been for the exploration, development, and acquisition of oil and natural gas properties. As we develop our reserves, we continually monitor what capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities, and liquidity requirements. Our future success in growing our proved reserves and production will be highly dependent on net cash provided by operating activities and the capital resources available to us.

During the nine months ended September 30, 2020, we repurchased shares of our common stock under our share repurchase program that expired March 31, 2020. We repurchased and retired 28,193,237 common shares at a weighted average price per share of $1.54 for approximately $43 million during the nine months ended September 30, 2020.

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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 will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. During the three and nine months ended September 30, 2020, we repurchased $461 million and $1.1 billion, respectively, principal amount of debt at a weighted average discount of 13% and 17%, respectively, which purchases included a portion of the 2021 Notes, 2022 Notes, 2023 Notes and 2025 Notes. Repurchases of the principal amount of debt during the three and nine months ended September 30, 2020 include repurchases of $367 million on the 2021 Notes, 2022 Notes and 2023 Notes through previously disclosed tender offers at a weighted average discount of 10%. These repurchases, at a discount, have resulted in a net reduction in total debt outstanding and interest expense.

As of September 30, 2020, we believe that funds from operating cash flows, distributions from unconsolidated affiliates, available borrowings under the Credit Facility, or capital market transactions will be sufficient to meet our cash requirements, including normal operating needs, debt service obligations, capital expenditures, and commitments and contingencies for at least the next 12 months.

Our 2021 Notes are due November 1, 2021 and our Credit Facility will become due 91 days prior to that date, or on August 1, 2021, if the 2021 Notes are not repaid prior to August 1, 2021. Under our business plan, we intend to extinguish the 2021 Notes prior to August 1, 2021 with proceeds from our asset sales program, cash flow from operations and available borrowings under the Credit Facility. Consequently, we have classified our Credit Facility as long-term debt. The classification of our Credit Facility does not impact any of our financial covenants.  

For more information on our outstanding indebtedness, see Note 8—Long Term Debt to the unaudited condensed consolidated financial statements included in this Quarterly Report on Form 10-Q. For information about the impacts of COVID-19 on our capital resources and liquidity, see “—COVID-19 Pandemic.”

The following table summarizes our cash flows for the nine months ended September 30, 2019 and 2020:

	Nine Months Ended
	September 30,				Increase
(in thousands)	2019		2020		(Decrease)
Net cash provided by operating activities	$	955,518		492,510		(463,008)
Net cash used in investing activities		(825,327)		(384,063)		441,264
Net cash provided by (used in) financing activities		489,341		(108,447)		(597,788)
Effect of deconsolidation of Antero Midstream Partners LP		(619,532)		—		619,532
Net increase (decrease) in cash and cash equivalents	$	—		—		—

The Company's condensed consolidated cash flow statements for the nine months ended September 30, 2019 includes the cash flows related to Antero Midstream Partners 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. Therefore, the cash flows for the nine months ended September 30, 2019 may not be representative of our expected future cash flows. See Note 3—Deconsolidation of Antero Midstream Partners LP to the unaudited condensed consolidated financial statements for more information.

Cash Flows Provided by Operating Activities

Net cash provided by operating activities was $956 million and $493 million for the nine months ended September 30, 2019 and 2020, respectively. Cash flow from operations decreased primarily due to decreases in commodity prices both before and after the effects of settled commodity derivatives and increases in gathering, compression, processing, and transportation costs.

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, storage capacity and other variables influence the market conditions for these products. For example, the impact of the COVID-19 outbreak has reduced domestic and international demand for natural gas, NGLs, and oil. These factors are beyond our control and are difficult to predict.

Cash Flows Used in Investing Activities

Cash flows used in investing activities decreased from $825 million for the nine months ended September 30, 2019 to $384 million for the nine months ended September 30, 2020, primarily due to a decrease in capital expenditures of $307 million during the

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nine months ended September 30, 2020 as compared to the same period in 2019, $297 million in proceeds received in connection with the simplification transactions impacting the nine months ended September 30, 2019 and $125 million in settlement of the water earnout impacting the nine months ended September 30, 2020.

In addition, the nine months ended September 30, 2019 included Antero Midstream Partners’ investments in joint ventures of $25 million and capital expenditures for water handling and treatment systems and gas gathering and compression systems of $73 million. Due to the deconsolidation of Antero Midstream Partners on March 12, 2019, cash flows used in investing activities for the nine months ended September 30, 2020 do not include costs attributable to Antero Midstream Partner’s investing activity. See Note 3—Deconsolidation of Antero Midstream Partners LP to the unaudited condensed consolidated financial statements.

Total capital expenditures for oil and gas properties decreased from $1.0 billion during the nine months ended September 30, 2019 to $726 million during the nine months ended September 30, 2020 primarily due to a decrease in drilling and completion activity, increased drilling and completion efficiencies and service cost deflation.

Our drilling and completion capital budget for 2020 has been reduced to $750 million from $1.15 billion. 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, the relative success in drilling activities, contractual obligations, internally generated cash flows, and other factors both within and outside our control.

Cash Flows Provided by (Used in) Financing Activities

Net cash flows provided by financing activities was $489 million for the nine months ended September 30, 2019, compared to net cash flows provided by financing activities of $108 million for the nine months ended September 30, 2020. This decrease was primarily due to the issuance of senior notes by Antero Midstream Partners prior to the simplification transactions and the associated deconsolidation of Antero Midstream Partners, partially offset by net repayments on our Credit Facility and Antero Midstream Partners’ credit facility. Additionally, during the nine months ended September 30, 2020, we received $300 million for the sale of a noncontrolling interest in Martica and issued $288 million principal amount of the 2026 Convertible Notes. See Note 4—Transactions and Note 8—Long-Term Debt for more information on these transactions, respectively.

Net borrowings (repayments) on our Credit Facility and Antero Midstream Partners’ credit facility changed from net repayments of $45 million during the nine months ended September 30, 2019 to net borrowings of $275 million during the nine months ended September 30, 2020. In the nine months ended September 30, 2020, approximately $900 million, partially funded with net borrowings on our Credit Facility, was used to repurchase a portion of our 2021 Notes, 2022 Notes, 2023 Notes and 2025 Notes. In addition, we repurchased and retired 28,193,237 common shares for approximately $43 million during the nine months ended September 30, 2020 compared to repurchases of common stock of $18 million during the nine months ended September 30, 2019. We did not repurchase any of our unsecured notes during the nine months ended September 30, 2019.

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 redeterminations. The borrowing base was re-affirmed in October 2020 at $2.85 billion and lender commitments are $2.64 billion.  The next redetermination of the borrowing base is scheduled to occur in April 2021.  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 then outstanding. 

At December 31, 2019, we had $552 million of borrowings under the Credit Facility with a weighted average interest rate of 3.28% and $623 million of letters of credit outstanding. As of September 30, 2020, we had $827 million of borrowings and $730 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, 2020 was approximately 3.28%. Our Credit Facility provides for borrowing under either LIBOR or an Alternative Rate of Interest.

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We were in compliance with the applicable covenants and ratios as of December 31, 2019 and September 30, 2020. As of September 30, 2020, our current ratio was 2.41 to 1.0 and our interest coverage ratio was 7.78 to 1.0.

For more information on the terms, conditions, and restrictions under the Credit Facility, please refer to the 2019 Form 10-K.

Senior Notes. Please refer to Note 8—Long Term Debt 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 the 2019 Form 10-K 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, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions, and other factors. The amounts involved could be material. During the nine months ended September 30, 2020, we repurchased $1.1 billion principal amount of debt at a 17% weighted average discount, including a portion of our 2021 Notes, 2022 Notes, 2023 Notes and 2025 Notes. 

Convertible Senior Notes. On August 21, 2020, we issued $250 million in aggregate principal amount of 4.25% Convertible Senior Notes due September 1, 2026 (the “2026 Convertible Notes”). On September 2, 2020, we issued an additional $37.5 million aggregate principal amount of 2026 Convertible Notes pursuant to the partial exercise of the initial purchasers’ option to purchase additional 2026 Convertible Notes. The 2026 Convertible Notes were issued pursuant to an indenture and are senior, unsecured obligations of Antero Resources and were issued in a private offering to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended. The 2026 Convertible Notes bear interest at a fixed rate of 4.25% per annum, payable semi-annually in arrears on March 1 and September 1 of each year, commencing on March 1, 2021. Proceeds from the issuance of the 2026 Convertible Notes totaled $278.6 million, net of initial purchasers’ fees and issuance costs of $8.9 million.  We used the net proceeds from this issuance to repay a portion of the debt outstanding under its Credit Facility.   Please refer to Note 8—Long Term Debt to the unaudited condensed consolidated financial statements included in this Quarterly Report on Form 10-Q for more information.

Contractual Obligations. A summary of our contractual obligations as of September 30, 2020 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 2020		2021		2022		2023		2024		2025		Thereafter		Total
Recorded contractual obligations:
Credit Facility(1)	$	—		827		—		—		—		—		—		827
Antero senior notes—principal(2)		—		315		661		579		—		590		288		2,433
Antero senior notes—interest(2)		42		124		107		56		40		25		11		405
Operating leases(3)		66		247		267		301		335		307		1,139		2,662
Finance leases(3)		—		1		—		—		—		—		—		1
Imputed interest for leases(3)		91		344		312		274		232		187		419		1,859
Asset retirement obligations(4)		—		—		—		—		—		—		59		59
Unrecorded contractual obligations:
Firm transportation(5)		278		1,076		1,034		1,061		1,021		981		6,941		12,392
Processing, gathering, and compression services(6)		14		55		53		59		59		47		106		393
Drilling and completion		2		—		—		—		—		—		—		2
Land payment obligations(7)		2		3		—		—		—		—		—		5
Total	$	495		2,992		2,434		2,330		1,687		2,137		8,963		21,038

(1) Includes outstanding principal amounts as of September 30, 2020. 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 then outstanding, which is August 1, 2021 if the 2021 Notes are not repaid prior to such date. Under our business plan, we intend to extinguish the 2021 Notes prior to August 1, 2021 with proceeds from our asset sales program, cash flow from operations and available borrowings under our Credit Facility. Consequently, we have classified our Credit Facility as long-term debt.

(2) Our senior notes include our 2021 Notes, 2022 Notes, 2023 Notes, 2025 notes and 2026 Convertible Notes.

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(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 13—Leases to the unaudited condensed consolidated financial statements for more information on our 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. 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 (loss), including noncontrolling interests, before interest expense, interest income, gains or losses from commodity derivatives and marketing derivatives, amortization of deferred revenue, but including net cash receipts or payments on derivative instruments included in derivative gains or losses other than proceeds from derivative monetizations, income taxes, impairments, depletion, depreciation, amortization, and accretion, exploration expense, equity-based compensation, gain or loss on early extinguishment of debt, contract termination and rig stacking costs, loss on sale of equity investment shares, equity in earnings or loss of unconsolidated affiliates, water earnout, simplification transaction fees, gain or loss on sale of assets and Antero Midstream Partners related adjustments.

Through March 12, 2019, the financial results of Antero Midstream Partners were included in our consolidated results. Effective March 13, 2019, we no longer consolidate Antero Midstream Partners and account for our interest in Antero Midstream using the equity method of accounting. See Note 6—Equity Method Investments to the unaudited condensed consolidated financial statements for more information on our equity investments. Adjusted EBITDAX 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 operating structure;

● 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; and

● is 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.

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 unaudited condensed consolidated statements of cash flows, in each case, for the three and nine months ended September 30, 2019 and 2020. Adjusted EBITDAX excludes the results of Antero Midstream Partners in order to provide comparability with the current structure of Antero Resources as effective March 13, 2019, we no longer consolidate Antero Midstream Partners results. These adjustments are disclosed

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in the table below as Antero Midstream Partners related adjustments. Adjusted EBITDAX also excludes the noncontrolling interests in Martica and these adjustments are disclosed in the table below as Martica related adjustments.

	Three months ended				Nine months ended
	September 30,				September 30,
(in thousands)	2019		2020		2019		2020
Reconciliation of net income (loss) to Adjusted EBITDAX:
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$	(878,864)		(535,613)	$	142,067		(1,337,727)
Net income (loss) and comprehensive income (loss) attributable to noncontrolling interests		—		(18,233)		46,993		(17,997)
Depletion, depreciation, amortization, and accretion		242,430		239,533		726,827		655,460
Impairment of oil and gas properties		1,041,469		29,392		1,253,712		155,962
Impairment of midstream assets		7,800		—		14,782		—
Unrealized commodity derivative gains (losses)		(100,785)		748,791		(210,053)		875,811
Proceeds from derivative monetizations		—		(18,073)		—		(18,073)
Amortization of deferred revenue, VPP		—		(5,175)		—		(5,175)
Equity-based compensation expense		3,875		5,699		19,327		17,001
Provision for income tax expense (benefit)		(272,627)		(168,778)		33,332		(421,167)
Gain on early extinguishment of debt		—		(55,633)		—		(175,365)
Equity in (earnings) loss of unconsolidated affiliates		117,859		(24,419)		90,193		83,408
Impairment of equity investment		—		—		—		610,632
Gain on deconsolidation of Antero Midstream Partners LP		—		—		(1,406,042)		—
Distributions/dividends from unconsolidated affiliates		48,714		42,755		109,241		128,267
Interest expense, net		47,754		48,043		173,868		152,956
Exploration expense		208		454		648		895
Gain on sale of assets		—		—		951		—
Contract termination and rig stacking		62		1,246		14,026		12,317
Simplification transaction fees		—		—		15,482		—
Transaction expense		—		524		—		6,662
		257,895		290,513		1,025,354		723,867
Antero Midstream Partners related adjustments (2)		—		—		(73,115)		—
Martica related adjustments (2)		—		(18,072)		—		(21,172)
Adjusted EBITDAX	$	257,895		272,441	$	952,239		702,695
Reconciliation of our Adjusted EBITDAX to net cash provided by operating activities:
Adjusted EBITDAX	$	257,895		272,441	$	952,239		702,695
Antero Midstream Partners related adjustments (1)		—		—		73,115		—
Martica related adjustments (2)		—		18,072		—		21,172
Interest expense, net		(47,754)		(48,043)		(173,868)		(152,956)
Exploration expense		(208)		(454)		(648)		(895)
Changes in current assets and liabilities		(13,653)		(86,618)		127,322		(78,891)
Simplification transaction fees		—		—		(15,482)		—
Transaction expense		—		(524)		—		(6,662)
Proceeds from derivative monetizations		—		18,073		—		18,073
Other items		2,130		2,923		(7,160)		(10,026)
Net cash provided by operating activities	$	198,410		175,870	$	955,518		492,510

(1) Amounts reflected are net of any elimination adjustments for intercompany activity and include activity related to Antero Midstream Partners through March 12, 2019. Effective March 13, 2019, Antero accounts for its unconsolidated investment in Antero Midstream Corporation using the equity method of accounting. See Note 6—Equity Method Investments to the unaudited condensed consolidated financial statements for further discussion on equity method investments.

(2) Adjustments reflect noncontrolling interests in Martica not otherwise adjusted in amounts above.

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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 the 2019 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—Summary of Significant Accounting Policies to the consolidated financial statements, included in the 2019 Form 10-K, for a discussion of additional accounting policies and estimates made by management.

We evaluate the carrying amount of our proved natural gas, NGLs, and oil properties for impairment for the Utica and Marcellus Shale properties, by property, when events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. Under GAAP for successful efforts accounting, if the carrying amount exceeds the estimated undiscounted future net cash flows (measured using future prices), we estimate the fair value of our proved properties and record an impairment charge for any excess of the carrying amount of the properties over the estimated fair value of the properties.

The estimated future net cash flows have been impacted by the COVID-19 pandemic and the decision in March 2020 by Saudi Arabia to reduce the price at which it sells oil and announcing plans to increase production. These events have caused, and continue to cause, significant volatility in future prices which are used in this evaluation. Based on future prices as of September 30, 2020, the estimated undiscounted future net cash flows exceeded the carrying amount and no further evaluation was required. We have not recorded any impairment expenses associated with our proved properties during the nine months ended September 30, 2019 and 2020. We recorded an impairment charge of $881 million related to the Utica Shale properties on September 30, 2019.

Estimated undiscounted future net cash flows are very sensitive to commodity price swings at current commodity price levels and a relatively small decline in prices could result in the carrying amount exceeding the estimated undiscounted future net cash flows at the end of a future reporting period, which would require us to further evaluate if an impairment charge would be necessary. If future prices decline further from September 30, 2020, the fair value of our properties may be below their carrying amounts and an impairment charge may be necessary. We are unable, however, to predict future commodity prices with any reasonable certainty.

New Accounting Pronouncements

On August 5, 2020, the Financial Accounting Standards Board issued Accounting Standards Update No. 2020-06, Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity, which eliminates the cash conversion model in ASC 470-20 (defined below in Item 1A. Risk Factors) that require separate accounting for conversion features that is currently being applied to the 2026 Convertible Notes, and instead, allows the debt instrument and conversion features to be accounted for as a single debt instrument. The new standard becomes effective on January 1, 2022, and early adoption is permitted. We are evaluating our plans for adoption, including the adoption date and transition method.

Upon adoption of this new standard, we expect to reclassify $62 million, net of deferred income taxes and equity issuance costs, to long-term debt and deferred income tax liability, as applicable, from stockholders’ equity. Additionally, annual interest expense for the 2026 Convertible Notes will be based on an effective interest rate of 4.8% as compared to 11.7% for the three and nine months ended September 30, 2020 in the statement of operations and the weighted average diluted shares outstanding will increase from zero as of September 30, 2020 under the treasury-stock method to 66 million under the if-converted method. We do not believe that adoption of the standard will impact our operational strategies or growth prospects.

Off-Balance Sheet Arrangements

As of September 30, 2020, we did not have any off balance sheet arrangements other than contractual commitments for firm transportation, gas processing and fractionation, gathering, and compression services and land payment obligations. See “—Debt Agreements and Contractual Obligations—Contractual Obligations” for our commitments under these agreements.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk.

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

Commodity Hedging Activities

Our primary market risk exposure is in the price we receive for our natural gas, NGLs, and oil production. Pricing is primarily driven by spot regional market prices applicable to our U.S. natural gas production and the prevailing worldwide price for 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 commodity 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, basis differential swaps or embedded options. These contracts are financial instruments and do not require or allow for physical delivery of the hedged commodity. As of September 30, 2020, our commodity derivatives included fixed price swaps and basis differential swaps at index-based pricing.

As of September 30, 2020, we had in place natural gas swaps covering portions of our projected production through 2023. Our commodity hedge position as of September 30, 2020 is summarized in Note 12—Derivative Instruments 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 and embedded put option that settled during the nine months ended September 30, 2020, our revenues would have decreased by approximately $31 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 as of September 30, 2020.

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

Mark-to-market adjustments of derivative instruments cause earnings volatility but have no cash flow impact relative to changes in market prices until the derivative contracts are settled or monetized prior to settlement. We expect continued volatility in the fair value of our derivative instruments. Our cash flows are only impacted when the associated derivative contracts are settled or monetized by making or receiving payments to or from the counterparty. As of September 30, 2020, the estimated fair value of our commodity derivative instruments was a net liability of $130 million comprised of current and noncurrent assets and liabilities. At December 31, 2019, the estimated fair value of our commodity derivative instruments was a net asset of $746 million comprised of current and noncurrent assets and liabilities.

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

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Counterparty and Customer Credit Risk

Our principal exposures to credit risk are through receivables resulting from the following: commodity derivative contracts ($127 million as of September 30, 2020); and the sale of our natural gas, NGLs and oil production ($301 million as of September 30, 2020), 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 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 16 different counterparties, 13 of which are lenders under our Credit Facility. The fair value of the net liability of our commodity derivative contracts of approximately $130 million as of September 30, 2020 included the following derivative assets by bank counterparty: Canadian Imperial Bank of Commerce - $29 million; Morgan Stanley - $17 million; Scotiabank - $14 million; BNP Paribas - $5 million; PNC - $3 million; TD Energy - $3 million; Natixis - $2 million and Truist - $1 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) as of September 30, 2020 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, 2020, 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 the Credit Facility, which has a floating interest rate. The average annualized interest rate incurred on the Credit Facility during the nine months ended September 30, 2020 was approximately 3.23%. We estimate that a 1.0% increase in the applicable average interest rates for the nine months ended September 30, 2020 would have resulted in an estimated $6.3 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, 2020 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, 2020 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 15—Contingencies 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 the 2019 Form 10-K and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 in addition to the risks described below. Other than as described below, there have been no material changes to the risks described in the 2019 Form 10-K and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020. 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 us. Any such risk, in addition to those described below, in the 2019 Form 10-K and in the Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, may materially and adversely affect our business, financial condition, cash flows and results of operations.

The accounting method for convertible debt securities that may be settled in cash, such as the 2026 Convertible Notes, could have a material effect on our reported financial results.

Under Accounting Standards Codification 470-20, Debt with Conversion and Other Options (“ASC 470-20”), an entity must separately account for the liability and equity components of the convertible debt instruments (such as the 2026 Convertible Notes) that may be settled entirely or partially in cash upon conversion in a manner that reflects the issuer’s economic interest cost. The effect of ASC 470-20 on the accounting for the 2026 Convertible Notes is that the equity component is required to be included in the additional paid-in capital section of stockholders’ equity on our consolidated balance sheet at the issuance date and the value of the equity component would be treated as a debt discount for purposes of accounting for the debt component of the 2026 Convertible Notes. As a result, we will be required to record a greater amount of non-cash interest expense as a result of the amortization of the discounted carrying value of the 2026 Convertible Notes to their face amount over the term of the 2026 Convertible Notes. We will report larger net losses (or lower net income) in our financial results because ASC 470-20 will require interest to include both the amortization of the debt discount and the instrument’s non-convertible coupon interest rate, which could adversely affect our reported earnings and financial condition.

In addition, under certain circumstances, convertible debt instruments (such as the 2026 Convertible Notes) that may be settled entirely or partly in cash may be accounted for utilizing the treasury stock method, the effect of which is that the shares issuable upon conversion of such 2026 Convertible Notes are not included in the calculation of diluted earnings per share except to the extent that the conversion value of such 2026 Convertible Notes exceeds their principal amount. Under the treasury stock method, for diluted earnings per share purposes, the transaction is accounted for as if the number of shares of common stock that would be necessary to settle such excess, if we elected to settle such excess in shares, are issued. We cannot be sure that the accounting standards in the future will continue to permit the use of the treasury stock method. If we are unable or otherwise elect not to use the treasury stock method in accounting for the shares issuable upon conversion of the 2026 Convertible Notes, then our diluted earnings per share could be adversely affected. For example, in August 2020, the Financial Accounting Standards Board issued ASU No. 2020-06, Debt—Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40) to amend current accounting standards to eliminate the treasury stock method for convertible instruments and instead require application of the “if-converted” method. Under that method, if it is adopted, diluted earnings per share would generally be calculated assuming that all the notes were converted solely into shares of common stock at the beginning of the reporting period, unless the result would be anti-dilutive. The application of the if-converted method may change previously reported per share results.

Conversion of the 2026 Convertible Notes may dilute the ownership interest of existing stockholders, including holders who had previously converted their 2026 Convertible Notes, or may otherwise depress the price of our common stock.

The conversion of some or all of the 2026 Convertible Notes will dilute the ownership interests of existing stockholders if we deliver shares of our common stock upon conversion of any of the 2026 Convertible Notes. The 2026 Convertible Notes may become convertible at the option of holders prior to their scheduled terms under certain circumstances. Any sales in the public market of the common stock issuable upon such conversion could adversely affect prevailing market prices of our common stock. In addition, the existence of the 2026 Convertible Notes may encourage short selling by market participants because the conversion of the 2026

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Convertible Notes could be used to satisfy short positions, or anticipated conversion of the 2026 Convertible Notes into shares of our common stock could depress the price of our common stock.

We may be unable to raise the funds necessary to repurchase the 2026 Convertible Notes for cash following a fundamental change, or to pay any cash amounts due upon conversion, and our other indebtedness may limit our ability to repurchase the 2026 Convertible Notes or pay cash upon their conversion.

Holders of our 2026 Convertible Notes may, subject to a limited exception, require us to repurchase their 2026 Convertible Notes following a fundamental change at a cash repurchase price generally equal to 100% of the principal amount of the 2026 Convertible Notes to be repurchased, plus accrued and unpaid interest, if any. In addition, upon conversion, we will satisfy part or all of our conversion obligation in cash unless we elect to settle conversions solely in shares of our common stock. We may not have enough available cash or be able to obtain financing at the time we are required to repurchase the 2026 Convertible Notes or pay the cash amounts due upon conversion. In addition, applicable law, regulatory authorities and the agreements governing our other indebtedness, may restrict our ability to repurchase the 2026 Convertible Notes or pay the cash amounts due upon conversion. Our inability to satisfy our obligations under the 2026 Convertible Notes could affect the trading price of our common stock.

Our failure to repurchase the 2026 Convertible Notes or to pay the cash amounts due upon conversion when required will constitute a default under the indenture governing the 2026 Convertible Notes. A default under this indenture or the occurrence of the fundamental change itself could also lead to a default under agreements governing our other indebtedness, which may result in that other indebtedness becoming immediately payable in full. We may not have sufficient funds to satisfy all amounts due under the other indebtedness and the 2026 Convertible Notes.

Provisions of our 2026 Convertible Notes could delay or prevent an otherwise beneficial takeover of us.

Certain provisions of our 2026 Convertible Notes and the indenture governing such notes could make a third-party attempt to acquire us more difficult or expensive. For example, if a takeover constitutes a “Fundamental Change” (as defined in the indenture governing such notes), then holders of our 2026 Convertible Notes will have the right to require us to repurchase their 2026 Convertible Notes for cash. In addition, if a takeover constitutes a “Make-Whole Fundamental Change” (as defined in such indenture), then we may be required to temporarily increase the conversion rate. In either case, and in other cases, our obligations under the 2026 Convertible Notes and the indenture governing such notes could increase the cost of acquiring us or otherwise discourage a third party from acquiring us, including in a transaction that holders of our 2026 Convertible Notes or holders of our common stock may view as favorable.

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:

				Total Number	Approximate
				of Shares	Dollar Value
				Repurchased	of Shares
	Total Number			as Part of	that May
	of Shares	Average Price		Publicly	Yet be Purchased
Period	Purchased	Paid Per Share		Announced Plans	Under the Plan
July 1, 2020 - July 31, 2020 (1)	14,485	$	2.85	—	$	—
August 1, 2020 - August 31, 2020	—	$	—	—	$	—
September 1, 2020 - September 30, 2020	—	$	—	—	$	—
Total	14,485	$	2.85	—	$	—

(1) The total number of shares purchased includes 14,485 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 RSUs held by our employees.

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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 the Company’s 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 the Company’s Current Report on Form 8-K (Commission File No. 001-36120) filed on October 17, 2013).
4.1	Indenture related to the 4.25% Convertible Senior Notes due 2026, dated as of August 21, 2020, by and among Antero Resources Corporation, the several guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-36120) filed on August 21, 2020).
4.2	Form of 4.25% Convertible Senior Note due 2026 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K (Commission File No. 001-36120) filed on August 21, 2020).
10.1*	Form of Retention Award Grant Notice and Retention Award Agreement under the Antero Resources Corporation 2020 Long-Term Incentive Plan (Employees).
10.2*	Form of Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement under the Antero Resources Corporation 2020 Long-Term Incentive Plan.
10.3*	Form of Performance Share Unit Grant Notice and Performance Share Unit Agreement under the Antero Resources Corporation 2020 Long-Term Incentive Plan.
22.1*	List of Guarantor Subsidiaries
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, 2020 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations and Comprehensive Income (Loss), (iii) Condensed Consolidated Statements of Equity, (iv) Condensed Consolidated Statements of Cash Flows, and (v) Notes to the Condensed Consolidated Financial Statements, tagged as blocks of text.
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

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 28, 2020

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