Antero Resources 10Q 2022 Q2 Quarterly report

Fee

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 June 30, 2022


☐	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 306,119,105 shares of common stock outstanding as of July 22, 2022.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Some of the information in this Quarterly Report on Form 10-Q may contain “forward-looking statements” 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;

●

our ability to execute our share repurchase program;

●

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

●

impacts of geopolitical events and 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 meet minimum volume commitments and to utilize or monetize our firm transportation commitments;

●

our future drilling plans;

●

our projected well costs, including with respect to water handling services provided by Antero Midstream Corporation (“Antero Midstream”);

●

competition;

●

government regulations and changes in laws;

●

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;

●

our ability to achieve our greenhouse gas reduction targets and the costs associated therewith;

●

general economic conditions;

●

credit markets;

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●

uncertainty regarding our future operating results; and

●

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 or changes in law, 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), cybersecurity risks, the state of markets for, and availability of, verified quality carbon offsets and the other risks described or referenced under the heading “Item 1A. Risk Factors” herein, including the risk factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2021 (the “2021 Form 10-K”), 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.

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PART I—FINANCIAL INFORMATION

ANTERO RESOURCES CORPORATION

Condensed Consolidated Balance Sheets

(In thousands)


			(Unaudited)
	December 31,		June 30,
	2021		2022
Assets
Current assets:
Accounts receivable	$	78,998		25,375
Accrued revenue		591,442		952,054
Derivative instruments		757		578
Other current assets		14,922		37,490
Total current assets		686,119		1,015,497
Property and equipment:
Oil and gas properties, at cost (successful efforts method):
Unproved properties		1,042,118		1,014,497
Proved properties		12,646,303		12,910,737
Gathering systems and facilities		5,802		5,802
Other property and equipment		116,522		126,807
		13,810,745		14,057,843
Less accumulated depletion, depreciation, and amortization		(4,283,700)		(4,466,297)
Property and equipment, net		9,527,045		9,591,546
Operating leases right-of-use assets		3,419,912		3,355,622
Derivative instruments		14,369		7,058
Investment in unconsolidated affiliate		232,399		229,095
Other assets		16,684		13,882
Total assets	$	13,896,528		14,212,700

Liabilities and Equity
Current liabilities:
Accounts payable	$	24,819		87,860
Accounts payable, related parties		76,240		72,871
Accrued liabilities		457,244		496,677
Revenue distributions payable		444,873		485,039
Derivative instruments		559,851		773,357
Short-term lease liabilities		456,347		506,724
Deferred revenue, VPP		37,603		34,107
Other current liabilities		11,140		18,769
Total current liabilities		2,068,117		2,475,404
Long-term liabilities:
Long-term debt		2,125,444		1,577,213
Deferred income tax liability, net		318,126		483,722
Derivative instruments		181,806		393,139
Long-term lease liabilities		2,964,115		2,849,598
Deferred revenue, VPP		118,366		103,215
Other liabilities		54,462		56,546
Total liabilities		7,830,436		7,938,837
Commitments and contingencies
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; 313,930 and 308,812 shares issued and outstanding as of December 31, 2021 and June 30, 2022, respectively		3,139		3,088
Additional paid-in capital		6,371,398		6,119,645
Accumulated deficit		(617,377)		(119,125)
Total stockholders' equity		5,757,160		6,003,608
Noncontrolling interests		308,932		270,255
Total equity		6,066,092		6,273,863
Total liabilities and equity	$	13,896,528		14,212,700

See accompanying notes to unaudited condensed consolidated financial statements.

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ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) (Unaudited)

(In thousands, except per share amounts)


	Three Months Ended June 30,
	2021		2022
Revenue and other:
Natural gas sales	$	626,520		1,558,994
Natural gas liquids sales		464,381		702,388
Oil sales		51,906		89,185
Commodity derivative fair value losses		(831,840)		(265,662)
Marketing		165,453		106,150
Amortization of deferred revenue, VPP		11,279		9,375
Other income (loss)		(619)		1,255
Total revenue		487,080		2,201,685
Operating expenses:
Lease operating		21,645		25,253
Gathering, compression, processing and transportation		641,362		656,212
Production and ad valorem taxes		33,694		81,842
Marketing		198,994		131,298
Exploration and mine expenses		5,638		1,394
General and administrative (including equity-based compensation expense of $4,249 and $8,171 in 2021 and 2022, respectively)		32,177		44,439
Depletion, depreciation and amortization		187,330		173,395
Impairment of oil and gas properties		9,303		23,363
Accretion of asset retirement obligations		1,331		804
Contract termination		844		2,096
(Gain) loss on sale of assets		(2,288)		71
Total operating expenses		1,130,030		1,140,167
Operating income (loss)		(642,950)		1,061,518
Other income (expense):
Interest expense, net		(49,963)		(34,213)
Equity in earnings of unconsolidated affiliate		17,477		14,713
Loss on early extinguishment of debt		(23,065)		(4,414)
Loss on convertible note equitization		(11,731)		—
Transaction expense		(185)		—
Total other expense		(67,467)		(23,914)
Income (loss) before income taxes		(710,417)		1,037,604
Income tax benefit (expense)		175,966		(225,571)
Net income (loss) and comprehensive income (loss) including noncontrolling interests		(534,451)		812,033
Less: net income (loss) and comprehensive income (loss) attributable to noncontrolling interests		(10,984)		46,898
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$	(523,467)		765,135

Income (loss) per share—basic	$	(1.70)		2.46
Income (loss) per share—diluted	$	(1.70)		2.29

Weighted average number of shares outstanding:
Basic		307,879		310,535
Diluted		307,879		334,561

See accompanying notes to unaudited condensed consolidated financial statements.

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ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) (Unaudited)

(In thousands, except per share amounts)


	Six Months Ended June 30,
	2021		2022
Revenue and other:
Natural gas sales	$	1,346,889		2,554,786
Natural gas liquids sales		904,700		1,362,693
Oil sales		96,592		152,479
Commodity derivative fair value losses		(1,009,596)		(1,277,042)
Marketing		330,243		175,188
Amortization of deferred revenue, VPP		22,429		18,647
Other income		21		1,774
Total revenue		1,691,278		2,988,525
Operating expenses:
Lease operating		46,192		43,033
Gathering, compression, processing and transportation		1,246,439		1,246,490
Production and ad valorem taxes		78,391		134,650
Marketing		361,071		230,194
Exploration and mine expenses		5,857		2,292
General and administrative (including equity-based compensation expense of $9,891 and $12,820 in 2021 and 2022, respectively)		76,251		80,130
Depletion, depreciation and amortization		381,356		341,783
Impairment of oil and gas properties		43,365		45,825
Accretion of asset retirement obligations		2,119		3,248
Contract termination		935		2,104
(Gain) loss on sale of assets		(2,288)		1,857
Total operating expenses		2,239,688		2,131,606
Operating income (loss)		(548,410)		856,919
Other income (expense):
Interest expense, net		(92,706)		(71,926)
Equity in earnings of unconsolidated affiliate		36,171		39,891
Loss on early extinguishment of debt		(66,269)		(15,068)
Loss on convertible note equitizations		(50,777)		—
Transaction expense		(2,476)		—
Total other expense		(176,057)		(47,103)
Income (loss) before income taxes		(724,467)		809,816
Income tax benefit (expense)		178,912		(172,479)
Net income (loss) and comprehensive income (loss) including noncontrolling interests		(545,555)		637,337
Less: net income (loss) and comprehensive income (loss) attributable to noncontrolling interests		(6,589)		28,621
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$	(538,966)		608,716

Income (loss) per share—basic	$	(1.78)		1.95
Income (loss) per share—diluted	$	(1.78)		1.81

Weighted average number of shares outstanding:
Basic		302,343		312,300
Diluted		302,343		337,589

See accompanying notes to unaudited condensed consolidated financial statements.

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ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)

(In thousands)


					Additional
	Common Stock				Paid-in		Accumulated		Noncontrolling		Total
	Shares		Amount		Capital		Deficit		Interests		Equity
Balances, December 31, 2020		268,672	$	2,686		6,195,497		(430,478)		322,566		6,090,271
Issuance of common shares		31,388		314		238,551		—		—		238,865
Issuance of common units in Martica Holdings, LLC		—		—		—		—		51,000		51,000
Equity component of 2026 Convertible Notes, net		—		—		(116,381)		—		—		(116,381)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		1,130		11		(5,656)		—		—		(5,645)
Equity-based compensation		—		—		5,642		—		—		5,642
Distributions to noncontrolling interests		—		—		—		—		(24,699)		(24,699)
Net income (loss) and comprehensive income (loss)		—		—		—		(15,499)		4,395		(11,104)
Balances, March 31, 2021		301,190		3,011		6,317,653		(445,977)		353,262		6,227,949
Issuance of common shares		11,588		116		125,262		—		—		125,378
Equity component of 2026 Convertible Notes, net		—		—		(79,497)		—		—		(79,497)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		749		8		(3,893)		—		—		(3,885)
Equity-based compensation		—		—		4,249		—		—		4,249
Distributions to noncontrolling interests		—		—		—		—		(21,329)		(21,329)
Net loss and comprehensive loss		—		—		—		(523,467)		(10,984)		(534,451)
Balances, June 30, 2021		313,527	$	3,135		6,363,774		(969,444)		320,949		5,718,414

Balances, December 31, 2021		313,930	$	3,139		6,371,398		(617,377)		308,932		6,066,092
Equity component of 2026 Convertible Notes, net		—		—		(24,411)		3,229		—		(21,182)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		780		8		(10,385)		—		—		(10,377)
Repurchases and retirements of common stock		(3,690)		(37)		(74,745)		(25,263)		—		(100,045)
Equity-based compensation		—		—		4,649		—		—		4,649
Distributions to noncontrolling interests		—		—		—		—		(35,757)		(35,757)
Net loss and comprehensive loss		—		—		—		(156,419)		(18,277)		(174,696)
Balances, March 31, 2022		311,020		3,110		6,266,506		(795,830)		254,898		5,728,684
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		2,112		21		(54,463)		—		—		(54,442)
Conversion of 2026 Convertible Notes		921		9		3,955		—		—		3,964
Repurchases and retirements of common stock		(5,241)		(52)		(104,524)		(88,430)		—		(193,006)
Equity-based compensation		—		—		8,171		—		—		8,171
Distributions to noncontrolling interests		—		—		—		—		(31,541)		(31,541)
Net income and comprehensive income		—		—		—		765,135		46,898		812,033
Balances, June 30, 2022		308,812	$	3,088		6,119,645		(119,125)		270,255		6,273,863

See accompanying notes to unaudited condensed consolidated financial statements.

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ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Cash Flows (Unaudited)

(In thousands)


	Six Months Ended June 30,
	2021		2022
Cash flows provided by (used in) operating activities:
Net income (loss) including noncontrolling interests	$	(545,555)		637,337
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion		383,475		345,031
Impairments		43,365		45,825
Commodity derivative fair value losses		1,009,596		1,277,042
Losses on settled commodity derivatives		(64,951)		(844,713)
Payments for derivative monetizations		(4,569)		—
Deferred income tax expense (benefit)		(178,912)		171,707
Equity-based compensation expense		9,891		12,820
Equity in earnings of unconsolidated affiliate		(36,171)		(39,891)
Dividends of earnings from unconsolidated affiliate		74,040		62,569
Amortization of deferred revenue		(22,429)		(18,647)
Amortization of debt issuance costs, debt discount and debt premium		7,877		2,515
Settlement of asset retirement obligations		—		(886)
(Gain) loss on sale of assets		(2,288)		1,857
Loss on early extinguishment of debt		66,269		15,068
Loss on convertible note equitizations		50,777		—
Changes in current assets and liabilities:
Accounts receivable		(7,687)		53,623
Accrued revenue		(68,425)		(360,612)
Other current assets		631		(22,566)
Accounts payable including related parties		6,681		50,378
Accrued liabilities		64,499		37,203
Revenue distributions payable		69,809		40,166
Other current liabilities		16,349		22,559
Net cash provided by operating activities		872,272		1,488,385
Cash flows provided by (used in) investing activities:
Additions to unproved properties		(29,473)		(72,072)
Drilling and completion costs		(273,956)		(393,506)
Additions to other property and equipment		(2,320)		(11,162)
Proceeds from asset sales		2,351		195
Change in other assets		597		1,711
Change in other liabilities		(77)		—
Net cash used in investing activities		(302,878)		(474,834)
Cash flows provided by (used in) financing activities:
Repurchases of common stock		—		(293,051)
Issuance of senior notes		1,800,000		—
Repayment of senior notes		(1,234,698)		(658,906)
Borrowings (repayments) on bank credit facilities, net		(1,017,000)		70,800
Payment of debt issuance costs		(22,440)		—
Distributions to noncontrolling interests in Martica Holdings LLC		(46,028)		(67,298)
Employee tax withholding for settlement of equity compensation awards		(9,530)		(64,819)
Convertible note equitizations		(85,648)		—
Other		(509)		(277)
Net cash used in financing activities		(564,853)		(1,013,551)
Net increase in cash and cash equivalents		4,541		0
Cash and cash equivalents, beginning of period		0		0
Cash and cash equivalents, end of period	$	4,541		0

Supplemental disclosure of cash flow information:
Cash paid during the period for interest	$	58,126		89,326
Increase (decrease) in accounts payable and accrued liabilities for additions to property and equipment	$	42,589		(3,504)

See accompanying notes to unaudited condensed consolidated financial statements.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(1) Organization

Antero Resources Corporation (individually referred to as “Antero” and together with its consolidated subsidiaries “Antero Resources,” or the “Company”) is engaged in the development, production, exploration 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 is 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, 2021 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, 2021 consolidated financial statements were included in Antero Resources’ 2021 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, 2021 and June 30, 2022, results of operations for the three and six months ended June 30, 2021 and 2022 and cash flows for the six months ended June 30, 2021 and 2022. 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 June 30, 2022 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 and its variable interest entity (“VIE”), Martica Holdings LLC, (“Martica”), for which the Company is the primary beneficiary. All significant intercompany accounts and transactions have been eliminated in the Company’s unaudited condensed consolidated financial statements.

(c)	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 condensed consolidated balance sheets, and classifies the change in accounts payable associated with book overdrafts as an operating activity within its unaudited condensed consolidated statements of cash flows. As of December 31, 2021, the book overdrafts included within accounts payable and revenue distributions payable were $5 million and $52 million, respectively. As of June 30, 2022, the book overdrafts included within accounts payable and revenue distributions payable were $63 million and $50 million, respectively.

(d)	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—diluted for each period is computed after giving consideration to the potential dilution from (i) outstanding equity awards using the treasury stock method and (ii) shares of common stock issuable upon conversion of the 2026 Convertible Notes (as defined below in Note 7—Long-Term Debt) using the if-converted method. The Company includes restricted stock unit (“RSU”) awards, performance share unit

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(“PSU”) 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 effects of all equity awards and the 2026 Convertible Notes are anti-dilutive.

The following is a reconciliation of the Company’s earnings (loss) attributable to common stockholders for basic and diluted earnings (loss) per share (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2022		2021		2022
Net income (loss) attributable to Antero Resources Corporation—common shareholders	$	(523,467)		765,135		(538,966)		608,716
Add: Interest expense for 2026 Convertible Notes		—		967		—		1,934
Less: Tax-effect of interest expense for 2026 Convertible Notes		—		(224)		—		(449)
Net income (loss) attributable to Antero Resources Corporation—common shareholders and assumed conversions	$	(523,467)		765,878		(538,966)		610,201

Income (loss) per share—basic	$	(1.70)		2.46		(1.78)		1.95
Income (loss) per share—diluted	$	(1.70)		2.29		(1.78)		1.81

Weighted average common shares outstanding—basic		307,879		310,535		302,343		312,300
Weighted average common shares outstanding—diluted		307,879		334,561		302,343		337,589

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 June 30,		Six Months Ended June 30,
	2021	2022	2021	2022
Basic weighted average number of shares outstanding	307,879	310,535	302,343	312,300
Add: Dilutive effect of RSUs	—	3,161	—	3,629
Add: Dilutive effect of PSUs	—	2,108	—	2,892
Add: Dilutive effect of stock options	—	—	—	—
Add: Dilutive effect of 2026 Convertible Notes	—	18,757	—	18,768
Diluted weighted average number of shares outstanding	307,879	334,561	302,343	337,589

Weighted average number of outstanding securities excluded from calculation of diluted earnings per common share ⁽¹⁾:
RSUs	6,642	—	6,767	—
PSUs	2,769	—	2,584	—
Stock options	380	351	404	351
2026 Convertible Notes	18,778	—	18,778	—

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

(e)	Recently Issued Accounting Standards

Convertible Debt Instruments

In August 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2020-06, Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity, which eliminates the cash conversion model in Accounting Standards Codification (“ASC”) 470-20, Debt with Conversion and Other Options, that required separate accounting for conversion features, and instead, allows the debt instrument and conversion features to be accounted for as a single debt instrument. It is effective for interim and annual reporting periods beginning after December 31, 2021. The Company adopted

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

the standard effective January 1, 2022 under the modified retrospective transition method, which impacts only the debt instruments outstanding on the adoption date.

Upon adoption of this new standard, the Company reclassified $24 million, net of deferred income taxes and equity issuance costs, from additional paid-in capital and increased long-term debt by $27 million, reduced deferred income tax liability by $6 million and reduced accumulated deficit by $3 million as of January 1, 2022. Additionally, annual interest expense for the 2026 Convertible Notes beginning January 1, 2022 is based on an effective interest rate of 4.9% as compared to 15.1% for the three and six months ended June 30, 2021.

Income Taxes

In December 2019, the FASB issued ASU No. 2019-12, Simplifying the Accounting for Income Taxes. This ASU removes certain exceptions to the general principles in ASC 740, Income Taxes (“ASC 740”) and also simplifies portions of ASC 740 by clarifying and amending existing guidance. It is effective for interim and annual reporting periods beginning after December 15, 2020. The Company adopted this ASU on January 1, 2021, and it did not have a material impact on the Company's consolidated financial statements.

(3) Transactions

(a)	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. The Company met the applicable production thresholds related to the third quarter of 2020 and the first quarter of 2021 as of September 30, 2020 and March 31, 2021, respectively. The Company received a $51 million cash distribution during each of the fourth quarter of 2020 and the second quarter of 2021.

(b)	Drilling Partnership

On February 17, 2021, Antero Resources announced the formation of a drilling partnership with QL Capital Partners (“QL”), an affiliate of Quantum Energy Partners, for the Company’s 2021 through 2024 drilling program. Under the terms of the arrangement, each year in which QL participates represents an annual tranche, and QL will be conveyed a working interest in any wells spud by Antero Resources during such tranche year. For 2021 and 2022, Antero Resources and QL agreed to the estimated internal rate of return (“IRR”) of the Company’s capital budget for each annual tranche, and QL agreed to participate in the 2021 and 2022 tranches. For each subsequent year through 2024, Antero Resources will propose a capital budget and estimated IRR for all wells to be spud during such year and, subject to the mutual agreement of the parties that the estimated IRR for the year exceeds a specified return, QL will be obligated to participate in such tranche. Antero Resources develops and manages the drilling program associated with each tranche, including the selection of wells. Additionally, for each annual tranche in which QL participates, Antero Resources and QL will enter into assignments, bills of sale and conveyances pursuant to which QL will be conveyed a proportionate working interest percentage in each well spud in that year, which conveyances will not be subject to any reversion.

Under the terms of the arrangement, QL funded 20% of development capital for wells spud in 2021, and will fund 15% in 2022 and between 15% and 20% of development capital spending for wells spud on an annual basis in 2023 and 2024, which funding amounts represent QL’s proportionate working interest in such wells. Additionally, Antero Resources may receive a carry in the form of a one-time payment from QL for each annual tranche if the IRR for such tranche exceeds certain specified returns, which will be determined no earlier than October 31 and no later than December 1 following the end of each tranche year. All of the wells spud during each calendar year period will be a separate annual tranche. Capital costs in excess of, and cost savings below, a specified percentage of budgeted amounts for each annual tranche will be for Antero Resources’ account.

Subject to the preceding sentence, for any wells included in a tranche, QL is obligated and responsible for its working interest share of costs and liabilities, and is entitled to its working interest share of revenues, associated with such wells for the life of such wells. If Antero Resources presents a capital budget for an annual tranche with an estimated IRR equal to or exceeding a specified

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Notes to Unaudited Condensed Consolidated Financial Statements

return that QL in good faith believes is less than such specified return and QL elects not to participate, Antero Resources will not be obligated to offer QL the opportunity to participate in subsequent annual tranches.

The Company has accounted for the drilling partnership as a conveyance under ASC 932 and such conveyances are recorded in the unaudited condensed consolidated financial statements as QL obtains its proportionate working interest in each well. NaN gain or loss was recognized for the interests conveyed during the three and six months ended June 30, 2021 and 2022.

(4) Revenue

(a)	Disaggregation of Revenue

The table set forth below presents revenue disaggregated by type and reportable segment to which it relates (in thousands). See Note 16—Reportable Segments to the unaudited condensed financial statements for more information on reportable segments.


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2022		2021		2022		Reportable Segment
Revenues from contracts with customers:
Natural gas sales	$	626,520		1,558,994		1,346,889		2,554,786	Exploration and production
Natural gas liquids sales (ethane)		43,417		90,230		79,527		157,293	Exploration and production
Natural gas liquids sales (C3+ NGLs)		420,964		612,158		825,173		1,205,400	Exploration and production
Oil sales		51,906		89,185		96,592		152,479	Exploration and production
Marketing		165,453		106,150		330,243		175,188	Marketing
Total revenue from contracts with customers		1,308,260		2,456,717		2,678,424		4,245,146
Loss from derivatives, deferred revenue and other sources, net		(821,180)		(255,032)		(987,146)		(1,256,621)
Total revenue	$	487,080		2,201,685		1,691,278		2,988,525

(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 in ASC 606, Revenue from Contracts with Customers (“ASC 606”), which does not require the disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under 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 in ASC 606, which does not require the disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

Under the Company’s sales contracts, the Company invoices customers after its 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. As of December 31, 2021 and June 30, 2022, the Company’s receivables from contracts with customers were $591 million and $952 million, respectively.

(5) Equity Method Investment

(a)	Summary of Equity Method Investment

As of June 30, 2022, Antero owned approximately 29.1% of Antero Midstream Corporation’s (“Antero Midstream”) common stock, which is reflected in Antero’s unaudited condensed consolidated financial statements using the equity method of accounting.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

The following table sets forth a reconciliation of Antero’s investment in unconsolidated affiliate (in thousands):


Balance as of December 31, 2021 ⁽¹⁾	$	232,399
Equity in earnings of unconsolidated affiliate		39,891
Dividends from unconsolidated affiliate		(62,569)
Elimination of intercompany profit		19,374
Balance as of June 30, 2022 ⁽¹⁾	$	229,095

(1)	The fair value of the Company’s investment in Antero Midstream as of December 31, 2021 and June 30, 2022 was $1.3 billion based on the quoted market share price of Antero Midstream.

(b)	Summarized Financial Information of Antero Midstream

The tables set forth below present summarized financial information of Antero Midstream (in thousands):

Balance Sheet


			(Unaudited)
	December 31,		June 30,
	2021		2022
Current assets	$	83,804		77,057
Noncurrent assets		5,460,197		5,508,444
Total assets	$	5,544,001		5,585,501

Current liabilities	$	114,009		123,772
Noncurrent liabilities		3,143,294		3,231,610
Stockholders' equity		2,286,698		2,230,119
Total liabilities and stockholders' equity	$	5,544,001		5,585,501

Statement of Operations


	Six Months Ended June 30,
	2021		2022
Revenues	$	456,908		447,398
Operating expenses		171,922		189,848
Income from operations		284,986		257,550
Net income	$	163,664		159,435

(6) Accrued Liabilities

Accrued liabilities consisted of the following items (in thousands):


			(Unaudited)
	December 31,		June 30,
	2021		2022
Capital expenditures	$	46,983		45,767
Gathering, compression, processing and transportation expenses		164,900		168,756
Marketing expenses		50,589		64,753
Interest expense, net		65,093		45,714
Production and ad valorem taxes		44,298		47,001
General and administrative expense		27,740		24,699
Derivative settlements payable		35,202		79,269
Other		22,439		20,718
Total accrued liabilities	$	457,244		496,677

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Notes to Unaudited Condensed Consolidated Financial Statements

(7) Long-Term Debt

Long-term debt consisted of the following items (in thousands):


			(Unaudited)
	December 31,		June 30,
	2021		2022
Credit Facility ^(a)	$	—		70,800
5.00% senior notes due 2025 ^(d)		584,635		—
8.375% senior notes due 2026 ^(e)		325,000		311,767
7.625% senior notes due 2029 ^(f)		584,000		534,000
5.375% senior notes due 2030 ^(g)		600,000		600,000
4.25% convertible senior notes due 2026 ^(h)		81,570		77,570
Total principal		2,175,205		1,594,137
Unamortized discount, net		(27,772)		—
Unamortized debt issuance costs		(21,989)		(16,924)
Long-term debt	$	2,125,444		1,577,213

(a)	Senior Secured Revolving Credit Facility

Antero Resources has a senior secured revolving credit facility with a consortium of bank lenders. On October 26, 2021, Antero Resources entered into an amended and restated senior secured revolving credit facility (the “Credit Facility”). As of December 31, 2021 and June 30, 2022, the Credit Facility had a borrowing base of $3.5 billion and lender commitments of $1.5 billion. The borrowing base was re-affirmed in the semi-annual redetermination in April 2022. The maturity date of the Credit Facility is the earlier of (i) October 26, 2026 and (ii) the date that is 180 days prior to the earliest stated redemption date of any series of the Company’s then outstanding senior notes. As of June 30, 2022, the Credit Facility had an available borrowing capacity of $924 million.

The Credit Facility contains requirements with respect to leverage and current ratios, and certain covenants, including restrictions on our ability to incur debt and limitations on our ability to pay dividends unless certain customary conditions are met, in each case, subject to customary carve-outs and exceptions. Antero Resources was in compliance with all of the financial covenants under the Credit Facility as of December 31, 2021 and June 30, 2022.

The senior secured revolving credit facility agreement in effect prior to October 26, 2021 provided for borrowing under either an Alternate Base Rate or as a Eurodollar Loan (as each term is defined in the agreement), and the Credit Facility provides for borrowing at either an Adjusted Term Secured Overnight Financing Rate (“SOFR”), an Adjusted Daily Simple SOFR or an Alternate Base Rate (each as defined in the Credit Facility). The Credit Facility provides for interest only payments until maturity at which time all outstanding borrowings are due. Interest was payable at a variable rate based on LIBOR or the Alternative Base Rate (as defined in the agreement), determined by election at the time of borrowing, plus an applicable margin rate under the senior secured revolving credit facility agreement in effect prior to October 26, 2021. Interest is payable at a variable rate based on SOFR or the Alternate Base Rate, determined by election at the time of borrowing, plus an applicable margin rate under the Credit Facility. Interest at the time of borrowing is determined with reference to the Antero Resources’ then-current leverage ratio subject to certain exceptions. Commitment fees on the unused portion of the Credit Facility are due quarterly at rates ranging from 0.375% to 0.500% with respect to the Credit Facility, determined with reference to borrowing base utilization, subject to certain exceptions based on the leverage ratio then in effect. The Credit Facility includes fall away covenants, lower interest rates and reduced collateral requirements that Antero Resources may elect if Antero Resources is assigned an Investment Grade Rating (as defined in the Credit Facility).

As of December 31, 2021, Antero Resources had 0 borrowings under the Credit Facility and outstanding letters of credit of $531 million. As of June 30, 2022, Antero Resources had an outstanding balance under the Credit Facility of $71 million, with a weighted average interest rate of 3.95%, and had outstanding letters of credit of $505 million.

(b)	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 Company

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Notes to Unaudited Condensed Consolidated Financial Statements

repurchased or otherwise fully redeemed all of the 2022 Notes between 2019 and the first quarter of 2021. Interest on the 2022 Notes was payable on June 1 and December 1 of each year. See “—Debt Repurchase Program” below for more information.

(c)	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 Company repurchased or otherwise fully redeemed all of the 2023 Notes between 2020 and the second quarter of 2021. Interest on the 2023 Notes was payable on June 1 and December 1 of each year. See “—Debt Repurchase Program” below for more information.

(d)	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 Company repurchased or otherwise fully redeemed all of the 2025 Notes between 2020 and the first quarter of 2022. Interest on the 2025 Notes was payable on March 1 and September 1 of each year. See “—Debt Repurchase Program” below for more information.

(e)	8.375% Senior Notes Due 2026

On January 4, 2021, Antero Resources issued $500 million of 8.375% senior notes due July 15, 2026 (the “2026 Notes”) at par. The Company redeemed $175 million of the 2026 Notes on July 1, 2021 and repurchased $13 million of the 2026 Notes during the second quarter of 2022, and as of June 30, 2022, $312 million principal amount of the 2026 Notes remained outstanding. See “—Debt Repurchase Program” below for more information. The 2026 Notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2026 Notes rank pari passu to Antero Resources’ other outstanding senior notes. The 2026 Notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by Antero Resources’ existing subsidiaries that guarantee the Credit Facility and certain of its future restricted subsidiaries. Interest on the 2026 Notes is payable on January 15 and July 15 of each year. Antero Resources may redeem all or part of the 2026 Notes at any time on or after January 15, 2024 at redemption prices ranging from 104.188% on or after January 15, 2024 to 100.00% on or after January 15, 2026. At any time prior to January 15, 2024, Antero Resources may also redeem the 2026 Notes, in whole or in part, at a price equal to 100% of the principal amount of the 2026 Notes plus a “make-whole” premium and accrued and unpaid interest. If Antero Resources undergoes a change of control followed by a rating decline, the holders of the 2026 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 2026 Notes, plus accrued and unpaid interest.

(f)	7.625% Senior Notes Due 2029

On January 26, 2021, Antero Resources issued $700 million of 7.625% senior notes due February 1, 2029 (the “2029 Notes”) at par. The Company redeemed $116 million of the 2029 Notes during the fourth quarter of 2021 and repurchased $50 million of the 2029 Notes during the second quarter of 2022, and as of June 30, 2022, $534 million principal amount of the 2029 Notes remained outstanding. See “—Debt Repurchase Program” below for more information. The 2029 Notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2029 Notes rank pari passu to Antero Resources’ other outstanding senior notes. The 2029 Notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by Antero Resources’ existing subsidiaries that guarantee the Credit Facility and certain of its future restricted subsidiaries. Interest on the 2029 Notes is payable on February 1 and August 1 of each year. Antero Resources may redeem all or part of the 2029 Notes at any time on or after February 1, 2024 at redemption prices ranging from 103.813% on or after February 1, 2024 to 100.00% on or after February 1, 2027. In addition, on or before February 1, 2024, Antero Resources may redeem up to 35% of the aggregate principal amount of the 2029 Notes, but in an amount not greater than the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 107.625% of the principal amount of the 2029 Notes, plus accrued and unpaid interest, which option the Company partially exercised on October 18, 2021 with its notice to redeem $116 million aggregate principal amount of outstanding 2029 Notes. At any time prior to February 1, 2024, Antero Resources may also redeem the 2029 Notes, in whole or in part, at a price equal to 100% of the principal amount of the 2029 Notes plus a “make-whole” premium and accrued and unpaid interest. If Antero Resources undergoes a change of control followed by a rating decline, the holders of the 2029 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 2029 Notes, plus accrued and unpaid interest.

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Notes to Unaudited Condensed Consolidated Financial Statements

(g)	5.375% Senior Notes Due 2030

On June 1, 2021, Antero Resources issued $600 million of 5.375% senior notes due March 1, 2030 (the “2030 Notes”) at par. The 2030 Notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2030 Notes rank pari passu to Antero Resources’ other outstanding senior notes. The 2030 Notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by Antero Resources’ existing subsidiaries that guarantee the Credit Facility and certain of its future restricted subsidiaries. Interest on the 2030 Notes is payable on March 1 and September 1 of each year. Antero Resources may redeem all or part of the 2030 Notes at any time on or after March 1, 2025 at redemption prices ranging from 102.688% on or after March 1, 2025 to 100.00% on or after March 1, 2028. In addition, on or before March 1, 2025, Antero Resources may redeem up to 35% of the aggregate principal amount of the 2030 Notes, but in an amount not greater than the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 105.375% of the principal amount of the 2030 Notes, plus accrued and unpaid interest. At any time prior to March 1, 2025, Antero Resources may also redeem the 2030 Notes, in whole or in part, at a price equal to 100% of the principal amount of the 2030 Notes plus a “make-whole” premium and accrued and unpaid interest. If Antero Resources undergoes a change of control followed by a rating decline, the holders of the 2030 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 2030 Notes, plus accrued and unpaid interest.

(h)	4.25% Convertible Senior Notes Due 2026

On August 21, 2020, Antero Resources 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, Antero Resources issued an additional $37.5 million of the 2026 Convertible Notes. During 2021, the Company completed the equitization transactions described below under “—Partial Equitizations of 2026 Convertible Notes,” that extinguished $206 million principal amount of the 2026 Convertible Notes. On June 29, 2022, a noteholder elected to convert $4 million in aggregate principal amount of the 2026 Convertible Notes pursuant to their terms. The Company elected to settle this conversion by issuing approximately 1 million shares of common stock to the noteholder. As of June 30, 2022, $78 million principal amount of the 2026 Convertible Notes remained outstanding. 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 $278.5 million, net of initial purchasers’ fees and issuance cost of $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. As of June 30, 2022, the if-converted value of the 2026 Convertible Notes was $547 million, which exceeded the principal amount of the 2026 Convertible Notes by $470 million. The 2026 Convertible Notes will mature on September 1, 2026, unless earlier repurchased, redeemed or converted. Before May 1, 2026, noteholders 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 (the “Stock Price Condition”);

●

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;

●

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.

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Notes to Unaudited Condensed Consolidated Financial Statements

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. The 2026 Convertible Notes have met the Stock Price Condition allowing holders of the 2026 Convertible Notes to exercise their conversion right as of June 30, 2022.

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 was amortized to interest expense, together with debt issuance costs, over the term of the 2026 Convertible Notes using the effective interest method, with an effective interest rate of 15.1% per annum. As of the issuance date, the fair value of the 2026 Convertible Notes was estimated at $172 million, resulting in a debt discount at inception of $116 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 condensed consolidated balance sheet and statement of stockholders’ equity

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 condensed consolidated balance sheet and were 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 condensed consolidated balance sheet and statement of stockholders’ equity.

Effective January 1, 2022, the Company adopted ASU 2020-06 whereby the Company reclassified the equity component of the 2026 Convertible Notes outstanding on such date, net of deferred income taxes and equity issuance costs, from additional paid-in capital to long-term debt. See Note 2—Summary of Significant Accounting Policies to the unaudited condensed consolidated financial statements.

Partial Equitizations of 2026 Convertible Notes

On January 12, 2021, the Company completed a registered direct offering (the “January Share Offering”) of an aggregate of 31.4 million shares of its common stock at a price of $6.35 per share to certain holders of the 2026 Convertible Notes. The Company used the proceeds from the January Share Offering and approximately $63 million of borrowings under the Credit Facility to repurchase from such holders $150 million aggregate principal amount of the 2026 Convertible Notes in privately negotiated transactions (the “January Convertible Note Repurchase,” and, collectively with the January Share Offering, the “January Equitization Transactions”). The 2026 Convertible Notes have an initial conversion rate of 230.2026 shares of the Company’s common stock per $1,000 principal amount, and the January Equitization Transactions had the effect of increasing this conversion rate to 275.3525 shares of common stock per $1,000 principal amount. The Company accounted for this transaction as an inducement of the 2026 Convertible Notes, and as a result, the Company recorded a $39 million loss on convertible note equitization in the unaudited condensed consolidated statements of operations and comprehensive loss for the three months ended March 31, 2021 for the consideration paid in excess of the original terms of the 2026 Convertible Notes. Additionally, the January Equitization Transactions

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

resulted in a loss on early extinguishment of debt of $41 million in the unaudited condensed consolidated statement of operations and comprehensive loss for the three months ended March 31, 2021.

On May 13, 2021, the Company completed a registered direct offering (the “May Share Offering”) of an aggregate of 11.6 million shares of its common stock at a price of $11.01 per share to certain holders of the 2026 Convertible Notes. The Company used the proceeds from the May Share Offering and approximately $26 million of borrowings under the Credit Facility to repurchase from such holders $56 million aggregate principal amount of the 2026 Convertible Notes in privately negotiated transactions (the “May Convertible Note Repurchase,” and, collectively with the May Share Offering, the “May Equitization Transactions”). The 2026 Convertible Notes have an initial conversion rate of 230.2026 shares of the Company’s common stock per $1,000 principal amount, and the May Equitization Transactions had the effect of increasing this conversion rate to 245.2802 shares of common stock per $1,000 principal amount. The Company accounted for this transaction as an inducement of the 2026 Convertible Notes, and as a result, the Company recorded a $12 million loss on convertible note equitization in the unaudited condensed consolidated statements of operations and comprehensive loss for the second quarter of 2021 for the consideration paid in excess of the original terms of the 2026 Convertible Notes. Additionally, the May Equitization Transactions resulted in a loss on early extinguishment of debt of $21 million in the unaudited condensed consolidated statement of operations and comprehensive loss for the second quarter of 2021.

The 2026 Convertible Notes consist of the following (in thousands):


			(Unaudited)
	December 31,		June 30,
	2021		2022
Liability component:
Principal	$	81,570		77,570
Less: unamortized note discount ⁽¹⁾		(27,772)		—
Less: unamortized debt issuance costs		(1,592)		(1,779)
Net carrying value	$	52,206		75,791
Equity component ⁽¹⁾	$	32,799		—

(1)

As of December 31, 2021, the equity component attributable to the outstanding 2026 Convertible Notes was recorded in additional paid-in capital net of $1 million of issuance costs and $8 million of deferred taxes. Upon adoption of ASU 2020-06 on January 1, 2022, the equity component was reclassified from additional paid-in capital to long-term debt and fully offset the remaining discount on the 2026 Convertible Notes. See Note 2—Summary of Significant Accounting Policies to the unaudited condensed consolidated financial statements.

Interest expense recognized on the 2026 Convertible Notes related to the stated interest rate, amortization of the debt discount and debt issuance costs totaled $3 million and $1 million for the three months ended June 30, 2021 and 2022, respectively, and $7 million and $2 million for the six months ended June 30, 2021 and 2022, respectively.

(i)	Debt Repurchase Program

During the first quarter of 2021, the Company redeemed the remaining $661 million aggregate principal amount of its 2022 Notes at par, plus accrued and unpaid interest, and as a result, the 2022 Notes were fully retired as of February 10, 2021. The Company redeemed the remaining $574 million of the 2023 Notes at par, plus accrued and unpaid interest, during the second quarter of 2021. The 2023 Notes were fully retired as of June 1, 2021.

During the first quarter of 2022, the Company redeemed the remaining $585 million aggregate principal amount of its 2025 Notes at a redemption price of 101.25% of the principal amount thereof, plus accrued and unpaid interest and recognized a loss on early debt extinguishment of $11 million. During the second quarter of 2022, the Company repurchased $13 million of its 2026 Notes and $50 million of its 2029 Notes at a weighted average premium of 106% and recognized a loss on early debt extinguishment of $4 million.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(8) Asset Retirement Obligations

The following table presents a reconciliation of the Company’s asset retirement obligations (in thousands):


Asset retirement obligations—December 31, 2021	$	53,952
Obligations incurred		1,427
Accretion expense		3,248
Settlement of obligations		(886)
Obligations on sold properties		(42)
Revisions to prior estimates		(1,512)
Asset retirement obligations—June 30, 2022	$	56,187

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

(9) Equity-Based Compensation and Cash Awards

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 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 8,459,269 shares were available for future grant under the 2020 Plan as of June 30, 2022.

Antero Midstream Partners LP’s (“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). Antero Resources deconsolidated Antero Midstream Partners on March 12, 2019, and on such date, each outstanding phantom unit award under the AMP Plan was assumed by Antero Midstream and converted into 1.8926 RSUs (all such RSUs, the “Converted AM RSU Awards”) under the Antero Midstream Long Term Incentive Plan (the “AM Plan”). Each RSU award under the AM Plan represents a right to receive 1 share of Antero Midstream common stock.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

The Company’s equity-based compensation expense, by type of award, is as follows (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2022		2021		2022
RSU awards	$	3,392		4,774		6,630		7,494
PSU awards		223		3,012		1,759		4,431
Converted AM RSU Awards ⁽¹⁾		284		35		802		195
Equity awards issued to directors		350		350		700		700
Total expense	$	4,249		8,171		9,891		12,820

(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 March 12, 2019 (date of deconsolidation) to Antero Midstream Partners based on its proportionate share of Antero Resources’ labor costs.

(a)	Restricted Stock Unit Awards

A summary of RSU award activity is as follows:


		Weighted
		Average
	Number of	Grant Date
	Shares	Fair Value
Total awarded and unvested—December 31, 2021	5,930,607	$	5.15
Granted	975,471		35.06
Vested	(2,544,921)		4.75
Forfeited	(28,441)		9.97
Total awarded and unvested—June 30, 2022	4,332,716	$	12.09

As of June 30, 2022, there was approximately $47 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 2.6 years.

(b)	Performance Share Unit Awards

Performance Share Unit Awards Based on Total Shareholder Return

In 2019, the Company granted PSUs to certain of its employees and executive officers that vest based on Antero Resources’ absolute total shareholder return at the end of a three-year performance period (“2019 Absolute TSR PSUs”). The number of shares of common stock that could ultimately be earned ranged from 0 to 200% of the target number of PSUs granted. During the second quarter of 2022, the market-based performance condition for the 2019 Absolute TSR PSUs was met at 200% of target and the 2019 Absolute TSR PSUs were converted into approximately 2 million shares of common stock.

In April 2022, the Company granted PSU awards to certain of its senior management and executive officers that vest based on Antero Resources’ absolute TSR determined as of the last day of each of 3 one-year performance periods ending on April 15, 2023, April 15, 2024 and April 15, 2025, and 1 cumulative three-year performance period ending on April 15, 2025, in each case, subject to certain continued employment criteria (“2022 Absolute TSR PSUs”). The number of shares of common stock that may ultimately be earned following the end of the cumulative three-year performance period with respect to the 2022 Absolute TSR PSUs ranges from 0 to 200% of the target number of 2022 Absolute TSR PSUs originally granted. Expense related to these PSUs is recognized on a graded-vested basis over the term of each performance period. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

The following table presents the assumptions used in the Monte Carlo valuation model and the grant date fair value information for the 2022 Absolute TSR PSUs:


Dividend yield		—	%
Volatility		88	%
Risk-free interest rate		2.65	%
Weighted average fair value of awards granted—Absolute TSR	$	47.53

Performance Share Unit Awards Based on Leverage Ratio

In April 2022, the Company granted PSUs to certain of its senior management and executive officers that vest based on the Company’s total debt less cash and cash equivalents divided by the Company’s Adjusted EBITDAX (as defined in the award agreement) determined as of the last day of each of 3 one-year performance periods ending on December 31, 2022, December 31, 2023 and December 31, 2024, in each case, subject to certain continued employment criteria (“Leverage Ratio PSUs”). The number of shares of common stock that may ultimately be earned following the end of the third performance period with respect to the Leverage Ratio PSUs ranges from zero to 200% of the target number of Leverage Ratio PSUs originally granted. Expense related to the Leverage Ratio PSUs is recognized on a graded-vested basis over the term of each performance period that reflects the number of shares of common stock that are expected to be issued at the end of each measurement period, and such expense is reversed if the likelihood of achieving the performance condition becomes improbable. As of June 30, 2022, the likelihood of achieving the performance conditions related to the Leverage Ratio PSUs was probable.

Summary Information for Performance Share Unit Awards

A summary of PSU award activity is as follows:


		Weighted
	Number of	Average Grant
	Units	Date Fair Value
Total awarded and unvested—December 31, 2021	1,847,279	$	8.31
Granted	436,537		29.98
Vested	(1,210,712)		9.26
Forfeited	—		—
Cancelled (unearned)	—		—
Total awarded and unvested—June 30, 2022	1,073,104	$	12.09

As of June 30, 2022, there was approximately $15 million of unamortized equity-based compensation expense related to unvested PSUs. That expense is expected to be recognized over a weighted average period of approximately 2.5 years.

(c)	Converted AM RSU Awards

A summary of the Converted AM RSU Awards is as follows:


		Weighted
		Average
	Number of	Grant Date
	Units	Fair Value
Total awarded and unvested—December 31, 2021	81,707	$	13.46
Granted	—		—
Vested	(76,435)		13.43
Forfeited	—		—
Total awarded and unvested—June 30, 2022	5,272	$	13.99

As of June 30, 2022, there was less than $0.1 million of unamortized equity-based compensation expense related to unvested Converted AM RSU Awards. That expense is expected to be recognized over a weighted average period of 0.5 years, and the Company’s proportionate share will be allocated to it as it is recognized.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(d)	Stock Options

A summary of stock option activity is as follows:


				Weighted
		Weighted		Average
		Average		Remaining	Intrinsic
	Stock	Exercise		Contractual	Value
	Options	Price		Life	(in thousands) ⁽¹⁾
Outstanding—December 31, 2021	351,794	$	50.79	3.0	$	—
Granted	—		—
Exercised	—		—
Forfeited	—		—
Expired	(1,000)		50.00
Outstanding—June 30, 2022	350,794	$	50.79	2.5	$	—
Vested—June 30, 2022	350,794	$	50.79	2.5	$	—
Exercisable—June 30, 2022	350,794	$	50.79	2.5	$	—

(1)	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 June 30, 2022, all stock options were fully vested resulting in 0 unamortized equity-based compensation expense.

(e)	Cash Awards

In January 2020, the Company granted cash awards of approximately $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 in the aggregate of $3 million to certain non-executive employees under the 2020 Plan that vest ratably over four years. As of December 31, 2021 and June 30, 2022, the Company has recorded approximately $2 million and $1 million, respectively, in Other liabilities in the condensed consolidated balance sheets related to unvested cash awards.

(10) Fair Value

The carrying values of accounts receivable and accounts payable as of December 31, 2021 and June 30, 2022 approximated market values because of their short-term nature. The carrying values of the amounts outstanding under the Credit Facility as of December 31, 2021 and June 30, 2022 approximated fair value because the variable interest rates are reflective of current market conditions.

The following table sets forth the fair value and carrying value of the senior notes and 2026 Convertible Notes (in thousands):


					(Unaudited)
	December 31, 2021				June 30, 2022
	Fair		Carrying		Fair		Carrying
	Value ⁽¹⁾		Value ⁽²⁾		Value ⁽¹⁾		Value ⁽²⁾
2025 Notes	$	594,866		581,117		—		—
2026 Notes		370,013		321,738		329,693		308,977
2029 Notes		654,080		577,149		543,345		528,078
2030 Notes		641,400		593,234		545,940		593,567
2026 Convertible Notes		331,655		52,206		548,940		75,791
Total	$	2,592,014		2,125,444		1,967,918		1,506,413

(1)	Fair values are based on Level 2 market data inputs.

(2)	Carrying values are presented net of unamortized debt issuance costs and debt discounts or premiums.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

See Note 9—Equity-Based Compensation and Cash Awards to the unaudited condensed consolidated financial statements for information regarding the fair value of equity-based awards. See Note 11—Derivative Instruments to the unaudited condensed consolidated financial statements for information regarding the fair value of derivative financial instruments.

(11) 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 three and six months ended June 30, 2021 and 2022. 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’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.

As of June 30, 2022, the Company’s fixed price swap positions excluding Martica, the Company’s consolidated VIE, were as follows:


				Weighted
				Average
Commodity / Settlement Period	Index	Contracted Volume		Price
Natural Gas
July-December 2022	Henry Hub	1,105,897	MMBtu/day	$	2.48	/MMBtu
January-December 2023	Henry Hub	43,000	MMBtu/day		2.37	/MMBtu

In addition, the Company has a swaption agreement, which entitles the counterparty 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 June 30, 2022, 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 Average
Commodity / Settlement Period	Index to Basis Differential	Contracted Volume		Hedged Differential
Natural Gas
July-December 2022	NYMEX to TCO	60,000	MMBtu/day	$	0.515	/MMBtu
January-December 2023	NYMEX to TCO	50,000	MMBtu/day		0.525	/MMBtu
January-December 2024	NYMEX to TCO	50,000	MMBtu/day		0.530	/MMBtu

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

As of June 30, 2022, the Company’s fixed price swap positions for Martica, the Company’s consolidated VIE, were as follows:


				Weighted
				Average
Commodity / Settlement Period	Index	Contracted Volume		Price
Natural Gas
July-December 2022	Henry Hub	41,585	MMBtu/day	$	2.39	/MMBtu
January-December 2023	Henry Hub	35,616	MMBtu/day		2.35	/MMBtu
January-December 2024	Henry Hub	23,885	MMBtu/day		2.33	/MMBtu
January-March 2025	Henry Hub	18,021	MMBtu/day		2.53	/MMBtu

Propane
July-December 2022	Mont Belvieu Propane-OPIS Non-TET	973	Bbl/day	$	19.32	/Bbl

Natural Gasoline
July-December 2022	Mont Belvieu Natural Gasoline-OPIS Non-TET	294	Bbl/day	$	34.86	/Bbl
January-December 2023	Mont Belvieu Natural Gasoline-OPIS Non-TET	247	Bbl/day		40.74	/Bbl

Oil
July-December 2022	West Texas Intermediate	112	Bbl/day	$	43.39	/Bbl
January-December 2023	West Texas Intermediate	99	Bbl/day		44.88	/Bbl
January-December 2024	West Texas Intermediate	43	Bbl/day		44.02	/Bbl
January-March 2025	West Texas Intermediate	39	Bbl/day		45.06	/Bbl

(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 78,069,000 MMBtu remaining through December 31, 2026 at a weighted average strike price of $2.55 per MMBtu. The embedded put option is not clearly and closely related to the host contract, and therefore, the Company bifurcated this derivative instrument and reflects it at fair value in the unaudited condensed consolidated financial statements.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(c)

Summary

The table below presents a summary of the fair values of the Company’s derivative instruments and where such values are recorded in the condensed consolidated balance sheets (in thousands).


				(Unaudited)
	Balance Sheet	December 31,		June 30,
	Location	2021		2022
Asset derivatives not designated as hedges for accounting purposes:
Commodity derivatives—current	Derivative instruments	$	—		—
Embedded derivatives—current	Derivative instruments		757		578
Commodity derivatives—noncurrent	Derivative instruments		—		—
Embedded derivatives—noncurrent	Derivative instruments		14,369		7,058

Total asset derivatives ⁽¹⁾			15,126		7,636

Liability derivatives not designated as hedges for accounting purposes:
Commodity derivatives—current ⁽²⁾	Derivative instruments		559,851		773,357
Commodity derivatives—noncurrent ⁽²⁾	Derivative instruments		181,806		393,139

Total liability derivatives ⁽¹⁾			741,657		1,166,496

Net derivatives liability ⁽¹⁾		$	(726,531)		(1,158,860)

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

(2)

As of December 31, 2021, approximately $55 million of commodity derivative liabilities, including $31 million of current commodity derivatives and $24 million of noncurrent commodity derivatives, are attributable to the Company’s consolidated VIE, Martica. As of June 30, 2022, approximately $88 million of commodity derivative liabilities, including $53 million of current commodity derivatives and $35 million of noncurrent commodity derivatives, are attributable to the Company’s consolidated VIE, Martica.

The following table sets forth 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 condensed consolidated balance sheets as of the dates presented, all at fair value (in thousands):


							(Unaudited)
	December 31, 2021						June 30, 2022
					Net Amounts of						Net Amounts of
	Gross		Gross		Assets		Gross		Gross		Assets
	Amounts		Amounts Offset		(Liabilities) on		Amounts		Amounts Offset		(Liabilities) on
	Recognized		Recognized		Balance Sheet		Recognized		Recognized		Balance Sheet
Commodity derivative assets	$	2,177		(2,177)		—		4		(4)		—
Embedded derivative assets	$	15,126		—		15,126		7,636		—		7,636
Commodity derivative liabilities	$	(743,834)		2,177		(741,657)		(1,166,500)		4		(1,166,496)

The following table sets forth a summary of derivative fair value gains and losses and where such values are recorded in the unaudited condensed consolidated statements of operations (in thousands):


	Statement of
	Operations	Three Months Ended June 30,				Six Months Ended June 30,
	Location	2021		2022		2021		2022
Commodity derivative fair value losses ⁽¹⁾	Revenue	$	(819,725)		(237,680)		(989,692)		(1,232,163)
Embedded derivative fair value losses ⁽¹⁾	Revenue	$	(12,115)		(27,982)		(19,904)		(44,879)

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

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(12) 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 is 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.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(a)	Supplemental Balance Sheet Information Related to Leases

The Company’s lease assets and liabilities consisted of the following items (in thousands):


				(Unaudited)
		December 31,		June 30,
Leases	Balance Sheet Classification	2021		2022
Operating Leases
Operating lease right-of-use assets:
Processing plants	Operating lease right-of-use assets	$	1,739,550		1,644,040
Drilling rigs and completion services	Operating lease right-of-use assets		9,860		79,350
Gas gathering lines and compressor stations ⁽¹⁾	Operating lease right-of-use assets		1,634,928		1,583,204
Office space	Operating lease right-of-use assets		33,083		42,987
Vehicles	Operating lease right-of-use assets		2,009		1,389
Other office and field equipment	Operating lease right-of-use assets		482		4,652
Total operating lease right-of-use assets		$	3,419,912		3,355,622

Short-term operating lease obligation	Short-term lease liabilities	$	455,950		506,459
Long-term operating lease obligation	Long-term lease liabilities		2,963,962		2,849,163
Total operating lease obligation		$	3,419,912		3,355,622

Finance Leases
Finance lease right-of-use assets:
Vehicles	Other property and equipment	$	550		700
Total finance lease right-of-use assets ⁽²⁾		$	550		700

Short-term finance lease obligation	Short-term lease liabilities	$	397		265
Long-term finance lease obligation	Long-term lease liabilities		153		435
Total finance lease obligation		$	550		700

(1)	Gas gathering lines and compressor stations leases includes $1.5 billion related to Antero Midstream as of December 31, 2021 and June 30, 2022. See “—Related party lease disclosure” for additional discussion.

(2)	Financing lease assets are recorded net of accumulated amortization of $2 million and $1 million as of December 31, 2021 and June 30, 2022, respectively.

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

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(b)	Supplemental Information Related to Leases

Costs associated with operating and finance leases were included in the unaudited condensed consolidated statement of operations and comprehensive loss (in thousands):


			Three Months Ended June 30,				Six Months Ended June 30,
Cost	Classification	Location	2021		2022		2021		2022
Operating lease cost	Statement of operations	Gathering, compression, processing and transportation	$	385,022		365,343		761,952		731,177
Operating lease cost	Statement of operations	General and administrative		2,736		2,787		5,224		5,654
Operating lease cost	Statement of operations	Contract termination		844		—		844		—
Operating lease cost	Statement of operations	Lease operating		44		44		66		89
Operating lease cost	Balance sheet	Proved properties ⁽¹⁾		28,432		41,100		57,191		48,859
Total operating lease cost			$	417,078		409,274		825,277		785,779

Finance lease cost:
Amortization of right-of-use assets	Statement of operations	Depletion, depreciation and amortization	$	132		107		259		225
Interest on lease liabilities	Statement of operations	Interest expense		23		51		51		65
Total finance lease cost			$	155		158		310		290

Short-term lease payments			$	24,456		28,348		41,298		77,108

(1)	Capitalized costs related to drilling and completion activities.

(c)	Supplemental Cash Flow Information Related to Leases

The following table presents the Company’s supplemental cash flow information related to leases (in thousands):


	Six Months Ended June 30,
	2021		2022
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	716,582		675,563
Investing cash flows from operating leases		44,747		39,781
Financing cash flows from finance leases		509		277

Noncash activities:
Right-of-use assets obtained in exchange for new operating lease obligations	$	6,849		215,157
Increase (decrease) to existing right-of-use assets and lease obligations from operating lease modifications, net ⁽¹⁾	$	(2,612)		(47,728)

(1)

During the six months ended June 30, 2021, the weighted average discount rate for remeasured operating leases decreased from 5.9% as of December 31, 2020 to 4.1% as of June 30, 2021. During the six months ended June 30, 2022, the weighted average discount rate for remeasured operating leases increased from 4.5% as of December 31, 2021 to 5.1% as of June 30, 2022.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(d)	Maturities of Lease Liabilities

The table below is a schedule of future minimum payments for operating and financing lease liabilities as of June 30, 2022 (in thousands):


	Operating Leases		Financing Leases		Total
Remainder of 2022	$	347,588		221		347,809	��
2023		680,572		215		680,787
2024		619,383		207		619,590
2025		558,900		165		559,065
2026		508,199		36		508,235
2027		415,958		—		415,958
Thereafter		1,069,257		—		1,069,257
Total lease payments		4,199,857		844		4,200,701
Less: imputed interest		(844,235)		(144)		(844,379)
Total	$	3,355,622		700		3,356,322

(e)	Lease Term and Discount Rate

The following table sets forth the Company’s weighted average remaining lease term and discount rate:


					(Unaudited)
	December 31, 2021				June 30, 2022
	Operating Leases		Finance Leases		Operating Leases		Finance Leases
Weighted average remaining lease term	7.6 years		1.9 years		7.3 years		3.1 years
Weighted average discount rate	5.5	%	5.6	%	5.8	%	6.0	%

(f)	Related Party Lease Disclosure

The Company has a gathering and compression agreement with Antero Midstream, whereby Antero Midstream 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 annual adjustments based on the consumer price index. If and to the extent the Company requests that Antero Midstream construct new low pressure lines, high pressure lines or compressor stations, the gathering and compression agreement contains options at Antero Midstream’s election for either (i) minimum volume commitments that require Antero Resources to utilize or pay for 75% of the high pressure gathering capacity and 70% of the compression capacity of the requested capacity of such new construction for 10 years or (ii) a cost of service fee that allows the Antero Midstream to earn a 13% rate of return on such new construction over seven years.

In December 2019, the Company and Antero Midstream 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 on or before the 180^th day prior to the anniversary of such effective date. The Company did 0t achieve the quarterly volumetric target for either the first or second quarter of 2021, and therefore, did not earn a rebate for the three and six months ended June 30, 2021. For the three and six months ended June 30, 2022, the Company earned rebates of $12 million and $24 million, respectively, by achieving the quarterly volumetric target during the first and second quarters of 2022.

Gathering and compression fees paid by Antero related to this agreement were $184 million and $164 million for the three months ended June 30, 2021 and 2022, respectively. For the six months ended June 30, 2021 and 2022, gathering and compression fees paid by Antero related to this agreement were $361 million and $327 million, respectively. As of December 31, 2021 and June 30, 2022, $54 million and $51 million, respectively, was included within Accounts payable, related parties on the condensed consolidated balance sheet as due to Antero Midstream related to this agreement.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(13) Commitments

The following table sets forth 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 a lease term in excess of one year as of June 30, 2022 (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 2022	$	524,136		26,531		1,033		253,211		94,598		899,509
2023		1,071,563		63,219		—		511,142		169,645		1,815,569
2024		1,044,479		59,262		—		476,770		142,820		1,723,331
2025		1,023,947		47,960		—		441,782		117,283		1,630,972
2026		1,018,345		14,783		—		414,646		93,589		1,541,363
2027		1,016,780		14,783		—		343,751		72,207		1,447,521
Thereafter		5,012,734		83,813		—		915,020		154,237		6,165,804
Total	$	10,711,984		310,351		1,033		3,356,322		844,379		15,224,069

(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 unaudited condensed 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 unaudited condensed 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. See Note 12—Leases to the unaudited condensed consolidated financial statements for more information on the Company’s operating and finance leases.

(e)	Contract Terminations

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 included in the statement of operations and comprehensive loss.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

There are no remaining payment obligations related to these delayed or cancelled drilling and completion contracts as of June 30, 2022.

(14) Contingencies

Environmental

In June 2018, the Company 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. The NOV alleges that combustion devices at these facilities did not meet applicable air permitting requirements. Separately, in June 2018, the Company received an information request from the 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, the West Virginia Department of Environmental Protection (“WVDEP”) and the EPA Region V (covering Ohio facilities) each conducted its own inspections, and the Company has separately received NOVs from WVDEP and EPA Region V related to similar issues being investigated by the EPA Region III. The Company continues to negotiate with the EPA and WVDEP to resolve the issues alleged in the NOVs and the information request. The Company’s operations at these facilities are not suspended, and management does not expect these matters to have a material adverse effect on the Company’s 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 multiple contractual disputes involving firm gas sales contracts executed June 20, 2014 (the “Contracts”) that the Company began delivering gas under in January 2016. In late 2015, WGL asserted that the natural gas index price specified in the Contracts was no longer appropriate and sought to invoke an alternative index clause in the Contracts. This dispute was referred to arbitration. In January 2017, the arbitration panel ruled in the Company’s favor and found that the natural gas index price specified in the Contracts should remain.

In March of 2017, WGL filed a lawsuit against the Company in Colorado district court claiming that the Company breached contractual obligations by failing to deliver “TCO pool” gas, ultimately seeking damages of more than $40 million. Subsequently, after WGL failed to take certain volumes of gas required under the Contracts, the Company filed a separate lawsuit against WGL to recover damages that WGL refused to pay. These 2 lawsuits were consolidated and tried in June 2019. On June 20, 2019, the Company was awarded a jury verdict of approximately $96 million in damages against WGL. In addition, the jury rejected WGL’s claim against the Company, finding that the Company did not breach the Contracts. On December 10, 2020, the Colorado Court of Appeals affirmed the judgment of the trial court in favor of the Company. In February 2021, the Company and its royalty owners received a gross payment of approximately $107 million from WGL, which was in full satisfaction and discharge of the June 2019 judgment entered in favor of the Company.

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 unaudited condensed consolidated financial position, results of operations or cash flows.

In addition, pending litigation against operators in the Appalachian Basin, including the Company, could have an impact on the methods for determining the amount of permitted post-production costs and types of costs that may be deducted from royalty payments, among other things, and the Company cannot predict how these issues may ultimately be resolved.

(15) Related Parties

Substantially all of Antero Midstream’s revenues were and are derived from transactions with Antero Resources. See Note 16—Reportable Segments to the unaudited condensed consolidated financial statements for the operating results of the Company’s reportable segments.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(16) Reportable Segments

(a)	Summary of Reportable Segments

The Company’s operations, which are located in the United States, are organized into 3 reportable segments: (i) the exploration, development, and production of natural gas, NGLs and oil; (ii) marketing and utilization of excess firm transportation capacity and (iii) midstream services through the Company’s equity method investment in Antero Midstream. Substantially all of the Company’s 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. These segments are monitored separately by management for performance and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Management evaluates the performance of the Company’s business segments based on operating income (loss). 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.

Exploration and Production

The exploration and production segment is engaged in the development, production, exploration and acquisition of natural gas, NGLs and oil properties located in the Appalachian Basin. 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

Marketing

Where feasible, the Company purchases and sells third-party natural gas and NGLs and markets its excess firm transportation capacity, or engages third parties to conduct these activities on the Company’s behalf, in order to optimize the revenues from these transportation agreements. The Company has entered into long-term firm transportation agreements for a significant portion of its current and expected future production in order to secure guaranteed capacity to favorable markets.

Equity Method Investment in Antero Midstream

The Company receives midstream services through its equity method investment in Antero Midstream. Antero Midstream owns, operates and develops midstream energy infrastructure primarily to service the Company’s production and completion activity in the Appalachian Basin. Antero Midstream’s assets consist of gathering pipelines, compressor stations, interests in processing and fractionation plants and water handling assets. Antero Midstream provides midstream services to Antero Resources under long-term contracts.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(b)	Reportable Segments Financial Information

The summarized operating results of the Company’s reportable segments are as follows (in thousands):


	Three Months Ended June 30, 2021
							Elimination of
					Equity Method		Intersegment
	Exploration				Investment in		Transactions and
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream		Affiliates		Total
Sales and revenues:
Third-party	$	322,246		165,453		70		(70)		487,699
Intersegment		(619)		—		232,717		(232,717)		(619)
Total revenue	$	321,627		165,453		232,787		(232,787)		487,080

Operating expenses:
Lease operating	$	21,645		—		—		—		21,645
Gathering, compression, processing and transportation		641,362		—		39,555		(39,555)		641,362
General and administrative		32,177		—		14,251		(14,251)		32,177
Depletion, depreciation and amortization		187,330		—		26,619		(26,619)		187,330
Impairment of oil and gas properties		9,303		—		—		—		9,303
Other		39,219		198,994		963		(963)		238,213
Total operating expenses		931,036		198,994		81,388		(81,388)		1,130,030
Operating income (loss)	$	(609,409)		(33,541)		151,399		(151,399)		(642,950)
Equity in earnings of unconsolidated affiliates	$	17,477		—		21,515		(21,515)		17,477
Capital expenditures for segment assets	$	182,591		—		45,976		(45,976)		182,591


	Three Months Ended June 30, 2022
							Elimination of
					Equity Method		Intersegment
	Exploration				Investment in		Transactions and
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream		Affiliates		Total
Sales and revenues:
Third-party	$	2,095,144		106,150		242		(242)		2,201,294
Intersegment		391		—		228,665		(228,665)		391
Total revenue	$	2,095,535		106,150		228,907		(228,907)		2,201,685

Operating expenses:
Lease operating	$	25,253		—		—		—		25,253
Gathering, compression, processing and transportation		656,212		—		43,299		(43,299)		656,212
General and administrative		44,439		—		16,079		(16,079)		44,439
Depletion, depreciation and amortization		173,395		—		35,675		(35,675)		173,395
Impairment of oil and gas properties		23,363		—		—		—		23,363
Other		86,207		131,298		5,458		(5,458)		217,505
Total operating expenses		1,008,869		131,298		100,511		(100,511)		1,140,167
Operating income (loss)	$	1,086,666		(25,148)		128,396		(128,396)		1,061,518
Equity in earnings of unconsolidated affiliates	$	14,713		—		22,824		(22,824)		14,713
Capital expenditures for segment assets	$	260,864		—		77,767		(77,767)		260,864

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements


	Six Months Ended June 30, 2021
					Equity Method		Elimination of
					Investment in		Intersegment
	Exploration				Antero		Transactions and
	and				Midstream		Unconsolidated		Consolidated
	Production		Marketing		Corporation		Affiliates		Total
Sales and revenues:
Third-party	$	1,361,014		330,243		95		(95)		1,691,257
Intersegment		21		—		456,813		(456,813)		21
Total revenue		1,361,035		330,243		456,908		(456,908)		1,691,278

Operating expenses:
Lease operating		46,192		—		—		—		46,192
Gathering, compression, processing and transportation		1,246,439		—		78,869		(78,869)		1,246,439
General and administrative		76,251		—		32,181		(32,181)		76,251
Depletion, depreciation and amortization		381,356		—		53,469		(53,469)		381,356
Impairment of oil and gas properties		43,365		—		—		—		43,365
Impairment of midstream assets		—		—		1,379		(1,379)		—
Other		85,014		361,071		6,024		(6,024)		446,085
Total operating expenses		1,878,617		361,071		171,922		(171,922)		2,239,688
Operating income (loss)	$	(517,582)		(30,828)		284,986		(284,986)		(548,410)
Equity in earnings of unconsolidated affiliates	$	36,171		—		42,259		(42,259)		36,171
Capital expenditures for segment assets	$	305,749		—		74,365		(74,365)		305,749


	Six Months Ended June 30, 2022
							Elimination of
					Equity Method		Intersegment
	Exploration				Investment in		Transactions and
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream		Affiliates		Total
Sales and revenues:
Third-party	$	2,812,525		175,188		637		(637)		2,987,713
Intersegment		812		—		446,761		(446,761)		812
Total revenue		2,813,337		175,188		447,398		(447,398)		2,988,525

Operating expenses:
Lease operating		43,033		—		—		—		43,033
Gathering, compression, processing and transportation		1,246,490		—		85,311		(85,311)		1,246,490
General and administrative		80,130		—		34,010		(34,010)		80,130
Depletion, depreciation and amortization		341,783		—		63,975		(63,975)		341,783
Impairment of oil and gas properties		45,825		—		—		—		45,825
Other		144,151		230,194		6,552		(6,552)		374,345
Total operating expenses		1,901,412		230,194		189,848		(189,848)		2,131,606
Operating income (loss)	$	911,925		(55,006)		257,550		(257,550)		856,919
Equity in earnings of unconsolidated affiliates	$	39,891		—		46,056		(46,056)		39,891
Capital expenditures for segment assets	$	476,740		—		162,034		(162,034)		476,740

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

The summarized assets of the Company’s reportable segments are as follows (in thousands):


	As of December 31, 2021
							Elimination of
					Equity Method		Intersegment
	Exploration				Investment in		Transactions and
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream		Affiliates		Total
Investments in unconsolidated affiliates	$	232,399		—		696,009		(696,009)		232,399
Total assets	$	13,864,402		32,126		5,544,001		(5,544,001)		13,896,528

(Unaudited)

As of June 30, 2022

Elimination of

Equity Method

Intersegment

Exploration

Investment in

Transactions and

and

Antero

Unconsolidated

Consolidated

Production

Marketing

Midstream

Affiliates

Total

Investments in unconsolidated affiliates

229,095

—

681,560

(681,560)

229,095

Total assets

14,156,611

56,089

5,585,501

(5,585,501)

14,212,700

(17) Subsidiary Guarantors

Antero Resources’ senior notes are fully and unconditionally guaranteed by Antero Resources’ existing subsidiaries that guarantee the Credit Facility. 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 tables set forth below present summarized financial information of Antero, as parent, and its guarantor subsidiaries (in thousands). The Company’s wholly owned subsidiaries are not restricted from making distributions to the Company.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements


Balance Sheet
			(Unaudited)
	December 31, 2021		June 30, 2022
Accounts receivable, non-guarantor subsidiaries	$	—		—
Accounts receivable, related parties		—		—
Other current assets		633,014		946,631
Total current assets		633,014		946,631
Noncurrent assets		12,480,350		12,498,696
Total assets	$	13,113,364		13,445,327

Accounts payable, non-guarantor subsidiaries	$	—		—
Accounts payable, related parties		76,240		72,871
Other current liabilities		1,961,041		2,355,076
Total current liabilities		2,037,281		2,427,947
Noncurrent liabilities		5,737,999		5,428,228
Total liabilities	$	7,775,280		7,856,175

Statement of Operations

			Six Months Ended
			June 30, 2022
Revenues			$	2,937,693
Operating expenses				2,109,395
Income from operations				828,298
Net income and comprehensive income including noncontrolling interests				608,716
Net income and comprehensive income attributable to Antero Resources Corporation			$	608,716

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our unaudited condensed consolidated financial statements and related notes included elsewhere in this 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, 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 development, production, exploration and acquisition 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 develop 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 Appalachian Basin. As of June 30, 2022, we held approximately 503,000 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.

COVID-19 Pandemic

Since the start of the COVID-19 pandemic, governments have tried to slow the spread of the virus by imposing social distancing guidelines, travel restrictions and stay-at-home orders, among other actions, which caused a significant decrease in activity in the global economy and the demand for oil and to a lesser extent natural gas and NGLs. As vaccines have become widely available, social distancing guidelines, travel restrictions and stay-at-home orders have eased, activity in the global economy has increased and demand for oil, natural gas and NGLs and related commodity pricing, has improved. However, new variants of the virus could cause further commodity market volatility and resulting financial market instability, and these are variables beyond our control that may adversely impact our generation of funds from operating cash flows, distributions from unconsolidated affiliate, available borrowings under our Credit Facility (defined below in “—Capital Resources and Liquidity—Sources and Uses of Cash”) and our ability to access the capital markets.

We have continued to operate throughout the pandemic, in some cases subject to federal, state and local regulations, and we are taking steps to protect the health and safety of our workers. We have implemented protocols to reduce the risk of an outbreak within our field operations, and these protocols have not reduced our production and throughput in a significant manner. A substantial portion of our non-field level employees currently operate in a hybrid working arrangement that involves a combination of in-office and remote work-from-home arrangements. 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. We continue to monitor the COVID-19 environment in order to protect the health and safety of our employees and contract workers.

Our supply chain has not experienced any significant interruptions as a result of the COVID-19 pandemic. 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

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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 limited or constrained. 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. As a result of the pandemic, we have expanded our customer base and our condensate storage capacity within the Appalachian Basin.

Our natural gas, NGLs and oil producing properties are located in the liquids-rich Appalachian Basin. We maintain a hedging program designed to mitigate volatility in commodity prices and to protect certain of our expected future cash flows for our future operations and capital spending plans. All of our hedges are financial hedges and do not have physical delivery requirements. As such, any decreases in anticipated production, such as a result of decreased development activity, would not impact our ability to realize the benefits of or reduce the obligations for our hedges. For the year ending December 31, 2022, we have hedged through fixed price contracts the sale of 203 Bcf of natural gas at a weighted average price of $2.48 per MMBtu and basis swaps for 11 Bcf with a weighted average pricing differential of $0.515 per MMBtu.

In addition, our borrowing capacity is directly impacted by the amount of financial assurance that 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 provided has not increased during the COVID-19 pandemic and as of June 30, 2022, our outstanding letters of credit decreased by $26 million since December 31, 2021. Therefore, 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.

As of June 30, 2022, we had $71 million of borrowings under our Credit Facility (defined below in “—Capital Resources and Liquidity—Sources and Uses of Cash”) and had outstanding letters of credit of $505 million. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements and “—Capital Resources and Liquidity—Debt Agreements.” Since the onset of the COVID-19 pandemic, we have timely serviced our debt and other obligations.

The global economy continues to be impacted by the effects of the COVID-19 pandemic and global events, among other factors. Employment activity has strengthened as demonstrated by the United States Bureau of Labor and Statistics (“BLS”) unemployment rate declining from a high of 15% in April 2020 to 4% in June 2022. However, the economy is also experiencing elevated inflation levels as a result of global supply and demand imbalances. For example, the BLS Consumer Price Index (“CPI”) for all urban consumers increased 9% from June 2021 to June 2022 as compared to the average annual increase of 3% over the previous 10 years. Inflationary pressures, particularly as they relate to certain of our long-term contracts with CPI-based adjustments, and labor shortages could result in increases to our operating and capital costs that are not fixed, renegotiation of contracts and/or supply agreements and higher labor costs, among others. These economic variables are beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows. For example, we announced a 7% increase to our drilling and completion capital budget, which primarily reflects higher diesel and steel costs and development optimization through the retention of preferred crews through 2022. See “—Capital Resources and Liquidity—2022 Capital Budget and Capital Spending” for more information.

Financing Highlights

Debt Repurchase Program

During the six months ended June 30, 2022, we fully redeemed the remaining $585 million of our outstanding 5.00% senior notes due March 1, 2025 (the “2025 Notes”) at a redemption price of 101.25% of the principal amount thereof, plus accrued and unpaid interest. Additionally, we repurchased on the open market (i) $13 million of our 8.375% senior notes due July 15, 2026 (the “2026 Notes”) and (ii) $50 million of our 7.625% senior notes due February 1, 2029 (the “2029 Notes”). See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information.

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Share Repurchase Program

On February 15, 2022, our Board of Directors authorized a share repurchase program that allows us to repurchase up to $1.0 billion of outstanding common stock. The shares may be repurchased from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws. The timing, as well as the number and value of shares repurchased under the program, will be determined by us at our discretion and will depend on a variety of factors, including the market price of our common stock, general market and economic conditions and applicable legal requirements. During the three and six months ended June 30, 2022, we repurchased approximately 5 million shares at a total cost of $193 million and approximately 9 million shares of our common stock at a total cost of $293 million, respectively.

2026 Convertible Notes Conversion

On June 29, 2022, a noteholder elected to convert $4 million in aggregate principal amount of the 4.25% convertible senior notes due 2026 (“2026 Convertible Notes”) pursuant to their terms. We elected to settle this conversion by issuing approximately 1 million shares of common stock to the noteholder. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information.

Hedge Position (Excluding Martica)

We are exposed to certain risks relating to our ongoing business operations, and we use derivative instruments to manage our commodity price risk. In addition, we periodically enter into contracts that contain embedded features that are required to be bifurcated and accounted for separately as derivatives. The table below excludes derivative instruments attributable to Martica, our consolidated variable interest entity (“VIE”), since all gains or losses from such contracts are fully attributable to the noncontrolling interests in Martica. As of June 30, 2022, our fixed price natural gas, oil and NGL swap positions excluding Martica were as follows:


				Weighted
				Average
Commodity / Settlement Period	Index	Contracted Volume		Price
Natural Gas
July-December 2022	Henry Hub	203	Bcf	$	2.48	/MMBtu
January-December 2023	Henry Hub	16	Bcf		2.37	/MMBtu
		219	Bcf		2.48	/MMBtu

In addition, we have a swaption agreement, which entitles the counterparty the right, but not the obligation, to enter into a fixed price swap agreement for approximately 156 Bcf at a price of $2.77 per MMBtu for the year ending December 31, 2024.

As of June 30, 2022, our 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 Average
Commodity / Settlement Period	Index to Basis Differential	Contracted Volume		Hedged Differential
Natural Gas
July-December 2022	NYMEX to TCO	12	Bcf	$	0.515	/MMBtu
January-December 2023	NYMEX to TCO	18	Bcf		0.525	/MMBtu
January-December 2024	NYMEX to TCO	18	Bcf		0.530	/MMBtu
		48	Bcf		0.525	/MMBtu

As of June 30, 2022, we also had an embedded put option tied to NYMEX pricing for the production volumes associated with our retained interest in the VPP (as defined below) properties of 78 Bcf remaining through December 31, 2026 at a weighted average strike price of $2.55 per MMBtu.

We maintain a hedging program designed to mitigate volatility in commodity prices and to protect certain of our expected future cash flows for our future operations and capital spending plans. As of June 30, 2022, the estimated fair value of our commodity derivative contracts, excluding Martica, was a net liability of $1.1 billion. See Note 11—Derivative Instruments to the unaudited condensed consolidated financial statements for more information.

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Results of Operations

We have three operating segments: (i) the exploration, development and production of natural gas, NGLs and oil; (ii) marketing and utilization of excess firm transportation capacity; and (iii) midstream services through our equity method investment in Antero Midstream. Revenues from Antero Midstream’s operations were primarily derived from intersegment transactions for services provided to our exploration and production operations by Antero Midstream. All intersegment transactions were eliminated upon consolidation, including revenues from water handling and treatment services provided by Antero Midstream, which we capitalized as proved property development costs. 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. See Note 16—Reportable Segments to the unaudited condensed consolidated financial statements.

Three Months Ended June 30, 2021 Compared to June 30, 2022

The operating results of our reportable segments were as follows (in thousands):


	Three Months Ended June 30, 2021
							Elimination of
					Equity Method		Intersegment
	Exploration				Investment in		Transactions and
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream		Affiliates		Total
Revenue and other:
Natural gas sales	$	626,520		—		—		—		626,520
Natural gas liquids sales		464,381		—		—		—		464,381
Oil sales		51,906		—		—		—		51,906
Commodity derivative fair value losses		(831,840)		—		—		—		(831,840)
Gathering, compression, water handling and treatment		—		—		250,455		(250,455)		—
Marketing		—		165,453		—		—		165,453
Amortization of deferred revenue, VPP		11,279		—		—		—		11,279
Other loss		(619)		—		(17,668)		17,668		(619)
Total revenue	$	321,627		165,453		232,787		(232,787)		487,080

Operating expenses:
Lease operating	$	21,645		—		—		—		21,645
Gathering and compression		224,073		—		39,555		(39,555)		224,073
Processing		209,627		—		—		—		209,627
Transportation		207,662		—		—		—		207,662
Production and ad valorem taxes		33,694		—		—		—		33,694
Marketing		—		198,994		—		—		198,994
Exploration		5,638		—		—		—		5,638
General and administrative (excluding equity-based compensation)		27,928		—		11,192		(11,192)		27,928
Equity-based compensation		4,249		—		3,059		(3,059)		4,249
Depletion, depreciation and amortization		187,330		—		26,619		(26,619)		187,330
Impairment of oil and gas properties		9,303		—		—		—		9,303
Accretion of asset retirement obligations		1,331		—		114		(114)		1,331
Contract termination and other expenses		844		—		849		(849)		844
Gain on sale of assets		(2,288)		—		—		—		(2,288)
Total operating expenses		931,036		198,994		81,388		(81,388)		1,130,030
Operating income (loss)	$	(609,409)		(33,541)		151,399		(151,399)		(642,950)

Equity in earnings of unconsolidated affiliates	$	17,477		—		21,515		(21,515)		17,477

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	Three Months Ended June 30, 2022
							Elimination of
					Equity Method		Intersegment
	Exploration				Investment in		Transactions and
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream		Affiliates		Total
Revenue and other:
Natural gas sales	$	1,558,994		—		—		—		1,558,994
Natural gas liquids sales		702,388		—		—		—		702,388
Oil sales		89,185		—		—		—		89,185
Commodity derivative fair value losses		(265,662)		—		—		—		(265,662)
Gathering, compression, water handling and treatment		—		—		246,575		(246,575)		—
Marketing		—		106,150		—		—		106,150
Amortization of deferred revenue, VPP		9,375		—		—		—		9,375
Other income (loss)		1,255		—		(17,668)		17,668		1,255
Total revenue	$	2,095,535		106,150		228,907		(228,907)		2,201,685

Operating expenses:
Lease operating	$	25,253		—		—		—		25,253
Gathering and compression		223,650		—		43,299		(43,299)		223,650
Processing		219,100		—		—		—		219,100
Transportation		213,462		—		—		—		213,462
Production and ad valorem taxes		81,842		—		—		—		81,842
Marketing		—		131,298		—		—		131,298
Exploration and mine expenses		1,394		—		—		—		1,394
General and administrative (excluding equity-based compensation)		36,268		—		10,438		(10,438)		36,268
Equity-based compensation		8,171		—		5,641		(5,641)		8,171
Depletion, depreciation and amortization		173,395		—		35,675		(35,675)		173,395
Impairment of oil and gas properties		23,363		—		—		—		23,363
Impairment of midstream assets		—		—		3,702		(3,702)		—
Accretion of asset retirement obligations		804		—		64		(64)		804
Contract termination and other expenses		2,096		—		1,724		(1,724)		2,096
Loss (gain) on sale of assets		71		—		(32)		32		71
Total operating expenses		1,008,869		131,298		100,511		(100,511)		1,140,167
Operating income (loss)	$	1,086,666		(25,148)		128,396		(128,396)		1,061,518

Equity in earnings of unconsolidated affiliates	$	14,713		—		22,824		(22,824)		14,713

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Exploration and Production Segment

The following table sets forth selected operating data of the exploration and production segment:


	Three Months Ended				Amount of
	June 30,				Increase		Percent
	2021		2022		(Decrease)		Change
Production data ^{(1) (2)}:
Natural gas (Bcf)		208		203		(5)	(2)	%
C2 Ethane (MBbl)		4,356		4,025		(331)	(8)	%
C3+ NGLs (MBbl)		10,440		10,156		(284)	(3)	%
Oil (MBbl)		940		906		(34)	(4)	%
Combined (Bcfe)		303		294		(9)	(3)	%
Daily combined production (MMcfe/d)		3,324		3,228		(96)	(3)	%
Average prices before effects of derivative settlements ⁽³⁾:
Natural gas (per Mcf)	$	3.01		7.67		4.66	155	%
C2 Ethane (per Bbl)	$	9.97		22.42		12.45	125	%
C3+ NGLs (per Bbl)	$	40.32		60.28		19.96	50	%
Oil (per Bbl)	$	55.22		98.49		43.27	78	%
Weighted Average Combined (per Mcfe)	$	3.78		8.00		4.22	112	%
Average realized prices after effects of derivative settlements⁽³⁾:
Natural gas (per Mcf)	$	2.91		4.94		2.03	70	%
C2 Ethane (per Bbl)	$	9.97		22.42		12.45	125	%
C3+ NGLs (per Bbl)	$	35.95		59.84		23.89	66	%
Oil (per Bbl)	$	52.05		97.73		45.68	88	%
Weighted Average Combined (per Mcfe)	$	3.55		6.10		2.55	72	%
Average costs (per Mcfe):
Lease operating	$	0.07		0.09		0.02	29	%
Gathering and compression	$	0.74		0.76		0.02	3	%
Processing	$	0.69		0.75		0.06	9	%
Transportation	$	0.69		0.73		0.04	6	%
Production and ad valorem taxes	$	0.11		0.28		0.17	155	%
Marketing (revenue) expense, net	$	0.11		0.09		(0.02)	(18)	%
Depletion, depreciation, amortization and accretion	$	0.62		0.59		(0.03)	(5)	%
General and administrative (excluding equity-based compensation)	$	0.09		0.12		0.03	33	%

*	Not meaningful.

(1)	Production data excludes volumes related to the volumetric production payment transaction (the “VPP”).

(2)	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 may not reflect their relative economic value.

(3)

Average prices reflect 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.

Natural gas sales. Revenues from sales of natural gas increased from $627 million for the three months ended June 30, 2021 to $1.6 billion for the three months ended June 30, 2022, an increase of $932 million, or 149%. Higher commodity prices (excluding the effects of derivative settlements) during the three months ended June 30, 2022 accounted for an approximate $947 million increase in year-over-year natural gas sales revenue (calculated as the change in the year-to-year average price times current year production volumes). Lower natural gas production volumes accounted for an approximate $15 million decrease in year-over-year natural gas sales revenue (calculated as the change in year-to-year volumes times the prior year average price).

NGLs sales. Revenues from sales of NGLs increased from $464 million for the three months ended June 30, 2021 to $702 million for the three months ended June 30, 2022, an increase of $238 million, or 51%. Higher commodity prices (excluding the effects of derivative settlements) during the three months ended June 30, 2022 accounted for an approximate $253 million increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). Lower NGLs production volumes accounted for an approximate $15 million decrease in year-over-year NGL revenues (calculated as the change in year-to-year volumes times the prior year average price).

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Oil sales. Revenues from sales of oil increased from $52 million for the three months ended June 30, 2021 to $89 million for the three months ended June 30, 2022, an increase of $37 million, or 72%. Higher oil prices, excluding the effects of derivative settlements, accounted for an approximate $39 million increase in year-over-year oil revenues (calculated as the change in the year-to-year average price times current year production volumes). Lower oil production volumes during the three months ended June 30, 2022 accounted for an approximate $2 million decrease in year-over-year oil revenues (calculated as the change in year-to-year volumes times the prior year average price).

Commodity derivative fair value losses. To achieve more predictable cash flows, and to reduce our exposure to price fluctuations, we enter into fixed for variable price swap contracts, swaptions, basis swap contracts and collar contracts when we believe that favorable future sales prices for our production can be secured. Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment. Consequently, all mark-to-market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our statements of operations. For the three months ended June 30, 2021 and 2022, our commodity hedges resulted in derivative fair value losses of $832 million and $266 million, respectively. For the three months ended June 30, 2021, commodity derivative fair value losses included $70 million of cash payments for settled commodity derivatives as well as $5 million for payments on derivative monetizations. For the three months ended June 30, 2022, commodity derivative fair value losses included $559 million of cash payments for settled commodity derivatives.

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. Amortization of deferred revenues associated with the VPP decreased from $11 million for the three months ended June 30, 2021 to $9 million for the three months ended June 30, 2022, a decrease of $2 million, or 17%, primarily due to a decrease in production volumes. Under the terms of the agreement, the production volumes are delivered at approximately $1.61 per MMBtu over the contractual term.

Lease operating expense. Lease operating expense increased from $22 million for the three months ended June 30, 2021 to $25 million for the three months ended June 30, 2022, an increase of $3 million, or 17%, primarily due to higher oilfield service costs and water disposal costs, partially offset by lower production volumes between periods. On a per-unit basis, lease operating expenses increased from $0.07 per Mcfe for the three months ended June 30, 2021 to $0.09 per Mcfe for the three months ended June 30, 2022, primarily due to higher oilfield service costs and water disposal costs.

Gathering, compression, processing and transportation expense. Gathering, compression, processing and transportation expense increased from $641 million for the three months ended June 30, 2021 to $656 million for the three months ended June 30, 2022, an increase of $15 million, or 2%, primarily a result of higher processing and transportation costs, partially offset by lower production between periods. Gathering and compression costs increased from $0.74 per Mcfe for the three months ended June 30, 2021 to $0.76 per Mcfe for the three months ended June 30, 2022, primarily due to annual CPI-based adjustments between periods, partially offset by $12 million in incentive fee rebates earned from Antero Midstream during the three months ended June 30, 2022 that were not earned during the three months ended June 30, 2021. Processing costs increased from $0.69 per Mcfe for the three months ended June 30, 2021 to $0.75 per Mcfe for the three months ended June 30, 2022, primarily due to increased costs for ethane transportation as well as increased processing fees as a result of an annual CPI-based adjustment during the first quarter of 2022. Transportation costs increased from $0.69 per Mcfe for the three months ended June 30, 2021 to $0.73 per Mcfe for the three months ended June 30, 2022 primarily due to higher fuel costs between periods.

Production and ad valorem tax expense. Total production and ad valorem taxes increased from $34 million for the three months ended June 30, 2021 to $82 million for the three months ended June 30, 2022, an increase of $48 million, or 143%, primarily due to higher commodity prices between periods. On a per Mcfe basis, production and ad valorem taxes increased from $0.11 per Mcfe for the three months ended June 30, 2021 to $0.28 per Mcfe for the three months ended June 30, 2022. Production and ad valorem taxes as a percentage of natural gas revenues remained consistent at 5% for each of the three months ended June 30, 2021 and 2022.

General and administrative expense. General and administrative expense (excluding equity-based compensation expense) increased from $28 million for the three months ended June 30, 2021 to $36 million for the three months ended June 30, 2022, an increase of $8 million, or 30%, primarily due to higher salary and wage expense, professional service fees and office operating costs between periods. On a per-unit basis, general and administrative expense excluding equity-based compensation increased from $0.09

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per Mcfe for the three months ended June 30, 2021 to $0.12 per Mcfe for the three months ended June 30, 2022, primarily due to higher overall general and administrative expense and lower production volumes between periods.

Equity-based compensation expense. Noncash equity-based compensation expense increased from $4 million for the three months ended June 30, 2021 to $8 million for the three months ended June 30, 2022, an increase of $4 million, or 92%, primarily due to an increase in the annual equity awards granted during the second quarter of 2022 as compared to prior years, partially offset by equity award forfeitures. When an equity award is forfeited, expense previously recognized for the award is reversed. See Note 9—Equity Based Compensation and Cash Awards to the unaudited condensed consolidated financial statements for more information.

Depletion, depreciation, and amortization expense. Depletion, depreciation and amortization (“DD&A”) expense decreased from $187 million for the three months ended June 30, 2021 to $173 million for the three months ended June 30, 2022, a decrease of $14 million, or 7%, primarily as a result of increased proved reserve volumes due to higher commodity prices as well as lower production volumes between periods. DD&A expense decreased from $0.62 per Mcfe for the three months ended June 30, 2021 to $0.59 per Mcfe June 30, 2022, primarily as a result of increased proved reserve volumes between periods.

Impairment of oil and gas properties. Impairment of oil and gas properties increased from $9 million for the three months ended June 30, 2021 to $23 million for the three months ended June 30, 2022, an increase of $14 million, or 151%, primarily related to higher impairments of expiring leases between periods. During both periods, we recognized impairments primarily related to expiring leases and initial costs related to pads we no longer plan to place into service.

Marketing Segment

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

Net marketing expense decreased from $34 million, or $0.11 per Mcfe, for the three months ended June 30, 2021 to $25 million, or $0.09 per Mcfe, for the three months ended June 30, 2022, primarily due to lower volumes partially offset by higher gas marketing margins between periods.

Marketing revenue. Marketing revenue decreased from $165 million for the three months ended June 30, 2021 to $106 million for the three months ended June 30, 2022, a decrease of $59 million, or 36%, primarily due to lower marketing volumes between periods, partially offset by increased commodity prices between periods. Lower natural gas marketing volumes accounted for a $285 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and higher natural gas prices accounted for an approximate $205 million increase in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes). Higher oil marketing volumes accounted for a $3 million increase in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and higher oil prices accounted for an approximate $8 million increase in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes). Lower ethane marketing volumes accounted for a $2 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and higher ethane prices accounted for an approximate $12 million increase in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes).

Marketing expense. Marketing expense decreased from $199 million for the three months ended June 30, 2021 to $131 million for the three months ended June 30, 2022, a decrease of $68 million, or 34%. Marketing expense includes the cost of third-party purchased natural gas, NGLs and oil as well as firm transportation costs, including costs related to current excess firm capacity. The cost of third-party natural gas decreased approximately $67 million, which was partially offset by increased NGL and oil purchases of approximately $9 million and $10 million, respectively, between periods. The total costs decreased primarily due to lower marketing volumes between periods, partially offset by increased commodity prices. Firm transportation costs were $55 million for the three months ended June 30, 2021 and $35 million for the three months ended June 30, 2022, a decrease of $20 million due to the reduction in firm transportation commitments and third-party marketed volumes between periods.

Antero Midstream Segment

Antero Midstream revenue. Revenue from the Antero Midstream segment decreased from $233 million for the three months ended June 30, 2021 to $229 million for the three months ended June 30, 2022, a decrease of $4 million, primarily due to a decrease in low pressure revenues due to higher fee rebates earned by us, partially offset by higher compression and high pressure gathering

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revenues due to increased throughput between periods, as well as higher low pressure, compression, high pressure and water handling fees as a result of an annual CPI-based adjustment.

Antero Midstream operating expense. Total operating expense related to the Antero Midstream segment increased from $81 million for the three months ended June 30, 2021 to $101 million for the three months ended June 30, 2022, an increase of $20 million, primarily due to an increase in depreciation expense during the three months ended June 30, 2022. This increase is primarily a result of a phased early retirement of an underutilized compressor station, which allows Antero Midstream to relocate and reuse the compressor units and equipment to (i) expand an existing compressor station and (ii) contribute to a new compressor station. There are certain costs associated with the underutilized compressor station that cannot be relocated or reused that will be depreciated over the remaining period of use. Additionally, operating expenses were higher between periods due to increased direct operating costs as a result of higher gathering throughput volumes and two new compressor stations that came online between periods.

Discussion of Items Not Allocated to Segments

Interest expense. Interest expense decreased from $50 million for the three months ended June 30, 2021 to $34 million for the three months ended June 30, 2022, a decrease of $16 million, or 32%, primarily due to the reduction in debt as a result of the repurchase of certain of our unsecured senior notes between periods. Interest expense includes approximately $3 million and $1 million of amortization of debt issuance costs and debt discounts and premiums for the three months ended June 30, 2021 and 2022, respectively.

Loss on early extinguishment of debt. During the three months ended June 30, 2021, we equitized $56 million aggregate principal amount of our 2026 Convertible Notes and as a result, we recognized a loss of $21 million, which represents the difference between the fair value of the liability component of the 2026 Convertible Notes and the carrying value of such notes. Additionally, during the three months ended June 30, 2021, we redeemed the remaining balance of $574 million of our 5.625% senior notes due June 1, 2023 (the “2023 Notes”) at par, plus accrued and unpaid interest, and recognized a $2 million loss on early extinguishment of debt. During the three months ended June 30, 2022, we repurchased $50 million of our 2029 Notes and $13 million of our 2026 Notes, which resulted in a loss on early debt extinguishment of $4 million. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information.

Loss on convertible note equitization. During the three months ended June 30, 2021, we recognized a loss of $12 million for the equitization of our 2026 Convertible Notes, which represents the consideration paid in excess of the original terms of the 2026 Convertible Notes. There were no equitization transactions during the three months ended June 30, 2022. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information.

Income tax benefit (expense). For the three months ended June 30, 2021, we had an income tax benefit of $176 million, with an effective tax rate of 25%, due to a loss before income taxes of $710 million. For the three months ended June 30, 2022, we had income tax expense of $226 million, with an effective tax rate of 22%, due to income before income taxes of $1.0 billion. The decrease in the effective tax rate between periods was primarily due to an income tax benefit for the equity-based awards that vested during the three months ended June 30, 2022 and the impact of tax law changes in West Virginia enacted in 2021.

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Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2022

The operating results of our reportable segments were as follows for the six months ended June 30, 2021 and 2022 (in thousands):


	Six Months Ended June 30, 2021
					Equity Method		Elimination of
					Investment in		Intersegment
	Exploration				Antero		Transactions and
	and				Midstream		Unconsolidated		Consolidated
	Production		Marketing		Corporation		Affiliates		Total
Revenue and other:
Natural gas sales	$	1,346,889		—		—		—		1,346,889
Natural gas liquids sales		904,700		—		—		—		904,700
Oil sales		96,592		—		—		—		96,592
Commodity derivative fair value losses		(1,009,596)		—		—		—		(1,009,596)
Gathering, compression, water handling and treatment		—		—		492,244		(492,244)		—
Marketing		—		330,243		—		—		330,243
Amortization of deferred revenue, VPP		22,429		—		—		—		22,429
Other income (loss)		21		—		(35,336)		35,336		21
Total revenue		1,361,035		330,243		456,908		(456,908)		1,691,278

Operating expenses:
Lease operating		46,192		—		—		—		46,192
Gathering and compression		444,361		—		78,869		(78,869)		444,361
Processing		393,947		—		—		—		393,947
Transportation		408,131		—		—		—		408,131
Production and ad valorem taxes		78,391		—		—		—		78,391
Marketing		—		361,071		—		—		361,071
Exploration		5,857		—		—		—		5,857
General and administrative (excluding equity-based compensation)		66,360		—		25,110		(25,110)		66,360
Equity-based compensation		9,891		—		7,071		(7,071)		9,891
Depletion, depreciation and amortization		381,356		—		53,469		(53,469)		381,356
Impairment of oil and gas properties		43,365		—		—		—		43,365
Impairment of midstream assets		—		—		1,379		(1,379)		—
Accretion of asset retirement obligations		2,119		—		233		(233)		2,119
Contract termination and other expenses		935		—		2,163		(2,163)		935
Loss (gain) on sale of assets		(2,288)		—		3,628		(3,628)		(2,288)
Total operating expenses		1,878,617		361,071		171,922		(171,922)		2,239,688
Operating income (loss)	$	(517,582)		(30,828)		284,986		(284,986)		(548,410)

Equity in earnings of unconsolidated affiliates	$	36,171		—		42,259		(42,259)		36,171

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	Six Months Ended June 30, 2022
							Elimination of
					Equity Method		Intersegment
	Exploration				Investment in		Transactions and
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream		Affiliates		Total
Revenue and other:
Natural gas sales	$	2,554,786		—		—		—		2,554,786
Natural gas liquids sales		1,362,693		—		—		—		1,362,693
Oil sales		152,479		—		—		—		152,479
Commodity derivative fair value losses		(1,277,042)		—		—		—		(1,277,042)
Gathering, compression, water handling and treatment		—		—		482,734		(482,734)		—
Marketing		—		175,188		—		—		175,188
Amortization of deferred revenue, VPP		18,647		—		—		—		18,647
Other income (loss)		1,774		—		(35,336)		35,336		1,774
Total revenue		2,813,337		175,188		447,398		(447,398)		2,988,525

Operating expenses:
Lease operating		43,033		—		—		—		43,033
Gathering and compression		425,112		—		85,311		(85,311)		425,112
Processing		409,701		—		—		—		409,701
Transportation		411,677		—		—		—		411,677
Production and ad valorem taxes		134,650		—		—		—		134,650
Marketing		—		230,194		—		—		230,194
Exploration and mine expenses		2,292		—		—		—		2,292
General and administrative (excluding equity-based compensation)		67,310		—		25,537		(25,537)		67,310
Equity-based compensation		12,820		—		8,473		(8,473)		12,820
Depletion, depreciation and amortization		341,783		—		63,975		(63,975)		341,783
Impairment of oil and gas properties		45,825		—		—		—		45,825
Impairment of midstream assets		—		—		3,702		(3,702)		—
Accretion of asset retirement obligations		3,248		—		128		(128)		3,248
Loss (gain) on sale of assets		1,857		—		(150)		150		1,857
Contract termination and other expenses		2,104		—		2,872		(2,872)		2,104
Total operating expenses		1,901,412		230,194		189,848		(189,848)		2,131,606
Operating income (loss)	$	911,925		(55,006)		257,550		(257,550)		856,919

Equity in earnings of unconsolidated affiliates	$	39,891		—		46,056		(46,056)		39,891

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Exploration and Production Segment

The following table sets forth selected operating data of the exploration and production segment for the six months ended June 30, 2021 compared to the six months ended June 30, 2022:


					Amount of
	Six Months Ended June 30,				Increase		Percent
	2021		2022		(Decrease)		Change
Production data ^{(1) (2)}:
Natural gas (Bcf)		415		402		(13)	(3)	%
C2 Ethane (MBbl)		8,761		8,030		(731)	(8)	%
C3+ NGLs (MBbl)		20,366		19,794		(572)	(3)	%
Oil (MBbl)		1,900		1,629		(271)	(14)	%
Combined (Bcfe)		601		579		(22)	(4)	%
Daily combined production (MMcfe/d)		3,323		3,197		(126)	(4)	%
Average prices before effects of derivative settlements⁽³⁾:
Natural gas (per Mcf) ⁽⁴⁾	$	3.24		6.36		3.12	96	%
C2 Ethane (per Bbl)	$	9.08		19.59		10.51	116	%
C3+ NGLs (per Bbl)	$	40.52		60.90		20.38	50	%
Oil (per Bbl)	$	50.84		93.59		42.75	84	%
Weighted Average Combined (per Mcfe)	$	3.90		7.03		3.13	80	%
Average realized prices after effects of derivative settlements⁽³⁾:
Natural gas (per Mcf)	$	3.23		4.28		1.05	33	%
C2 Ethane (per Bbl)	$	8.74		19.53		10.79	123	%
C3+ NGLs (per Bbl)	$	37.82		60.48		22.66	60	%
Oil (per Bbl)	$	48.90		92.86		43.96	90	%
Weighted Average Combined (per Mcfe)	$	3.80		5.57		1.77	47	%
Average costs (per Mcfe):
Lease operating	$	0.08		0.07		(0.01)	(13)	%
Gathering and compression	$	0.74		0.73		(0.01)	(1)	%
Processing	$	0.65		0.71		0.06	9	%
Transportation	$	0.68		0.71		0.03	4	%
Production and ad valorem taxes	$	0.13		0.23		0.10	77	%
Marketing expense, net	$	0.05		0.10		0.05	100	%
Depletion, depreciation, amortization and accretion	$	0.64		0.60		(0.04)	(6)	%
General and administrative (excluding equity-based compensation)	$	0.11		0.12		0.01	9	%

*	Not meaningful.

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

(2)	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 may not reflect their relative economic value.

(3)

(4)

The average realized price for the six months ended June 30, 2021 includes $85 million of net litigation proceeds related to a favorable litigation judgment. See Note 14—Contingencies to the unaudited condensed consolidated financial statements for further discussion on the litigation proceeds. Excluding the effect of the litigation proceeds received, the average realized price for natural gas would have been $3.04 per Mcf for the six months ended June 30, 2021.

Natural gas sales. Revenues from sales of natural gas increased from $1.3 billion for the six months ended June 30, 2021 to $2.6 billion, which included litigation proceeds of $85 million, for the six months ended June 30, 2022, an increase of $1.3 billion, or 90%. See Note 14—Contingencies to the unaudited condensed consolidated financial statements for more information on the litigation proceeds.

Excluding net litigation proceeds received during the six months ended June 30, 2021, higher commodity prices (excluding the effects of derivative settlements) during the six months ended June 30, 2022 accounted for an approximate $1.3 billion increase in year-over-year natural gas sales revenue (calculated as the change in the year-to-year average price excluding the net proceeds from the litigation times current year production volumes). Lower natural gas production volumes accounted for an approximate $44 million decrease in year-over-year natural gas sales revenue (calculated as the change in year-to-year volumes times the prior year average price excluding the net proceeds from the litigation). See Note 14—Contingencies to the unaudited condensed consolidated financial statements for further discussion on the litigation proceeds.

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NGLs sales. Revenues from sales of NGLs increased from $905 million for the six months ended June 30, 2021 to $1.4 billion for the six months ended June 30, 2022, an increase of $458 million, or 51%. Higher commodity prices (excluding the effects of derivative settlements) during the six months ended June 30, 2022 accounted for an approximate $488 million increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). Lower NGLs production volumes accounted for an approximate $30 million decrease in year-over-year NGL revenues (calculated as the change in year-to-year volumes times the prior year average price).

Oil sales. Revenues from sales of oil increased from $97 million for the six months ended June 30, 2021 to $152 million for the six months ended June 30, 2022, an increase of $55 million, or 58%. Higher oil prices, excluding the effects of derivative settlements, accounted for an approximate $69 million increase in year-over-year oil revenues (calculated as the change in the year-to-year average price times current year production volumes). Lower oil production volumes during the six months ended June 30, 2022 accounted for an approximate $14 million decrease in year-over-year oil revenues (calculated as the change in year-to-year volumes times the prior year average price).

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, swaptions, basis swap contracts and collar contracts when we believe that favorable future sales prices for our production can be secured. Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment. Consequently, all mark-to-market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our statements of operations. For the six months ended June 30, 2021, our commodity hedges resulted in derivative fair value losses of $1.0 billion. For the six months ended June 30, 2022, our commodity hedges resulted in derivative fair value losses of $1.3 billion. Commodity derivative fair value losses included $65 million of cash payments on commodity derivative losses as well as $5 million for payments on derivative monetizations gains on settled derivatives for the six months ended June 30, 2021. For the six months ended June 30, 2022, commodity derivative fair value losses included $845 million of cash payments on commodity derivative losses.

Amortization of deferred revenue, VPP. Amortization of deferred revenues associated with the VPP decreased from $22 million for the six months ended June 30, 2021 to $19 million for the six months ended June 30, 2022, a decrease of $3 million or 17%, primarily due to a decrease in production volumes. Under the terms of the agreement, the production volumes are delivered at approximately $1.61 per MMBtu over the contractual term.

Lease operating expense. Lease operating expense decreased from $46 million for the six months ended June 30, 2021 to $43 million for the six months ended June 30, 2022, a decrease of $3 million, or 7%, primarily due to lower production volumes and water disposal costs. On a per-unit basis, lease operating expenses decreased from $0.08 per Mcfe for the six months ended June 30, 2021 to $0.07 per Mcfe for the six months ended June 30, 2022 primarily due to lower water disposal costs, partially offset by higher workover costs.

Gathering, compression, processing and transportation expense. Gathering, compression, processing and transportation expense remained consistent at $1.2 billion for both the six months ended June 30, 2021 and 2022. Gathering and compression costs decreased from $0.74 per Mcfe for the six months ended June 30, 2021 to $0.73 per Mcfe for the six months ended June 30, 2022, primarily due to $24 million in incentive fee rebates earned from Antero Midstream during the six months ended June 30, 2022 that were not earned during the six months ended June 30, 2021. Processing costs increased from $0.65 per Mcfe for the six months ended June 30, 2021 to $0.71 per Mcfe for the six months ended June 30, 2022, primarily due to increased costs for ethane transportation as well as increased processing fees as a result of an annual CPI-based adjustment during the first quarter of 2022. Transportation costs increased from $0.68 per Mcfe for the six months ended June 30, 2021 to $0.71 per Mcfe for the six months ended June 30, 2022 primarily due to higher fuel costs between periods.

Production and ad valorem tax expense. Production and ad valorem taxes increased from $78 million for the six months ended June 30, 2021 to $135 million for the six months ended June 30, 2022, an increase of $57 million, or 72%, primarily due to higher commodity prices between periods partially offset by $5 million for the litigation judgment in 2021. Production and ad valorem taxes as a percentage of natural gas revenues remained relatively consistent at 6% and 5% for the six months ended June 30, 2021 and 2022, respectively.

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General and administrative expense. General and administrative expense (excluding equity-based compensation expense) remained relatively consistent at $66 million and $67 million for the six months ended June 30, 2021 and 2022, respectively. The slight increase in expense between periods is primarily due to higher professional service fees and office operating costs, partially offset by lower salary and wage expense. On a per-unit basis, general and administrative expense excluding equity-based compensation increased from $0.11 per Mcfe during the six months ended June 30, 2021 to $0.12 per Mcfe during the six months ended June 30, 2022 as a result of lower production volumes and higher overall costs between periods.

Equity-based compensation expense. Noncash equity-based compensation expense increased from $10 million for the six months ended June 30, 2021 to $13 million for the six months ended June 30, 2022, an increase of $3 million, or 30%, primarily due to an increase in the annual equity awards granted during the second quarter of 2022 as compared to prior years, partially offset by equity award forfeitures. When an equity award is forfeited, expense previously recognized for the award is reversed. See Note 9—Equity Based Compensation and Cash Awards to the unaudited condensed consolidated financial statements for more information on equity-based compensation awards.

Depletion, depreciation, and amortization expense. DD&A expense decreased from $381 million for the six months ended June 30, 2021 to $342 million for the six months ended June 30, 2022, a decrease of $39 million, or 10%, primarily as a result of increased proved reserve volumes due to higher commodity prices as well as lower production volumes between periods. DD&A expense per Mcfe decreased from $0.64 per Mcfe for the six months ended June 30, 2021 to $0.60 per Mcfe for the six months ended June 30, 2022, primarily as a result of increased proved reserve volumes between periods.

Impairment of oil and gas properties. Impairment of oil and gas properties increased from $43 million for the six months ended June 30, 2021 to $46 million for the six months ended June 30, 2022, an increase of $3 million, or 6%, primarily related to higher impairments of expiring leases between periods. During both periods, we recognized impairments primarily related to expiring leases as well as design and initial costs related to pads we no longer plan to place into service.

Marketing Segment

Net marketing expense increased from $31 million, or $0.05 per Mcfe, for the six months ended June 30, 2021 to $55 million, or $0.10 per Mcfe, for the six months ended June 30, 2022, primarily due to lower volumes partially offset by higher gas marketing margins between periods.

Marketing revenue. Marketing revenue decreased from $330 million for the six months ended June 30, 2021 to $175 million for the six months ended June 30, 2022, a decrease of $155 million, or 47%, primarily due to lower marketing volumes between periods, partially offset by increased commodity prices between periods. Lower natural gas marketing volumes accounted for a $865 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and higher natural gas prices accounted for an approximate $685 million increase in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes). Higher oil marketing volumes accounted for a $7 million increase in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and higher oil prices accounted for an approximate $13 million increase in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes). Lower ethane marketing volumes accounted for a $43 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and higher ethane prices accounted for an approximate $54 million increase in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes).

Marketing expense. Marketing expense decreased from $361 million for the six months ended June 30, 2021 to $230 million for the six months ended June 30, 2022, a decrease of $131 million, or 36%. Marketing expense includes the cost of third-party purchased natural gas, NGLs and oil as well as firm transportation costs, including costs related to current excess firm capacity. The cost of third-party natural gas decreased approximately $121 million, which was partially offset by increased oil and NGL purchases of approximately $18 million and $9 million, respectively, between periods. The total costs decreased primarily due to decreased marketing volumes between periods, partially offset by increased commodity prices. Firm transportation costs were $110 million for the six months ended June 30, 2021 and $73 million for the six months ended June 30, 2022, a decrease of $37 million due to the reduction in firm transportation commitments and third-party marketed volumes between periods.

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Equity Method Investment in Antero Midstream

Antero Midstream revenue. Revenue from the Antero Midstream segment decreased from $457 million for the six months ended June 30, 2021 to $447 million for the six months ended June 30, 2022, a decrease of $10 million, primarily due to a decrease in low pressure revenues due to higher fee rebates earned by us and lower fresh water delivery revenue as a result of decreased well completions period-over-period, partially offset by higher compression and high pressure gathering revenues due to increased throughput between periods as well as higher low pressure, compression and high pressure fees as a result of an annual CPI-based adjustment.

Antero Midstream operating expense. Total operating expense related to the Antero Midstream segment increased from $172 million for the six months ended June 30, 2021 to $190 million for the six months ended June 30, 2022, an increase of $18 million, primarily due to an increase in depreciation expense during the six months ended June 30, 2022. This increase is primarily a result of a phased early retirement of an underutilized compressor station, which allows Antero Midstream to relocate and reuse the compressor units and equipment to (i) expand an existing compressor station and (ii) contribute to a new compressor station. There are certain costs associated with the underutilized compressor station that cannot be relocated or reused that will be depreciated over the remaining period of use. Additionally, operating expenses were higher between periods due to increased direct operating costs as a result of higher gathering throughput volumes, two new compressor stations and resuming fresh water deliveries to us in the Utica Shale.

Items Not Allocated to Segments

Interest expense. Interest expense decreased from $93 million for the six months ended June 30, 2021 to $72 million for the six months ended June 30, 2022, a decrease of $21 million or 22%, primarily due to the reduction in debt as a result of the repurchase of certain of our unsecured senior notes between periods.

Loss on early extinguishment of debt. During the six months ended June 30, 2021, we equitized $206 million aggregate principal amount of our 2026 Convertible Notes in privately negotiated exchange transactions and as a result, we recognized a loss of $61 million, which represents the difference between the fair value of the liability component of the 2026 Convertible Notes and the carrying value of such notes. Additionally, during the six months ended June 30, 2021, we redeemed the remaining balance of $661 million of our 5.125% senior notes due 2022 (“2022 Notes”) at par, plus accrued and unpaid interest and the remaining balance of $574 million of our 2023 Notes at par, plus accrued and unpaid interest, and recognized a $5 million loss on early extinguishment of debt. During the six months ended June 30, 2022, we (i) redeemed the remaining $585 million aggregate principal amount of our 2025 Notes at a redemption price of 101.25% of par, plus accrued and unpaid interest and (ii) repurchased $50 million of our 2029 Notes and $13 million of our 2026 Notes, which resulted in a loss on early debt extinguishment of $15 million. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information.

Loss on convertible note equitization. During the six months ended June 30, 2021, we recognized a loss of $51 million for the equitization of our 2026 Convertible Notes, which represents the consideration paid in excess of the original terms of the 2026 Convertible Notes. There were no equitization transactions during the six months ended June 30, 2022. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information.

Income tax benefit (expense). For the six months ended June 30, 2021, we had an income tax benefit of $179 million, with an effective tax rate of 25%, due to a loss before income taxes of $724 million. For the six months ended June 30, 2022, we had income tax expense of $172 million, with an effective tax rate of 21%, due to income before income taxes of $810 million. The decrease in the effective tax rate between periods was primarily due to an income tax benefit for the equity-based awards that vested during the six months ended June 30, 2022, partially offset by a higher amount of taxable income being apportioned to West Virginia.

Capital Resources and Liquidity

Sources and Uses of Cash

Our primary sources of liquidity have been through net cash provided by operating activities, borrowings under our senior secured revolving credit facility (the “Credit Facility”), issuances of debt and equity securities and additional contributions from our asset sales program, including our drilling partnership. 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

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operating activities and the capital resources available to us. For information about the impacts of COVID-19 on our capital resources and liquidity, see “—COVID-19 Pandemic.”

Based on strip prices as of June 30, 2022, we believe that net cash provided by operating activities, distributions from our unconsolidated affiliate and available borrowings under the Credit Facility 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.

Cash Flows

The following table summarizes our cash flows (in thousands):


	Six Months Ended June 30,
	2021		2022
Net cash provided by operating activities	$	872,272		1,488,385
Net cash used in investing activities		(302,878)		(474,834)
Net cash used in financing activities		(564,853)		(1,013,551)
Net increase in cash and cash equivalents	$	4,541		—

Operating Activities. Net cash provided by operating activities was $872 million and $1.5 billion for the six months ended June 30, 2021 and 2022, respectively. Net cash provided by operating activities increased primarily due to increases in commodity prices both before and after the effects of settled commodity derivatives, partially offset by decreased production and increased (i) cash utilized for working capital, (ii) net marketing expense and (iii) production and ad valorem taxes between periods.

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 reduced global demand for natural gas, NGLs and oil. These factors are beyond our control and are difficult to predict.

Investing Activities. Net cash used in investing activities increased from $303 million for the six months ended June 30, 2021 to $475 million for the six months ended June 30, 2022, primarily due to an increase in capital expenditures of $171 million between periods.

Financing Activities. Net cash flows used in financing activities increased from $565 million for the six months ended June 30, 2021 to $1.0 billion for the six months ended June 30, 2022. During the six months ended June 30, 2021, we issued $500 million aggregate principal amount of 2026 Notes, $700 million aggregate principal amount of 2029 Notes and $600 million aggregate principal amount of 5.375% senior notes due March 1, 2030 (net of $22 million of aggregate debt issuance costs), of which proceeds were used to (i) redeem $661 million aggregate principal amount of our 2022 Notes, which were fully retired, (ii) redeem $574 million of our 2023 Notes, which were fully retired and (iii) partially repay borrowings on the Credit Facility. Also, during the six months ended June 30, 2021, we completed two equitization transactions and used the proceeds and approximately $89 million of borrowings under the Credit Facility to repurchase $206 million aggregate principal amount of the 2026 Convertible Notes in privately negotiated transactions. Additionally, during the six months ended June 30, 2021, we received a $51 million payment from Martica and distributed $46 million to the noncontrolling interest in Martica. During the six months ended June 30, 2022, we (i) redeemed $585 million aggregate principal amount of our 2025 Notes and repurchased $13 million of our 2026 Notes and $50 million of our 2029 Notes (ii) repurchased approximately 9 million shares of our common stock at a total cost of approximately $293 million, (iii) distributed $67 million to the noncontrolling interest in Martica and (iv) paid $65 million in employee withholding taxes for vested equity-based awards. Additionally, we borrowed $71 million, net, on our Credit Facility during the six months ended June 30, 2022.

2022 Capital Budget and Capital Spending

On July 27, 2022, we announced a revised net capital budget for 2022 of $825 million to $860 million. Our revised budget includes: a range of $725 million to $750 million for drilling and completion and a range of $100 million to $110 million for leasehold expenditures. We do not budget for acquisitions. During 2022, we plan to complete 60 to 65 net horizontal wells in the Appalachian Basin. We periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, drilling results, leasehold acquisition opportunities and commodity prices.

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For the three months ended June 30, 2022, our total consolidated capital expenditures were approximately $268 million, including drilling and completion costs of $217 million, leasehold acquisitions of $49 million, and other capital expenditures of $2 million. For the six months ended June 30, 2022, our total consolidated capital expenditures were approximately $474 million, including drilling and completion costs of $392 million, leasehold acquisitions of $73 million, and other capital expenditures of $9 million.

Debt Agreements

See Note 7—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 2021 Form 10-K for information on our senior notes.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our unaudited condensed consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our unaudited condensed consolidated 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 unaudited condensed 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 measure 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 2021 Form 10-K. We believe these accounting policies reflect our more significant estimates and assumptions used in the preparation of our unaudited condensed consolidated financial statements. Also, see Note 2—Summary of Significant Accounting Policies to the consolidated financial statements, included in the 2021 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.

Based on future prices as of June 30, 2022, 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 three and six months ended June 30, 2021 and 2022.

Estimated undiscounted future net cash flows are sensitive to commodity price swings and a 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 from June 30, 2022, 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

See Note 2—Summary of Significant Accounting Policies to the unaudited condensed consolidated financial statements for information on new accounting pronouncements.

Off-Balance Sheet Arrangements

See Note 13—Commitments to the unaudited condensed consolidated financial statements for further information on off balance sheet arrangements.

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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 June 30, 2022, our commodity derivatives included fixed price swaps and basis differential swaps at index-based pricing.

As of June 30, 2022, we had in place natural gas swaps covering portions of our projected production through 2023. Our commodity hedge position as of June 30, 2022 is summarized in Note 11—Derivative Instruments to our unaudited condensed consolidated financial statements. 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 six months ended June 30, 2022, our revenues would have decreased by approximately $47 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 June 30, 2022.

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 impacted when the associated derivative contracts are settled or monetized by making or receiving payments to or from the counterparty. As of June 30, 2022, the estimated fair value of our commodity derivative instruments was a net liability of $1.2 billion comprised of current and noncurrent assets and liabilities. As of December 31, 2021, the estimated fair value of our commodity derivative instruments was a net liability of $727 million comprised of current and noncurrent assets and liabilities.

By removing price volatility from a portion of our expected production through December 2024, 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 ($8 million as of June 30, 2022); and the sale of our natural gas, NGLs and oil production ($896 million as of June 30, 2022), 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 10 different counterparties, 7 of which are lenders under our Credit Facility. As of June 30, 2022, we did not have any derivative assets by bank counterparties under our Credit Facility. 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 June 30, 2022 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 June 30, 2022, 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 for borrowings during the six months ended June 30, 2022 was approximately 4.52%. We estimate that a 1.0% increase in the applicable average interest rates for the six months ended June 30, 2022 would have resulted in an estimated $1.0 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 June 30, 2022 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 June 30, 2022 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1. Legal Proceedings

The information required by this item is included in Note 14—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 2021 Form 10-K. There have been no material changes to the risks described in such report. 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.

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
				as Part of	that May
	Total Number			Publicly	Yet be Purchased
	of Shares	Average Price		Announced	Under the Plan ⁽²⁾
Period	Purchased	Paid Per Share		Plans	($ in thousands)
April 1, 2022 - April 30, 2022 ⁽¹⁾	2,417,879	$	34.92	908,839	$	869,946
May 1, 2022 - May 31, 2022	2,206,199		35.81	2,206,199		790,948
June 1, 2022 - June 30, 2022	2,125,340		39.52	2,125,340		706,948
Total	6,749,418	$	36.66	5,240,378

(1)	The total number of shares purchased includes shares of our common stock transferred to us in order to satisfy tax withholding obligations incurred upon the vesting of restricted stock units and performance share units held by our employees.

(2)	On February 15, 2022, our Board of Directors authorized a share repurchase program that allows the Company to repurchase up to $1.0 billion of outstanding common stock.

Item 4. Mine Safety Disclosures

The required disclosure under Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 C.F.R Section 229.104) is included in Exhibit 95.1 to this Quarterly Report on Form 10-Q.

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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).
10.1*		Form of Performance Share Unit Grant Notice and Performance Share Unit Agreement under the Antero Resources Corporation 2020 Long-Term Incentive Plan.
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).
95.1*		Federal Mine Safety and Health Act Information.
101*		The following financial information from this Quarterly Report on Form 10-Q of Antero Resources Corporation for the quarter ended June 30, 2022 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations and Comprehensive Loss, (iii) Condensed Consolidated Statements of Equity, (iv) Condensed Consolidated Statements of Cash Flows, and (v) Notes to the Condensed Consolidated Financial Statements, tagged as blocks of text.
104		Cover Page Interactive Data File (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/ MICHAEL N. KENNEDY
	Michael N. Kennedy
	Chief Financial Officer and Senior Vice President–Finance

Date:	July 27, 2022

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Antero Resources (AR) 10-Q2022 Q2 Quarterly report

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