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~~2023


☐	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~~300,383,794 shares of common stock outstanding as of July ~~22, 2022.~~21, 2023.

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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~~return of capital program;

●

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

●

impacts of geopolitical events, including the Russia-Ukraine conflict, and world health ~~events, including the coronavirus (“COVID-19”) pandemic;~~events;

●

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”);~~costs;

●

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;~~Midstream Corporation (“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, supply chain or other disruption, availability and cost 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 geopolitical and 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~~2022 (the ~~“2021~~“2022 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)~~thousands, except per share amounts)

(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


			(Unaudited)
	December 31,		June 30,
	2022		2023
Assets
Current assets:
Accounts receivable	$	35,488		36,887
Accrued revenue		707,685		323,440
Derivative instruments		1,900		3,099
Prepaid expenses and other current assets		42,452		21,302
Total current assets		787,525		384,728
Property and equipment:
Oil and gas properties, at cost (successful efforts method):
Unproved properties		997,715		1,017,828
Proved properties		13,234,777		13,615,891
Gathering systems and facilities		5,802		5,802
Other property and equipment		83,909		91,255
		14,322,203		14,730,776
Less accumulated depletion, depreciation and amortization		(4,683,399)		(4,854,565)
Property and equipment, net		9,638,804		9,876,211
Operating leases right-of-use assets		3,444,331		3,262,253
Derivative instruments		9,844		7,934
Investment in unconsolidated affiliate		220,429		218,196
Other assets		17,106		17,488
Total assets	$	14,118,039		13,766,810
Liabilities and Equity
Current liabilities:
Accounts payable	$	77,543		60,911
Accounts payable, related parties		80,708		95,360
Accrued liabilities		461,788		366,038
Revenue distributions payable		468,210		359,487
Derivative instruments		97,765		35,509
Short-term lease liabilities		556,636		553,953
Deferred revenue, VPP		30,552		28,878
Other current liabilities		1,707		6,728
Total current liabilities		1,774,909		1,506,864
Long-term liabilities:
Long-term debt		1,183,476		1,492,270
Deferred income tax liability, net		759,861		792,149
Derivative instruments		345,280		59,224
Long-term lease liabilities		2,889,854		2,711,735
Deferred revenue, VPP		87,813		74,337
Other liabilities		59,692		61,903
Total liabilities		7,100,885		6,698,482
Commitments and contingencies
Equity:
Stockholders' equity:
Preferred stock, $0.01 par value; authorized - 50,000 shares; none issued		—		—
Common stock, $0.01 par value; authorized - 1,000,000 shares; 297,393 shares issued and 297,359 outstanding as of December 31, 2022, and 300,359 shares issued and outstanding as of June 30, 2023		2,974		3,004
Additional paid-in capital		5,838,848		5,803,634
Retained earnings		913,896		1,019,256
Treasury stock, at cost; 34 shares and zero shares as of December 31, 2022 and June 30, 2023, respectively		(1,160)		—
Total stockholders' equity		6,754,558		6,825,894
Noncontrolling interests		262,596		242,434
Total equity		7,017,154		7,068,328
Total liabilities and equity	$	14,118,039		13,766,810

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,				Three Months Ended June 30,
	2021		2022		2022		2023
Revenue and other:
Natural gas sales	$	626,520		1,558,994	$	1,558,994		437,130
Natural gas liquids sales		464,381		702,388		702,388		397,733
Oil sales		51,906		89,185		89,185		57,962
Commodity derivative fair value losses		(831,840)		(265,662)
Commodity derivative fair value gains (losses)						(265,662)		8,284
Marketing		165,453		106,150		106,150		43,793
Amortization of deferred revenue, VPP		11,279		9,375		9,375		7,618
Other income (loss)		(619)		1,255
Other revenue and income						1,255		785
Total revenue		487,080		2,201,685		2,201,685		953,305
Operating expenses:
Lease operating		21,645		25,253		25,253		28,748
Gathering, compression, processing and transportation		641,362		656,212		656,212		663,975
Production and ad valorem taxes		33,694		81,842		81,842		36,158
Marketing		198,994		131,298		131,298		66,175
Exploration and mine expenses		5,638		1,394		1,394		743
General and administrative (including equity-based compensation expense of $4,249 and $8,171 in 2021 and 2022, respectively)		32,177		44,439
General and administrative (including equity-based compensation expense of $8,171 and $13,512 in 2022 and 2023, respectively)						44,439		53,901
Depletion, depreciation and amortization		187,330		173,395		173,395		171,406
Impairment of oil and gas properties		9,303		23,363
Impairment of property and equipment						23,363		15,710
Accretion of asset retirement obligations		1,331		804		804		1,204
Contract termination		844		2,096		2,096		4,441
(Gain) loss on sale of assets		(2,288)		71
Loss (gain) on sale of assets						71		(220)
Total operating expenses		1,130,030		1,140,167		1,140,167		1,042,241
Operating income (loss)		(642,950)		1,061,518		1,061,518		(88,936)
Other income (expense):
Interest expense, net		(49,963)		(34,213)		(34,213)		(27,928)
Equity in earnings of unconsolidated affiliate		17,477		14,713		14,713		19,098
Loss on early extinguishment of debt		(23,065)		(4,414)		(4,414)		—
Loss on convertible note equitization		(11,731)		—
Transaction expense		(185)		—
Total other expense		(67,467)		(23,914)		(23,914)		(8,830)
Income (loss) before income taxes		(710,417)		1,037,604		1,037,604		(97,766)
Income tax benefit (expense)		175,966		(225,571)		(225,571)		29,833
Net income (loss) and comprehensive income (loss) including noncontrolling interests		(534,451)		812,033		812,033		(67,933)
Less: net income (loss) and comprehensive income (loss) attributable to noncontrolling interests		(10,984)		46,898
Less: net income and comprehensive income attributable to noncontrolling interests						46,898		15,151
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$	(523,467)		765,135	$	765,135		(83,084)

Income (loss) per share—basic	$	(1.70)		2.46	$	2.46		(0.28)
Income (loss) per share—diluted	$	(1.70)		2.29	$	2.29		(0.28)

Weighted average number of shares outstanding:
Basic		307,879		310,535		310,535		300,141
Diluted		307,879		334,561		334,561		300,141

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


	Six Months Ended June 30,
	2022		2023
Revenue and other:
Natural gas sales	$	2,554,786		1,105,445
Natural gas liquids sales		1,362,693		893,168
Oil sales		152,479		109,773
Commodity derivative fair value gains (losses)		(1,277,042)		134,476
Marketing		175,188		102,322
Amortization of deferred revenue, VPP		18,647		15,151
Other revenue and income		1,774		1,318
Total revenue		2,988,525		2,361,653
Operating expenses:
Lease operating		43,033		58,069
Gathering, compression, processing and transportation		1,246,490		1,309,147
Production and ad valorem taxes		134,650		85,434
Marketing		230,194		147,536
Exploration and mine expenses		2,292		1,506
General and administrative (including equity-based compensation expense of $12,820 and $26,530 in 2022 and 2023, respectively)		80,130		111,162
Depletion, depreciation and amortization		341,783		338,988
Impairment of property and equipment		45,825		31,270
Accretion of asset retirement obligations		3,248		2,082
Contract termination		2,104		33,991
Loss (gain) on sale of assets		1,857		(311)
Other operating expense		—		225
Total operating expenses		2,131,606		2,119,099
Operating income		856,919		242,554
Other income (expense):
Interest expense, net		(71,926)		(53,628)
Equity in earnings of unconsolidated affiliate		39,891		36,779
Loss on early extinguishment of debt		(15,068)		—
Loss on convertible note inducement		—		(86)
Total other expense		(47,103)		(16,935)
Income before income taxes		809,816		225,619
Income tax expense		(172,479)		(32,350)
Net income and comprehensive income including noncontrolling interests		637,337		193,269
Less: net income and comprehensive income attributable to noncontrolling interests		28,621		62,922
Net income and comprehensive income attributable to Antero Resources Corporation	$	608,716		130,347

Income per share—basic	$	1.95		0.44
Income per share—diluted	$	1.81		0.42

Weighted average number of shares outstanding:
Basic		312,300		298,461
Diluted		337,589		311,488

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		Retained Earnings
	Common Stock				Paid-in		(Accumulated		Treasury Stock				Noncontrolling		Total
	Shares		Amount		Capital		Deficit)		Shares		Amount		Interests		Equity
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 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


					Additional
	Common Stock				Paid-in		Retained		Treasury Stock				Noncontrolling		Total
	Shares		Amount		Capital		Earnings		Shares		Amount		Interests		Equity
Balances, December 31, 2022		297,393	$	2,974		5,838,848		913,896		(34)	$	(1,160)		262,596		7,017,154
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		514		5		(11,464)		—		—		—		—		(11,459)
Conversion of 2026 Convertible Notes		4,030		40		17,132		—								17,172
Repurchases and retirements of common stock		(2,616)		(26)		(51,503)		(24,987)		34		1,160		—		(75,356)
Equity-based compensation		—		—		13,018		—		—		—		—		13,018
Distributions to noncontrolling interests		—		—		—		—		—		—		(51,339)		(51,339)
Net income and comprehensive income		—		—		—		213,431		—		—		47,771		261,202
Balances, March 31, 2023		299,321		2,993		5,806,031		1,102,340		—		—		259,028		7,170,392
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		1,038		11		(15,909)		—		—		—		—		(15,898)
Equity-based compensation		—		—		13,512		—		—		—		—		13,512
Distributions to noncontrolling interests		—		—		—		—		—		—		(31,745)		(31,745)
Net income (loss) and comprehensive income (loss)		—		—		—		(83,084)		—		—		15,151		(67,933)
Balances, June 30, 2023		300,359	$	3,004		5,803,634		1,019,256		—	$	—		242,434		7,068,328

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,				Six Months Ended June 30,
	2021		2022		2022		2023
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:
Net income including noncontrolling interests					$	637,337		193,269
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion		383,475		345,031		345,031		341,070
Impairments		43,365		45,825		45,825		31,270
Commodity derivative fair value losses		1,009,596		1,277,042
Commodity derivative fair value losses (gains)						1,277,042		(134,476)
Losses on settled commodity derivatives		(64,951)		(844,713)		(844,713)		(10,787)
Payments for derivative monetizations		(4,569)		—		—		(202,339)
Deferred income tax expense (benefit)		(178,912)		171,707
Deferred income tax expense						171,707		32,288
Equity-based compensation expense		9,891		12,820		12,820		26,530
Equity in earnings of unconsolidated affiliate		(36,171)		(39,891)		(39,891)		(36,779)
Dividends of earnings from unconsolidated affiliate		74,040		62,569		62,569		62,569
Amortization of deferred revenue		(22,429)		(18,647)		(18,647)		(15,151)
Amortization of debt issuance costs, debt discount and debt premium		7,877		2,515		2,515		1,732
Settlement of asset retirement obligations		—		(886)		(886)		(633)
(Gain) loss on sale of assets		(2,288)		1,857
Loss (gain) on sale of assets						1,857		(311)
Loss on early extinguishment of debt		66,269		15,068		15,068		—
Loss on convertible note equitizations		50,777		—
Loss on convertible note inducement						—		86
Changes in current assets and liabilities:
Accounts receivable		(7,687)		53,623		53,623		(1,399)
Accrued revenue		(68,425)		(360,612)		(360,612)		384,245
Other current assets		631		(22,566)		(22,566)		21,294
Accounts payable including related parties		6,681		50,378		50,378		12,701
Accrued liabilities		64,499		37,203		37,203		(102,668)
Revenue distributions payable		69,809		40,166		40,166		(108,723)
Other current liabilities		16,349		22,559		22,559		5,377
Net cash provided by operating activities		872,272		1,488,385		1,488,385		499,165
Cash flows provided by (used in) investing activities:
Additions to unproved properties		(29,473)		(72,072)		(72,072)		(110,447)
Drilling and completion costs		(273,956)		(393,506)		(393,506)		(517,591)
Additions to other property and equipment		(2,320)		(11,162)		(11,162)		(9,058)
Proceeds from asset sales		2,351		195		195		311
Change in other assets		597		1,711		1,711		(1,255)
Change in other liabilities		(77)		—
Net cash used in investing activities		(302,878)		(474,834)		(474,834)		(638,040)
Cash flows provided by (used in) financing activities:
Repurchases of common stock		—		(293,051)		(293,051)		(75,356)
Issuance of senior notes		1,800,000		—
Repayment of senior notes		(1,234,698)		(658,906)		(658,906)		—
Borrowings (repayments) on bank credit facilities, net		(1,017,000)		70,800
Payment of debt issuance costs		(22,440)		—
Borrowings on bank credit facilities, net						70,800		325,100
Convertible note inducement						—		(86)
Distributions to noncontrolling interests in Martica Holdings LLC		(46,028)		(67,298)		(67,298)		(83,084)
Employee tax withholding for settlement of equity compensation awards		(9,530)		(64,819)		(64,819)		(27,357)
Convertible note equitizations		(85,648)		—
Other		(509)		(277)		(277)		(342)
Net cash used in financing activities		(564,853)		(1,013,551)
Net cash provided by (used in) financing activities						(1,013,551)		138,875
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	$	89,326		51,927
Increase (decrease) in accounts payable and accrued liabilities for additions to property and equipment	$	42,589		(3,504)
Decrease in accounts payable and accrued liabilities for additions to property and equipment					$	(3,504)		(8,353)

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~~2022 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~~2022 consolidated financial statements were included in Antero Resources’ ~~2021~~2022 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~~2022 and June 30, ~~2022,~~2023, results of operations for the three and six months ended June 30, ~~2021~~2022 and ~~2022~~2023 and cash flows for the six months ended June 30, ~~2021~~2022 and ~~2022.~~2023. 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~~2023 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 $6328 million and ~~$50~~$43 million, respectively. As of June 30, 2023, the book overdrafts included within accounts payable and revenue distributions payable were $33 million and $16 million, respectively.

(d)	~~Earnings~~Income (Loss) Per Common Share

~~Earnings~~Income (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~~Income (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

awards, performance share unit (“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~~income (loss) attributable to common stockholders for basic and diluted ~~earnings~~income (loss) per share (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,				Six Months Ended June 30,
	2021		2022		2021		2022		2022		2023		2022		2023
Net income (loss) attributable to Antero Resources Corporation—common shareholders	$	(523,467)		765,135		(538,966)		608,716	$	765,135		(83,084)		608,716		130,347
Add: Interest expense for 2026 Convertible Notes		—		967		—		1,934		967		—		1,934		1,085
Less: Tax-effect of interest expense for 2026 Convertible Notes		—		(224)		—		(449)		(224)		—		(449)		(233)
Net income (loss) attributable to Antero Resources Corporation—common shareholders and assumed conversions	$	(523,467)		765,878		(538,966)		610,201	$	765,878		(83,084)		610,201		131,199

Income (loss) per share—basic	$	(1.70)		2.46		(1.78)		1.95	$	2.46		(0.28)		1.95		0.44
Income (loss) per share—diluted	$	(1.70)		2.29		(1.78)		1.81	$	2.29		(0.28)		1.81		0.42

Weighted average common shares outstanding—basic		307,879		310,535		302,343		312,300		310,535		300,141		312,300		298,461
Weighted average common shares outstanding—diluted		307,879		334,561		302,343		337,589		334,561		300,141		337,589		311,488

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,		Three Months Ended June 30,		Six Months Ended June 30,
	2021	2022	2021	2022	2022	2023	2022	2023
Basic weighted average number of shares outstanding	307,879	310,535	302,343	312,300	310,535	300,141	312,300	298,461
Add: Dilutive effect of RSUs	—	3,161	—	3,629	3,161	—	3,629	1,593
Add: Dilutive effect of PSUs	—	2,108	—	2,892	2,108	—	2,892	967
Add: Dilutive effect of stock options	—	—	—	—
Add: Dilutive effect of 2026 Convertible Notes	—	18,757	—	18,768	18,757	—	18,768	10,467
Diluted weighted average number of shares outstanding	307,879	334,561	302,343	337,589	334,561	300,141	337,589	311,488

Weighted average number of outstanding securities excluded from calculation of diluted earnings per common share ⁽¹⁾:
Weighted average number of outstanding securities excluded from calculation of diluted income (loss) per common share ⁽¹⁾:
RSUs	6,642	—	6,767	—	—	4,070	—	2,260
PSUs	2,769	—	2,584	—	—	1,791	—	377
Stock options	380	351	404	351	351	324	351	324
2026 Convertible Notes	18,778	—	18,778	—	—	9,076	—	—

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

(e)	Recently Issued Accounting ~~Standards~~Standard

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~~require 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~~

Table of Contents

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

2021. The Company adopted 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~~prior to the ~~general principles in ASC 740,~~ ~~Income Taxes~~ ~~(“ASC 740”) and also simplifies portions~~adoption 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.~~new standard.

(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 ORRIs include an overriding royalty interest of 1.25% in all of the ~~transaction,~~Company’s operated proved developed properties in West Virginia and Ohio, subject to certain excluded wells (the “Initial PDP Override”) as of April 1, 2020, and an overriding royalty interest of 3.75% in all of the Company’s undeveloped properties in West Virginia and Ohio (the “Development Override”) as of April 1, 2020. Wells turned to sales after April 1, 2020 and prior to the later of (a) the date on which the Company ~~contributed~~turns to sales 2.2 million lateral feet (net to the Company’s interest) of horizontal wells burdened by the Development Override and (b) the earlier of (i) April 1, 2023 and (ii) the date on which the Company turns to sales 3.82 million lateral feet (net to the Company’s interest) of horizontal wells burdened by the Development Override, are subject to the Development Override. As of April 1, 2023, the Company had turned to sales over 2.2 million lateral feet and less than 3.82 million lateral feet. As a result, wells turned to sales on or after April 1, 2023 will not be subject to the ORRIs.

The ORRIs ~~to Martica and Sixth Street contributed~~ ~~$300 million in cash (subject to customary adjustments) and agreed to contribute up to~~also include an additional ~~$102~~overriding royalty interest of 2.00% ~~million~~of the Company’s working interest in ~~cash~~the properties underlying the Initial PDP Override (the “Incremental Override”). The Incremental Override (or a portion thereof, as applicable) may be re-conveyed to the Company (at the Company’s election) if certain production ~~thresholds~~targets attributable to the ORRIs are achieved inthrough March 31, 2023. Any portion of the ~~third quarter~~Incremental Override that may not be re-conveyed to the Company based on the Company failing to achieve such production volumes through March 31, 2023 will remain with Martica. As of ~~2020~~March 31, 2023, the portion of the Incremental Override that may be re-conveyed to the Company as a result of achieving certain production targets was 76% and ~~first quarter of 2021. All cash contributed by~~the portion that will remain with Martica was 24%.

Prior to Sixth Street atachieving an internal rate of return of 13% and 1.5x cash-on-cash return (the “Hurdle”), Sixth Street will receive all distributions in respect of the ~~initial closing~~Initial PDP Override and the Development Override, and 24% of all distributions in respect of the Incremental Override, and the Company will receive 76% of all distributions in respect of the Incremental Override. Following Sixth Street achieving the Hurdle, the Company will receive 85% of the distributions in respect of the ORRIs to which Sixth Street was ~~distributed~~entitled immediately prior 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.~~Hurdle being achieved.

(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, 2022 and ~~2022,~~2023, 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, 2022, and ~~2022~~2023 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% and 15% of development capital for wells spud in 2021 and 2022, respectively, and will fund development capital of (i) 15% for wells spud in ~~2022~~2023 and (ii) if they participate in 2024,

Table of Contents

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

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. During the year ended December 31, 2022, the Company received a carry of $29 million attributable to the 2021 tranche. 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~~

~~Table of Contents~~

~~ANTERO RESOURCES CORPORATION~~

~~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,Extractive Activities—Oil and Gas, and such conveyances are recorded in the unaudited condensed consolidated financial statements as QL obtains its proportionate working interest in each well. ~~NaN~~No gain or loss was recognized for the interests conveyed during the three and six months ended June 30, ~~2021~~2022 and ~~2022.~~2023.

(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,					Three Months Ended June 30,				Six Months Ended June 30,
	2021		2022		2021		2022		Reportable Segment	2022		2023		2022		2023		Reportable Segment
Revenues from contracts with customers:
Natural gas sales	$	626,520		1,558,994		1,346,889		2,554,786	Exploration and production	$	1,558,994		437,130		2,554,786		1,105,445	Exploration and production
Natural gas liquids sales (ethane)		43,417		90,230		79,527		157,293	Exploration and production		90,230		50,163		157,293		122,213	Exploration and production
Natural gas liquids sales (C3+ NGLs)		420,964		612,158		825,173		1,205,400	Exploration and production		612,158		347,570		1,205,400		770,955	Exploration and production
Oil sales		51,906		89,185		96,592		152,479	Exploration and production		89,185		57,962		152,479		109,773	Exploration and production
Marketing		165,453		106,150		330,243		175,188	Marketing		106,150		43,793		175,188		102,322	Marketing
Other revenue											—		365		—		540	Exploration and production
Total revenue from contracts with customers		1,308,260		2,456,717		2,678,424		4,245,146			2,456,717		936,983		4,245,146		2,211,248
Loss from derivatives, deferred revenue and other sources, net		(821,180)		(255,032)		(987,146)		(1,256,621)
Income (loss) from derivatives, deferred revenue and other sources, net											(255,032)		16,322		(1,256,621)		150,405
Total revenue	$	487,080		2,201,685		1,691,278		2,988,525		$	2,201,685		953,305		2,988,525		2,361,653

(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~~2022 and June 30, ~~2022,~~2023, the Company’s receivables from contracts with customers were $~~591~~708 million and ~~$952~~$323 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

(5) Equity Method Investment

(a)	Summary of Equity Method Investment

As of June 30, 2023, Antero owned 29.0% of Antero Midstream’s common stock, which is reflected in Antero’s unaudited condensed consolidated financial statements using the equity method of accounting.

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
Balance as of December 31, 2022 ⁽¹⁾			$	220,429
Equity in earnings of unconsolidated affiliate		39,891		36,779
Dividends from unconsolidated affiliate		(62,569)		(62,569)
Elimination of intercompany profit		19,374		23,557
Balance as of June 30, 2022 ⁽¹⁾	$	229,095
Balance as of June 30, 2023 ⁽¹⁾			$	218,196

(1)	The fair value of the Company’s investment in Antero Midstream as of December 31, ~~2021~~2022 and June 30, ~~2022~~2023 was ~~$1.3~~$1.5 billion and $1.6 billion, respectively, 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)				(Unaudited)
	December 31,		June 30,		December 31,		June 30,
	2021		2022		2022		2023
Capital expenditures	$	46,983		45,767	$	57,361		51,364
Gathering, compression, processing and transportation expenses		164,900		168,756		162,783		159,685
Marketing expenses		50,589		64,753		61,118		30,823
Interest expense, net		65,093		45,714		31,892		32,454
Production and ad valorem taxes		44,298		47,001		32,536		55,073
General and administrative expense		27,740		24,699		32,477		24,558
Derivative settlements payable		35,202		79,269		53,732		183
Other		22,439		20,718		29,889		11,898
Total accrued liabilities	$	457,244		496,677	$	461,788		366,038

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~~ANTERO RESOURCES CORPORATION~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

(7) Long-Term Debt

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


			(Unaudited)				(Unaudited)
	December 31,		June 30,		December 31,		June 30,
	2021		2022		2022		2023
Credit Facility ^(a)	$	—		70,800	$	34,800		359,900
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
8.375% senior notes due 2026 ^(c)						96,870		96,870
7.625% senior notes due 2029 ^(d)						407,115		407,115
5.375% senior notes due 2030 ^(e)						600,000		600,000
4.25% convertible senior notes due 2026 ^(f)						56,932		39,426
Total principal		2,175,205		1,594,137		1,195,717		1,503,311
Unamortized discount, net		(27,772)		—
Unamortized debt issuance costs		(21,989)		(16,924)		(12,241)		(11,041)
Long-term debt	$	2,125,444		1,577,213	$	1,183,476		1,492,270

(a)	Senior Secured Revolving Credit Facility

Antero Resources has a senior secured revolving credit facility (the “Credit Facility”) with a consortium of ~~bank lenders. On October 26, 2021,~~banks. Borrowings under the Credit Facility are subject to borrowing base limitations based on the collateral value of Antero ~~Resources entered into an amended~~Resources’ assets and ~~restated senior secured revolving credit facility (the “Credit Facility”).~~are subject to regular semi-annual redeterminations. As of December 31, ~~2021~~2022 and June 30, ~~2022,~~2023, the Credit Facility had a borrowing base of $3.5 billion and lender commitments of $1.5 billion. The borrowing base was ~~re-affirmed~~re-

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

affirmed in the semi-annual redetermination in April ~~2022.~~2023. 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,~~2023, the Credit Facility had an available borrowing capacity of $~~924~~638 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~~2022 and June 30, ~~2022.~~2023.

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$35 million, with a weighted average interest rate of ~~3.95%~~6.42%, and ~~had~~ outstanding letters of credit of ~~$505~~$504 million. As of June 30, 2023, Antero Resources had an outstanding balance under the Credit Facility of $360 million, with a weighted average interest rate of 7.44%, and outstanding letters of credit of $502 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~~

~~Table of Contents~~

~~ANTERO RESOURCES CORPORATION~~

~~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, and the 2025 Notes were fully retired as of March 1, 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)~~(c)

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 or otherwise repurchased $~~175~~403 million ~~of the 2026 Notes on July 1, 2021 and repurchased $13 million~~principal amount of the 2026 Notes during ~~the second quarter of~~2021 and 2022, and as of June 30, ~~2022, $312~~2023, $97 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)~~(d)

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 or otherwise repurchased $~~116~~293 million principal amount 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~~2023, $407 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

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

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.

~~Table of Contents~~

~~ANTERO RESOURCES CORPORATION~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

~~(g)~~(e)

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)~~(f)

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,~~Proceeds from the ~~Company completed~~issuance of the ~~equitization transactions described below under “—Partial Equitizations of~~ 2026 Convertible Notes~~” that~~ totaled $278.5 million, net of initial purchasers’ fees and issuance cost of $9 million. The Company extinguished $206 million principal amount of the 2026 Convertible ~~Notes. On June 29,~~Notes in 2021. In addition, between 2022 ~~a noteholder elected to convert~~and the second quarter of 2023, $443 million in aggregate principal amount of the 2026 Convertible Notes were converted pursuant to their ~~terms. The Company elected to settle this~~terms or induced into conversion by ~~issuing approximately~~ 1 ~~million shares of common stock to~~ the ~~noteholder.~~Company. See “—Conversions and Inducements,” for more information. As of June 30, ~~2022,~~2023, $7839 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,~~2023, the if-converted value of the 2026 Convertible Notes was $~~547~~209 million, which exceeded the principal amount of the 2026 Convertible Notes by ~~$470~~$170 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

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

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 5five consecutive Business Days immediately after any 10 consecutive ~~trading day~~Trading Day period (such 10 consecutive Trading Day period, the “Measurement Period”) if the ~~trading~~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~~Trading Day of the Measurement Period was less than 98% of the product of the ~~last reported sale price~~Last Reported Sales Price per share of common stock on such ~~trading day~~Trading Day and the conversion rate on such ~~trading day;~~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~~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.

~~Table of Contents~~

~~ANTERO RESOURCES CORPORATION~~

~~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~~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.~~2023.

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.~~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~~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~~Conversions and Inducements

During the first quarter 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~~2023, $9 million aggregate principal amount of the 2026 Convertible Notes ~~in privately negotiated transactions (the “May Convertible Note Repurchase,”~~were converted pursuant to their terms, 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~~additional $9 million aggregate 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~~were induced into conversion by the Company. The Company elected to settle these conversions by issuing 4 million shares of common stock to the noteholders together with a ~~result,~~cash inducement premium of $0.1 million. There were no conversions of the ~~Company recorded a~~ ~~$12~~ ~~million loss on convertible note equitization in the unaudited condensed consolidated statements of operations and comprehensive loss for~~2026 Convertible Notes during the second quarter of ~~2021 for~~2023 or the ~~consideration paid in excess~~first or second quarters of ~~the original terms of the 2026 Convertible Notes. Additionally, the May Equitization Transactions resulted in a loss on early extinguishment of debt of~~ 2022.~~$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.


			(Unaudited)
	December 31,		June 30,
	2022		2023
Principal	$	56,932		39,426
Less: unamortized debt issuance costs		(1,159)		(702)
Net carrying value	$	55,773		38,724

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$1 million and $1$0.5 million for the three months ended June 30, ~~2021~~2022 and ~~2022,~~2023, respectively, and $7$2 million and $2$1 million for the six months ended June 30, ~~2021~~2022 and ~~2022,~~2023, respectively.

~~(i)~~(g)

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~~$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.

There were

~~Table~~no debt repurchases or redemptions during the first or second quarters of ~~Contents~~2023.

~~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
Asset retirement obligations—December 31, 2022			$	59,485
Obligations incurred		1,427		561
Accretion expense		3,248		2,082
Settlement of obligations		(886)		(633)
Obligations on sold properties		(42)
Revisions to prior estimates		(1,512)		301
Asset retirement obligations—June 30, 2022	$	56,187
Asset retirement obligations—June 30, 2023			$	61,796

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

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

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~~6,835,261 shares were available for future grant under the 2020 Plan as of June 30, ~~2022.~~2023.

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 Corporation Long Term Incentive Plan (the “AM Plan”). Each RSU award under the AM Plan ~~represents~~represented a right to receive 1one share of Antero Midstream common stock.

~~Table~~ As of ~~Contents~~June 30, 2023, all Converted AM RSU Awards were fully vested.

~~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,				Three Months Ended June 30,				Six Months Ended June 30,
	2021		2022		2021		2022		2022		2023		2022		2023
RSU awards	$	3,392		4,774		6,630		7,494	$	4,774		8,720		7,494		15,982
PSU awards		223		3,012		1,759		4,431		3,012		4,442		4,431		9,847
Converted AM RSU Awards ⁽¹⁾		284		35		802		195		35		—		195		1
Equity awards issued to directors		350		350		700		700		350		350		700		700
Total expense	$	4,249		8,171		9,891		12,820	$	8,171		13,512		12,820		26,530

(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. As of June 30, 2023, all Converted AM RSU Awards were fully vested, and there is no remaining unamortized expense attributable to these awards.

(a)	Restricted Stock Unit Awards

A summary of RSU ~~award~~ activity is as follows:


		Weighted			Weighted
		Average			Average
	Number of	Grant Date		Number of	Grant Date
	Shares	Fair Value		Shares	Fair Value
Total awarded and unvested—December 31, 2021	5,930,607	$	5.15
Total awarded and unvested—December 31, 2022				4,676,219	$	15.29
Granted	975,471		35.06	1,458,594		25.87
Vested	(2,544,921)		4.75	(2,202,895)		9.02
Forfeited	(28,441)		9.97	(69,321)		22.57
Total awarded and unvested—June 30, 2022	4,332,716	$	12.09
Total awarded and unvested—June 30, 2023				3,862,597	$	22.74

As of June 30, ~~2022,~~2023, there was ~~approximately $47~~$76 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~~ 2.3 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,~~March 2023, the Company granted PSU awards to certain of its senior management and executive officers that vest based on Antero Resources’ absolute ~~TSR~~total shareholder return (“TSR”) determined as of the last day of each of 3three one-year performance periods ending on ~~April 15, 2023, April 15,~~March 7, 2024, ~~and April 15,~~March 7, 2025 and 1March 7, 2026, and one cumulative three-year performance period ending on ~~April 15, 2025,~~March 7, 2026, in each case, subject to certain continued employment criteria (“~~2022~~2023 Absolute TSR PSUs”).

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

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~~2023 Absolute TSR PSUs ranges from 0zero to 200% of the target number of ~~2022~~2023 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.

~~Table of Contents~~

~~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~~2023 Absolute TSR PSUs:


Dividend yield		—	%		—	%
Volatility		88	%		82	%
Risk-free interest rate		2.65	%		4.61	%
Weighted average fair value of awards granted—Absolute TSR	$	47.53		$	33.96

Performance Share Unit Awards Based on Leverage Ratio

In ~~April 2022,~~March 2023, 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(as defined in the award ~~agreement~~)agreement) determined as of the last day of each of 3three one-year performance periods ending on December 31, ~~2022,~~2023, December 31, ~~2023~~2024 and December 31, ~~2024,~~2025, in each case, subject to certain continued employment criteria (“2023 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 2023 Leverage Ratio PSUs ranges from zero to 200% of the target number of 2023 Leverage Ratio PSUs originally granted. Expense related to the 2023 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,~~2023, the likelihood of achieving the performance conditions related to the 2023 Leverage Ratio PSUs was probable.

Summary Information for Performance Share Unit Awards

A summary of PSU ~~award~~ activity is as follows:


		Weighted			Weighted
	Number of	Average Grant			Average
	Units	Date Fair Value		Number of	Grant Date
Total awarded and unvested—December 31, 2021	1,847,279	$	8.31
				Units	Fair Value
Total awarded and unvested—December 31, 2022				1,329,725	$	23.18
Granted	436,537		29.98	417,466		28.51
Vested	(1,210,712)		9.26
Forfeited	—		—
Cancelled (unearned)	—		—
Total awarded and unvested—June 30, 2022	1,073,104	$	12.09
Vested ⁽¹⁾				(335,000)		2.97
Total awarded and unvested—June 30, 2023				1,412,191	$	29.54

(1)	During the three months ended June 30, 2023, the PSUs granted in 2020 that were based on absolute TSR and relative TSR met the performance criteria to achieve vesting at 112% and 126% of target, respectively, and converted into approximately 0.4 million shares of the Company’s common stock.

As of June 30, ~~2022,~~2023, there was ~~approximately $15~~$29 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~~1.7 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.~~

2119

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

~~(d)~~(c)

~~Stock Options~~Converted AM RSU Awards

A summary of ~~stock option activity~~the Converted AM RSU Awards 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)~~


		Weighted
		Average
	Number of	Grant Date
	Units	Fair Value
Total awarded and unvested—December 31, 2022	2,827	$	12.38
Vested	(2,827)		12.38
Total awarded and unvested—June 30, 2023	—	$	—

~~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,~~2023, all ~~stock options~~Converted AM RSU Awards were fully vested resulting in 0no unamortized equity-based compensation expense.

~~(e)~~(d)

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 iswas recognized ratably over the vesting period for each of 3three 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~~2022 and June 30, ~~2022,~~2023, the Company has recorded ~~approximately~~ $21 million and $1$0.4 million, respectively, in ~~Other~~Accrued 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~~2022 and June 30, ~~2022~~2023 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~~2022 and June 30, ~~2022~~2023 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)								(Unaudited)
	December 31, 2021				June 30, 2022				December 31, 2022				June 30, 2023
	Fair		Carrying		Fair		Carrying		Fair		Carrying		Fair		Carrying
	Value ⁽¹⁾		Value ⁽²⁾		Value ⁽¹⁾		Value ⁽²⁾		Value ⁽¹⁾		Value ⁽²⁾		Value ⁽¹⁾		Value ⁽²⁾
2025 Notes	$	594,866		581,117		—		—
2026 Notes		370,013		321,738		329,693		308,977	$	100,987		96,123		100,076		96,235
2029 Notes		654,080		577,149		543,345		528,078		410,860		402,872		412,204		403,151
2030 Notes		641,400		593,234		545,940		593,567		556,260		593,908		548,220		594,260
2026 Convertible Notes		331,655		52,206		548,940		75,791		406,039		55,773		208,414		38,724
Total	$	2,592,014		2,125,444		1,967,918		1,506,413	$	1,474,146		1,148,676		1,268,914		1,132,370

(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.

~~Table of Contents~~

~~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~~may use 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.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(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~~2022 and ~~2022.~~2023. 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. Under these basis swap agreements, when actual commodity prices upon settlement exceed the fixed price provided by the swap contracts, the Company receives the difference from the counterparty. When actual commodity prices upon settlement are less than the contractually provided fixed price, the Company pays the difference to the counterparty.

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,~~2023, 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

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

July-December 2023

Henry Hub

43,000

MMBtu/day

2.37

/MMBtu

~~In addition, the~~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

~~Table of Contents~~

~~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~~call option and 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.~~volumetric production payment transaction (“VPP”) properties. The put option was embedded within another contract, and since the embedded put option iswas not clearly and closely related to ~~the~~its host contract, ~~and therefore,~~ the Company bifurcated this derivative instrument and reflects it at fair value in the unaudited condensed consolidated financial statements. As of June 30, 2023, the Company’s call option and embedded put option arrangements were as follows:

Embedded

Call Option

Put Option

Commodity / Settlement Period

Index

Contracted Volume

Strike Price

Natural Gas

July-December 2023

Henry Hub

55,000

MMBtu/day

2.466

/MMBtu

2.466

/MMBtu

January-December 2024

Henry Hub

53,000

MMBtu/day

2.477

/MMBtu

2.527

/MMBtu

January-December 2025

Henry Hub

44,000

MMBtu/day

2.564

/MMBtu

2.614

/MMBtu

January-December 2026

Henry Hub

32,000

MMBtu/day

2.629

/MMBtu

2.679

/MMBtu

2421

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

As of June 30, 2023, 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 2023	NYMEX to TCO	50,000	MMBtu/day	$	0.525	/MMBtu
January-December 2024	NYMEX to TCO	50,000	MMBtu/day		0.530	/MMBtu

As of June 30, 2023, 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 2023	Henry Hub	32,496	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

Natural Gasoline
July-December 2023	Mont Belvieu Natural Gasoline-OPIS Non-TET	227	Bbl/day		40.74	/Bbl

Oil
July-December 2023	West Texas Intermediate	77	Bbl/day		44.72	/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

~~(c)~~(b)

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)					(Unaudited)
	Balance Sheet	December 31,		June 30,		Balance Sheet	December 31,		June 30,
	Location	2021		2022		Location	2022		2023
Asset derivatives not designated as hedges for accounting purposes:
Commodity derivatives—current	Derivative instruments	$	—		—
Embedded derivatives—current	Derivative instruments		757		578	Derivative instruments		1,900		3,099
Commodity derivatives—noncurrent	Derivative instruments		—		—
Embedded derivatives—noncurrent	Derivative instruments		14,369		7,058	Derivative instruments		9,844		7,934

Total asset derivatives ⁽¹⁾			15,126		7,636			11,744		11,033

Liability derivatives not designated as hedges for accounting purposes:
Commodity derivatives—current ⁽²⁾	Derivative instruments		559,851		773,357	Derivative instruments		97,765		35,509
Commodity derivatives—noncurrent ⁽²⁾	Derivative instruments		181,806		393,139	Derivative instruments		345,280		59,224

Total liability derivatives ⁽¹⁾			741,657		1,166,496			443,045		94,733

Net derivatives liability ⁽¹⁾		$	(726,531)		(1,158,860)		$	(431,301)		(83,700)

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

(2)

As of December 31, ~~2021, approximately $55~~2022, $47 million of commodity derivative liabilities, including ~~$31~~$28 million of current commodity derivatives and ~~$24~~$19 million of noncurrent commodity derivatives, are attributable to the Company’s consolidated VIE, Martica. As of June 30, ~~2022, approximately~~2023, $8817 million of commodity derivative liabilities, including ~~$53~~$10 million of current commodity derivatives and ~~$35~~$7 million of noncurrent commodity derivatives, are attributable to the Company’s consolidated VIE, Martica.

Table of Contents

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

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)												(Unaudited)
	December 31, 2021						June 30, 2022						December 31, 2022						June 30, 2023
					Net Amounts of						Net Amounts of						Net Amounts of						Net Amounts of
	Gross		Gross		Assets		Gross		Gross		Assets		Gross		Gross		Assets		Gross		Gross		Assets
	Amounts		Amounts Offset		(Liabilities) on		Amounts		Amounts Offset		(Liabilities) on		Amounts		Amounts Offset		(Liabilities) on		Amounts		Amounts Offset		(Liabilities) on
	Recognized		Recognized		Balance Sheet		Recognized		Recognized		Balance Sheet		Recognized		Recognized		Balance Sheet		Recognized		Recognized		Balance Sheet
Commodity derivative assets	$	2,177		(2,177)		—		4		(4)		—	$	276		(276)		—	$	422		(422)		—
Embedded derivative assets	$	15,126		—		15,126		7,636		—		7,636		11,744		—		11,744		11,033		—		11,033
Commodity derivative liabilities	$	(743,834)		2,177		(741,657)		(1,166,500)		4		(1,166,496)		(443,321)		276		(443,045)		(95,155)		422		(94,733)

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									Statement of
	Operations	Three Months Ended June 30,				Six Months Ended June 30,				Operations	Three Months Ended June 30,				Six Months Ended June 30,
	Location	2021		2022		2021		2022		Location	2022		2023		2022		2023
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)
Commodity derivative fair value gains (losses) ⁽¹⁾										Revenue	$	(237,680)		6,232		(1,232,163)		133,312
Embedded derivative fair value gains (losses) ⁽¹⁾										Revenue	$	(27,982)		2,052		(44,879)		1,164

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

Commodity derivative fair value gains (losses) for the six months ended June 30, 2023, includes a loss of $202 million related to the early settlement of the Company’s natural gas swaption agreement during the first quarter of 2023. The payment for this early settlement is classified as an operating cash flow on the Company’s condensed consolidated statement of cash flows.

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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.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

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.

~~Table of Contents~~

~~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)					(Unaudited)
		December 31,		June 30,			December 31,		June 30,
Leases	Balance Sheet Classification	2021		2022		Balance Sheet Classification	2022		2023
Operating Leases
Operating lease right-of-use assets:
Processing plants	Operating lease right-of-use assets	$	1,739,550		1,644,040	Operating lease right-of-use assets	$	1,849,116		1,732,132
Drilling rigs and completion services	Operating lease right-of-use assets		9,860		79,350	Operating lease right-of-use assets		85,405		52,094
Gas gathering lines and compressor stations ⁽¹⁾	Operating lease right-of-use assets		1,634,928		1,583,204	Operating lease right-of-use assets		1,463,756		1,435,070
Office space	Operating lease right-of-use assets		33,083		42,987	Operating lease right-of-use assets		41,822		39,777
Vehicles	Operating lease right-of-use assets		2,009		1,389	Operating lease right-of-use assets		756		109
Other office and field equipment	Operating lease right-of-use assets		482		4,652	Operating lease right-of-use assets		3,476		3,071
Total operating lease right-of-use assets		$	3,419,912		3,355,622		$	3,444,331		3,262,253

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
Operating lease liabilities:
Short-term operating lease liabilities						Short-term lease liabilities	$	556,137		553,107
Long-term operating lease liabilities						Long-term lease liabilities		2,888,194		2,709,146
Total operating lease liabilities							$	3,444,331		3,262,253

Finance Leases
Finance lease right-of-use assets:
Vehicles	Other property and equipment	$	550		700	Other property and equipment	$	2,159		3,435
Total finance lease right-of-use assets ⁽²⁾		$	550		700		$	2,159		3,435

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
Finance lease liabilities:
Short-term finance lease liabilities						Short-term lease liabilities	$	499		846
Long-term finance lease liabilities						Long-term lease liabilities		1,660		2,589
Total finance lease liabilities							$	2,159		3,435

(1)	Gas gathering lines and compressor stations ~~leases~~ includes ~~$1.5~~$1.4 billion related to Antero Midstream as of December 31, ~~2021~~2022 and June 30, ~~2022.~~2023. 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~~2022 and June 30, 2023~~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,						Three Months Ended June 30,				Six Months Ended June 30,
Cost	Classification	Location	2021		2022		2021		2022		Classification	Location	2022		2023		2022		2023
Operating lease cost	Statement of operations	Gathering, compression, processing and transportation	$	385,022		365,343		761,952		731,177	Statement of operations	Gathering, compression, processing and transportation	$	365,343		407,445		731,177		788,728
Operating lease cost	Statement of operations	General and administrative		2,736		2,787		5,224		5,654	Statement of operations	General and administrative		2,787		3,030		5,654		5,967
Operating lease cost	Statement of operations	Contract termination		844		—		844		—	Statement of operations	Contract termination		—		2,808		—		3,930
Operating lease cost	Statement of operations	Lease operating		44		44		66		89	Statement of operations	Lease operating		44		21		89		42
Operating lease cost	Balance sheet	Proved properties ⁽¹⁾		28,432		41,100		57,191		48,859	Balance sheet	Proved properties ⁽¹⁾		41,100		31,602		48,859		71,372
Total operating lease cost			$	417,078		409,274		825,277		785,779			$	409,274		444,906		785,779		870,039

Finance lease cost:
Amortization of right-of-use assets	Statement of operations	Depletion, depreciation and amortization	$	132		107		259		225	Statement of operations	Depletion, depreciation and amortization	$	107		546		225		638
Interest on lease liabilities	Statement of operations	Interest expense		23		51		51		65	Statement of operations	Interest expense		51		162		65		276
Total finance lease cost			$	155		158		310		290			$	158		708		290		914

Short-term lease payments			$	24,456		28,348		41,298		77,108			$	28,348		34,707		77,108		72,408

(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,				Six Months Ended June 30,
	2021		2022		2022		2023
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	716,582		675,563	$	675,563		654,938
Operating cash flows from finance leases						66		276
Investing cash flows from operating leases		44,747		39,781		39,781		61,092
Financing cash flows from finance leases		509		277		277		343

Noncash activities:
Right-of-use assets obtained in exchange for new operating lease obligations	$	6,849		215,157	$	215,157		51,737
Increase (decrease) to existing right-of-use assets and lease obligations from operating lease modifications, net ⁽¹⁾	$	(2,612)		(47,728)	$	(47,728)		40,176

(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. During the six months ended June 30, 2023, the weighted average discount rate for remeasured operating leases increased from 5.2% as of December 31, 2022 to 5.8% as of June 30, 2023.

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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~~2023 (in thousands):


	Operating Leases		Financing Leases		Total			Operating Leases		Financing Leases		Total
Remainder of 2022	$	347,588		221		347,809	��
2023		680,572		215		680,787		$	374,215		669		374,884
2024		619,383		207		619,590			685,594		1,339		686,933
2025		558,900		165		559,065			609,747		1,297		611,044
2026		508,199		36		508,235			556,196		961		557,157
2027		415,958		—		415,958			457,972		112		458,084
Thereafter		1,069,257		—		1,069,257			1,252,713		33		1,252,746
Total lease payments		4,199,857		844		4,200,701			3,936,437		4,411		3,940,848
Less: imputed interest		(844,235)		(144)		(844,379)			(674,184)		(976)		(675,160)
Total	$	3,355,622		700		3,356,322		$	3,262,253		3,435		3,265,688

(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				December 31, 2022				June 30, 2023
	Operating Leases		Finance Leases		Operating Leases		Finance Leases		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		7.2 years		3.5 years		6.9 years		3.4 years
Weighted average discount rate	5.5	%	5.6	%	5.8	%	6.0	%	5.3	%	7.4	%	5.6	%	8.1	%

(f)	Related Party Lease Disclosure

The Company has agathering and compression service agreements with Antero Midstream that include: (i) the second amended and restated gathering and compression agreement dated December 8, 2019 (the “2019 gathering and compression agreement”), (ii) gathering and compression agreements from Antero Midstream’s acquisition of certain Marcellus gathering and compression assets (the “Marcellus gathering and compression agreements”) and (iii) a compression agreement from Antero Midstream’s acquisition of certain Utica compressors (the “Utica compression agreement” and, together with the 2019 gathering and compression agreement and the Marcellus gathering and compression agreements, the “gathering and compression agreements”). Pursuant to the gathering and compression agreements with Antero Midstream, ~~whereby~~the Company has dedicated substantially all of its current and future acreage in West Virginia, Ohio and Pennsylvania to Antero Midstream for gathering and compression services. The 2019 gathering and compression agreement has an initial term through 2038, the Marcellus gathering and compression agreements expire between 2024 and 2031, and the Utica compression agreement has two dedicated areas that expire in 2024 and 2030. Upon expiration of each of the Marcellus gathering and compression agreements and the Utica compression agreement, Antero Midstream will continue to provide gathering and compression services under the 2019 gathering and compression agreement.

Under the gathering and compression agreements, 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~~as applicable, 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 orand compressor stations, the 2019 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,~~addition, certain of the Marcellus gathering and compression agreements provide for a minimum volume commitment that requires the Company ~~and Antero Midstream agreed~~ to ~~extend the initial term~~utilize or pay for 25% of the capacity of new compressor station construction for 10 years.

The 2019 gathering and compression agreement ~~to 2038 and established~~includes a growth incentive fee program whereby ~~low pressure~~low-pressure gathering fees will be reduced from 2020 through 2023 to the extent the Company achieves certain quarterly volumetric ~~targets at certain points during such time.~~targets. The Company’s throughput gathered under the Marcellus gathering and compression agreements is not considered in low pressure gathering volume targets. Upon completion of the initial contract term, the 2019 gathering and compression agreement will continue in effect from year to year until such time as the agreement is terminated, effective upon an

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

anniversary of the effective date of the agreement, by either the Company or Antero Midstream on or before the ~~180~~^th180th day prior to the anniversary of such effective date. The Company ~~did~~ ~~0t achieve~~achieved the ~~quarterly~~ volumetric ~~target for either~~targets during each of the first orand second ~~quarter~~quarters of ~~2021,~~2022 and ~~therefore, did not earn a rebate~~2023, and earned fee rebates of $12 million for the three ~~and six~~ months ended June 30, ~~2021. For~~2022 and 2023 and $24 million 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.~~2023.

Gathering and compression fees paid by Antero related to ~~this agreement~~these agreements were ~~$184~~$164 million and ~~$164~~$185 million for the three months ended June 30, ~~2021~~2022 and ~~2022,~~2023, respectively. For the six months ended June 30, ~~2021~~2022 and ~~2022,~~2023, gathering and compression fees paid by Antero related to this agreement were ~~$361~~$327 million and ~~$327~~$361 million, respectively. As of December 31, ~~2021~~2022 and June 30, ~~2022,~~ ~~$54~~2023, $59 million and ~~$51~~$69 million, respectively, was included within Accounts payable, related parties on the condensed consolidated balance sheet as due to Antero Midstream related to ~~this agreement.~~these agreements.

~~Table of Contents~~

~~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,~~the Company’s contractual obligations, which include leases that have a lease term in excess of one year as of June 30, ~~2022~~2023 (in thousands):


			Processing,												Processing,
	Firm		Gathering and		Land Payment		Operating and		Imputed Interest						Gathering,
	Transportation		Compression		Obligations		Financing Leases		for Leases				Firm		Compression		Operating and		Imputed Interest
	(a)		(b)		(c)		(d)		(d)		Total		Transportation		and Water Service		Financing Leases		for Leases		Other
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
													(a)		(b)		(c)		(c)		(d)		Total
Remainder of 2023													$	594,682		35,382		286,449		88,435		2,586		1,007,534
2024		1,044,479		59,262		—		476,770		142,820		1,723,331		1,147,772		63,212		533,031		153,902		6,009		1,903,926
2025		1,023,947		47,960		—		441,782		117,283		1,630,972		1,134,296		51,865		486,261		124,783		4,875		1,802,080
2026		1,018,345		14,783		—		414,646		93,589		1,541,363		1,131,882		18,688		459,146		98,011		2,250		1,709,977
2027		1,016,780		14,783		—		343,751		72,207		1,447,521		1,127,234		17,400		384,429		73,655		—		1,602,718
Thereafter		5,012,734		83,813		—		915,020		154,237		6,165,804		5,444,784		80,556		1,116,372		136,374		—		6,778,086
Total	$	10,711,984		310,351		1,033		3,356,322		844,379		15,224,069	$	10,580,650		267,103		3,265,688		675,160		15,720		14,804,321

(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, Compression and ~~Compression~~Water Service Commitments

The Company has entered into various long-term gas processing, gathering, compression and ~~compression~~water 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)~~

Operating and Finance 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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Notes to Unaudited Condensed Consolidated Financial Statements

(d)

Other

The Company has entered into various land acquisition and sand supply 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.

(e)	Contract Terminations

The Company incurs costs associated with the delay or cancellation of certain contracts with third-parties. These costs are recorded in Contract termination and included in the statement of operations and comprehensive income (loss). During the six months ended June 30, 2023, the Company executed an early termination of its firm transportation commitment of 200,000 MMBtu per day on the Equitrans pipeline and made a cash payment of $24 million. There are no remaining payment obligations related to these delayed or cancelled ~~drilling and completion~~ contracts as of June 30, ~~2022.~~2023.

(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 and other similarly situated peer operators could have an impact on the methods for determining the amount of permitted post-production costs and types of costs that have been, and may be, deducted from royalty payments, among other ~~things,~~things. A ruling was recently received in an immaterial case to which the Company is a party, and the Company continues to analyze how this decision may impact other cases to which the Company is a party. The Company cannot predict how these issues may ultimately be ~~resolved.~~resolved, and therefore is also unable to estimate any potential damages, if any, that may result.

(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 3three 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~~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 and assets of the Company’s reportable segments ~~are~~were as follows (in thousands):


	Three Months Ended June 30, 2021
							Elimination of				Three Months Ended June 30, 2022
					Equity Method		Intersegment								Equity Method
	Exploration				Investment in		Transactions and				Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated		and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream		Affiliates		Total		Production		Marketing		Midstream		Affiliate		Total
Sales and revenues:
Third-party	$	322,246		165,453		70		(70)		487,699	$	2,095,144		106,150		242		(242)		2,201,294
Intersegment		(619)		—		232,717		(232,717)		(619)		391		—		228,665		(228,665)		391
Total revenue	$	321,627		165,453		232,787		(232,787)		487,080		2,095,535		106,150		228,907		(228,907)		2,201,685

Operating expenses:
Lease operating	$	21,645		—		—		—		21,645		25,253		—		—		—		25,253
Gathering, compression, processing and transportation		641,362		—		39,555		(39,555)		641,362
Gathering, compression, processing, transportation and water handling												656,212		—		43,299		(43,299)		656,212
General and administrative		32,177		—		14,251		(14,251)		32,177		44,439		—		16,079		(16,079)		44,439
Depletion, depreciation and amortization		187,330		—		26,619		(26,619)		187,330		173,395		—		35,675		(35,675)		173,395
Impairment of oil and gas properties		9,303		—		—		—		9,303
Impairment of property and equipment												23,363		—		3,702		(3,702)		23,363
Other		39,219		198,994		963		(963)		238,213		86,207		131,298		1,756		(1,756)		217,505
Total operating expenses		931,036		198,994		81,388		(81,388)		1,130,030		1,008,869		131,298		100,511		(100,511)		1,140,167
Operating income (loss)	$	(609,409)		(33,541)		151,399		(151,399)		(642,950)	$	1,086,666		(25,148)		128,396		(128,396)		1,061,518
Equity in earnings of unconsolidated affiliates	$	17,477		—		21,515		(21,515)		17,477	$	14,713		—		22,824		(22,824)		14,713
Capital expenditures for segment assets	$	182,591		—		45,976		(45,976)		182,591	$	260,864		—		77,767		(77,767)		260,864


	Three Months Ended June 30, 2022
							Elimination of				Three Months Ended June 30, 2023
					Equity Method		Intersegment								Equity Method
	Exploration				Investment in		Transactions and				Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated		and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream		Affiliates		Total		Production		Marketing		Midstream		Affiliate		Total
Sales and revenues:
Third-party	$	2,095,144		106,150		242		(242)		2,201,294	$	909,092		43,793		274		(274)		952,885
Intersegment		391		—		228,665		(228,665)		391		420		—		258,013		(258,013)		420
Total revenue	$	2,095,535		106,150		228,907		(228,907)		2,201,685		909,512		43,793		258,287		(258,287)		953,305

Operating expenses:
Lease operating	$	25,253		—		—		—		25,253		28,748		—		—		—		28,748
Gathering, compression, processing and transportation		656,212		—		43,299		(43,299)		656,212
Gathering, compression, processing, transportation and water handling												663,975		—		52,595		(52,595)		663,975
General and administrative		44,439		—		16,079		(16,079)		44,439		53,901		—		18,162		(18,162)		53,901
Depletion, depreciation and amortization		173,395		—		35,675		(35,675)		173,395		171,406		—		35,233		(35,233)		171,406
Impairment of oil and gas properties		23,363		—		—		—		23,363
Impairment of property and equipment												15,710		—		—		—		15,710
Other		86,207		131,298		5,458		(5,458)		217,505		42,326		66,175		6,774		(6,774)		108,501
Total operating expenses		1,008,869		131,298		100,511		(100,511)		1,140,167		976,066		66,175		112,764		(112,764)		1,042,241
Operating income (loss)	$	1,086,666		(25,148)		128,396		(128,396)		1,061,518	$	(66,554)		(22,382)		145,523		(145,523)		(88,936)
Equity in earnings of unconsolidated affiliates	$	14,713		—		22,824		(22,824)		14,713	$	19,098		—		25,972		(25,972)		19,098
Capital expenditures for segment assets	$	260,864		—		77,767		(77,767)		260,864	$	637,096		—		41,782		(41,782)		637,096

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements


	Six Months Ended June 30, 2021
					Equity Method		Elimination of				Six Months Ended June 30, 2022
					Investment in		Intersegment								Equity Method
	Exploration				Antero		Transactions and				Exploration				Investment in		Elimination of
	and				Midstream		Unconsolidated		Consolidated		and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Corporation		Affiliates		Total		Production		Marketing		Midstream		Affiliate		Total
Sales and revenues:
Third-party	$	1,361,014		330,243		95		(95)		1,691,257	$	2,812,525		175,188		637		(637)		2,987,713
Intersegment		21		—		456,813		(456,813)		21		812		—		446,761		(446,761)		812
Total revenue		1,361,035		330,243		456,908		(456,908)		1,691,278		2,813,337		175,188		447,398		(447,398)		2,988,525

Operating expenses:
Lease operating		46,192		—		—		—		46,192		43,033		—		—		—		43,033
Gathering, compression, processing and transportation		1,246,439		—		78,869		(78,869)		1,246,439
Gathering, compression, processing, transportation and water handling												1,246,490		—		85,311		(85,311)		1,246,490
General and administrative		76,251		—		32,181		(32,181)		76,251		80,130		—		34,010		(34,010)		80,130
Depletion, depreciation and amortization		381,356		—		53,469		(53,469)		381,356		341,783		—		63,975		(63,975)		341,783
Impairment of oil and gas properties		43,365		—		—		—		43,365
Impairment of midstream assets		—		—		1,379		(1,379)		—
Impairment of property and equipment												45,825		—		3,702		(3,702)		45,825
Other		85,014		361,071		6,024		(6,024)		446,085		144,151		230,194		2,850		(2,850)		374,345
Total operating expenses		1,878,617		361,071		171,922		(171,922)		2,239,688		1,901,412		230,194		189,848		(189,848)		2,131,606
Operating income (loss)	$	(517,582)		(30,828)		284,986		(284,986)		(548,410)	$	911,925		(55,006)		257,550		(257,550)		856,919
Equity in earnings of unconsolidated affiliates	$	36,171		—		42,259		(42,259)		36,171	$	39,891		—		46,056		(46,056)		39,891
Capital expenditures for segment assets	$	305,749		—		74,365		(74,365)		305,749	$	476,740		—		162,034		(162,034)		476,740


	Six Months Ended June 30, 2022
							Elimination of				Six Months Ended June 30, 2023
					Equity Method		Intersegment								Equity Method
	Exploration				Investment in		Transactions and				Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated		and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream		Affiliates		Total		Production		Marketing		Midstream		Affiliate		Total
Sales and revenues:
Third-party	$	2,812,525		175,188		637		(637)		2,987,713	$	2,258,568		102,322		546		(546)		2,360,890
Intersegment		812		—		446,761		(446,761)		812		763		—		517,216		(517,216)		763
Total revenue		2,813,337		175,188		447,398		(447,398)		2,988,525		2,259,331		102,322		517,762		(517,762)		2,361,653

Operating expenses:
Lease operating		43,033		—		—		—		43,033		58,069		—		—		—		58,069
Gathering, compression, processing and transportation		1,246,490		—		85,311		(85,311)		1,246,490
Gathering, compression, processing, transportation and water handling												1,309,147		—		110,468		(110,468)		1,309,147
General and administrative		80,130		—		34,010		(34,010)		80,130		111,162		—		35,509		(35,509)		111,162
Depletion, depreciation and amortization		341,783		—		63,975		(63,975)		341,783		338,988		—		70,429		(70,429)		338,988
Impairment of oil and gas properties		45,825		—		—		—		45,825
Impairment of property and equipment												31,270		—		—		—		31,270
Other		144,151		230,194		6,552		(6,552)		374,345		99,164		171,299		7,488		(7,488)		270,463
Total operating expenses		1,901,412		230,194		189,848		(189,848)		2,131,606		1,947,800		171,299		223,894		(223,894)		2,119,099
Operating income (loss)	$	911,925		(55,006)		257,550		(257,550)		856,919	$	311,531		(68,977)		293,868		(293,868)		242,554
Equity in earnings of unconsolidated affiliates	$	39,891		—		46,056		(46,056)		39,891	$	36,779		—		50,428		(50,428)		36,779
Capital expenditures for segment assets	$	476,740		—		162,034		(162,034)		476,740	$	637,096		—		84,739		(84,739)		637,096

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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				As of December 31, 2022
					Equity Method		Intersegment								Equity Method
	Exploration				Investment in		Transactions and				Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated		and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream		Affiliates		Total		Production		Marketing		Midstream		Affiliate		Total
Investments in unconsolidated affiliates	$	232,399		—		696,009		(696,009)		232,399	$	220,429		—		652,767		(652,767)		220,429
Total assets	$	13,864,402		32,126		5,544,001		(5,544,001)		13,896,528		14,081,077		36,962		5,791,320		(5,791,320)		14,118,039


	(Unaudited)
	As of June 30, 2022										(Unaudited)
							Elimination of				As of June 30, 2023
					Equity Method		Intersegment								Equity Method
	Exploration				Investment in		Transactions and				Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated		and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream		Affiliates		Total		Production		Marketing		Midstream		Affiliate		Total
Investments in unconsolidated affiliates	$	229,095		—		681,560		(681,560)		229,095	$	218,196		—		639,887		(639,887)		218,196
Total assets	$	14,156,611		56,089		5,585,501		(5,585,501)		14,212,700		13,747,226		19,584		5,752,883		(5,752,883)		13,766,810

(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~~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)				(Unaudited)
	December 31, 2021		June 30, 2022		December 31, 2022		June 30, 2023
Accounts receivable, non-guarantor subsidiaries	$	—		—
Accounts receivable, related parties		—		—
Other current assets		633,014		946,631
Total current assets		633,014		946,631
Current assets					$	739,104		363,698
Noncurrent assets		12,480,350		12,498,696		12,663,911		12,775,341
Total assets	$	13,113,364		13,445,327	$	13,403,015		13,139,039

Accounts payable, non-guarantor subsidiaries	$	—		—
Accounts payable, related parties		76,240		72,871	$	80,708		95,360
Other current liabilities		1,961,041		2,355,076		1,668,426		1,398,840
Total current liabilities		2,037,281		2,427,947		1,749,134		1,494,200
Noncurrent liabilities		5,737,999		5,428,228		5,306,539		5,184,049
Total liabilities	$	7,775,280		7,856,175	$	7,055,673		6,678,249

Statement of Operations

			Six Months Ended				Six Months Ended
			June 30, 2022				June 30, 2023
Revenues			$	2,937,693			$	2,275,190
Operating expenses				2,109,395				2,095,558
Income from operations				828,298				179,632
Net income and comprehensive income including noncontrolling interests				608,716				130,347
Net income and comprehensive income attributable to Antero Resources Corporation			$	608,716			$	130,347

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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,~~2023, we held approximately ~~503,000~~516,000 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

~~Table of Contents~~

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.

Market Conditions and Business Trends

~~Our~~Commodity Markets

Prices for 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 notthat we produce significantly 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~~revenues and cash flows. Natural gas, ~~at a weighted average price of $2.48 per MMBtu~~NGLs 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 increasedoil benchmark prices decreased significantly during the ~~COVID-19 pandemic~~three and ~~as of~~six months ended 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 20222023 as compared to the ~~average annual increase~~same periods of ~~3% over~~2022. As a result, we experienced a decrease in price realizations during the ~~previous 10 years. Inflationary pressures, particularly as they relate to certain~~three and six months ended June 30, 2023. We monitor the economic factors that impact natural gas, NGLs and oil prices, including domestic and foreign supply and demand indicators, domestic and foreign commodity inventories, the actions of ~~our long-term contracts with CPI-based adjustments,~~Organization of Petroleum Exporting Countries and ~~labor shortages could result in increases to our operating~~other large producing nations and ~~capital costs that are not fixed, renegotiation of contracts and/or supply agreements and higher labor costs,~~the current Russia-Ukraine conflict, among others. ~~These~~In the current economic ~~variables are~~environment, we expect that commodity prices for some or all of the commodities we produce could remain volatile. This volatility is 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~~

The following table details the average benchmark natural gas 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.oil prices:

~~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.


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2023		2022		2023
Henry Hub ⁽¹⁾ ($/Mcf)	$	7.17		2.10	$	6.06		2.76
West Texas Intermediate ⁽²⁾ ($/Bbl)		108.41		73.78		101.35		74.95

(1)	NYMEX first of month average natural gas price.

(2)	Energy Information Administration calendar month average settled futures price.

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~~Share Repurchase Program~~Hedge Position

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.Antero Resources (Excluding Martica)

~~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 commodity price risks relating to our ongoing business operations, and we use derivative instruments as we deem necessary to manage ~~our commodity price risk.~~ such risks. In addition, we periodically enter into contracts that contain embedded features that are required to be bifurcated and accounted for separately as derivatives. Due to our improved liquidity and leverage position as compared to past levels, the percentage of our expected production that we hedge has decreased. For the three and six months ended June 30, 2022, 34% and 35%, respectively, of our production was hedged through fixed price commodity swaps as compared to 1% and 2% for the three and six months ended June 30, 2023, respectively. Assuming our 2023 production is the same as our production in 2022, 1% of our production for 2023 will be hedged through fixed price commodity swaps. The ~~table~~tables and narrative below ~~excludes~~exclude derivative instruments attributable to Martica, our consolidated ~~variable interest entity (“VIE”),~~VIE, since all gains or losses from such contracts are fully attributable to the noncontrolling interests in Martica.

As of June 30, ~~2022,~~2023, our fixed price natural gas ~~oil and NGL~~ swap positions excluding Martica were as follows:

Weighted

Average

Commodity / Settlement Period

Index

Contracted Volume

Price

Index

Contracted Volume

Price

Natural Gas

July-December 2022

Henry Hub

203

Bcf

2.48

/MMBtu

January-December 2023

Henry Hub

Bcf

2.37

/MMBtu

219

Bcf

2.48

/MMBtu

July-December 2023

Henry Hub

Bcf

2.37

/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,~~2023, 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

Index to Basis Differential

Contracted Volume

Hedged Differential

Natural Gas

July-December 2022

NYMEX to TCO

Bcf

0.515

/MMBtu

January-December 2023

NYMEX to TCO

Bcf

0.525

/MMBtu

July-December 2023

NYMEX to TCO

Bcf

0.525

/MMBtu

January-December 2024

NYMEX to TCO

Bcf

0.530

/MMBtu

NYMEX to TCO

Bcf

0.530

/MMBtu

Bcf

0.525

/MMBtu

Bcf

0.528

/MMBtu

~~As of June 30, 2022, we also had~~We have a call option and an embedded put option tied to NYMEX pricing for the production volumes associated with ~~our~~the Company’s 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.~~properties. As of June 30, ~~2022,~~2023, our call option and embedded put option arrangements were as follows:

Embedded

Call Option

Put Option

Commodity / Settlement Period

Index

Contracted Volume

Strike Price

Natural Gas

July-December 2023

Henry Hub

Bcf

2.466

/MMBtu

2.466

/MMBtu

January-December 2024

Henry Hub

Bcf

2.477

/MMBtu

2.527

/MMBtu

January-December 2025

Henry Hub

Bcf

2.564

/MMBtu

2.614

/MMBtu

January-December 2026

Henry Hub

Bcf

2.629

/MMBtu

2.679

/MMBtu

Bcf

2.525

/MMBtu

2.563

/MMBtu

In addition, we had a swaption agreement, which entitled the counterparty the right, but not the obligation, to enter into a fixed price swap agreement for 156 Bcf at a price of $2.77 per MMBtu for the year ending December 31, 2024. In January 2023, we executed an early settlement of this swaption agreement and made a cash payment of $202 million, which was funded by cash flows from operations and borrowings under our Credit Facility.

As of June 30, 2023, the estimated fair value of our commodity derivative contracts, excluding Martica, was a net liability of ~~$1.1 billion.~~$67 million. See Note 11—Derivative Instruments to the unaudited condensed consolidated financial statements for more information.

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Martica

Our consolidated VIE, Martica, also maintains a portfolio of fixed swap natural gas, NGLs and oil derivatives for the benefit of the noncontrolling interests in Martica. As such, all gains and losses attributable to Martica’s derivative portfolio are fully attributable to the noncontrolling interests in Martica. As of June 30, 2023, Martica’s fixed price natural gas, NGLs and oil swap positions were as follows:


				Weighted
				Average
Commodity / Settlement Period	Index	Contracted Volume		Price
Natural Gas
July-December 2023	Henry Hub	6	Bcf	$	2.35	/MMBtu
January-December 2024	Henry Hub	9	Bcf		2.33	/MMBtu
January-March 2025	Henry Hub	1	Bcf		2.53	/MMBtu
		16	Bcf		2.35	/MMBtu

Natural Gasoline
July-December 2023	Mont Belvieu Natural Gasoline-OPIS Non-TET	42	MBbl		40.74	/Bbl

Oil
July-December 2023	West Texas Intermediate	14	MBbl		44.72	/Bbl
January-December 2024	West Texas Intermediate	16	MBbl		44.02	/Bbl
January-March 2025	West Texas Intermediate	3	MBbl		45.06	/Bbl
		33	MBbl		44.43	/Bbl

As of June 30, 2023, the estimated fair value of Martica’s commodity derivative contracts was a net liability of $17 million. See Note 11—Derivative Instruments to the unaudited condensed consolidated financial statements for more information.

Economic Indicators

The economy experienced elevated inflation levels as a result of global supply and demand imbalances, where global demand outpaced supplies beginning in 2021 and continuing through the first half of 2023. For example, the Consumer Price Index (“CPI”) for all urban consumers increased 9% from June 2021 to June 2022 and an additional 3% from June 2022 to June 2023 as compared to the Federal Reserve’s stated goal of 2%. In order to manage the inflation risk present in the United States’ economy, the Federal Reserve utilized monetary policy in the form of interest rate increases beginning in March 2022 in an effort to bring the inflation rate in line with its stated goal of 2% on a long-term basis. Between March 2022 and May 2023, the Federal Reserve increased the federal funds interest rate by 5.0%. While inflationary pressures in the United States’ economy have begun to subside, we continue to be impacted by the increased federal funds interest rate. See “—Results of Operations” for more information.

The economy also continues to be impacted by the effects of global events. These events have often caused global supply chain disruptions with additional pressure due to trade sanctions on Russia and other global trade restrictions, among others. However, our supply chain has not experienced any significant interruptions as a result of such events.

Inflationary pressures, particularly as they relate to certain of our long-term contracts with CPI-based adjustments, and supply chain disruptions have and could continue to result in increases to our operating and capital costs that are not fixed. For example, our 2023 capital budget reflects an approximate 10% increase in service cost inflation as compared to the year ended December 31, 2022. These economic variables are beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows.

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

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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.~~statements for more information.

Three Months Ended June 30, ~~2021~~2022 Compared to Three Months Ended June 30, ~~2022~~2023

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


	Three Months Ended June 30, 2021
							Elimination of				Three Months Ended June 30, 2022
					Equity Method		Intersegment								Equity Method
	Exploration				Investment in		Transactions and				Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated		and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream		Affiliates		Total		Production		Marketing		Midstream		Affiliate		Total
Revenue and other:
Natural gas sales	$	626,520		—		—		—		626,520	$	1,558,994		—		—		—		1,558,994
Natural gas liquids sales		464,381		—		—		—		464,381		702,388		—		—		—		702,388
Oil sales		51,906		—		—		—		51,906		89,185		—		—		—		89,185
Commodity derivative fair value losses		(831,840)		—		—		—		(831,840)		(265,662)		—		—		—		(265,662)
Gathering, compression, water handling and treatment		—		—		250,455		(250,455)		—
Gathering, compression and water handling												—		—		228,907		(228,907)		—
Marketing		—		165,453		—		—		165,453		—		106,150		—		—		106,150
Amortization of deferred revenue, VPP		11,279		—		—		—		11,279		9,375		—		—		—		9,375
Other loss		(619)		—		(17,668)		17,668		(619)
Other revenue and income												1,255		—		—		—		1,255
Total revenue	$	321,627		165,453		232,787		(232,787)		487,080		2,095,535		106,150		228,907		(228,907)		2,201,685

Operating expenses:
Lease operating	$	21,645		—		—		—		21,645		25,253		—		—		—		25,253
Gathering and compression		224,073		—		39,555		(39,555)		224,073		223,650		—		19,343		(19,343)		223,650
Processing		209,627		—		—		—		209,627		219,100		—		—		—		219,100
Transportation		207,662		—		—		—		207,662		213,462		—		—		—		213,462
Water handling												—		—		23,956		(23,956)		—
Production and ad valorem taxes		33,694		—		—		—		33,694		81,842		—		—		—		81,842
Marketing		—		198,994		—		—		198,994		—		131,298		—		—		131,298
Exploration		5,638		—		—		—		5,638
Exploration and mine expenses												1,394		—		—		—		1,394
General and administrative (excluding equity-based compensation)		27,928		—		11,192		(11,192)		27,928		36,268		—		10,438		(10,438)		36,268
Equity-based compensation		4,249		—		3,059		(3,059)		4,249		8,171		—		5,641		(5,641)		8,171
Depletion, depreciation and amortization		187,330		—		26,619		(26,619)		187,330		173,395		—		35,675		(35,675)		173,395
Impairment of oil and gas properties		9,303		—		—		—		9,303
Impairment of property and equipment												23,363		—		3,702		(3,702)		23,363
Accretion of asset retirement obligations		1,331		—		114		(114)		1,331		804		—		64		(64)		804
Contract termination and other expenses		844		—		849		(849)		844
Gain on sale of assets		(2,288)		—		—		—		(2,288)
Contract termination and other operating expenses												2,096		—		1,724		(1,724)		2,096
Loss (gain) on sale of assets												71		—		(32)		32		71
Total operating expenses		931,036		198,994		81,388		(81,388)		1,130,030		1,008,869		131,298		100,511		(100,511)		1,140,167
Operating income (loss)	$	(609,409)		(33,541)		151,399		(151,399)		(642,950)	$	1,086,666		(25,148)		128,396		(128,396)		1,061,518

Equity in earnings of unconsolidated affiliates	$	17,477		—		21,515		(21,515)		17,477	$	14,713		—		22,824		(22,824)		14,713

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	Three Months Ended June 30, 2022
							Elimination of				Three Months Ended June 30, 2023
					Equity Method		Intersegment								Equity Method
	Exploration				Investment in		Transactions and				Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated		and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream		Affiliates		Total		Production		Marketing		Midstream		Affiliate		Total
Revenue and other:
Natural gas sales	$	1,558,994		—		—		—		1,558,994	$	437,130		—		—		—		437,130
Natural gas liquids sales		702,388		—		—		—		702,388		397,733		—		—		—		397,733
Oil sales		89,185		—		—		—		89,185		57,962		—		—		—		57,962
Commodity derivative fair value losses		(265,662)		—		—		—		(265,662)
Gathering, compression, water handling and treatment		—		—		246,575		(246,575)		—
Commodity derivative fair value gains												8,284		—		—		—		8,284
Gathering, compression and water handling												—		—		258,287		(258,287)		—
Marketing		—		106,150		—		—		106,150		—		43,793		—		—		43,793
Amortization of deferred revenue, VPP		9,375		—		—		—		9,375		7,618		—		—		—		7,618
Other income (loss)		1,255		—		(17,668)		17,668		1,255
Other revenue and income												785		—		—		—		785
Total revenue	$	2,095,535		106,150		228,907		(228,907)		2,201,685		909,512		43,793		258,287		(258,287)		953,305

Operating expenses:
Lease operating	$	25,253		—		—		—		25,253		28,748		—		—		—		28,748
Gathering and compression		223,650		—		43,299		(43,299)		223,650		211,691		—		25,154		(25,154)		211,691
Processing		219,100		—		—		—		219,100		262,642		—		.		—		262,642
Transportation		213,462		—		—		—		213,462		189,642		—		—		—		189,642
Water handling												—		—		27,441		(27,441)		—
Production and ad valorem taxes		81,842		—		—		—		81,842		36,158		—		—		—		36,158
Marketing		—		131,298		—		—		131,298		—		66,175		—		—		66,175
Exploration and mine expenses		1,394		—		—		—		1,394		743		—		—		—		743
General and administrative (excluding equity-based compensation)		36,268		—		10,438		(10,438)		36,268		40,389		—		9,663		(9,663)		40,389
Equity-based compensation		8,171		—		5,641		(5,641)		8,171		13,512		—		8,499		(8,499)		13,512
Depletion, depreciation and amortization		173,395		—		35,675		(35,675)		173,395		171,406		—		35,233		(35,233)		171,406
Impairment of oil and gas properties		23,363		—		—		—		23,363
Impairment of midstream assets		—		—		3,702		(3,702)		—
Impairment of property and equipment												15,710		—		—		—		15,710
Accretion of asset retirement obligations		804		—		64		(64)		804		1,204		—		44		(44)		1,204
Contract termination and other expenses		2,096		—		1,724		(1,724)		2,096
Loss (gain) on sale of assets		71		—		(32)		32		71		(220)		—		5,814		(5,814)		(220)
Contract termination and other operating expenses												4,441		—		916		(916)		4,441
Total operating expenses		1,008,869		131,298		100,511		(100,511)		1,140,167		976,066		66,175		112,764		(112,764)		1,042,241
Operating income (loss)	$	1,086,666		(25,148)		128,396		(128,396)		1,061,518	$	(66,554)		(22,382)		145,523		(145,523)		(88,936)

Equity in earnings of unconsolidated affiliates	$	14,713		—		22,824		(22,824)		14,713	$	19,098		—		25,972		(25,972)		19,098

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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				Three Months Ended				Amount of
	June 30,				Increase		Percent		June 30,				Increase		Percent
	2021		2022		(Decrease)		Change		2022		2023		(Decrease)		Change
Production data ^{(1) (2)}:
Natural gas (Bcf)		208		203		(5)	(2)	%		203		204		1	*
C2 Ethane (MBbl)		4,356		4,025		(331)	(8)	%		4,025		6,414		2,389	59	%
C3+ NGLs (MBbl)		10,440		10,156		(284)	(3)	%		10,156		10,175		19	*
Oil (MBbl)		940		906		(34)	(4)	%		906		971		65	7	%
Combined (Bcfe)		303		294		(9)	(3)	%		294		309		15	5	%
Daily combined production (MMcfe/d)		3,324		3,228		(96)	(3)	%		3,228		3,400		172	5	%
Average prices before effects of derivative settlements ⁽³⁾:
Natural gas (per Mcf)	$	3.01		7.67		4.66	155	%	$	7.67		2.14		(5.53)	(72)	%
C2 Ethane (per Bbl)	$	9.97		22.42		12.45	125	%
C2 Ethane (per Bbl) ⁽⁴⁾									$	22.42		7.82		(14.60)	(65)	%
C3+ NGLs (per Bbl)	$	40.32		60.28		19.96	50	%	$	60.28		34.16		(26.12)	(43)	%
Oil (per Bbl)	$	55.22		98.49		43.27	78	%	$	98.49		59.69		(38.80)	(39)	%
Weighted Average Combined (per Mcfe)	$	3.78		8.00		4.22	112	%	$	8.00		2.89		(5.11)	(64)	%
Average realized prices after effects of derivative settlements⁽³⁾:
Natural gas (per Mcf)	$	2.91		4.94		2.03	70	%	$	4.94		2.16		(2.78)	(56)	%
C2 Ethane (per Bbl)	$	9.97		22.42		12.45	125	%
C2 Ethane (per Bbl) ⁽⁴⁾									$	22.42		7.82		(14.60)	(65)	%
C3+ NGLs (per Bbl)	$	35.95		59.84		23.89	66	%	$	59.84		34.11		(25.73)	(43)	%
Oil (per Bbl)	$	52.05		97.73		45.68	88	%	$	97.73		59.40		(38.33)	(39)	%
Weighted Average Combined (per Mcfe)	$	3.55		6.10		2.55	72	%	$	6.10		2.90		(3.20)	(52)	%
Average costs (per Mcfe):
Lease operating	$	0.07		0.09		0.02	29	%	$	0.09		0.09		—	*
Gathering and compression	$	0.74		0.76		0.02	3	%	$	0.76		0.68		(0.08)	(11)	%
Processing	$	0.69		0.75		0.06	9	%	$	0.75		0.85		0.10	13	%
Transportation	$	0.69		0.73		0.04	6	%	$	0.73		0.61		(0.12)	(16)	%
Production and ad valorem taxes	$	0.11		0.28		0.17	155	%	$	0.28		0.12		(0.16)	(57)	%
Marketing (revenue) expense, net	$	0.11		0.09		(0.02)	(18)	%
Marketing expense, net									$	0.09		0.07		(0.02)	(22)	%
General and administrative (excluding equity-based compensation)									$	0.12		0.13		0.01	8	%
Depletion, depreciation, amortization and accretion	$	0.62		0.59		(0.03)	(5)	%	$	0.59		0.56		(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”).~~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 (losses) 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.

(4)	The average realized price for the three months ended June 30, 2023 includes $1 million of proceeds related to a take-or-pay contract. Excluding the effect of these proceeds, the average realized price for ethane before and after the effects of derivatives would have been $7.65 per Bbl.

Natural gas sales. Revenues from sales of natural gas ~~increased~~decreased 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~~to $437 million for the three months ended June 30, 2023, a decrease of ~~$932 million,~~$1.2 billion, or ~~149%~~72%. ~~Higher~~Lower commodity prices (excluding the effects of derivative settlements) during the three months ended June 30, ~~2022~~2023 accounted for an approximate ~~$947 million increase~~$1.2 billion decrease 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~~Higher natural gas production volumes accounted for an approximate ~~$15~~$6 million ~~decrease~~increase 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~~decreased from ~~$464 million for the three months ended June 30, 2021 to~~ $702 million for the three months ended June 30, 2022 ~~an increase~~to $398 million for the three months ended June 30, 2023, a decrease of ~~$238~~$304 million, or ~~51%~~43%. ~~Higher~~Lower commodity prices (excluding the effects of derivative settlements) during the three months ended June 30, ~~2022~~2023 accounted for an approximate ~~$253~~$359 million ~~increase~~decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). ~~Lower~~Higher NGLs production volumes accounted for an approximate ~~$15~~$55 million ~~decrease~~increase in year-over-year ~~NGL~~NGLs 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~~decreased from ~~$52 million for the three months ended June 30, 2021 to~~ $89 million for the three months ended June 30, 2022 ~~an increase~~to $58 million for the three months ended June 30, 2023, a decrease of ~~$37~~$31 million, or ~~72%~~35%. ~~Higher~~Lower oil prices, excluding the effects of derivative settlements, accounted for an approximate ~~$39~~$38 million ~~increase~~decrease in year-over-year oil revenues (calculated as the change in the year-to-year average price times current year production volumes). ~~Lower~~Higher oil production volumes during the three months ended June 30, ~~2022~~2023 accounted for an approximate $2$7 million ~~decrease~~increase 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.~~gains (losses). ~~To achieve more predictable cash flows, and to reduce our exposure to price fluctuations, we enter into fixed for~~Our commodity derivatives included variable price swap contracts, ~~swaptions,~~ basis swap contracts, call options and ~~collar contracts when we believe that favorable future sales prices for our production can be secured.~~embedded put options. 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~~2022 and ~~2022,~~2023, our commodity hedges resulted in derivative fair value losses of ~~$832~~$266 million and ~~$266~~fair value gains of $8 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~~on settled commodity ~~derivatives.~~derivatives losses. For the three months ended June 30, 2023, commodity derivative fair value gains included $3 million of cash proceeds on settled commodity derivative gains.

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 to $8 million for the three months ended June 30, 2023, a decrease of $2$1 million, or ~~17%~~19%, primarily due to ~~a decrease in~~lower production ~~volumes. Under~~volumes attributable to the ~~terms~~VPP properties between periods. Amortization of the ~~agreement,~~deferred revenues associated with the VPP are recognized as 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 to $29 million, or $0.09 per Mcfe, for the three months ended June 30, 2023, an increase of $4 million, primarily due to higher ~~oilfield service~~water disposal costs and ~~water disposal costs.~~workover expense. On a per unit basis, our higher costs during the three months ended June 30, 2023 were fully offset by increased production volumes during the period.

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~~to $664 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~~2023, an increase of $8 million, or 1%. This fluctuation primarily resulted from 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.following:

●

Gathering and compression costs decreased from $0.76 per Mcfe for the three months ended June 30, 2022 to $0.68 per Mcfe for the three months ended June 30, 2023, primarily due to due to lower fuel costs as a result of decreased commodity prices, partially offset by annual CPI-based adjustments between periods.

●

Processing costs increased from $0.75 per Mcfe for the three months ended June 30, 2022 to $0.85 per Mcfe for the three months ended June 30, 2023, primarily due to increased costs for NGLs processing, which includes an annual CPI-based adjustment during the first quarter of 2023, and higher NGLs transportation fees.

●

Transportation costs decreased from $0.73 per Mcfe for the three months ended June 30, 2022 to $0.61 per Mcfe for the three months ended June 30, 2023 primarily due to lower fuel costs as a result of lower commodity prices and demand fees between periods.

Production and ad valorem tax expense. Total production and ad valorem taxes ~~increased~~decreased from ~~$34~~$82 million for the three months ended June 30, ~~2021~~2022 to ~~$82~~$36 million for the three months ended June 30, ~~2022, an increase~~2023, a decrease of ~~$48~~$46 million, or ~~143%~~56%, primarily due to ~~higher~~lower 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~~increased from 5% for ~~each of~~ the three months ended June 30, ~~2021 and 2022.~~2022 to 8% for the three months ended June 30, 2023, primarily as a result of higher ad valorem taxes, which 2023 West Virginia ad valorem taxes are based on commodity prices during 2021.

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 to $40 million for the three months ended June 30, 2023, an increase of $8$4 million, or ~~30%~~11%, primarily due to higher salary and wage expense~~professional service fees~~ and ~~office operating~~software license costs ~~between periods. On a per-unit basis, general and administrative expense excluding equity-based compensation increased from $0.09~~

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between periods. We had 530 and 604 employees as of June 30, 2022 and 2023, respectively. General and administrative expense on a per ~~Mcfe for the three months ended June 30, 2021 to~~unit basis (excluding equity-based compensation) increased from $0.12 per Mcfe for the three months ended June 30, 2022 ~~primarily due~~ to $0.13 per Mcfe for the three months ended June 30, 2023 as a result of our higher overall general and administrative ~~expense and lower~~costs, partially offset by increased 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 to $14 million for the three months ended June 30, 2023, an increase of $4$6 million, or ~~92%~~65%, primarily due to an increase in the annual equity awards granted during the ~~second~~fourth quarter of 2022 and the first half of 2023 as compared to prior years, ~~partially offset~~which were temporarily and significantly reduced during 2020 and supplemented by our cash awards program. Our equity ~~award forfeitures. When an~~awards vest over three or four year service periods, and our equity ~~award is forfeited, expense previously recognized for the award is reversed.~~incentive program began returning to normal levels during 2021. 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~~DD&A expense remained relatively consistent at $173 million, or $0.59 per Mcfe, and ~~amortization (“DD&A”) expense decreased from $187~~$171 million, or $0.56 per Mcfe, for the three months ended June 30, ~~2021~~2022 and 2023, respectively. This decrease in DD&A expense per Mcfe between periods was primarily due to ~~$173~~higher reserve volumes during the three months ended June 30, 2023.

Impairment of property and equipment. Impairment of oil and gas properties decreased from $23 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~~$16 million for the three months ended June 30, ~~2022, an increase~~2023, a decrease of ~~$14~~$7 million, or ~~151%~~33%, primarily related to ~~higher~~lower 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

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 to $22 million, or $0.07 per Mcfe, for the three months ended June 30, 2023, primarily due to lower ~~volumes~~firm transportation commitments, partially offset by ~~higher gas~~lower 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~~$44 million for the three months ended June 30, ~~2021~~2023, a decrease of $62 million, or 59%. This fluctuation primarily resulted from the following:

●

Natural gas marketing revenue decreased by $41 million between periods primarily due to lower natural gas prices, partially offset by higher natural gas marketing volumes. Lower natural gas prices accounted for a $47 million decrease in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes), and higher natural gas marketing volumes accounted for an approximate $6 million increase in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price).

●

Oil marketing revenue decreased by $1 million between periods primarily due to lower oil prices, partially offset by higher oil marketing volumes. Lower oil prices accounted for an approximate $8 million decrease in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes), and 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).

●

Ethane marketing revenues were $20 million for the three months ended June 30, 2022. There were no ethane marketing revenues for the three months ended June 30, 2023.

Marketing expense. Marketing expense decreased from $131 million for the three months ended June 30, 2022 to $66 million for the three months ended June 30, 2023, a decrease of ~~$68~~$65 million, or ~~34%~~50%. 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~~ethane and oil purchases ~~of approximately $9~~decreased $44 million, $12 million and ~~$10~~$1 million, respectively, between periods. The total ~~costs~~cost of third-party commodity purchases decreased primarily due to lower commodity prices, partially offset by higher marketing volumes between ~~periods, partially offset by increased commodity prices.~~periods. Firm transportation costs were ~~$55~~$35 million for the three

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months ended June 30, 2022 and $27 million for the three months ended June 30, ~~2021 and $35 million for the three months ended June 30, 2022,~~2023, a decrease of ~~$20~~$8 million due to the reduction in firm transportation commitments and higher third-party ~~marketed~~marketing volumes between periods.

Antero Midstream Segment

Antero Midstream revenue. Revenue from the Antero Midstream segment ~~decreased~~increased from ~~$233 million for the three months ended June 30, 2021 to~~ $229 million for the three months ended June 30, 2022 ~~a decrease~~to $258 million for the three months ended June 30, 2023, an increase of $4$29 million, primarily due to ~~a decrease in~~higher low pressure ~~revenues due to higher fee rebates earned by us, partially offset by higher~~gathering, compression and high pressure gathering

~~Table of Contents~~

delivery revenues due to annual CPI-based adjustments and 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.~~periods.

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~~to $113 million ~~primarily due to an increase in depreciation expense during~~for the three months ended June 30, ~~2022. This~~2023, an increase isof $12 million, 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~~12 compressor stations that ~~came online~~were acquired during the fourth quarter of 2022 and higher wastewater trucking costs and equity-based compensation expense 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 to $28 million for the three months ended June 30, 2023, a decrease of ~~$16~~$6 million, or ~~32%~~18%, 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~~periods and ~~$1 million of amortization of debt issuance costs and debt discounts and premiums for~~lower Credit Facility borrowings between periods, partially offset by higher benchmark interest rates during the three months ended June 30, ~~2021 and 2022, respectively.~~2023.

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. There were no debt redemptions or repurchases during the three months ended June 30, 2023. 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,~~2022, 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. For the three months ended June 30, 2023, we had an income tax benefit of $30 million, with an effective tax rate of 31%, due to a loss before income taxes of $98 million. The ~~decrease~~increase in the effective tax rate between periods was primarily due to anthe net loss before income ~~tax benefit for the equity-based awards that vested~~taxes during the three months ended June 30, ~~2022 and~~2023 that when taken together with net income before taxes during the ~~impact of~~three months ended March 31, 2023 results in a 14% effective tax ~~law changes in West Virginia enacted in 2021.~~

rate for the six months ended June 30, 2023.

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Six Months Ended June 30, ~~2021~~2022 Compared to Six Months Ended June 30, ~~2022~~2023

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				Six Months Ended June 30, 2022
					Investment in		Intersegment								Equity Method
	Exploration				Antero		Transactions and				Exploration				Investment in		Elimination of
	and				Midstream		Unconsolidated		Consolidated		and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Corporation		Affiliates		Total		Production		Marketing		Midstream		Affiliate		Total
Revenue and other:
Natural gas sales	$	1,346,889		—		—		—		1,346,889	$	2,554,786		—		—		—		2,554,786
Natural gas liquids sales		904,700		—		—		—		904,700		1,362,693		—		—		—		1,362,693
Oil sales		96,592		—		—		—		96,592		152,479		—		—		—		152,479
Commodity derivative fair value losses		(1,009,596)		—		—		—		(1,009,596)		(1,277,042)		—		—		—		(1,277,042)
Gathering, compression, water handling and treatment		—		—		492,244		(492,244)		—
Gathering, compression and water handling												—		—		447,398		(447,398)		—
Marketing		—		330,243		—		—		330,243		—		175,188		—		—		175,188
Amortization of deferred revenue, VPP		22,429		—		—		—		22,429		18,647		—		—		—		18,647
Other income (loss)		21		—		(35,336)		35,336		21
Other revenue and income												1,774		—		—		—		1,774
Total revenue		1,361,035		330,243		456,908		(456,908)		1,691,278		2,813,337		175,188		447,398		(447,398)		2,988,525

Operating expenses:
Lease operating		46,192		—		—		—		46,192		43,033		—		—		—		43,033
Gathering and compression		444,361		—		78,869		(78,869)		444,361		425,112		—		36,525		(36,525)		425,112
Processing		393,947		—		—		—		393,947		409,701		—		—		—		409,701
Transportation		408,131		—		—		—		408,131		411,677		—		—		—		411,677
Water handling												—		—		48,786		(48,786)		—
Production and ad valorem taxes		78,391		—		—		—		78,391		134,650		—		—		—		134,650
Marketing		—		361,071		—		—		361,071		—		230,194		—		—		230,194
Exploration		5,857		—		—		—		5,857
Exploration and mine expenses												2,292		—		—		—		2,292
General and administrative (excluding equity-based compensation)		66,360		—		25,110		(25,110)		66,360		67,310		—		25,537		(25,537)		67,310
Equity-based compensation		9,891		—		7,071		(7,071)		9,891		12,820		—		8,473		(8,473)		12,820
Depletion, depreciation and amortization		381,356		—		53,469		(53,469)		381,356		341,783		—		63,975		(63,975)		341,783
Impairment of oil and gas properties		43,365		—		—		—		43,365
Impairment of midstream assets		—		—		1,379		(1,379)		—
Impairment of property and equipment												45,825		—		3,702		(3,702)		45,825
Accretion of asset retirement obligations		2,119		—		233		(233)		2,119		3,248		—		128		(128)		3,248
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)
Contract termination and other operating expenses												2,104		—		(150)		150		2,104
Loss on sale of assets												1,857		—		2,872		(2,872)		1,857
Total operating expenses		1,878,617		361,071		171,922		(171,922)		2,239,688		1,901,412		230,194		189,848		(189,848)		2,131,606
Operating income (loss)	$	(517,582)		(30,828)		284,986		(284,986)		(548,410)	$	911,925		(55,006)		257,550		(257,550)		856,919

Equity in earnings of unconsolidated affiliates	$	36,171		—		42,259		(42,259)		36,171	$	39,891		—		46,056		(46,056)		39,891

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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


	Six Months Ended June 30, 2023
					Equity Method
	Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream		Affiliate		Total
Revenue and other:
Natural gas sales	$	1,105,445		—		—		—		1,105,445
Natural gas liquids sales		893,168		—		—		—		893,168
Oil sales		109,773		—		—		—		109,773
Commodity derivative fair value losses		134,476		—		—		—		134,476
Gathering, compression and water handling		—		—		517,762		(517,762)		—
Marketing		—		102,322		—		—		102,322
Amortization of deferred revenue, VPP		15,151		—		—		—		15,151
Other revenue and income		1,318		—		—		—		1,318
Total revenue		2,259,331		102,322		517,762		(517,762)		2,361,653

Operating expenses:
Lease operating		58,069		—		—		—		58,069
Gathering and compression		424,295		—		49,272		(49,272)		424,295
Processing		499,910		—		—		—		499,910
Transportation		384,942		—		—		—		384,942
Water handling		—		—		61,196		(61,196)		—
Production and ad valorem taxes		85,434		—		—		—		85,434
Marketing		—		147,536		—		—		147,536
Exploration and mine expenses		1,506		—		—		—		1,506
General and administrative (excluding equity-based compensation)		84,632		—		20,683		(20,683)		84,632
Equity-based compensation		26,530		—		14,826		(14,826)		26,530
Depletion, depreciation and amortization		338,988		—		70,429		(70,429)		338,988
Impairment of property and equipment		31,270		—		—		—		31,270
Accretion of asset retirement obligations		2,082		—		88		(88)		2,082
Loss (gain) on sale of assets		(311)		—		5,569		(5,569)		(311)
Contract termination and other operating expenses		10,453		23,763		1,831		(1,831)		34,216
Total operating expenses		1,947,800		171,299		223,894		(223,894)		2,119,099
Operating income (loss)	$	311,531		(68,977)		293,868		(293,868)		242,554

Equity in earnings of unconsolidated affiliates	$	36,779		—		50,428		(50,428)		36,779

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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:~~segment:


					Amount of								Amount of
	Six Months Ended June 30,				Increase		Percent		Six Months Ended June 30,				Increase		Percent
	2021		2022		(Decrease)		Change		2022		2023		(Decrease)		Change
Production data ^{(1) (2)}:
Natural gas (Bcf)		415		402		(13)	(3)	%		402		398		(4)	(1)	%
C2 Ethane (MBbl)		8,761		8,030		(731)	(8)	%		8,030		12,555		4,525	56	%
C3+ NGLs (MBbl)		20,366		19,794		(572)	(3)	%		19,794		20,032		238	1	%
Oil (MBbl)		1,900		1,629		(271)	(14)	%		1,629		1,802		173	11	%
Combined (Bcfe)		601		579		(22)	(4)	%		579		604		25	4	%
Daily combined production (MMcfe/d)		3,323		3,197		(126)	(4)	%		3,197		3,337		140	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	%
Natural gas (per Mcf)									$	6.36		2.78		(3.58)	(56)	%
C2 Ethane (per Bbl) ⁽⁴⁾									$	19.59		9.73		(9.86)	(50)	%
C3+ NGLs (per Bbl)	$	40.52		60.90		20.38	50	%	$	60.90		38.49		(22.41)	(37)	%
Oil (per Bbl)	$	50.84		93.59		42.75	84	%	$	93.59		60.92		(32.67)	(35)	%
Weighted Average Combined (per Mcfe)	$	3.90		7.03		3.13	80	%	$	7.03		3.49		(3.54)	(50)	%
Average realized prices after effects of derivative settlements⁽³⁾:
Natural gas (per Mcf)	$	3.23		4.28		1.05	33	%	$	4.28		2.76		(1.52)	(36)	%
C2 Ethane (per Bbl)	$	8.74		19.53		10.79	123	%
C2 Ethane (per Bbl) ⁽⁴⁾									$	19.53		9.73		(9.80)	(50)	%
C3+ NGLs (per Bbl)	$	37.82		60.48		22.66	60	%	$	60.48		38.43		(22.05)	(36)	%
Oil (per Bbl)	$	48.90		92.86		43.96	90	%	$	92.86		60.55		(32.31)	(35)	%
Weighted Average Combined (per Mcfe)	$	3.80		5.57		1.77	47	%	$	5.57		3.47		(2.10)	(38)	%
Average costs (per Mcfe):
Lease operating	$	0.08		0.07		(0.01)	(13)	%	$	0.07		0.10		0.03	43	%
Gathering and compression	$	0.74		0.73		(0.01)	(1)	%	$	0.73		0.70		(0.03)	(4)	%
Processing	$	0.65		0.71		0.06	9	%	$	0.71		0.83		0.12	17	%
Transportation	$	0.68		0.71		0.03	4	%	$	0.71		0.64		(0.07)	(10)	%
Production and ad valorem taxes	$	0.13		0.23		0.10	77	%	$	0.23		0.14		(0.09)	(39)	%
Marketing expense, net	$	0.05		0.10		0.05	100	%	$	0.10		0.07		(0.03)	(30)	%
General and administrative (excluding equity-based compensation)									$	0.12		0.14		0.02	17	%
Depletion, depreciation, amortization and accretion	$	0.64		0.60		(0.04)	(6)	%	$	0.60		0.56		(0.04)	(7)	%
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~~2023 includes ~~$85~~$7 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.~~take-or-pay contract. Excluding the effect of ~~the litigation~~these proceeds, ~~received,~~ the average realized price for ~~natural gas~~ethane before and after the effects of derivatives would have been ~~$3.04~~$9.17 per ~~Mcf for the six months ended June 30, 2021.~~Bbl.

Natural gas sales. Revenues from sales of natural gas ~~increased~~decreased from ~~$1.3~~$2.6 billion for the six months ended June 30, ~~2021~~2022 to ~~$2.6~~$1.1 billion ~~which included litigation proceeds of $85 million,~~ for the six months ended June 30, ~~2022, an increase~~2023, a decrease of ~~$1.3 billion,~~$1.5 million, or ~~90%~~57%. ~~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~~Lower commodity prices (excluding the effects of derivative settlements) during the six months ended June 30, ~~2022~~2023 accounted for an approximate ~~$1.3~~$1.4 billion ~~increase~~decrease 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~~$27 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)~~price). ~~See Note 14—Contingencies to the unaudited condensed consolidated financial statements for further discussion on the litigation proceeds.~~

~~Table of Contents~~

NGLs sales. Revenues from sales of NGLs ~~increased~~decreased 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~~to $893 million for the six months ended June 30, 2023, a decrease of ~~$458~~$470 million, or ~~51%~~34%. ~~Higher~~Lower commodity prices (excluding the effects of derivative settlements) during the six months ended June 30, ~~2022~~2023 accounted for an approximate ~~$488~~$573 million ~~increase~~decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). ~~Lower~~Higher NGLs production volumes accounted for an approximate ~~$30~~$103 million ~~decrease~~increase in year-over-year ~~NGL~~NGLs revenues (calculated as the change in year-to-year volumes times the prior year average price).

Table of Contents

Oil sales. Revenues from sales of oil ~~increased~~decreased from ~~$97 million for the six months ended June 30, 2021 to~~ $152 million for the six months ended June 30, 2022 ~~an increase~~to $110 million for the six months ended June 30, 2023, a decrease of ~~$55~~$42 million, or ~~58%~~28%. ~~Higher~~Lower oil prices, excluding the effects of derivative settlements, accounted for an approximate ~~$69~~$58 million ~~increase~~decrease in year-over-year oil revenues (calculated as the change in the year-to-year average price times current year production volumes). ~~Lower~~Higher oil production volumes during the six months ended June 30, ~~2022~~2023 accounted for an approximate ~~$14~~$16 million ~~decrease~~increase 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~~Our commodity derivatives included variable price swap contracts, swaptions, basis swap contracts, call options and ~~collar contracts when we believe that favorable future sales prices for our production can be secured.~~embedded put options. 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 and 2023, our commodity hedges resulted in derivative fair value losses of $1.3 ~~billion. Commodity derivative~~billion and fair value ~~losses included $65~~gains of $134 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.~~respectively. For the six months ended June 30, 2022, commodity derivative fair value losses included $845 million of cash payments on settled commodity derivative losses. For the six months ended June 30, 2023, commodity derivative fair value gains included $11 million of cash payments on settled commodity derivative losses and a $202 million cash payment for the early settlement of our swaption.

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~~Additionally, substantially all of our production is currently unhedged for 2023 and beyond, which limits our exposure to volatility in ~~commodity prices and~~ the ~~related~~ fair value of our derivative instruments related to commodity price changes in the future.

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 to $15 million for the six months ended June 30, 2023, a decrease of $3$4 million or ~~17%~~19%, primarily due to ~~a decrease in~~lower production ~~volumes. Under~~volumes attributable to the ~~terms~~VPP properties between periods. Amortization of the ~~agreement,~~deferred revenues associated with the VPP are recognized as the production volumes are delivered at ~~approximately~~ $1.61 per MMBtu over the contractual term.

Lease operating expense. Lease operating expense ~~decreased~~increased 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 to $58 million, or $0.10 per Mcfe for the six months ended June 30, 2023, an increase of $15 million or $0.03 per Mcfe, primarily due to ~~lower~~higher oilfield service and produced water ~~disposal costs, partially offset by higher workover~~handling costs.

Gathering, compression, processing and transportation expense. Gathering, compression, processing and transportation expense ~~remained consistent at~~increased from $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$1.3 billion for the six months ended June 30, ~~2021 to $0.71 per Mcfe for~~2023, an increase of $0.1 billion, or 5%. This fluctuation primarily resulted from 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.following:

●

Gathering and compression costs on a per unit basis decreased from $0.73 per Mcfe for the six months ended June 30, 2022 to $0.70 per Mcfe for the six months ended June 30, 2023, primarily due to lower fuel costs as a result of decreased commodity prices, partially offset by annual CPI-based based adjustments between periods.

●

Processing costs on a per unit basis increased from $0.71 per Mcfe for the six months ended June 30, 2022 to $0.83 per Mcfe for the six months ended June 30, 2023, primarily due to increased costs for NGLs processing and transportation, which include annual CPI-based and commodity based adjustments, as well as higher terminal fees and ethane transportation.

●

Transportation costs on a per unit basis decreased from $0.71 per Mcfe for the six months ended June 30, 2022 to $0.64 per Mcfe for the six months ended June 30, 2023 primarily due to lower fuel costs as a result of lower commodity prices between periods.

Production and ad valorem tax expense. Production and ad valorem taxes ~~increased~~decreased from ~~$78~~$135 million for the six months ended June 30, ~~2021~~2022 to ~~$135~~$85 million for the six months ended June 30, ~~2022, an increase~~2023, a decrease of ~~$57~~$50 million, or ~~72%~~37%, primarily due to ~~higher~~lower commodity prices between periods, partially offset by ~~$5 million for the litigation judgment in 2021.~~higher production volumes between periods. Production and ad valorem taxes as a percentage of natural gas revenues ~~remained relatively consistent at 6% and~~increased from 5% for the six months ended June 30, ~~2021 and~~ 2022 ~~respectively.~~to 8% for the six months ended June 30, 2023 primarily as a result of higher ad valorem taxes, which 2023 West Virginia ad valorem taxes are based on commodity prices during 2021.

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General and administrative expense. General and administrative expense (excluding equity-based compensation expense) ~~remained relatively consistent at $66 million and~~increased from $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$85 million for the six months ended June 30, ~~2021~~2023, an increase of $18 million, or 26%, primarily due to higher salary and wage expense, software license costs, office operating costs and professional service fees between periods. We had 530 and 604 employees as of June 30, 2022 and 2023, respectively. General and administrative expense on a per unit basis (excluding equity-based compensation) increased from $0.12 per Mcfe ~~during~~for the six months ended June 30, 2022 to $0.14 per Mcfe for the six months ended June 30, 2023 as a result of ~~lower~~our higher overall general and administrative costs, partially offset by increased 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 to $27 million for the six months ended June 30, 2023, an increase of $3$14 million, ~~or 30%,~~ primarily due to an increase in the annual equity awards granted during the ~~second~~fourth quarter of 2022 and first half of 2023 as compared to prior years, ~~partially offset~~which were temporarily and significantly reduced during 2020 and supplemented by our cash awards program. Our equity ~~award forfeitures. When an~~awards vest over three or four year service periods, and our equity ~~award is forfeited, expense previously recognized for the award is reversed.~~incentive program began returning to normal levels in 2021. 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”). DD&A expense ~~decreased from $381 million for the six months ended June 30, 2021 to~~remained relatively consistent at $342 million, ~~for the six months ended June 30, 2022, a decrease of $39~~or $0.60 per Mcfe, and $339 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$0.56 per Mcfe, for the six months ended June 30, 2022 and 2023, respectively. This decrease in DD&A expense per Mcfe between periods was primarily ~~as a result of increased proved~~due to higher reserve volumes ~~between periods.~~during the six months ended June 30, 2023.

Impairment of ~~oil~~property and ~~gas properties~~equipment. Impairment of oil and gas properties ~~increased~~decreased from ~~$43~~$46 million for the six months ended June 30, ~~2021~~2022 to ~~$46~~$31 million for the six months ended June 30, ~~2022, an increase~~2023, a decrease of $3$15 million, or 6%32%, primarily related to ~~higher~~lower 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~~(calculated as marketing revenues less marketing expense) decreased 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~~$45 million, or $0.07 per Mcfe, for the six months ended June 30, ~~2021~~2023, primarily due to lower firm transportation commitments partially offset by lower marketing margins between periods.

Marketing revenue. Marketing revenue decreased from $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~~$102 million for the six months ended June 30, ~~2021~~2023, a decrease of $73 million, or 42%. This fluctuation primarily resulted from the following:

●

Natural gas marketing revenue decreased by $41 million between periods primarily due to lower natural gas prices, partially offset by higher natural gas marketing volumes. Lower natural gas prices accounted for an approximate $57 million decrease in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes), and higher natural gas marketing volumes accounted for a $16 million increase in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price).

●

Oil marketing revenue increased by $2 million between periods primarily due to higher marketing volumes, partially offset by lower oil prices. Higher oil marketing volumes accounted for a $15 million increase in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and lower oil prices accounted for an approximate $13 million decrease in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes).

●

Ethane marketing revenues were $34 million for the six months ended June 30, 2022. There were no third-party ethane marketing revenues for the six months ended June 30, 2023.

Marketing expense. Marketing expense decreased from $230 million for the six months ended June 30, 2022 to $148 million for the six months ended June 30, 2023, a decrease of ~~$131~~$82 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~~firm capacity. The cost of third-party natural gas and ethane purchases decreased $49 million and $19 million, respectively, partially offset by oil purchase increases of $4 million. The total cost of third-party commodity purchases decreased primarily due to lower commodity prices between periods, partially offset by higher third-party natural gas and oil marketing volumes. Firm transportation costs were $73 million for the six months ended June 30, 2022 and $55 million for the six months ended June 30, 2023, a decrease of $18 million due to the reduction in firm transportation commitments and higher third-party marketing volumes between periods.

Contract termination and other operating expenses. Our marketing segment did not incur any contract termination and other operating expenses for the six months ended June 30, 2022. Contract termination and other operating expenses attributable to our marketing segment for the six months ended June 30, 2023, are due to a $24 million payment for the early termination of our firm transportation commitment of 200,000 MMBtu per day on the Equitrans pipeline.

Antero Midstream Segment

Antero Midstream revenue. Revenue from the Antero Midstream segment ~~decreased~~increased from ~~$457 million for the six months ended June 30, 2021 to~~ $447 million for the six months ended June 30, 2022 ~~a decrease~~to $518 million for the six months ended June 30, 2023, an increase of ~~$10~~$71 million, primarily due to ~~a decrease in low pressure revenues due to higher fee rebates earned by us~~increased throughput 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~~handling volumes between periods as well as higher low pressure, compression, ~~and~~ high pressure and fresh water handling fees primarily as a result of an annual CPI-based ~~adjustment.~~adjustments and higher water handling fees primarily due to increased costs.

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 to $224 million for the six months ended June 30, 2023, an increase of ~~$18~~$34 million, primarily due to ~~an increase in~~increased direct operating costs, depreciation expense and equity-based compensation expense during the six months ended June 30, ~~2022. This~~2023, partially offset by lower general and administrative (excluding equity-based compensation) costs between periods Direct operating costs increased between periods primarily as a result of 12 compressors that were acquired during the fourth quarter of 2022, increased heavy maintenance expense and higher wastewater trucking expense between periods. The increase in depreciation expense is primarily a result of the 12 compressors that were acquired during the fourth quarter of 2022 and a phased early retirement of an underutilized compressor station, which ~~allows~~allowed 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~~were certain costs associated with the underutilized compressor station that ~~cannot~~could not be relocated or reused that ~~will be~~were fully depreciated over the ~~remaining period~~first half of ~~use. Additionally, operating expenses were higher~~2023. Antero Midstream also had incremental depreciation expense related to gathering and compression assets acquired or placed in service 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.~~periods.

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 to $54 million for the six months ended June 30, 2023, a decrease of ~~$21~~$18 million or ~~22%~~25%, primarily due to the reduction in debt as a result of the repurchase of certain of our unsecured senior notes between ~~periods.~~periods and lower Credit Facility borrowings between periods, partially offset by higher benchmark interest rates during the six months ended June 30, 2023.

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. D~~uring 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~~notes and $13 million of our 2026 Notes, which resulted in a loss on early debt extinguishment of $15 million. There were no debt redemptions or repurchases during the six months ended June 30, 2023.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)~~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 an income tax expense of $172 million, with an effective tax rate of 21%, due to income before income taxes of $810 million. For the six months ended June 30, 2023, we had income tax expense of $32 million, with an effective tax rate of 14%, due to income before income taxes of $226 million. The decrease in the effective tax rate between periods was primarily due to anlower income ~~tax benefit for~~before income taxes and the ~~equity-based awards that vested during the six months ended June 30, 2022, partially offset by a higher amount~~effects of ~~taxable income being apportioned to West Virginia.~~noncontrolling interests.

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”),~~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,

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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,~~2023, 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,				Six Months Ended June 30,
	2021		2022		2022		2023
Net cash provided by operating activities	$	872,272		1,488,385	$	1,488,385		499,165
Net cash used in investing activities		(302,878)		(474,834)		(474,834)		(638,040)
Net cash used in financing activities		(564,853)		(1,013,551)
Net cash provided by (used in) financing activities						(1,013,551)		138,875
Net increase in cash and cash equivalents	$	4,541		—	$	—		—

Operating ~~Activities.~~activities. Net cash provided by operating activities was ~~$872 million and~~ $1.5 billion and $499 million for the six months ended June 30, ~~2021~~2022 and ~~2022,~~2023, respectively. Net cash provided by operating activities ~~increased~~decreased primarily due to ~~increases in~~lower commodity prices, ~~both before~~a $202 million payment for early settlement of our swaption agreement and ~~after the effects of settled commodity derivatives,~~increased gathering compression, processing and transportation expenses, contract termination expense, general and administrative expenses (excluding equity-based compensation expense) and lease operating expenses, partially offset by ~~decreased~~increased production and ~~increased (i) cash utilized for working capital, (ii)~~decreased net marketing expense, ~~and (iii)~~ production and ad valorem taxes and interest expense 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.~~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 to $638 million for the six months ended June 30, 2023, primarily due to an increase in capital expenditures of ~~$171~~$160 million between periods. The increase in capital expenditures between periods is primarily due to increased drilling and completions activity and land purchases, as well as higher drilling and water costs between periods.

Financing ~~Activities~~activities.. Net cash flows used in financing activities ~~increased from $565 million~~ for the six months ended June 30, ~~2021~~2022 were $1.0 billion, as compared to ~~$1.0 billion~~$139 million in net cash flows provided by financing activities 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~~.2023. During the six months ended June 30, 2022, we ~~(i)~~ redeemed $585 million aggregate principal amount of our 2025 Notes, repurchased $50 million of our 2029 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. During the six months ended June 30, 2023, we borrowed $325 million, net, on our Credit Facility, partially offset by distributions to the noncontrolling interests in Martica of $83 million, repurchases of approximately 3 million shares of our common stock at a total cost of $75 million and payments for employee withholding taxes for vested equity-based awards of $27 million.

~~2022~~2023 Capital Budget and Capital Spending

On ~~July 27, 2022,~~February 15, 2023, we announced a ~~revised~~ net capital budget for ~~2022~~2023 of ~~$825 million~~$1.025 billion to ~~$860 million.~~$1.075 billion. Our ~~revised~~ budget includes: a range of ~~$725~~$875 million to ~~$750~~$925 million for drilling and completion and ~~a range of $100 million to $110~~$150 million for leasehold expenditures. We do not budget for acquisitions. During ~~2022,~~2023, 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.

For the three months ended June 30, 2023, our total consolidated capital expenditures were $287 million, including drilling and completion costs of $247 million, leasehold acquisitions of $36 million and other capital expenditures of $4 million. For the six months ended June 30, 2023, our total consolidated capital expenditures were $628 million, including

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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~~$514 million, leasehold acquisitions of ~~$49~~$107 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$7 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~~2022 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~~2022 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~~2022 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,~~2023, 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~~2022 and ~~2022.~~2023.

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,~~2023, 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 may 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,~~2023, we had in place natural gas swaps and basis swaps, as well as a call option and embedded put option covering portions of our projected ~~production through~~production. Substantially all of our derivative arrangements terminate by December 31, 2023. Our commodity hedge position as of June 30, ~~2022~~2023 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, call option and embedded put option that settled during the six months ended June 30, ~~2022,~~2023, our revenues would have decreased by ~~approximately $47~~$73 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.~~2023.
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 December 31, 2022 and June 30, ~~2022,~~2023, the estimated fair value of our commodity derivative instruments was a net liability ~~of $1.2 billion comprised of current~~$431 million 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~~$84 million, respectively, comprised of current and noncurrent assets and liabilities.
~~By removing price volatility from a portion~~Due to our improved liquidity and leverage position as compared to past levels, the percentage of our expected production that we hedge has decreased. For the three and six months ended June 30, 2022, 34% and 35%, respectively, of our production was hedged through ~~December 2024, we have mitigated, but not eliminated,~~fixed price commodity swaps as compared to 1% and 2% for 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.three and six months ended

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June 30, 2023, respectively. Assuming our 2023 production is the same as our production in 2022, 1% of our production for 2023 will be hedged through fixed price commodity swaps.

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~~304 million as of June 30, ~~2022)~~2023), which we market to energy companies, end users and ~~refineries.~~refineries, and commodity derivative contracts ($11 million as of June 30, 2023).

ByWe are subject to credit risk due to the concentration of our receivables from several significant customers for sales of natural gas, NGLs and oil. While we do at times require customers to post letters of credit or other credit support in connection with their obligations, 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.

In addition, 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 10three different counterparties, 7one of which are lenders under ~~our~~the Credit Facility. As of June 30, ~~2022, we did not have any~~2023, substantially all of our derivative assets ~~by bank counterparties under~~were with one counterparty that is not affiliated with 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~~2023 for each of the European and American banks. We believe that all of ~~these institutions,~~our counterparties 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,~~2023, 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~~2023 was ~~approximately 4.52%~~7.17%. We estimate that a 1.0% increase in the applicable average interest rates for the six months ended June 30, ~~2022~~2023 would have resulted in an estimated ~~$1.0~~$1.1 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~~2023 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~~2023 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~~2022 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

Total Number

Approximate

of Shares

Dollar Value

of Shares

Dollar Value

Repurchased

of Shares

Repurchased

of Shares

as Part of

that May

as Part of

that May

Total Number

Publicly

Yet be Purchased

Total Number

Publicly

Yet be Purchased

of Shares

Average Price

Announced

Under the Plan ⁽²⁾

of Shares

Average Price

Announced

Under the Plan

Period

Purchased

Paid Per Share

Plans

($ in thousands)

Purchased ⁽¹⁾

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
April 1, 2023 - April 30, 2023

510,131

23.89

—

$
1,234,929

May 1, 2023 - May 31, 2023

175,879

21.10

—

1,234,929

June 1, 2023 - June 30, 2023

—

—

—

1,234,929

Total

6,749,418

$
36.66

5,240,378

686,010

$
23.17

—

(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~~equity awards 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

Certificate of Amendment to Second Amended and Restated ~~Bylaws~~Certificate of Incorporation of Antero Resources Corporation, dated June 8, 2023 (incorporated by reference to Exhibit ~~3.2~~3.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-36120) filed on ~~October 17, 2013).~~June 8, 2023).

10.1*3.3

~~Form~~Second Amended and Restated Bylaws of ~~Performance Share Unit Grant Notice and Performance Share Unit Agreement under the~~ Antero Resources Corporation, ~~2020 Long-Term Incentive Plan.~~dated February 14, 2023 (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 10-K (Commission File No. 001-36120) filed on February 15, 2023).

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~~2023 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations and Comprehensive ~~Loss,~~Income (Loss), (iii) Condensed Consolidated Statements of Equity, (iv) Condensed Consolidated Statements of Cash Flows, and (v) Notes to the Condensed Consolidated Financial Statements, tagged as blocks of text.

104

Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

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

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

ANTERO RESOURCES CORPORATION

By:
/s/ MICHAEL N. KENNEDY

Michael N. Kennedy

Chief Financial Officer and Senior Vice President–Finance

Date:
July ~~27, 2022~~26, 2023

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS		21
PART I—FINANCIAL INFORMATION		43
Item 1.	Financial Statements (Unaudited)	43
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3734
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	5451
Item 4.	Controls and Procedures	55
		52
PART II—OTHER INFORMATION		5653
Item 1.	Legal Proceedings	5653
Item 1A.	Risk Factors	5653
Item 2.	Unregistered Sales of Equity Securities	5653
Item 4.	Mine Safety Disclosures	5653
Item 6.	Exhibits	5754
SIGNATURES		5855


				Total Number	Approximate					Total Number	Approximate
				of Shares	Dollar Value					of Shares	Dollar Value
				Repurchased	of Shares					Repurchased	of Shares
				as Part of	that May					as Part of	that May
	Total Number			Publicly	Yet be Purchased		Total Number			Publicly	Yet be Purchased
	of Shares	Average Price		Announced	Under the Plan ⁽²⁾		of Shares	Average Price		Announced	Under the Plan
Period	Purchased	Paid Per Share		Plans	($ in thousands)		Purchased ⁽¹⁾	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
April 1, 2023 - April 30, 2023							510,131		23.89	—	$	1,234,929
May 1, 2023 - May 31, 2023							175,879		21.10	—		1,234,929
June 1, 2023 - June 30, 2023							—		—	—		1,234,929
Total	6,749,418	$	36.66	5,240,378			686,010	$	23.17	—


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		Certificate of Amendment to Second Amended and Restated ~~Bylaws~~Certificate of Incorporation of Antero Resources Corporation, dated June 8, 2023 (incorporated by reference to Exhibit ~~3.2~~3.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-36120) filed on ~~October 17, 2013).~~June 8, 2023).
10.1*3.3		~~Form~~Second Amended and Restated Bylaws of ~~Performance Share Unit Grant Notice and Performance Share Unit Agreement under the~~ Antero Resources Corporation, ~~2020 Long-Term Incentive Plan.~~dated February 14, 2023 (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 10-K (Commission File No. 001-36120) filed on February 15, 2023).
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~~2023 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations and Comprehensive ~~Loss,~~Income (Loss), (iii) Condensed Consolidated Statements of Equity, (iv) Condensed Consolidated Statements of Cash Flows, and (v) Notes to the Condensed Consolidated Financial Statements, tagged as blocks of text.
104		Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).


ANTERO RESOURCES CORPORATION

By:	/s/ MICHAEL N. KENNEDY
	Michael N. Kennedy
	Chief Financial Officer and Senior Vice President–Finance

Date:	July ~~27, 2022~~26, 2023