Antero Resources 10Q 2024 Q2 Quarterly report

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, 2024


☐	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

Number of shares of the registrant’s common stock outstanding as of July 26, 2024 (in thousands): 311,007

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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 and in our Annual Report on Form 10-K for the year ended December 31, 2023. 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 natural gas, natural gas liquids (“NGLs”) and oil 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 acquisitions, expansion projects, working capital requirements and the repayment or refinancing of indebtedness;

●

our ability to execute our return of capital program;

●

natural gas, NGLs and oil prices;

●

impacts of geopolitical events, including the conflicts in Ukraine and in the Middle East, and world health 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;

●

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 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, 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, 2023 (the “2023 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, except per share amounts)


			(Unaudited)
	December 31,		June 30,
	2023		2024
Assets
Current assets:
Accounts receivable	$	42,619		23,552
Accrued revenue		400,805		362,451
Derivative instruments		5,175		2,440
Prepaid expenses		12,901		9,789
Other current assets		14,192		10,758
Total current assets		475,692		408,990
Property and equipment:
Oil and gas properties, at cost (successful efforts method):
Unproved properties		974,642		963,023
Proved properties		13,908,804		14,179,028
Gathering systems and facilities		5,802		5,802
Other property and equipment		98,668		106,684
		14,987,916		15,254,537
Less accumulated depletion, depreciation and amortization		(5,063,274)		(5,296,438)
Property and equipment, net		9,924,642		9,958,099
Operating leases right-of-use assets		2,965,880		2,797,447
Derivative instruments		5,570		3,176
Investment in unconsolidated affiliate		222,255		223,552
Other assets		25,375		24,579
Total assets	$	13,619,414		13,415,843
Liabilities and Equity
Current liabilities:
Accounts payable	$	38,993		38,229
Accounts payable, related parties		86,284		97,455
Accrued liabilities		381,340		365,347
Revenue distributions payable		361,782		329,375
Derivative instruments		15,236		22,756
Short-term lease liabilities		540,060		525,636
Deferred revenue, VPP		27,101		26,153
Other current liabilities		1,295		1,061
Total current liabilities		1,452,091		1,406,012
Long-term liabilities:
Long-term debt		1,537,596		1,591,208
Deferred income tax liability, net		834,268		830,826
Derivative instruments		32,764		23,516
Long-term lease liabilities		2,428,450		2,268,031
Deferred revenue, VPP		60,712		48,184
Other liabilities		59,431		56,107
Total liabilities		6,405,312		6,223,884
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; 303,544 and 310,988 shares issued and outstanding as of December 31, 2023 and June 30, 2024, respectively		3,035		3,110
Additional paid-in capital		5,846,541		5,879,390
Retained earnings		1,131,828		1,102,510
Total stockholders' equity		6,981,404		6,985,010
Noncontrolling interests		232,698		206,949
Total equity		7,214,102		7,191,959
Total liabilities and equity	$	13,619,414		13,415,843

See accompanying notes to unaudited condensed consolidated financial statements.

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ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Operations and Comprehensive Loss (Unaudited)

(In thousands, except per share amounts)


	Three Months Ended June 30,
	2023		2024
Revenue and other:
Natural gas sales	$	437,130		374,568
Natural gas liquids sales		397,733		489,191
Oil sales		57,962		63,458
Commodity derivative fair value gains (losses)		8,284		(5,585)
Marketing		43,793		49,418
Amortization of deferred revenue, VPP		7,618		6,739
Other revenue and income		785		865
Total revenue		953,305		978,654
Operating expenses:
Lease operating		28,748		29,759
Gathering, compression, processing and transportation		663,975		663,442
Production and ad valorem taxes		36,158		41,933
Marketing		66,175		70,807
Exploration		743		643
General and administrative (including equity-based compensation expense of $13,512 and $17,151 in 2023 and 2024, respectively)		53,901		59,428
Depletion, depreciation and amortization		171,406		170,536
Impairment of property and equipment		15,710		313
Accretion of asset retirement obligations		1,204		780
Contract termination and loss contingency		4,441		3,009
Gain on sale of assets		(220)		(18)
Other operating expense		—		11
Total operating expenses		1,042,241		1,040,643
Operating loss		(88,936)		(61,989)
Other income (expense):
Interest expense, net		(27,928)		(32,681)
Equity in earnings of unconsolidated affiliate		19,098		20,881
Total other expense		(8,830)		(11,800)
Loss before income taxes		(97,766)		(73,789)
Income tax benefit		29,833		13,334
Net loss and comprehensive loss including noncontrolling interests		(67,933)		(60,455)
Less: net income and comprehensive income attributable to noncontrolling interests		15,151		5,208
Net loss and comprehensive loss attributable to Antero Resources Corporation	$	(83,084)		(65,663)

Loss per common share—basic	$	(0.28)		(0.21)
Loss per common share—diluted	$	(0.28)		(0.21)

Weighted average number of common shares outstanding:
Basic		300,141		310,806
Diluted		300,141		310,806

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,
	2023		2024
Revenue and other:
Natural gas sales	$	1,105,445		848,701
Natural gas liquids sales		893,168		1,007,053
Oil sales		109,773		128,175
Commodity derivative fair value gains		134,476		3,861
Marketing		102,322		97,938
Amortization of deferred revenue, VPP		15,151		13,477
Other revenue and income		1,318		1,720
Total revenue		2,361,653		2,100,925
Operating expenses:
Lease operating		58,069		58,880
Gathering, compression, processing and transportation		1,309,147		1,335,723
Production and ad valorem taxes		85,434		100,101
Marketing		147,536		130,620
Exploration and mine expenses		1,506		1,245
General and administrative (including equity-based compensation expense of $26,530 and $33,228 in 2023 and 2024, respectively)		111,162		115,290
Depletion, depreciation and amortization		338,988		343,590
Impairment of property and equipment		31,270		5,503
Accretion of asset retirement obligations		2,082		1,556
Contract termination and loss contingency		33,991		5,048
Loss (gain) on sale of assets		(311)		170
Other operating expense		225		28
Total operating expenses		2,119,099		2,097,754
Operating income		242,554		3,171
Other income (expense):
Interest expense, net		(53,628)		(62,868)
Equity in earnings of unconsolidated affiliate		36,779		44,228
Loss on convertible note inducement		(86)		—
Total other expense		(16,935)		(18,640)
Income (loss) before income taxes		225,619		(15,469)
Income tax benefit (expense)		(32,350)		3,301
Net income (loss) and comprehensive income (loss) including noncontrolling interests		193,269		(12,168)
Less: net income and comprehensive income attributable to noncontrolling interests		62,922		17,150
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$	130,347		(29,318)

Net income (loss) per common share—basic	$	0.44		(0.10)
Net income (loss) per common share—diluted	$	0.42		(0.10)

Weighted average number of common shares outstanding:
Basic		298,461		307,875
Diluted		311,488		307,875

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		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

Balances, December 31, 2023		303,544	$	3,035		5,846,541		1,131,828		—	$	—		232,698		7,214,102
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		552		6		(9,030)		—		—		—		—		(9,024)
Conversion of 2026 Convertible Notes		6,074		61		25,990		—		—		—		—		26,051
Equity-based compensation		—		—		16,077		—		—		—		—		16,077
Distributions to noncontrolling interests		—		—		—		—		—		—		(23,617)		(23,617)
Net income and comprehensive income		—		—		—		36,345		—		—		11,942		48,287
Balances, March 31, 2024		310,170		3,102		5,879,578		1,168,173		—		—		221,023		7,271,876
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		818		8		(17,339)		—		—		—		—		(17,331)
Equity-based compensation		—		—		17,151		—		—		—		—		17,151
Distributions to noncontrolling interests		—		—		—		—		—		—		(19,282)		(19,282)
Net income (loss) and comprehensive income (loss)		—		—		—		(65,663)		—		—		5,208		(60,455)
Balances, June 30, 2024		310,988	$	3,110		5,879,390		1,102,510		—	$	—		206,949		7,191,959

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,
	2023		2024
Cash flows provided by (used in) operating activities:
Net income (loss) including noncontrolling interests	$	193,269		(12,168)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion		341,070		345,146
Impairments		31,270		5,503
Commodity derivative fair value gains		(134,476)		(3,861)
Gains (losses) on settled commodity derivatives		(10,787)		7,262
Payments for derivative monetizations		(202,339)		—
Deferred income tax expense (benefit)		32,288		(3,442)
Equity-based compensation expense		26,530		33,228
Equity in earnings of unconsolidated affiliate		(36,779)		(44,228)
Dividends of earnings from unconsolidated affiliate		62,569		62,569
Amortization of deferred revenue		(15,151)		(13,477)
Amortization of debt issuance costs and other		1,732		1,328
Settlement of asset retirement obligations		(633)		(1,680)
Contract termination and loss contingency		—		3,006
Loss (gain) on sale of assets		(311)		170
Loss on convertible note inducement		86		—
Changes in current assets and liabilities:
Accounts receivable		(1,399)		19,067
Accrued revenue		384,245		38,354
Prepaid expenses and other current assets		21,294		6,547
Accounts payable including related parties		12,701		6,616
Accrued liabilities		(102,668)		(14,830)
Revenue distributions payable		(108,723)		(32,406)
Other current liabilities		5,377		2,405
Net cash provided by operating activities		499,165		405,109
Cash flows provided by (used in) investing activities:
Additions to unproved properties		(110,447)		(43,571)
Drilling and completion costs		(517,591)		(362,228)
Additions to other property and equipment		(9,058)		(9,035)
Proceeds from asset sales		311		418
Change in other assets		(1,255)		291
Net cash used in investing activities		(638,040)		(414,125)
Cash flows provided by (used in) financing activities:
Repurchases of common stock		(75,356)		—
Borrowings on Credit Facility		2,533,300		1,950,000
Repayments on Credit Facility		(2,208,200)		(1,871,200)
Convertible note inducement		(86)		—
Distributions to noncontrolling interests in Martica Holdings LLC		(83,084)		(42,899)
Employee tax withholding for settlement of equity-based compensation awards		(27,357)		(26,355)
Other		(342)		(530)
Net cash provided by financing activities		138,875		9,016
Net increase in cash and cash equivalents		—		—
Cash and cash equivalents, beginning of period		—		—
Cash and cash equivalents, end of period	$	—		—

Supplemental disclosure of cash flow information:
Cash paid during the period for interest	$	51,927		63,512
Decrease in accounts payable and accrued liabilities for additions to property and equipment	$	(8,353)		(2,967)

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 SEC applicable to interim financial information and should be read in the context of the Company’s December 31, 2023 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, 2023 consolidated financial statements were included in Antero Resources’ 2023 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, 2023 and June 30, 2024, results of operations for the three and six months ended June 30, 2023 and 2024 and cash flows for the six months ended June 30, 2023 and 2024. 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 three and six months ended June 30, 2024 are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received for natural gas, NGLs and oil, natural production declines, the uncertainty of exploration and development drilling results, fluctuations in the fair value of derivative instruments and other factors.

(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, 2023, the book overdrafts included within accounts payable and revenue distributions payable were $11 million and $19 million, respectively. As of June 30, 2024, the book overdrafts included within accounts payable and revenue distributions payable were $5 million and $16 million, respectively.

(d)	Net Income (Loss) Per Common Share

Net 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 common shares outstanding during the period. Net income (loss) per common share—diluted for each period is computed after giving consideration to the potential dilution from (i) outstanding equity-based 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 (“PSU”) awards and stock options in the calculation of diluted

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

weighted average common 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 common shares outstanding are equal to basic weighted average common shares outstanding because the effects of all equity-based awards and the 2026 Convertible Notes are anti-dilutive.

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2024		2023		2024
Net income (loss) attributable to Antero Resources Corporation—common shareholders	$	(83,084)		(65,663)		130,347		(29,318)
Add: Interest expense for 2026 Convertible Notes		—		—		1,085		—
Less: Tax-effect of interest expense for 2026 Convertible Notes		—		—		(233)		—
Net income (loss) attributable to Antero Resources Corporation—common shareholders and assumed conversions	$	(83,084)		(65,663)		131,199		(29,318)

Net income (loss) per common share—basic	$	(0.28)		(0.21)		0.44		(0.10)
Net income (loss) per common share—diluted	$	(0.28)		(0.21)		0.42		(0.10)

Weighted average common shares outstanding—basic		300,141		310,806		298,461		307,875
Weighted average common shares outstanding—diluted		300,141		310,806		311,488		307,875

The following is a reconciliation of the Company’s basic weighted average common shares outstanding to diluted weighted average common shares outstanding during the periods presented (in thousands):


	Three Months Ended June 30,		Six Months Ended June 30,
	2023	2024	2023	2024
Basic weighted average number of common shares outstanding	300,141	310,806	298,461	307,875
Add: Dilutive effect of RSUs	—	—	1,593	—
Add: Dilutive effect of PSUs	—	—	967	—
Add: Dilutive effect of 2026 Convertible Notes	—	—	10,467	—
Diluted weighted average number of common shares outstanding	300,141	310,806	311,488	307,875

Weighted average number of outstanding securities excluded from calculation of diluted net income (loss) per commonshare ⁽¹⁾:
RSUs	4,070	3,537	2,260	3,654
PSUs	1,791	2,010	377	2,032
Stock options	324	259	324	259
2026 Convertible Notes	9,076	—	—	2,432

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

(e)	Recently Issued Accounting Standards

Reportable Segments

In November 2023, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2023-07, Improvements to Reportable Segment Disclosures (“ASU 2023-07”). ASU 2023-07 is intended to improve reportable segment disclosures primarily through enhanced disclosure of reportable segment expenses. This ASU is effective for annual reporting periods beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted. ASU 2023-07 is required to be applied retrospectively to all prior

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

periods presented in the financial statements. The Company is evaluating the impact that ASU 2023-07 will have on the financial statements and its plans for adoption, including the adoption date.

Income Taxes

In December 2023, the FASB issued ASU No. 2023-09, Improvements to Income Tax Disclosures (“ASU 2023-09”). ASU 2023-09 is intended to improve income tax disclosures primarily through enhanced disclosure of income tax rate reconciliation items, and disaggregation of income (loss) from continuing operations, income tax expense (benefit) and income taxes paid, net disclosures by federal, state and foreign jurisdictions, among others. This ASU is effective for annual reporting periods beginning after December 15, 2024, and early adoption is permitted. ASU 2023-09 should be applied on a prospective basis, although retrospective application is permitted. The Company is evaluating the impact that ASU 2023-09 will have on the financial statements and its plans for adoption, including the adoption date and transition method.

(3) Transactions

(a)	Conveyance of Overriding Royalty Interest

On June 15, 2020, the Company announced the consummation of a transaction with an affiliate of Sixth Street Partners, LLC (“Sixth Street”) relating to certain overriding royalty interests across the Company’s existing asset base (the “ORRIs”). In connection with the transaction, the Company contributed the ORRIs to Martica and Sixth Street contributed $300 million in cash (subject to customary adjustments) and agreed to contribute up to an additional $102 million in cash if certain production thresholds attributable to the ORRIs were achieved in 2020 and 2021. The Company met these production thresholds and received the $102 million of additional contributions from Sixth Street during 2020 and 2021. All cash contributed by Sixth Street at the initial closing and received as part of these additional contributions was distributed to the Company.

The ORRIs include an overriding royalty interest of 1.25% of the Company’s working interest in all of its operated proved developed properties in West Virginia and Ohio, subject to certain excluded wells (the “Initial PDP Override”), and an overriding royalty interest of 3.75% of the Company’s working interest in all of its undeveloped properties in West Virginia and Ohio (the “Development Override”). Wells turned to sales after April 1, 2020 and prior to the later of (a) the date on which the Company turns to sales 2.2 million lateral feet (net to the Company’s interest) of horizontal wells burdened by the Development Override or (b) the earlier of (i) April 1, 2023 or (ii) the date on which the Company turns to sales 3.82 million lateral feet (net to the Company’s interest) of horizontal wells are subject to the Development Override. As of April 1, 2023, Sixth Street no longer has the right to participate in any new wells, and Martica reconveyed the Development Override to the Company, except for the portion relating to wells turned to sales prior to April 1, 2023.

The ORRIs also include an additional overriding royalty interest of 2.00% of the Company’s working interest in the properties underlying the Initial PDP Override (the “Incremental Override”). The Incremental Override (or a portion thereof, as applicable) may be re-conveyed to the Company (at the Company’s election) if certain production targets attributable to the ORRIs are achieved through March 31, 2023. Any portion of the Incremental Override that may not be re-conveyed to the Company based on the Company failing to achieve such production volumes through March 31, 2023 will remain with Martica. As of March 31, 2023, 24% of the Incremental Override (or a 0.48% overriding royalty interest) will remain with Martica.

Prior to Sixth Street achieving an internal rate of return of 13% and 1.5x cash-on-cash return (the “Hurdle”), Sixth Street will receive all distributions in respect of the Initial PDP Override and the Development Override, and 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 entitled immediately prior to the 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 through 2024, 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

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

participate in all four annual tranches. Antero Resources develops and manages the drilling program associated with each tranche, including the selection of wells. Additionally, for each annual tranche, 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 development capital of 20%, 15% and 15% for wells spud in 2021, 2022 and 2023, respectively, and will fund 20% of development capital for wells spud in 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. The Company received a carry of $29 million for each of the 2021 and 2022 tranches during the three months ended December 31, 2022 and 2023. 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.

The Company has accounted for the drilling partnership as a conveyance under FASB Accounting Standards Codification (“ASC”) Topic 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. No gain or loss was recognized for the interests conveyed during the three and six months ended June 30, 2023 and 2024.

(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 consolidated financial statements for more information on reportable segments.


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2024		2023		2024		Reportable Segment
Revenues from contracts with customers:
Natural gas sales	$	437,130		374,568		1,105,445		848,701	Exploration and production
Natural gas liquids sales (ethane)		50,163		65,764		122,213		128,794	Exploration and production
Natural gas liquids sales (C3+ NGLs)		347,570		423,427		770,955		878,259	Exploration and production
Oil sales		57,962		63,458		109,773		128,175	Exploration and production
Marketing		43,793		49,418		102,322		97,938	Marketing
Other revenue		365		273		540		546	Exploration and production
Total revenue from contracts with customers		936,983		976,908		2,211,248		2,082,413
Income from derivatives, deferred revenue and other sources, net		16,322		1,746		150,405		18,512
Total revenue	$	953,305		978,654		2,361,653		2,100,925

(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 FASB ASC Topic 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.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(c)	Contract Balances

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, 2023 and June 30, 2024, the Company’s receivables from contracts with customers were $401 million and $362 million, respectively.

(5) Equity Method Investment

As of June 30, 2024, Antero owned 28.9% 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, 2023 ⁽¹⁾	$	222,255
Equity in earnings of unconsolidated affiliate		44,228
Dividends from unconsolidated affiliate		(62,569)
Elimination of intercompany profit		19,638
Balance as of June 30, 2024 ⁽¹⁾	$	223,552

(1)	The fair value of the Company’s investment in Antero Midstream as of December 31, 2023 and June 30, 2024 was $1.7 billion and $2.0 billion, respectively, based on the quoted market share price of Antero Midstream.

(6) Accrued Liabilities

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


			(Unaudited)
	December 31,		June 30,
	2023		2024
Capital expenditures	$	38,848		30,878
Gathering, compression, processing and transportation expenses		160,758		154,452
Marketing expenses		36,428		25,931
Interest expense, net		33,066		31,191
Production and ad valorem taxes		51,516		72,763
General and administrative expense		35,641		24,570
Derivative settlements payable		1,037		71
Other		24,046		25,491
Total accrued liabilities	$	381,340		365,347

(7) Long-Term Debt

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


			(Unaudited)
	December 31,		June 30,
	2023		2024
Credit Facility ^(a)	$	417,200		496,000
8.375% senior notes due 2026 ^(b)		96,870		96,870
7.625% senior notes due 2029 ^(c)		407,115		407,115
5.375% senior notes due 2030 ^(d)		600,000		600,000
4.25% convertible senior notes due 2026 ^(e)		26,386		—
Total principal		1,547,571		1,599,985
Unamortized debt issuance costs		(9,975)		(8,777)
Long-term debt	$	1,537,596		1,591,208

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(a)	Senior Revolving Credit Facility

On July 30, 2024, Antero Resources entered into an amendment and restatement of its senior revolving credit facility with a consortium of bank lenders. References to the (i) “Prior Credit Facility” refer to the credit facility in effect for periods prior to July 30, 2024, (ii) “New Credit Facility” refer to the credit facility in effect on or after July 30, 2024 and (iii) “Credit Facility” refer to the Prior Credit Facility and New Credit Facility, collectively.

Borrowings under the Prior Credit Facility were secured by substantially all of the assets of Antero Resources and certain of its subsidiaries, were subject to borrowing base limitations based on the collateral value of Antero Resources’ assets and were subject to regular semi-annual redeterminations. As of December 31, 2023 and June 30, 2024, the Prior Credit Facility had a borrowing base of $3.5 billion with lender commitments of $1.6 billion. The borrowing base was re-affirmed in the semi-annual redetermination in April 2024. The maturity date of the Prior Credit Facility was 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 Antero Resources’ then outstanding senior notes. As of June 30, 2024, the Prior Credit Facility had an available borrowing capacity of $994 million.

The Prior Credit Facility contained 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 Prior Credit Facility as of December 31, 2023 and June 30, 2024.

The Prior Credit Facility provided for borrowing at either an Adjusted Term Secured Overnight Financing Rate (“SOFR”), an Adjusted Daily Simple SOFR or an Alternate Base Rate, in each case, plus an Applicable Margin (each as defined in the Prior Credit Facility). The Prior Credit Facility provided for interest only payments until maturity at which time all outstanding borrowings would be due. Interest was 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 under the Prior Credit Facility. The Applicable Margin was determined with reference to Antero Resources’ then-current leverage ratio subject to certain exceptions, which for SOFR loans ranged from 1.75% to 2.75% during a non-investment grade period (based on utilization of the Prior Credit Facility) and 1.25% and 1.875% during an investment grade period (based on a ratings grid). Commitment fees on the unused portion of the Prior Credit Facility were due quarterly at rates ranging from 0.375% to 0.500% with respect to the Prior Credit Facility, determined with reference to borrowing base utilization, subject to certain exceptions based on the leverage ratio then in effect. The Prior Credit Facility included fall away covenants, lower interest rates and reduced collateral requirements that Antero Resources could elect if Antero Resources was assigned an Investment Grade Rating (as defined in the Prior Credit Facility). As of June 30, 2024, Antero Resources had not made such election.

As of December 31, 2023, Antero Resources had an outstanding balance under the Prior Credit Facility of $417 million, with a weighted average interest rate of 7.71%, and outstanding letters of credit of $501 million. As of June 30, 2024, Antero Resources had an outstanding balance under the Prior Credit Facility of $496 million, with a weighted average interest rate of 7.44%, and outstanding letters of credit of $120 million.

Borrowings under the New Credit Facility are unsecured and are not guaranteed by any of Antero Resources’ subsidiaries. As of July 30, 2024, the New Credit Facility had lender commitments of $1.65 billion. The New Credit Facility matures on July 30, 2029 (the “Maturity Date”), provided that Antero Resources may request two one-year extensions of the Maturity Date, subject to satisfaction of certain conditions and consent of the extending lenders. Commitments under the New Credit Facility may be increased by up to $500 million subject to the agreement of Antero Resources and new or existing lenders under the New Credit Facility.

The New Credit Facility contains a financial maintenance covenant with respect to Antero Resources’ total indebtedness to capitalization ratio not to exceed 65% at the end of any fiscal quarter, and certain covenants, including restrictions on our ability to incur liens or debt, subject in each case to certain significant exceptions. Antero Resources was in compliance with the financial covenant under the New Credit Facility as of July 30, 2024.

The New Credit Facility provides for borrowing at either an Adjusted Term SOFR, an Adjusted Daily Simple SOFR or an Alternate Base Rate, in each case, plus an Applicable Margin (each as defined in the New Credit Facility). The New Credit Facility provides for interest only payments until maturity at which time all outstanding borrowings are due. 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 under the New Credit Facility. The Applicable Margin is determined with reference to the Antero Resources’ then-current credit ratings ranging from 1.125% to 2.00% for SOFR loans. Commitment fees on the unused

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

portion of the New Credit Facility are due quarterly at rates ranging from 0.125% to 0.300% with respect to the New Credit Facility, determined with reference to Antero Resources’ then-current credit ratings.

The proceeds of the loans made under the New Credit Facility may be used (i) to pay fees and expenses incurred in connection with the transactions related thereto and the refinancing of the Prior Credit Facility and (ii) to finance working capital needs, and for other general corporate purposes, of Antero Resources and its subsidiaries.

(b)	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 $403 million principal amount of the 2026 Notes during 2021 and 2022, and as of June 30, 2024, $97 million principal amount of the 2026 Notes remained outstanding. 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 at redemption prices ranging from 104.188% currently to 100.00% on or after January 15, 2026. 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.

(c)	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 $293 million principal amount of the 2029 Notes during 2021 and 2022, and as of June 30, 2024, $407 million principal amount of the 2029 Notes remained outstanding. The 2029 Notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2029 Notes rank pari passu to Antero Resources’ other outstanding senior notes. The 2029 Notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by Antero Resources’ existing subsidiaries that guarantee the Credit Facility and certain of its future restricted subsidiaries. Interest on the 2029 Notes is payable on February 1 and August 1 of each year. Antero Resources may redeem all or part of the 2029 Notes at any time at redemption prices ranging from 103.813% currently to 100.00% on or after February 1, 2027. 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.

(d)	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.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(e)	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. Proceeds from the issuance of the 2026 Convertible Notes totaled $278.5 million, net of initial purchasers’ fees and issuance cost of $9 million. Transaction costs related to the 2026 Convertible Notes 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.

The Company extinguished $206 million principal amount of the 2026 Convertible Notes in 2021. In addition, between 2022 and the first quarter of 2024, $81 million aggregate principal amount of the 2026 Convertible Notes were converted pursuant to their terms or induced into conversion by the Company, and as of June 30, 2024, no 2026 Convertible Notes remained outstanding. See “—Conversions and Inducements,” for more information.

The 2026 Convertible Notes bore 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. The initial conversion rate was 230.2026 shares of Antero Resources’ common stock per $1,000 principal amount of 2026 Convertible Notes, and such conversion rate was not adjusted during the term for which the 2026 Convertible Notes were outstanding. The noteholders had the right to convert their 2026 Convertible Notes only upon the occurrence of certain events pursuant to the terms and conditions provided in the indenture governing the 2026 Convertible Notes. Upon conversion, Antero Resources could 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.

Conversions and Inducements

During the first quarter of 2023, $9 million aggregate principal amount of the 2026 Convertible Notes were converted pursuant to their terms, and an additional $9 million aggregate principal amount of the 2026 Convertible Notes 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 cash inducement premium of $0.1 million. There were no conversions of the 2026 Convertible Notes during the second quarter of 2023.

On March 11, 2024, the Company called the $26 million aggregate principal amount of the 2026 Convertible Notes that remained outstanding for redemption on April 1, 2024, at a redemption price equal to 100% of the principal amount thereof, plus accrued and unpaid interest. The Company’s election to call the remaining 2026 Convertible Notes allowed holders of the 2026 Convertible Notes to exercise their conversion right through March 28, 2024. During the first quarter of 2024, all remaining $26 million aggregate principal amount of the 2026 Convertible Notes converted pursuant to their terms. The Company elected to settle these conversions by issuing 6 million shares of common stock to the noteholders.

(8) Asset Retirement Obligations

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


Asset retirement obligations—December 31, 2023	$	59,214
Obligations incurred		538
Accretion expense		1,556
Settlement of obligations		(1,680)
Revisions to prior estimates		(3,750)
Asset retirement obligations—June 30, 2024	$	55,878

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

(9) Equity-Based Compensation

On June 17, 2020, Antero Resources’ stockholders approved the Antero Resources Corporation 2020 Long Term Incentive Plan (the “AR LTIP”), which replaced the Antero Resources Corporation Long Term Incentive Plan (the “2013 Plan”) and became effective as of such date. On June 5, 2024, the Company’s stockholders approved the Amended and

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

Restated Antero Resources Corporation 2020 Long Term Incentive Plan (the “Amended AR LTIP”). This amendment increased the number of shares of the Company’s common stock reserved for awards from 10,050,000 shares to 14,916,100 shares, and extended the term of the plan from June 17, 2030 to June 5, 2034. The Amended AR LTIP 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 Amended AR LTIP.

The Amended AR LTIP provides for the reservation of 14,916,100 shares of the Company’s common stock, plus the number of certain shares that become available again for delivery in accordance with the share recycling provisions described below. The share recycling provisions allow for all or any portion of an award (including an award granted under the 2013 Plan that was outstanding as of June 17, 2020) that expires or is cancelled, forfeited, exchanged, settled for cash or otherwise terminated without the actual delivery of shares to be considered not delivered and thus, available for new awards under the Amended AR LTIP. 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 AR LTIP or Amended AR LTIP (other than stock options and stock appreciation rights), will again be available for new awards under the Amended AR LTIP.

A total of 10,815,035 shares were available for future grant under the Amended AR LTIP as of June 30, 2024.

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,
	2023		2024		2023		2024
RSU awards	$	8,720		11,148		15,982		20,409
PSU awards		4,442		5,627		9,847		12,067
Converted AM RSU Awards ⁽¹⁾		—		—		1		—
Equity awards issued to directors		350		376		700		752
Total expense	$	13,512		17,151		26,530		33,228

(1)

Antero Resources recognized compensation expense for equity-based awards granted by Antero Midstream Partners LP’s (“Antero Midstream Partners”) under its equity compensation plans prior to March 12, 2019 (date of deconsolidation) because the awards under such plans were accounted for as if they were distributed by Antero Midstream Partners to Antero Resources. Antero Resources allocated a portion of equity-based compensation expense related to grants prior to March 12, 2019 to Antero Midstream Partners based on its proportionate share of Antero Resources’ labor costs. As of March 31, 2023, all such awards were fully vested, and there is no remaining unamortized expense attributable to these awards after such date.

(a)	Restricted Stock Unit Awards

A summary of RSU award activity is as follows:


		Weighted
		Average
	Number	Grant Date
	of Units	Fair Value
Total awarded and unvested—December 31, 2023	3,521,050	$	22.40
Granted	1,387,062		26.49
Vested	(1,536,814)		17.48
Forfeited	(22,940)		25.71
Total awarded and unvested—June 30, 2024	3,348,358	$	26.33

As of June 30, 2024, there was $73 million of unamortized equity-based compensation expense related to unvested RSUs. That expense is expected to be recognized over a weighted average period of 2.0 years.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(b)	Performance Share Unit Awards

Performance Share Unit Awards Based on Total Shareholder Return

In March 2024, the Company granted PSU awards to certain of its senior management and executive officers that vest based on Antero Resources’ absolute total shareholder return (“TSR”) determined as of the last day of each of three one-year performance periods ending on March 7, 2025, March 7, 2026 and March 7, 2027, and one cumulative three-year performance period ending on March 7, 2027, in each case, subject to certain continued employment criteria (“2024 Absolute TSR PSUs”). The number of shares of common stock that may ultimately be earned following the end of the cumulative three-year performance period with respect to the 2024 Absolute TSR PSUs ranges from zero to 200% of the target number of 2024 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.

The following table presents the assumptions used in the Monte Carlo valuation model and the grant date fair value information for the 2024 Absolute TSR PSUs:


Dividend yield		—	%
Volatility		55	%
Risk-free interest rate		4.23	%
Weighted average fair value of awards granted	$	32.29

Performance Share Unit Awards Based on Leverage Ratio

In March 2024, the Company granted PSUs to certain of its senior management and executive officers that vest based on the Company’s total debt less cash and cash equivalents divided by the Company’s Adjusted EBITDAX (as defined in the award agreement) (“Net Debt to EBITDAX”) determined as of the last day of each of three one-year performance periods ending on December 31, 2024 December 31, 2025 and December 31, 2026, in each case, subject to certain continued employment criteria (“2024 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 2024 Leverage Ratio PSUs ranges from zero to 200% of the target number of 2024 Leverage Ratio PSUs originally granted. Expense related to the 2024 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, 2024, the likelihood of achieving the performance conditions related to the 2024 Leverage Ratio PSUs was probable.

Summary Information for Performance Share Unit Awards

A summary of PSU activity is as follows:


		Weighted
		Average
	Number	Grant Date
	of Units	Fair Value
Total awarded and unvested—December 31, 2023	1,412,191	$	29.54
Granted	354,016		29.39
Vested ⁽¹⁾	(414,912)		10.76
Total awarded and unvested—June 30, 2024	1,351,295	$	35.27

(1)	During the three months ended June 30, 2024, the PSUs granted in 2021 that were based on absolute TSR and Net Debt to EBITDAX met the performance criteria to achieve vesting at 150% and 200% of target, respectively, and converted into approximately 0.7 million shares of the Company’s common stock.

As of June 30, 2024, there was $24 million of unamortized equity-based compensation expense related to unvested PSUs. That expense is expected to be recognized over a weighted average period of 1.5 years.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(10) Fair Value

The carrying values of accounts receivable and accounts payable as of December 31, 2023 and June 30, 2024 approximated market values because of their short-term nature. The carrying values of the amounts outstanding under the Prior Credit Facility as of December 31, 2023 and June 30, 2024 approximated fair value because the variable interest rates are reflective of current market conditions.

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


					(Unaudited)
	December 31, 2023				June 30, 2024
	Fair		Carrying		Fair		Carrying
	Value ⁽¹⁾		Value ⁽²⁾		Value ⁽¹⁾		Value ⁽²⁾
2026 Notes	$	99,534		96,351		100,503		96,472
2029 Notes		417,781		403,441		416,764		403,742
2030 Notes		573,720		594,622		578,880		594,994
2026 Convertible Notes		138,337		25,982		—		—
Total	$	1,229,372		1,120,396		1,096,147		1,095,208

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

(2)	Carrying values are presented net of unamortized debt issuance costs.

See Note 9—Equity-Based Compensation 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 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.

(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, 2023 and 2024. 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 and comprehensive income.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

As of June 30, 2024, 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
Propane
July-December 2024	Mont Belvieu Propane-OPIS TET	10,000	Bbl/day	$	33.67	/Bbl

The Company has a call option and an embedded put option tied to NYMEX pricing for the production volumes associated with the Company’s retained interest in the volumetric production payment transaction (“VPP”) properties. The put option was embedded within another contract, and since the embedded put option was not clearly and closely related to its host contract, the Company bifurcated this derivative instrument and reflects it at fair value in the unaudited condensed consolidated financial statements. As of June 30, 2024, 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 2024

Henry Hub

53,000

MMBtu/day

2.477

/MMBtu

2.477

/MMBtu

January-December 2025

Henry Hub

44,000

MMBtu/day

2.564

/MMBtu

2.564

/MMBtu

January-December 2026

Henry Hub

32,000

MMBtu/day

2.629

/MMBtu

2.629

/MMBtu

As of June 30, 2024, 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 2024	NYMEX to TCO	50,000	MMBtu/day	$	0.530	/MMBtu

As of June 30, 2024, 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 2024	Henry Hub	22,565	MMBtu/day	$	2.33	/MMBtu
January-March 2025	Henry Hub	18,021	MMBtu/day		2.53	/MMBtu

Oil
July-December 2024	West Texas Intermediate	39	Bbl/day	$	44.02	/Bbl
January-March 2025	West Texas Intermediate	39	Bbl/day		45.06	/Bbl

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(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)
	Balance Sheet Location	December 31, 2023		June 30, 2024
Asset derivatives not designated as hedges for accounting purposes:
Embedded derivatives—current	Derivative instruments	$	5,175		2,440
Embedded derivatives—noncurrent	Derivative instruments		5,570		3,176
Total asset derivatives ⁽¹⁾			10,745		5,616

Liability derivatives not designated as hedges for accounting purposes:
Commodity derivatives—current ⁽²⁾	Derivative instruments		15,236		22,756
Commodity derivatives—noncurrent ⁽²⁾	Derivative instruments		32,764		23,516
Total liability derivatives ⁽¹⁾			48,000		46,272

Net derivatives liability ⁽¹⁾		$	(37,255)		(40,656)

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

(2)

As of December 31, 2023, approximately $5 million of commodity derivative liabilities, including $3 million of current commodity derivatives and $2 million of noncurrent commodity derivatives, are attributable to the Company’s consolidated VIE, Martica. As of June 30, 2024, $4 million of current commodity derivative liabilities are attributable to the Company’s consolidated VIE, Martica.

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


							(Unaudited)
	December 31, 2023						June 30, 2024
					Net Amounts of						Net Amounts of
	Gross		Gross		Assets		Gross		Gross		Assets
	Amounts		Amounts Offset		(Liabilities) on		Amounts		Amounts Offset		(Liabilities) on
	Recognized		Recognized		Balance Sheet		Recognized		Recognized		Balance Sheet
Commodity derivative assets	$	406		(406)		—		—		—		—
Embedded derivative assets		10,745		—		10,745		5,616		—		5,616
Commodity derivative liabilities		(48,406)		406		(48,000)		(46,272)		—		(46,272)

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 and comprehensive income (in thousands):


	Statement of
	Operations	Three Months Ended June 30,				Six Months Ended June 30,
	Location	2023		2024		2023		2024
Commodity derivative fair value gains (losses) ⁽¹⁾	Revenue	$	6,232		(3,545)		133,312		4,721
Embedded derivative fair value gains (losses) ⁽¹⁾	Revenue		2,052		(2,040)		1,164		(860)

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

Commodity derivative fair value gains 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. 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.

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

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(a)	Supplemental Balance Sheet Information Related to Leases

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


				(Unaudited)
		December 31,		June 30,
Leases	Balance Sheet Classification	2023		2024
Operating Leases
Operating lease right-of-use assets:
Processing plants	Operating lease right-of-use assets	$	1,611,903		1,488,336
Drilling rigs and completion services	Operating lease right-of-use assets		32,187		16,841
Gas gathering lines and compressor stations ⁽¹⁾	Operating lease right-of-use assets		1,283,668		1,255,989
Office space	Operating lease right-of-use assets		37,706		35,711
Office, field and other equipment	Operating lease right-of-use assets		416		570
Total operating lease right-of-use assets		$	2,965,880		2,797,447
Operating lease liabilities:
Short-term operating lease liabilities	Short-term lease liabilities	$	538,954		524,439
Long-term operating lease liabilities	Long-term lease liabilities		2,425,785		2,265,986
Total operating lease liabilities		$	2,964,739		2,790,425

Finance Leases
Finance lease right-of-use assets:
Vehicles	Other property and equipment	$	3,771		3,242
Total finance lease right-of-use assets ⁽²⁾		$	3,771		3,242
Finance lease liabilities:
Short-term finance lease liabilities	Short-term lease liabilities	$	1,106		1,197
Long-term finance lease liabilities	Long-term lease liabilities		2,665		2,045
Total finance lease liabilities		$	3,771		3,242

(1)	Gas gathering lines and compressor stations includes $1.3 billion and $1.2 billion related to Antero Midstream as of December 31, 2023 and June 30, 2024, respectively. See “—Related party lease disclosure” for additional discussion.

(2)	Financing lease assets are recorded net of accumulated amortization of $1 million as of December 31, 2023 and June 30, 2024.

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


			Three Months Ended June 30,				Six Months Ended June 30,
Cost	Classification	Location	2023		2024		2023		2024
Operating lease cost	Statement of operations	Gathering, compression, processing and transportation	$	407,445		425,926		788,728		847,994
Operating lease cost	Statement of operations	General and administrative		3,030		2,986		5,967		6,069
Operating lease cost	Statement of operations	Contract termination		2,808		—		3,930		—
Operating lease cost	Statement of operations	Lease operating		21		27		42		48
Operating lease cost	Balance sheet	Proved properties ⁽¹⁾		31,602		28,714		71,372		62,126
Total operating lease cost			$	444,906		457,653		870,039		916,237

Finance lease cost:
Amortization of right-of-use assets	Statement of operations	Depletion, depreciation and amortization	$	546		418		638		848
Interest on lease liabilities	Statement of operations	Interest expense		162		137		276		285
Total finance lease cost			$	708		555		914		1,133

Short-term lease payments			$	34,707		28,228		72,408		57,671

(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,
	2023		2024
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	654,938		709,807
Operating cash flows from finance leases		276		285
Investing cash flows from operating leases		61,092		55,704
Financing cash flows from finance leases		343		529

Noncash activities:
Right-of-use assets obtained in exchange for new operating lease obligations	$	51,737		97,720
Increase (decrease) to existing right-of-use assets and lease obligations from operating lease modifications, net ⁽¹⁾	$	40,176		(1,472)

(1)

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. During the six months ended June 30, 2024, the weighted average discount rate for remeasured operating leases decreased from 6.5% as of December 31, 2023 to 6.0% as of June 30, 2024.

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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, 2024 (in thousands):


	Operating Leases		Financing Leases		Total
Remainder of 2024	$	351,430		814		352,244
2025		617,297		1,585		618,882
2026		564,792		1,230		566,022
2027		465,588		197		465,785
2028		388,734		23		388,757
Thereafter		943,071		10		943,081
Total lease payments		3,330,912		3,859		3,334,771
Less: imputed interest		(540,487)		(617)		(541,104)
Total	$	2,790,425		3,242		2,793,667

(e)	Lease Term and Discount Rate

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


	December 31, 2023				June 30, 2024
	Operating Leases		Finance Leases		Operating Leases		Finance Leases
Weighted average remaining lease term	6.5 years		3.0 years		6.3 years		2.5 years
Weighted average discount rate	5.9	%	8.3	%	5.7	%	8.3	%

(f)	Related Party Lease Disclosure

The Company has gathering 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) a gathering and compression agreement from Antero Midstream’s acquisition in 2022 of certain Marcellus gathering and compression assets in an area of dedication (the “Marcellus gathering and compression agreement”) and (iii) a compression agreement from Antero Midstream’s acquisition in 2022 of certain Utica compressors (the “Utica compression agreement” and (iv) a gathering and compression agreement from Antero Midstream’s acquisition in the second quarter of 2024 of certain central Marcellus gathering and compression assets (the “Mountaineer gathering and compression agreement,” and together with the 2019 gathering and compression agreement, Marcellus gathering and compression agreement and the Utica compression agreement, the “gathering and compression agreements”). Pursuant to the gathering and compression agreements with Antero Midstream, 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, Marcellus gathering and compression agreement and Mountaineer gathering and compression agreement have initial terms through 2038, 2031 and 2026, respectively, and the Utica compression agreement has two dedicated areas that expire in 2024 and 2030. Upon expiration of the Marcellus gathering and compression agreement, the Utica compression agreement and the Mountaineer gathering and 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, as applicable, subject to annual Consumer Price Index (“CPI”)-based adjustments. If and to the extent the Company requests that Antero Midstream construct new low pressure lines, high pressure lines and 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. The Marcellus gathering and compression agreement provides for a minimum volume commitment that requires the Company to utilize or pay for 25% of the compression capacity for a period of 10 years from the in-service date. The Mountaineer gathering and compression agreement provides for monthly minimum compression and gathering fees for each compressor station or high pressure gathering line, respectively, for a period of 12 years commencing 90 days after such asset’s in-service date. As of June 30, 2024, the minimum volume commitments for the 2019 gathering and compression

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

agreement and Marcellus gathering and compression agreement end in 2034 and 2024, respectively, and the minimum compression and gathering fees for the Mountaineer gathering and compression agreement end in 2026.

The 2019 gathering and compression agreement included a growth incentive fee program that expired on December 31, 2023 whereby low pressure gathering fees were reduced from 2020 through 2023 to the extent the Company achieved certain quarterly volumetric targets. The Company’s throughput gathered under the Marcellus gathering and compression agreement was not considered in the low pressure gathering volume targets. The Company earned fee rebates of $12 million and $24 million for the three and six months ended June 30, 2023, respectively.

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 anniversary of the effective date of the agreement, by notice from either the Company or Antero Midstream to the other party on or before the 180th day prior to the anniversary of such agreement.

Gathering and compression fees paid by the Company related to these agreements were $185 million and $202 million for the three months ended June 30, 2023 and 2024, respectively. For the six months ended June 30, 2023 and 2024, gathering and compression fees paid by the Company related to this agreement were $361 million and $401 million, respectively. As of December 31, 2023 and June 30, 2024, $65 million and $75 million, respectively, was included within accounts payable, related parties on the condensed consolidated balance sheets as due to Antero Midstream related to these agreements.

(13) Commitments

The following table sets forth a schedule of future minimum payments for the Company’s contractual obligations, which include leases that have a lease term in excess of one year as of June 30, 2024 (in thousands):


			Processing,
			Gathering,
	Firm		Compression		Operating and		Imputed Interest
	Transportation		and Water Service		Financing Leases		for Leases		Other
	(a)		(b)		(c)		(c)		(d)		Total
Remainder of 2024	$	594,064		35,312		275,605		76,639		4,322		985,942
2025		1,176,592		59,080		487,920		130,962		5,818		1,860,372
2026		1,174,126		25,903		462,462		103,560		3,193		1,769,244
2027		1,169,146		24,614		387,207		78,578		375		1,659,920
2028		1,110,821		23,281		330,912		57,845		—		1,522,859
Thereafter		4,413,299		86,234		849,561		93,520		—		5,442,614
Total	$	9,638,048		254,424		2,793,667		541,104		13,708		13,240,951

(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 Water Service Commitments

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

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(c)	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.

(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 loss contingency in the statements of operations and comprehensive income. During the first quarter of 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 any delayed or cancelled contracts as of June 30, 2024.

(14) Contingencies

(a)	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.

(b)	Production Taxes

The Company is subject to production taxes in the states in which it operates. The Company’s production tax filings in West Virginia for 2018 to 2020 tax years were subject to audit by the State of West Virginia. All assessments received in conjunction with this audit have been recorded in the unaudited condensed consolidated statements of operations and comprehensive net loss during the three months ended June 30, 2024; however, the Company has filed an appeal with regard to such assessments. At this time, the Company believes the outcome of this matter will not have a material adverse effect on the Company’s unaudited condensed consolidated financial position, results of operations or cash flows.

(c)

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 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. While the amounts claimed could be material, we are unable to predict

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

with certainty the ultimate outcome of such claims and proceedings. Rulings were recently received in two cases to which the Company is a party, and where the plaintiffs alleged, and the court found, that certain post-production costs may not be deducted: a non-class action lawsuit in West Virginia and a class action lawsuit in Ohio. In each case, the alleged damages were not material. The Company will continue to challenge the legal conclusions reached in each of these cases with respect to deductibility of post-production costs, and continues to analyze how these decisions may impact other cases to which the Company is a party. At this time, the Company cannot predict how these issues may ultimately be resolved, and therefore is also unable to estimate any potential damages, if any, that may result. The Company accrues for litigation, claims and proceedings when liability is both probable and the amount can be reasonably estimated, and does not currently have any material amounts accrued with respect to its pending litigation matters.

(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.

(16) Reportable Segments

(a)	Summary of Reportable Segments

The Company’s operations, which are located in the United States, are organized into three reportable segments: (i) the exploration, development and production of natural gas, NGLs and oil; (ii) marketing and utilization of excess firm transportation capacity and (iii) midstream services through the Company’s equity method investment in Antero Midstream. Substantially all of the Company’s production revenues are attributable to customers located in the United States; however, some of the Company’s production revenues are attributable to customers who then transport the Company’s production to foreign countries for resale or consumption. These segments are monitored separately by management for performance and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Management evaluates the performance of the Company’s business segments based on operating income (loss). General and administrative expenses were allocated to the midstream segment based on the nature of the expenses and on a combination of the segments’ proportionate share of the Company’s consolidated property and equipment, capital expenditures and labor costs, as applicable. General and administrative expenses related to the marketing segment are not allocated because they are immaterial. Other income, income taxes and interest expense are primarily managed and evaluated on a consolidated basis. Intersegment sales were transacted at prices which approximate market. Accounting policies for each segment are the same as the Company’s accounting policies described in Note 2—Summary of Significant Accounting Policies to the unaudited condensed consolidated financial statements.

Exploration and Production

The exploration and production segment is engaged in the development, production, exploration and acquisition of natural gas, NGLs and oil properties located in the Appalachian Basin. The Company targets large, repeatable resource plays where horizontal drilling and advanced fracture stimulation technologies provide the means to economically develop and produce natural gas, NGLs and oil from unconventional formations.

Marketing

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

Equity Method Investment in Antero Midstream

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

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(b)	Reportable Segments Financial Information

The operating results and assets of the Company’s reportable segments were as follows (in thousands):


	Three Months Ended June 30, 2023
					Equity Method
	Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream		Affiliate		Total
Sales and revenues:
Third-party	$	909,092		43,793		274		(274)		952,885
Intersegment		420		—		258,013		(258,013)		420
Total revenue		909,512		43,793		258,287		(258,287)		953,305

Operating expenses:
Lease operating		28,748		—		—		—		28,748
Gathering, compression, processing, transportation and water handling		663,975		—		52,595		(52,595)		663,975
General and administrative		53,901		—		18,162		(18,162)		53,901
Depletion, depreciation and amortization		171,406		—		35,233		(35,233)		171,406
Impairment of property and equipment		15,710		—		—		—		15,710
Other		42,326		66,175		6,774		(6,774)		108,501
Total operating expenses		976,066		66,175		112,764		(112,764)		1,042,241
Operating income (loss)	$	(66,554)		(22,382)		145,523		(145,523)		(88,936)
Equity in earnings of unconsolidated affiliates	$	19,098		—		25,972		(25,972)		19,098
Capital expenditures for segment assets	$	285,784		—		41,782		(41,782)		285,784


	Three Months Ended June 30, 2024
					Equity Method
	Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream		Affiliate		Total
Sales and revenues:
Third-party	$	928,644		49,418		414		(414)		978,062
Intersegment		592		—		269,381		(269,381)		592
Total revenue		929,236		49,418		269,795		(269,795)		978,654

Operating expenses:
Lease operating		29,759		—		—		—		29,759
Gathering, compression, processing, transportation and water handling		663,442		—		56,409		(56,409)		663,442
General and administrative		59,428		—		21,219		(21,219)		59,428
Depletion, depreciation and amortization		170,536		—		37,576		(37,576)		170,536
Impairment of property and equipment		313		—		—		—		313
Other		46,358		70,807		1,838		(1,838)		117,165
Total operating expenses		969,836		70,807		117,042		(117,042)		1,040,643
Operating income (loss)	$	(40,600)		(21,389)		152,753		(152,753)		(61,989)
Equity in earnings of unconsolidated affiliates	$	20,881		—		27,597		(27,597)		20,881
Capital expenditures for segment assets	$	192,385		—		43,399		(43,399)		192,385

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements


	Six Months Ended June 30, 2023
					Equity Method
	Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream		Affiliate		Total
Sales and revenues:
Third-party	$	2,258,568		102,322		546		(546)		2,360,890
Intersegment		763		—		517,216		(517,216)		763
Total revenue		2,259,331		102,322		517,762		(517,762)		2,361,653

Operating expenses:
Lease operating		58,069		—		—		—		58,069
Gathering, compression, processing, transportation and water handling		1,309,147		—		110,468		(110,468)		1,309,147
General and administrative		111,162		—		35,509		(35,509)		111,162
Depletion, depreciation and amortization		338,988		—		70,429		(70,429)		338,988
Impairment of property and equipment		31,270		—		—		—		31,270
Other		99,164		171,299		7,488		(7,488)		270,463
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
Capital expenditures for segment assets	$	637,096		—		84,739		(84,739)		637,096


	Six Months Ended June 30, 2024
					Equity Method
	Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream		Affiliate		Total
Sales and revenues:
Third-party	$	2,001,813		97,938		1,085		(1,085)		2,099,751
Intersegment		1,174		—		547,761		(547,761)		1,174
Total revenue		2,002,987		97,938		548,846		(548,846)		2,100,925

Operating expenses:
Lease operating		58,880		—		—		—		58,880
Gathering, compression, processing, transportation and water handling		1,335,723		—		110,327		(110,327)		1,335,723
General and administrative		115,290		—		42,440		(42,440)		115,290
Depletion, depreciation and amortization		343,590		—		74,671		(74,671)		343,590
Impairment of property and equipment		5,503		—		—		—		5,503
Other		108,148		130,620		2,404		(2,404)		238,768
Total operating expenses		1,967,134		130,620		229,842		(229,842)		2,097,754
Operating income (loss)	$	35,853		(32,682)		319,004		(319,004)		3,171
Equity in earnings of unconsolidated affiliates	$	44,228		—		55,127		(55,127)		44,228
Capital expenditures for segment assets	$	414,834		—		78,472		(78,472)		414,834

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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, 2023
					Equity Method
	Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream		Affiliate		Total
Investments in unconsolidated affiliates	$	222,255		—		626,650		(626,650)		222,255
Total assets		13,602,297		17,117		5,737,618		(5,737,618)		13,619,414

(Unaudited)

As of June 30, 2024

Equity Method

Exploration

Investment in

Elimination of

and

Antero

Unconsolidated

Consolidated

Production

Marketing

Midstream

Affiliate

Total

Investments in unconsolidated affiliates

223,552

—

612,847

(612,847)

223,552

Total assets

13,398,055

17,788

5,774,967

(5,774,967)

13,415,843

(17) Subsidiary Guarantors

As of June 30, 2024, Antero Resources’ senior notes were fully and unconditionally guaranteed by Antero Resources’ existing subsidiaries that guaranteed the Prior 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 (i) 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, (ii) 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 (iii) in connection with any covenant defeasance, legal defeasance or satisfaction and discharge of the notes. As described in Note 7—Long-Term Debt, the New Credit Facility is unsecured and is not guaranteed by any of Antero Resources’ subsidiaries. As such, each subsidiary guarantor was released from its obligations under the indentures and its guarantee effective July 30, 2024.

The tables set forth below present summarized financial information of Antero, as parent, and its guarantor subsidiaries as of December 31, 2023 and June 30, 2024 and for the six months ended June 30, 2024 (in thousands). The Company’s wholly owned subsidiaries are not restricted from making distributions to the Company.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements


Balance Sheets
			(Unaudited)
	December 31, 2023		June 30, 2024
Accounts receivable, non-guarantor subsidiaries	$	—		534
Other current assets		453,581		392,597
Total current assets		453,581		393,131
Noncurrent assets		12,562,439		12,447,779
Total assets	$	13,016,020		12,840,910

Accounts payable, related parties	$	86,284		97,455
Other current liabilities		1,360,102		1,299,231
Total current liabilities		1,446,386		1,396,686
Noncurrent liabilities		4,951,464		4,817,872
Total liabilities	$	6,397,850		6,214,558

Statement of Operations

			Six Months Ended
			June 30, 2024
Revenues			$	2,063,405
Operating expenses				2,077,373
Loss from operations				(13,968)
Net loss and comprehensive loss including noncontrolling interests				(29,307)
Net loss and comprehensive loss attributable to Antero Resources Corporation			$	(29,318)

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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 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, 2024, we held approximately 519,000 net acres in the Appalachian Basin.

Financing Highlights

Credit Facility

During the three months ended, June 30, 2024, we achieved an investment grade credit rating from S&P Global Inc. As a result of this investment grade credit rating, on July 30, 2024, we entered into an amendment and restatement of our senior revolving credit facility with lender commitments of $1.65 billion that matures on July 30, 2029, subject to certain extension terms and conditions. The New Credit Facility is unsecured and is not guaranteed by any of our subsidiaries. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information.

Market Conditions and Business Trends

Commodity Markets

Prices for natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. Natural gas benchmark prices decreased significantly while NGLs and oil benchmark prices increased during the three and six months ended June 30, 2024 as compared to the same period of 2023. As a result of the lower benchmark natural gas prices, we experienced a decrease in price realizations for natural gas and ethane products during the three and six months ended June 30, 2024. 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 Organization of Petroleum Exporting Countries and other large producing nations and the current conflicts in Ukraine and in the Middle East, among others. In the current economic 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.

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2024		2023		2024
Henry Hub ⁽¹⁾ ($/Mcf)	$	2.10		1.89		2.76		2.07
West Texas Intermediate ⁽²⁾ ($/Bbl)		73.78		80.57		74.95		78.77

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

(2)	NYMEX calendar month average settled futures price.

Hedge Position

Antero Resources (Excluding Martica)

We are exposed to certain commodity price risks relating to our ongoing business operations, and we use derivative instruments when circumstances warrant to manage 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 historical levels, the percentage of our expected production that we hedge has decreased. For the three and six months ended June 30, 2023 and 2024, substantially all of our production was unhedged. The tables and narrative below exclude derivative instruments attributable to Martica, our consolidated VIE, since all gains or losses from such contracts are fully attributable to the noncontrolling interests in Martica.

As of June 30, 2024, our fixed price NGLs swap positions excluding Martica were as follows:


				Weighted
				Average
Commodity / Settlement Period	Index	Contracted Volume		Price
Propane
July-December 2024	Mont Belvieu Propane-OPIS TET	1,840	MBbl	$	33.67	/Bbl

As of June 30, 2024, our natural gas basis swap positions 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 2024	NYMEX to TCO	9	Bcf	$	0.530	/MMBtu

We have a 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. As of June 30, 2024, 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 2024

Henry Hub

Bcf

2.477

/MMBtu

2.477

/MMBtu

January-December 2025

Henry Hub

Bcf

2.564

/MMBtu

2.564

/MMBtu

January-December 2026

Henry Hub

Bcf

2.629

/MMBtu

2.629

/MMBtu

Bcf

2.562

/MMBtu

2.562

/MMBtu

As of June 30, 2024, the estimated fair value of our commodity derivative contracts, excluding Martica, was a net liability of $37 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, 2024, Martica’s fixed price natural gas and oil swap positions were as follows:


				Weighted
				Average
Commodity / Settlement Period	Index	Contracted Volume		Price
Natural Gas
July-December 2024	Henry Hub	5	Bcf	$	2.33	/MMBtu
January-March 2025	Henry Hub	1	Bcf		2.53	/MMBtu
		6	Bcf		2.38	/MMBtu
Oil
July-December 2024	West Texas Intermediate	8	MBbl	$	44.02	/Bbl
January-March 2025	West Texas Intermediate	3	MBbl		45.06	/Bbl
		11	MBbl		44.36	/Bbl

As of June 30, 2024, the estimated fair value of Martica’s commodity derivative contracts was a net liability of $4 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 second quarter of 2024. For example, the Consumer Price Index (“CPI”) for all urban consumers increased 3% from June 2022 to June 2023 and an additional 3% from June 2023 to June 2024 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 June 2024, the Federal Reserve increased the federal funds interest rate by 5.25%. 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. 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 services provided by Antero Midstream, which we capitalized as proved property development costs. Marketing revenues are primarily derived from activities to purchase and sell third-party natural gas and NGLs and to market and utilize excess firm transportation capacity. See Note 16—Reportable Segments to the unaudited condensed consolidated financial statements for more information.

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Three Months Ended June 30, 2023 Compared to Three Months Ended June 30, 2024

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


	Three 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	$	437,130		—		—		—		437,130
Natural gas liquids sales		397,733		—		—		—		397,733
Oil sales		57,962		—		—		—		57,962
Commodity derivative fair value gains		8,284		—		—		—		8,284
Gathering, compression and water handling		—		—		258,287		(258,287)		—
Marketing		—		43,793		—		—		43,793
Amortization of deferred revenue, VPP		7,618		—		—		—		7,618
Other revenue and income		785		—		—		—		785
Total revenue		909,512		43,793		258,287		(258,287)		953,305

Operating expenses:
Lease operating		28,748		—		—		—		28,748
Gathering and compression		211,691		—		25,154		(25,154)		211,691
Processing		262,642		—		—		—		262,642
Transportation		189,642		—		—		—		189,642
Water handling		—		—		27,441		(27,441)		—
Production and ad valorem taxes		36,158		—		—		—		36,158
Marketing		—		66,175		—		—		66,175
Exploration and mine expenses		743		—		—		—		743
General and administrative (excluding equity-based compensation)		40,389		—		9,663		(9,663)		40,389
Equity-based compensation		13,512		—		8,499		(8,499)		13,512
Depletion, depreciation and amortization		171,406		—		35,233		(35,233)		171,406
Impairment of property and equipment		15,710		—		—		—		15,710
Accretion of asset retirement obligations		1,204		—		44		(44)		1,204
Contract termination and other operating expenses		4,441		—		916		(916)		4,441
Loss (gain) on sale of assets		(220)		—		5,814		(5,814)		(220)
Total operating expenses		976,066		66,175		112,764		(112,764)		1,042,241
Operating income (loss)	$	(66,554)		(22,382)		145,523		(145,523)		(88,936)

Equity in earnings of unconsolidated affiliates	$	19,098		—		25,972		(25,972)		19,098

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	Three Months Ended June 30, 2024
					Equity Method
	Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream		Affiliate		Total
Revenue and other:
Natural gas sales	$	374,568		—		—		—		374,568
Natural gas liquids sales		489,191		—		—		—		489,191
Oil sales		63,458		—		—		—		63,458
Commodity derivative fair value losses		(5,585)		—		—		—		(5,585)
Gathering, compression and water handling		—		—		269,795		(269,795)		—
Marketing		—		49,418		—		—		49,418
Amortization of deferred revenue, VPP		6,739		—		—		—		6,739
Other revenue and income		865		—		—		—		865
Total revenue		929,236		49,418		269,795		(269,795)		978,654

Operating expenses:
Lease operating		29,759		—		—		—		29,759
Gathering and compression		222,139		—		26,190		(26,190)		222,139
Processing		269,985		—		—		—		269,985
Transportation		171,318		—		—		—		171,318
Water handling		—		—		30,219		(30,219)		—
Production and ad valorem taxes		41,933		—		—		—		41,933
Marketing		—		70,807		—		—		70,807
Exploration		643		—		—		—		643
General and administrative (excluding equity-based compensation)		42,277		—		9,620		(9,620)		42,277
Equity-based compensation		17,151		—		11,599		(11,599)		17,151
Depletion, depreciation and amortization		170,536		—		37,576		(37,576)		170,536
Impairment of property and equipment		313		—		—		—		313
Accretion of asset retirement obligations		780		—		47		(47)		780
Loss (gain) on sale of assets		(18)		—		1,379		(1,379)		(18)
Contract termination, loss contingency and other operating expenses		3,020		—		412		(412)		3,020
Total operating expenses		969,836		70,807		117,042		(117,042)		1,040,643
Operating income (loss)	$	(40,600)		(21,389)		152,753		(152,753)		(61,989)

Equity in earnings of unconsolidated affiliates	$	20,881		—		27,597		(27,597)		20,881

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Exploration and Production Segment

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


	Three Months Ended				Amount of
	June 30,				Increase		Percent
	2023		2024		(Decrease)		Change
Production data ^{(1) (2)}:
Natural gas (Bcf)		204		196		(8)	(4)	%
C2 Ethane (MBbl)		6,414		7,811		1,397	22	%
C3+ NGLs (MBbl)		10,175		10,514		339	3	%
Oil (MBbl)		971		952		(19)	(2)	%
Combined (Bcfe)		309		311		2	1	%
Daily combined production (MMcfe/d)		3,400		3,420		20	1	%
Average prices before effects of derivative settlements ⁽³⁾:
Natural gas (per Mcf)	$	2.14		1.92		(0.22)	(10)	%
C2 Ethane (per Bbl) ⁽⁴⁾	$	7.82		8.42		0.60	8	%
C3+ NGLs (per Bbl)	$	34.16		40.27		6.11	18	%
Oil (per Bbl)	$	59.69		66.66		6.97	12	%
Weighted Average Combined (per Mcfe)	$	2.89		2.98		0.09	3	%
Average realized prices after effects of derivative settlements⁽³⁾:
Natural gas (per Mcf)	$	2.16		1.94		(0.22)	(10)	%
C2 Ethane (per Bbl) ⁽⁴⁾	$	7.82		8.42		0.60	8	%
C3+ NGLs (per Bbl)	$	34.11		40.44		6.33	19	%
Oil (per Bbl)	$	59.40		66.50		7.10	12	%
Weighted Average Combined (per Mcfe)	$	2.90		3.00		0.10	3	%
Average costs (per Mcfe):
Lease operating	$	0.09		0.10		0.01	11	%
Gathering and compression	$	0.68		0.71		0.03	4	%
Processing	$	0.85		0.87		0.02	2	%
Transportation	$	0.61		0.55		(0.06)	(10)	%
Production and ad valorem taxes	$	0.12		0.13		0.01	8	%
Marketing expense, net	$	0.07		0.07		—	*
General and administrative (excluding equity-based compensation)	$	0.13		0.14		0.01	8	%
Depletion, depreciation, amortization and accretion	$	0.56		0.55		(0.01)	(2)	%

*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)

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 and 2024 includes $1 million and $0.1 million, respectively, 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 for the three months ended June 30, 2023 and 2024 would have been $7.65 per Bbl and $8.41 per Bbl, respectively.

Natural gas sales. Revenues from sales of natural gas decreased from $437 million for the three months ended June 30, 2023 to $375 million for the three months ended June 30, 2024, a decrease of $62 million, or 14%. Lower commodity prices (excluding the effects of derivative settlements) during the three months ended June 30, 2024 accounted for an approximate $43 million 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 natural gas production volumes accounted for an approximate $19 million decrease in year-over-year natural gas sales revenue (calculated as the change in year-to-year volumes times the prior year average price).

NGLs sales. Revenues from sales of NGLs increased from $398 million for the three months ended June 30, 2023 to $489 million for the three months ended June 30, 2024, an increase of $91 million, or 23%. Higher commodity prices (excluding the effects of derivative settlements) during the three months ended June 30, 2024 accounted for an approximate $69 million increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). Higher NGLs production volumes accounted for an approximate $22 million increase in year-over-year 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 from $58 million for the three months ended June 30, 2023 to $63 million for the three months ended June 30, 2024, an increase of $5 million, or 9%. Higher commodity prices (excluding the effects of derivative settlements) during the three months ended June 30, 2024 accounted for an approximate $6 million increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). Lower oil production volumes during the three months ended June 30, 2024 accounted for an approximate $1 million decrease in year-over-year oil revenues (calculated as the change in year-to-year volumes times the prior year average price).

Commodity derivative fair value gains (losses). Our commodity derivatives included fixed price swap contracts, basis swap contracts, call options and 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 and comprehensive income. For the three months ended June 30, 2023 and 2024, our commodity hedges resulted in derivative fair value gains of $8 million and fair value losses of $6 million, respectively. For the three months ended June 30, 2023 and 2024, commodity derivative fair value gains (losses) included $3 million and $6 million, respectively, of net 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 $8 million for the three months ended June 30, 2023 to $7 million for the three months ended June 30, 2024, a decrease of $1 million, or 12%, primarily due to lower production volumes attributable to the VPP properties between periods. Amortization of the deferred revenues associated with the VPP are recognized as the production volumes are delivered at $1.61 per MMBtu over the contractual term.

Lease operating expense. Lease operating expense remained relatively consistent for the three months ended June 30, 2023 and 2024 at $29 million and $30 million, respectively. On a per-unit basis, lease operating expense increased from $0.09 per Mcfe for the three months ended June 30, 2023 to $0.10 per Mcfe for the three months ended June 30, 2024 primarily due to increased oilfield services costs between periods.

Gathering, compression, processing and transportation expense. Gathering, compression, processing and transportation expense remained relatively consistent at $664 million and $663 million for the three months ended June 30, 2023 and 2024, respectively. This was primarily a result of the following:

●

Gathering and compression costs increased from $0.68 per Mcfe for the three months ended June 30, 2023 to $0.71 per Mcfe for the three months ended June 30, 2024, primarily due to the expiration of the growth incentive fee rebate program on December 31, 2023 and annual CPI-based adjustments between periods. During the three months ended June 30, 2023, we earned a fee rebate of $12 million under this program.

●

Processing costs increased from $0.85 per Mcfe for the three months ended June 30, 2023 to $0.87 per Mcfe for the three months ended June 30, 2024, primarily due to increased costs for NGLs processing, which includes an annual CPI-based adjustment during the first quarter of 2024 and higher NGLs transportation fees.

●

Transportation costs decreased from $0.61 per Mcfe for the three months ended June 30, 2023 to $0.55 per Mcfe for the three months ended June 30, 2024 primarily due to lower demand fees and fuel costs as a result of lower natural gas prices between periods.

Production and ad valorem tax expense. Production and ad valorem taxes increased from $36 million for the three months ended June 30, 2023 to $42 million for the three months ended June 30, 2024, an increase of $6 million, or 16%, primarily due to higher ad valorem taxes and production volumes between periods, partially offset by lower natural gas prices during the three months ended June 30, 2024. Production and ad valorem taxes as a percentage of natural gas revenues increased from 8% for the three months ended June 30, 2023 to 11% for the three months ended June 30, 2024, primarily as a result of higher ad valorem taxes, which 2024 ad valorem taxes are based on commodity prices during 2022.

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General and administrative expense. General and administrative expense (excluding equity-based compensation expense) increased from $40 million for the three months ended June 30, 2023 to $42 million for the three months ended June 30, 2024, an increase of $2 million, or 5%, primarily due to higher professional service fees between periods. General and administrative expense on a per unit basis (excluding equity-based compensation) increased from $0.13 per Mcfe for the three months ended June 30, 2023 to $0.14 per Mcfe for the three months ended June 30, 2024 as a result of higher overall costs between periods.

Equity-based compensation expense. Noncash equity-based compensation expense increased from $14 million for the three months ended June 30, 2023 to $17 million for the three months ended June 30, 2024, an increase of $3 million, or 27%. This increase was primarily due to annual equity-based awards granted during the first quarter of 2024. See Note 9—Equity-Based Compensation to the unaudited condensed consolidated financial statements for more information.

Depletion, depreciation, and amortization expense (“DD&A expense”). DD&A expense remained relatively consistent at $171 million, or $0.56 per Mcfe, and $171 million, or $0.55 per Mcfe, for the three months ended June 30, 2023 and 2024, respectively.

Impairment of property and equipment. Impairment of oil and gas properties of $16 million for the three months ended June 30, 2023 primarily related to expiring leases we no longer plan to utilize.

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 for the three months ended June 30, 2023 and 2024 remained relatively consistent at $22 million and $21 million, respectively, or $0.07 per Mcfe.

Marketing revenue. Marketing revenue increased from $44 million for the three months ended June 30, 2023 to $49 million for the three months ended June 30, 2024, an increase of $5 million, or 13%. This fluctuation primarily resulted from the following:

●

Natural gas marketing revenue decreased by $16 million between periods primarily due to lower natural gas marketing volumes between periods.

●

Oil marketing revenue increased by $21 million between periods primarily due to higher oil marketing volumes and prices. Higher oil marketing volumes accounted for an $16 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 $5 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 increased from $66 million for the three months ended June 30, 2023 to $71 million for the three months ended June 30, 2024, an increase of $5 million, or 7%. 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, oil and NGLs purchases increased $5 million between periods, primarily due to higher oil marketing volumes and prices between periods, partially offset by lower natural gas marketing volumes and prices between periods. Firm transportation costs remained consistent at $27 million for the three months ended June 30, 2023 and 2024.

Antero Midstream Segment

Antero Midstream revenue. Revenue from the Antero Midstream segment increased from $258 million for the three months ended June 30, 2023 to $270 million for the three months ended June 30, 2024, an increase of $12 million. This increase is primarily due to higher gathering and processing revenues of $18 million, partially offset by lower water handling revenues of $6 million. The increased gathering and processing revenues between periods is primarily a result of the expiration of the growth incentive fee rebate program on December 31, 2023, annual CPI-based gathering and compression rate adjustments and increased high pressure gathering throughput between periods. The decreased water handling revenues between periods was primarily due to lower fresh water delivery volumes, partially offset by higher other fluid handing

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volumes and an increased fresh water delivery rate due to an annual CPI-based adjustment during the three months ended June 30, 2024.

Antero Midstream operating expense. Total operating expense related to the Antero Midstream segment increased from $113 million for the three months ended June 30, 2023 to $117 million for the three months ended June 30, 2024, an increase of $4 million. This increase is primarily due to higher direct operating expenses, equity-based compensation expenses and depreciation expense between periods, partially offset by lower interest expense. Direct operating expenses increased by $3 million between periods primarily due to higher compression expense for the addition of two compressor stations that were acquired during the second quarter of 2024 and increased high pressure gathering volumes, partially offset by increased pipeline maintenance, repair and monitoring activities for the three months ended June 30, 2024.

Discussion of Items Not Allocated to Segments

Interest expense. Interest expense increased from $28 million for the three months ended June 30, 2023 to $33 million for the three months ended June 30, 2024, an increase of $5 million, or 17%, primarily due to higher average Prior Credit Facility borrowings between periods and higher benchmark interest rates during the three months ended June 30, 2024.

Income tax benefit. 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. For the three months ended June 30, 2024, we had an income tax benefit of $13 million, with an effective tax rate of 18%, due to a loss before income taxes of $74 million. The decrease in income tax benefit between periods of $17 million is primarily due to lower loss before income taxes between periods. The decrease in the effective tax rate between periods was primarily due to the effects of noncontrolling interests and our loss before income taxes.

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Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2024

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


	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 gains		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
Contract termination and other operating expenses		10,453		23,763		1,831		(1,831)		34,216
Loss (gain) on sale of assets		(311)		—		5,569		(5,569)		(311)
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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	Six Months Ended June 30, 2024
					Equity Method
	Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream		Affiliate		Total
Revenue and other:
Natural gas sales	$	848,701		—		—		—		848,701
Natural gas liquids sales		1,007,053		—		—		—		1,007,053
Oil sales		128,175		—		—		—		128,175
Commodity derivative fair value gains		3,861		—		—		—		3,861
Gathering, compression and water handling		—		—		548,846		(548,846)		—
Marketing		—		97,938		—		—		97,938
Amortization of deferred revenue, VPP		13,477		—		—		—		13,477
Other revenue and income		1,720		—		—		—		1,720
Total revenue		2,002,987		97,938		548,846		(548,846)		2,100,925

Operating expenses:
Lease operating		58,880		—		—		—		58,880
Gathering and compression		445,669		—		52,333		(52,333)		445,669
Processing		525,780		—		—		—		525,780
Transportation		364,274		—		—		—		364,274
Water handling		—		—		57,994		(57,994)		—
Production and ad valorem taxes		100,101		—		—		—		100,101
Marketing		—		130,620		—		—		130,620
Exploration		1,245		—		—		—		1,245
General and administrative (excluding equity-based compensation)		82,062		—		21,514		(21,514)		82,062
Equity-based compensation		33,228		—		20,926		(20,926)		33,228
Depletion, depreciation and amortization		343,590		—		74,671		(74,671)		343,590
Impairment of property and equipment		5,503		—		—		—		5,503
Accretion of asset retirement obligations		1,556		—		91		(91)		1,556
Loss on sale of assets		170		—		1,379		(1,379)		170
Contract termination, loss contingency and other operating expenses		5,076		—		934		(934)		5,076
Total operating expenses		1,967,134		130,620		229,842		(229,842)		2,097,754
Operating income (loss)	$	35,853		(32,682)		319,004		(319,004)		3,171

Equity in earnings of unconsolidated affiliates	$	44,228		—		55,127		(55,127)		44,228

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Exploration and Production Segment

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


	Six Months Ended				Amount of
	June 30,				Increase		Percent
	2023		2024		(Decrease)		Change
Production data ^{(1) (2)}:
Natural gas (Bcf)		398		397		(1)	*
C2 Ethane (MBbl)		12,555		14,571		2,016	16	%
C3+ NGLs (MBbl)		20,032		21,078		1,046	5	%
Oil (MBbl)		1,802		1,987		185	10	%
Combined (Bcfe)		604		623		19	3	%
Daily combined production (MMcfe/d)		3,337		3,423		86	3	%
Average prices before effects of derivative settlements⁽³⁾:
Natural gas (per Mcf)	$	2.78		2.14		(0.64)	(23)	%
C2 Ethane (per Bbl) ⁽⁴⁾	$	9.73		8.84		(0.89)	(9)	%
C3+ NGLs (per Bbl)	$	38.49		41.67		3.18	8	%
Oil (per Bbl)	$	60.92		64.51		3.59	6	%
Weighted Average Combined (per Mcfe)	$	3.49		3.18		(0.31)	(9)	%
Average realized prices after effects of derivative settlements⁽³⁾:
Natural gas (per Mcf)	$	2.76		2.15		(0.61)	(22)	%
C2 Ethane (per Bbl) ⁽⁴⁾	$	9.73		8.84		(0.89)	(9)	%
C3+ NGLs (per Bbl)	$	38.43		41.74		3.31	9	%
Oil (per Bbl)	$	60.55		64.36		3.81	6	%
Weighted Average Combined (per Mcfe)	$	3.47		3.20		(0.27)	(8)	%
Average costs (per Mcfe):
Lease operating	$	0.10		0.09		(0.01)	(10)	%
Gathering and compression	$	0.70		0.72		0.02	3	%
Processing	$	0.83		0.84		0.01	1	%
Transportation	$	0.64		0.58		(0.06)	(9)	%
Production and ad valorem taxes	$	0.14		0.16		0.02	14	%
Marketing expense, net	$	0.07		0.05		(0.02)	(29)	%
General and administrative (excluding equity-based compensation)	$	0.14		0.13		(0.01)	(7)	%
Depletion, depreciation, amortization and accretion	$	0.56		0.55		(0.01)	(2)	%

*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)

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 (but do not include payments from the derivative monetizations in 2023), 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 six months ended June 30, 2023 and 2024 includes $7 million and $2 million, respectively, 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 for the six months ended June 30, 2023 and 2024 would have been $9.17 per Bbl and $8.72 per Bbl, respectively.

Natural gas sales. Revenues from sales of natural gas decreased from $1.1 billion for the six months ended June 30, 2023 to $849 million for the six months ended June 30, 2024, a decrease of $257 million, or 23%. Lower commodity prices (excluding the effects of derivative settlements) during the six months ended June 30, 2024 accounted for an approximate $255 million 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). Higher natural gas production volumes accounted for an approximate $2 million 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 from $893 million for the six months ended June 30, 2023 to $1.0 billion for the six months ended June 30, 2024, an increase of $114 million, or 13%. Higher commodity prices (excluding the effects of derivative settlements) during the six months ended June 30, 2024 accounted for an approximate $54 million increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). Higher NGLs production volumes accounted for an approximate $60 million increase in year-over-year 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 from $110 million for the six months ended June 30, 2023 to $128 million for the six months ended June 30, 2024, an increase of $18 million, or 17%. Higher oil prices, excluding the effects of derivative settlements, accounted for an approximate $7 million increase in year-over-year oil revenues (calculated as the change in the year-to-year average price times current year production volumes). Higher oil production volumes during the six months ended June 30, 2024 accounted for an approximate $11 million 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. Our commodity derivatives included variable price swap contracts, swaptions, basis swap contracts, call options and 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, 2023 and 2024, our commodity hedges resulted in derivative fair value gains of $134 million and $4 million, respectively. 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. For the six months ended June 30, 2024, commodity derivative fair value gains included $7 million of net cash proceeds for settled 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. Additionally, substantially all of our production is currently unhedged for 2024 and beyond, which limits our exposure to volatility in the 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 $15 million for the six months ended June 30, 2023 to $13 million for the six months ended June 30, 2024, a decrease of $2 million or 11%, primarily due to lower production volumes attributable to the VPP properties between periods. Amortization of the deferred revenues associated with the VPP are recognized as the production volumes are delivered at $1.61 per MMBtu over the contractual term.

Lease operating expense. Lease operating expense increased from $58 million for the six months ended June 30, 2023 to $59 million for the six months ended June 30, 2024, primarily due to higher oilfield service costs. On a per-unit basis, lease operating expenses decreased from $0.10 per Mcfe for the six months ended June 30, 2023 to $0.09 per Mcfe for the six months ended June 30, 2024, primarily due to higher production volumes between periods, partially offset by higher overall costs during the six months ended June 30, 2024.

Gathering, compression, processing and transportation expense. Gathering, compression, processing and transportation expense remained consistent at $1.3 billion for the six months ended June 30, 2023 and 2024. This was primarily a result of the following:

●

Gathering and compression costs on a per unit basis increased from $0.70 per Mcfe for the six months ended June 30, 2023 to $0.72 per Mcfe for the six months ended June 30, 2024, primarily due to the expiration of the growth incentive fee rebate program on December 31, 2023 and annual CPI-based adjustments between periods. During the six months ended June 30, 2023, we earned fee rebates of $24 million under this program.

●

Processing costs on a per unit basis increased from $0.83 per Mcfe for the six months ended June 30, 2023 to $0.84 per Mcfe for the six months ended June 30, 2024, primarily due to increased costs for NGLs processing and transportation, which includes an annual CPI-based adjustment during the first quarter of 2024 and higher NGLs transportation fees.

●

Transportation costs on a per unit basis decreased from $0.64 per Mcfe for the six months ended June 30, 2023 to $0.58 per Mcfe for the six months ended June 30, 2024 primarily due to lower demand fees and lower fuel costs as a result of lower natural gas prices between periods.

Production and ad valorem tax expense. Production and ad valorem taxes increased from $85 million for the six months ended June 30, 2023 to $100 million for the six months ended June 30, 2024, an increase of $15 million, or 17%, primarily due to higher ad valorem taxes and production volumes between periods, partially offset by lower natural gas prices during the six months ended June 30, 2024. Production and ad valorem taxes as a percentage of natural gas revenues increased

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from 8% for the six months ended June 30, 2023 to 12% for the six months ended June 30, 2024, primarily as a result of higher ad valorem taxes, which 2024 West Virginia ad valorem taxes are based on commodity prices during 2022.

General and administrative expense. General and administrative expense (excluding equity-based compensation expense) decreased from $85 million for the six months ended June 30, 2023 to $82 million for six months ended June 30, 2024, a decrease of $3 million, or 3%, primarily due to lower professional service fees between periods. General and administrative expense on a per unit basis (excluding equity-based compensation) decreased from $0.14 per Mcfe for the six months ended June 30, 2023 to $0.13 per Mcfe for the six months ended June 30, 2024 as a result of lower overall costs and increased production volumes between periods.

Equity-based compensation expense. Noncash equity-based compensation expense increased from $27 million for the six months ended June 30, 2023 to $33 million for the six months ended June 30, 2024, an increase of $6 million, or 25%. This increase was primarily due to annual equity-based awards granted in the first quarters of 2023 and 2024, partially offset by equity-based awards granted in prior years that were fully vested between periods. See Note 9—Equity-Based Compensation to the unaudited condensed consolidated financial statements for more information.

Depletion, depreciation and amortization expense. DD&A expense increased from $339 million for the six months ended June 30, 2023 to $344 million for the six months ended June 30, 2024, an increase of $5 million, or 1%, primarily due to higher production volumes between periods. On a per unit basis, DD&A expense remained relatively consistent at $0.56 and $0.55 per Mcfe for the six months ended June 30, 2023 and 2024, respectively.

Impairment of property and equipment. Impairment of oil and gas properties decreased from $31 million for the six months ended June 30, 2023 to $6 million for the six months ended June 30, 2024, a decrease of $25 million, primarily due to 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.

Contract termination, loss contingency and other operating expenses. Contract termination, loss contingency and other operating expenses attributable to our exploration and production segment decreased from $10 million for the six months ended June 30, 2023 to $5 million for the six months ended June 30, 2024. This decrease was primarily due to lower expense associated with the early termination of certain completion contracts between periods.

Marketing Segment

Net marketing expense decreased from $45 million, or $0.07 per Mcfe, for the six months ended June 30, 2023 to $33 million, or $0.05 per Mcfe, for the six months ended June 30, 2024, primarily due to lower firm transportation commitments between periods.

Marketing revenue. Marketing revenue decreased from $102 million for the six months ended June 30, 2023 to $98 million for the six months ended June 30, 2024, a decrease of $4 million, or 4%. This fluctuation primarily resulted from the following:

●

Natural gas marketing revenue decreased by $46 million between periods primarily due to lower natural gas marketing volumes and prices. Lower natural gas marketing volumes accounted for a $41 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and lower natural gas prices accounted for a $5 million decrease in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes).

●

Oil marketing revenue increased by $37 million between periods primarily due to higher oil marketing volumes and prices. Higher oil marketing volumes accounted for a $24 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 a $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).

●

NGLs marketing revenues were $3 million for the six months ended June 30, 2024. There were no NGLs marketing revenues for the six months ended June 30, 2023.

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Marketing expense. Marketing expense decreased from $148 million for the six months ended June 30, 2023 to $131 million for the six months ended June 30, 2024, a decrease of $17 million, or 11%. 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 purchases decreased $39 million, partially offset by oil and NGLs purchases increase of $31 million and $3 million, respectively. The total cost of third-party commodity purchases decreased primarily due to lower natural gas marketing volumes and prices between periods, partially offset by higher oil prices and marketing volumes during the six months ended June 30, 2024. Firm transportation costs decreased $12 million from $55 million for the six months ended June 30, 2023 to $43 million for the six months ended June 30, 2024, due to the reduction in firm transportation commitments between periods.

Contract termination, loss contingency and other operating expenses. Contract termination, loss contingency and other operating expenses attributable to our marketing segment for the six months ended June 30, 2023, relate to a $24 million payment for the early termination of our firm transportation commitment of 200,000 MMBtu per day on the Equitrans pipeline. Our marketing segment did not incur any contract termination, loss contingency and other operating expenses for the six months ended June 30, 2024.

Antero Midstream Segment

Antero Midstream revenue. Revenue from the Antero Midstream segment increased from $518 million for the six months ended June 30, 2023 to $549 million for the six months ended June 30, 2024, an increase of $31 million. This increase is primarily due to higher gathering and processing revenues of $46 million, partially offset by lower water handling revenues of $15 million. The increased gathering and processing revenues between periods is primarily a result of the expiration of the growth incentive fee rebate program on December 31, 2023, increased throughput and annual CPI-based gathering and compression rate adjustments between periods. The decreased water handling revenues between periods is primarily due to lower fresh water delivery volumes and lower water handling volumes that are billed at cost plus 3%, partially offset by higher blending volumes and an increased fresh water delivery rate due to an annual CPI-based adjustment during the six months ended June 30, 2024.

Antero Midstream operating expense. Total operating expense related to the Antero Midstream segment increased from $224 million for the six months ended June 30, 2023 to $230 million for the six months ended June 30, 2024, an increase of $6 million. This increase is primarily due to higher equity-based compensation expense and depreciation expense between periods, partially offset by lower interest expense during the six months ended June 30, 2024.

Items Not Allocated to Segments

Interest expense. Interest expense increased from $54 million for the six months ended June 30, 2023 to $63 million for the six months ended June 30, 2024, an increase of $9 million or 17%, primarily due to higher average Prior Credit Facility borrowings between periods and higher benchmark interest rates during the six months ended June 30, 2024.

Income tax expense (benefit). For the six months ended June 30, 2023, we had income tax expense of $32 million, with an effective tax rate of 14%, related to our income before income taxes of $226 million. For the six months ended June 30, 2024, we had an income tax benefit of $3 million, with an effective tax rate of 21%, related to our loss before income taxes of $15 million. The increase in the effective tax rate between periods was primarily due to the effects of noncontrolling interests and our income (loss) before income taxes.

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 Credit Facility, issuances of debt and equity securities and additional contributions from our asset sales, including our drilling partnership. Our primary use of cash has been for the exploration, development and acquisition of oil and natural gas properties. As we develop our reserves, we continually monitor what capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future success in developing our proved reserves and production will be highly dependent on net cash provided by operating activities and the capital resources available to us.

Based on strip prices as of June 30, 2024, we believe that net cash provided by operating activities 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.

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Cash Flows

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


	Six Months Ended June 30,
	2023		2024
Net cash provided by operating activities	$	499,165		405,109
Net cash used in investing activities		(638,040)		(414,125)
Net cash provided by financing activities		138,875		9,016
Net increase in cash and cash equivalents	$	—		—

Operating activities. Net cash provided by operating activities was $499 million and $405 million for the six months ended June 30, 2023 and 2024, respectively. Net cash provided by operating activities decreased between periods primarily due to lower natural gas prices, changes in working capital and higher gathering, compression, processing and transportation expenses, partially offset by a $202 million payment for early settlement of our swaption agreement in the six months ended June 30, 2023.

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. These factors are beyond our control and are difficult to predict.

Investing activities. Net cash used in investing activities decreased from $638 million for the six months ended June 30, 2023 to $414 million for the six months ended June 30, 2024, primarily due to a decrease in drilling and completions activity as a result of lower rig and completion crew counts between periods, and decreased leasing activity during the six months ended June 30, 2024.

Financing activities. Net cash provided by financing activities decreased from $139 million for the six months ended June 30, 2023 to $9 million for the six months ended June 30, 2024. The decrease between periods is primarily due to lower net borrowings on our Prior Credit Facility of $246 million, partially offset by decreased share repurchases of $75 million and decreased distributions to the noncontrolling interests in Martica of $40 million between periods.

2024 Capital Budget and Capital Spending

On February 14, 2024, we announced a net capital budget for 2024 of $725 million to $800 million. Our budget includes: a range of $650 million to $700 million for drilling and completion and $75 million to $100 million for leasehold expenditures. We do not budget for acquisitions. During 2024, we plan to complete 45 to 50 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, 2024, our total consolidated capital expenditures were $188 million, including drilling and completion costs of $164 million, leasehold acquisitions of $21 million and other capital expenditures of $3 million. For the six months ended June 30, 2024, our total consolidated capital expenditures were $407 million, including drilling and completion costs of $351 million, leasehold acquisitions of $47 million and other capital expenditures of $9 million.

Debt Agreements

See Note 7—Long Term Debt to the unaudited condensed consolidated financial statements included in this Quarterly Report on Form 10-Q and to “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in the 2023 Form 10-K for information on our debt agreements.

Critical Accounting 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. Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements have been included in Note 2—Summary of Significant Accounting Policies to our unaudited condensed consolidated financial statements. The preparation of our unaudited condensed consolidated financial statements requires us to make estimates and assumptions that

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affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure of contingent liabilities. Accounting estimates and assumptions are considered to be critical if 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 reported amounts in our unaudited condensed consolidated financial statements 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. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in the 2023 Form 10-K for information on our critical accounting estimates.

We evaluate the carrying amount of our proved natural gas, NGLs and oil properties for impairment on a geological reservoir basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying amount of our proved properties exceeds the estimated undiscounted future net cash flows (measured using futures prices at the balance sheet date), we further evaluate our proved properties and record an impairment charge if the carrying amount of our proved properties exceeds the estimated fair value of the properties.

Based on future prices as of June 30, 2024, 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, 2023 and 2024.

We believe that the estimates and assumptions related to our undiscounted future net cash flows and the fair value of our proved properties are critical because different natural gas, NGLs and oil pricing, cost assumptions or discount rates, as applicable, may affect the recognition, timing and amount of an impairment and, if changed, could have a material effect on the Company's financial position and results of operations.

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.

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.

We may enter into financial derivative instruments for a portion of our natural gas, NGLs and oil production when circumstances warrant and management believes that favorable future prices can be secured in order to mitigate some of the potential negative impact on our cash flows caused by changes in commodity prices. Due to our improved liquidity and leverage position as compared to historical levels, the percentage of our expected production that we hedge has decreased. For the three and six months ended June 30, 2023 and 2024, substantially all of our production was unhedged. Our financial hedging activities may include commodity fixed price swaps, basis swaps, collars or other similar instruments related to the price risk associated with our production. These contracts are financial instruments and do not require or allow for physical delivery of the hedged commodity. As of June 30, 2024, our commodity derivatives included fixed swaps, basis differential

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swaps, call options and embedded put options at index-based pricing for a portion of our production. See Note 11—Derivative Instruments to our unaudited condensed consolidated financial statements for more information.

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.

Under the Prior 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 derivative instruments that settled during the six months ended June 30, 2024, our revenues would have decreased by $75 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, 2024.

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 and comprehensive income. We present total gains or losses on commodity derivatives (for both settled derivatives and derivative positions which remain open) within operating revenues as “Commodity derivative fair value gains.”

Mark-to-market adjustments of derivative instruments cause earnings volatility but have no cash flow impact relative to changes in market prices until the derivative contracts are settled or monetized prior to settlement. We expect continued volatility in the fair value of our derivative instruments. Our cash flows are impacted when the associated derivative contracts are settled or monetized by making or receiving payments to or from the counterparty. As of December 31, 2023 and June 30, 2024, the estimated fair value of our commodity derivative instruments was a net liability $37 million and $41 million, respectively, comprised of current and noncurrent assets and liabilities.

Counterparty and Customer Credit Risk

Our principal exposures to credit risk are through receivables resulting from the following: the sale of our natural gas, NGLs and oil production ($363 million as of June 30, 2024), which we market to energy companies, end users and refineries, and commodity derivative contracts ($6 million as of June 30, 2024).

We 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, we are exposed to the credit risk of our counterparties for our derivative instruments. 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. As of June 30, 2024, we have commodity hedges in place with four different counterparties, three of which are lenders under the Prior Credit Facility. We did not have any derivative assets with bank counterparties under our Prior Credit Facility as of June 30, 2024. 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, 2024. We believe that all of the counterparties to our derivative instruments are acceptable credit risks as of June 30, 2024. Other than as provided by the Prior Credit Facility, we are not required to provide credit support or collateral to any of our counterparties under our

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derivative contracts, nor are they required to provide credit support to us. As of June 30, 2024, we did not have any past-due receivables from, or payables to, any of the counterparties to our derivative contracts.

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 Prior Credit Facility for borrowings during the six months ended June 30, 2024 was 7.71%. We estimate that a 1.0% increase in the applicable average interest rates for the six months ended June 30, 2024 would have resulted in an estimated $2 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, 2024 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, 2024 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

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 2023 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.

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Item 2. Unregistered Sales of Equity Securities

Issuer Purchases of Equity Securities

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


				Total Number	Approximate
				of Shares	Dollar Value
				Repurchased	of Shares
				as Part of	that May
	Total Number			Publicly	Yet be Purchased
	of Shares	Average Price		Announced	Under the Plan
Period	Purchased ⁽¹⁾	Paid Per Share		Plans	($ in thousands)
April 1, 2024 - April 30, 2024	433,432	$	29.00	—	$	1,050,901
May 1, 2024 - May 31, 2024	140,232		33.95	—		1,050,901
June 1, 2024 - June 30, 2024	—		—	—		1,050,901
Total	573,664	$	30.21	—

(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 equity-based awards held by our employees.

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.

Item 5. Other Information

Amended and Restated Credit Facility

On July 30, 2024, we entered into an amendment and restatement of our senior revolving credit facility. A description of the New Credit Facility is included in Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements and is incorporated into this Item 5. The description of the New Credit Facility is a summary and is qualified in its entirety by the terms of the New Credit Facility. A copy of the New Credit Facility is filed as Exhibit 10.2 hereto, and is incorporated herein by reference.

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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 Certificate of Incorporation of Antero Resources Corporation, dated June 8, 2023 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-36120) filed on June 8, 2023).
3.3		Second Amended and Restated Bylaws of Antero Resources Corporation, 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).
10.1		Amended and Restated Antero Resources Corporation 2020 Long Term Incentive Plan, dated June 5, 2024 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-36120) filed on June 6, 2024).
10.2		Amended and Restated Credit Agreement, dated as of July 30, 2024, among Antero Resources Corporation, as Borrower, the Lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent.
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, 2024 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations and Comprehensive Income, (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 31, 2024

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Antero Resources (AR) 10-Q2024 Q2 Quarterly report

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