ANTERO RESOURCES CORPORATION

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, 2026


☐	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 24, 2026 (in thousands): 307,439

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TABLE OF CONTENTS


CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS		1
PART I—FINANCIAL INFORMATION		3
Item 1.	Financial Statements (Unaudited)	3
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	54
Item 4.	Controls and Procedures	55
PART II—OTHER INFORMATION		56
Item 1.	Legal Proceedings	56
Item 1A.	Risk Factors	56
Item 2.	Unregistered Sales of Equity Securities	56
Item 4.	Mine Safety Disclosures	56
Item 5.	Other Information	56
Item 6.	Exhibits	57
SIGNATURES		58

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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, 2025. 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:

●

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

●

our ability to execute our business strategy;

●

our production and natural gas, 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, capital expenditures, working capital requirements and the repayment or refinancing of indebtedness;

●

risks associated with the successful integration and future performance of the HG Acquisition (as defined in Note 3—Transactions to the unaudited condensed consolidated financial statements);

●

our ability to execute our return of capital program;

●

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

●

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

●

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

●

marketing of natural gas, NGLs and oil;

●

our future drilling plans;

●

our projected well costs;

●

our hedging strategy and results;

●

costs of developing our properties;

●

uncertainty regarding our future operating results;

●

operations of Antero Midstream Corporation (“Antero Midstream”);

●

competition;

●

government regulations and changes in laws;

●

pending legal or environmental matters;

●

leasehold or business acquisitions;

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●

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

●

general economic conditions;

●

credit markets; 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, 2025 (the “2025 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,
	2025		2026
Assets
Current assets:
Restricted cash	$	210,000		—
Accounts receivable		33,773		25,064
Accrued revenue		473,453		458,197
Derivative instruments		68,913		180,848
Prepaid expenses		14,554		12,807
Current assets held for sale		20,269		—
Other current assets		10,818		16,654
Total current assets		831,780		693,570
Property and equipment:
Oil and gas properties, at cost (successful efforts method):
Unproved properties		796,705		1,124,479
Proved properties		14,049,003		16,976,193
Other property and equipment		113,020		125,054
		14,958,728		18,225,726
Less accumulated depletion, depreciation and amortization		(5,753,416)		(6,082,594)
Property and equipment, net		9,205,312		12,143,132
Operating leases right-of-use assets		2,132,509		2,005,573
Derivative instruments		12,524		50,767
Investment in unconsolidated affiliate		245,653		259,313
Assets held for sale		754,737		—
Other assets		62,892		80,279
Total assets	$	13,245,407		15,232,634
Liabilities and Equity
Current liabilities:
Accounts payable	$	49,514		45,468
Accounts payable, related parties		101,454		130,082
Accrued liabilities		338,847		359,272
Revenue distributions payable		384,777		443,186
Commercial paper		—		182,000
Derivative instruments		—		1,913
Short-term lease liabilities		516,256		531,669
Deferred revenue, VPP		23,502		23,793
Current liabilities held for sale		62,310		—
Other current liabilities		26,653		11,382
Total current liabilities		1,503,313		1,728,765
Long-term liabilities:
Long-term debt		1,397,976		2,432,258
Deferred income tax liability, net		907,306		1,218,788
Derivative instruments		—		1,613
Long-term lease liabilities		1,612,288		1,469,378
Deferred revenue, VPP		11,946		—
Liabilities held for sale		39,789		—
Other liabilities		57,140		64,929
Total liabilities		5,529,758		6,915,731
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; 308,510 and 308,739 shares issued and outstanding as of December 31, 2025 and June 30, 2026, respectively		3,085		3,087
Additional paid-in capital		5,865,447		5,834,394
Retained earnings		1,682,295		2,479,422
Total stockholders' equity		7,550,827		8,316,903
Noncontrolling interests		164,822		—
Total equity		7,715,649		8,316,903
Total liabilities and equity	$	13,245,407		15,232,634

See accompanying notes to unaudited condensed consolidated financial statements.

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ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Operations and Comprehensive Income (Unaudited)

(In thousands, except per share amounts)


	Three Months Ended June 30,
	2025		2026
Revenue and other:
Natural gas sales	$	688,753		688,478
Natural gas liquids sales		480,757		587,714
Oil sales		33,700		59,579
Commodity derivative fair value gains		53,409		160,633
Marketing		33,743		56,066
Amortization of deferred revenue, VPP		6,298		5,860
Other revenue and income		833		1,512
Total revenue		1,297,493		1,559,842
Operating expenses:
Lease operating		37,244		48,148
Gathering, compression, processing and transportation		701,722		748,181
Production and ad valorem taxes		34,830		37,535
Marketing		51,988		72,059
Exploration		648		904
General and administrative (including equity-based compensation expense of $15,855 and $13,266 in 2025 and 2026, respectively)		57,183		57,795
Depletion, depreciation and amortization		187,589		227,254
Impairment of property and equipment		6,297		4,455
Accretion of asset retirement obligations		942		983
Contract termination, loss contingency and settlements		13,596		1,659
Loss (gain) on sale of assets		546		(14,616)
Other operating expense		25		26
Total operating expenses		1,092,610		1,184,383
Operating income		204,883		375,459
Other income (expense):
Interest expense, net		(19,954)		(37,520)
Equity in earnings of unconsolidated affiliate		30,563		29,379
Loss on early extinguishment of debt		(729)		—
Transaction expense		—		(1,903)
Total other income (expense)		9,880		(10,044)
Income before income taxes		214,763		365,415
Income tax expense		(48,190)		(78,998)
Net income and comprehensive income including noncontrolling interests		166,573		286,417
Less: net income and comprehensive income attributable to noncontrolling interests		9,988		7,760
Net income and comprehensive income attributable to Antero Resources Corporation	$	156,585		278,657

Net income per common share—basic	$	0.50		0.90
Net income per common share—diluted	$	0.50		0.90

Weighted average number of common shares outstanding:
Basic		310,323		309,712
Diluted		313,184		310,643

See accompanying notes to unaudited condensed consolidated financial statements.

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ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Operations and Comprehensive Income (Unaudited)

(In thousands, except per share amounts)


	Six Months Ended June 30,
	2025		2026
Revenue and other:
Natural gas sales	$	1,468,758		1,999,954
Natural gas liquids sales		1,042,189		1,091,363
Oil sales		84,035		106,274
Commodity derivative fair value gains (losses)		(18,262)		195,656
Marketing		59,301		97,727
Amortization of deferred revenue, VPP		12,528		11,655
Other revenue and income		1,651		2,339
Total revenue		2,650,200		3,504,968
Operating expenses:
Lease operating		71,230		92,677
Gathering, compression, processing and transportation		1,396,739		1,537,287
Production and ad valorem taxes		90,129		118,532
Marketing		94,758		134,612
Exploration		1,316		1,696
General and administrative (including equity-based compensation expense of $31,000 and $24,999 in 2025 and 2026, respectively)		119,628		121,135
Depletion, depreciation and amortization		373,941		433,493
Impairment of property and equipment		11,915		5,403
Accretion of asset retirement obligations		1,881		2,046
Contract termination, loss contingency and settlements		12,288		13,694
Gain on sale of assets		(29)		(60,566)
Other operating expense		49		48
Total operating expenses		2,173,845		2,400,057
Operating income		476,355		1,104,911
Other income (expense):
Interest expense, net		(43,322)		(74,483)
Equity in earnings of unconsolidated affiliate		59,224		59,497
Loss on early extinguishment of debt		(3,628)		(6,742)
Transaction expense		—		(24,047)
Total other income (expense)		12,274		(45,775)
Income before income taxes		488,629		1,059,136
Income tax expense		(102,590)		(224,506)
Net income and comprehensive income including noncontrolling interests		386,039		834,630
Less: net income and comprehensive income attributable to noncontrolling interests		21,483		20,757
Net income and comprehensive income attributable to Antero Resources Corporation	$	364,556		813,873

Net income per common share—basic	$	1.17		2.63
Net income per common share—diluted	$	1.16		2.62

Weighted average number of common shares outstanding:
Basic		310,822		309,325
Diluted		314,096		310,931

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		Noncontrolling		Total
	Shares		Amount		Capital		Earnings		Interests		Equity
Balances, December 31, 2024		311,165	$	3,111		5,909,373		1,109,166		194,883		7,216,533
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		699		7		(16,305)		—		—		(16,298)
Repurchases and retirements of common stock		(280)		(3)		(5,320)		(4,771)		—		(10,094)
Equity-based compensation		—		—		15,145		—		—		15,145
Distributions to noncontrolling interests		—		—		—		—		(15,969)		(15,969)
Net income and comprehensive income		—		—		—		207,971		11,495		219,466
Balances, March 31, 2025		311,584		3,115		5,902,893		1,312,366		190,409		7,408,783
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		457		5		(10,325)		—		—		(10,320)
Repurchases and retirements of common stock		(2,172)		(22)		(41,197)		(33,653)		—		(74,872)
Equity-based compensation		—		—		15,855		—		—		15,855
Distributions to noncontrolling interests		—		—		—		—		(21,512)		(21,512)
Net income and comprehensive income		—		—		—		156,585		9,988		166,573
Balances, June 30, 2025		309,869	$	3,098		5,867,226		1,435,298		178,885		7,484,507

Balances, December 31, 2025		308,510	$	3,085		5,865,447		1,682,295		164,822		7,715,649
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		1,315		13		(34,745)		—		—		(34,732)
Equity-based compensation		—		—		11,733		—		—		11,733
Distributions to noncontrolling interests		—		—		—		—		(17,650)		(17,650)
Net income and comprehensive income		—		—		—		535,216		12,997		548,213
Balances, March 31, 2026		309,825		3,098		5,842,435		2,217,511		160,169		8,223,213
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		21		—		(174)		—		—		(174)
Repurchases and retirements of common stock		(1,107)		(11)		(21,133)		(16,746)		—		(37,890)
Equity-based compensation		—		—		13,266		—		—		13,266
Distributions to noncontrolling interests		—		—		—		—		(7,346)		(7,346)
In-kind liquidating distribution to noncontrolling interests		—		—		—		—		(160,583)		(160,583)
Net income and comprehensive income		—		—		—		278,657		7,760		286,417
Balances, June 30, 2026		308,739	$	3,087		5,834,394		2,479,422		—		8,316,903

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,
	2025		2026
Cash flows provided by (used in) operating activities:
Net income including noncontrolling interests	$	386,039		834,630
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion		375,822		435,539
Impairment of property and equipment		11,915		5,403
Commodity derivative fair value losses (gains)		18,262		(195,656)
Losses on settled commodity derivatives		(17,371)		(30,914)
Deferred income tax expense		102,475		220,675
Equity-based compensation expense		31,000		24,999
Equity in earnings of unconsolidated affiliate		(59,224)		(59,497)
Dividends of earnings from unconsolidated affiliate		62,628		62,628
Amortization of deferred revenue		(12,528)		(11,655)
Amortization of debt issuance costs and other		823		953
Settlement of asset retirement obligations		(71)		(110)
Contract termination, loss contingency and settlements		12,001		2,153
Gain on sale of assets		(29)		(60,566)
Loss on early extinguishment of debt		3,628		6,742
Changes in current assets and liabilities:
Accounts receivable		2,763		8,721
Accrued revenue		85,718		31,866
Prepaid expenses and other current assets		(8,382)		10,832
Accounts payable including related parties		(15,139)		23,815
Accrued liabilities		(85,528)		(39,486)
Revenue distributions payable		48,121		41,811
Other current liabilities		7,174		(14,976)
Net cash provided by operating activities		950,097		1,297,907
Cash flows provided by (used in) investing activities:
Additions to unproved properties		(56,640)		(45,551)
Drilling and completion costs		(356,334)		(492,372)
Additions to other property and equipment		(1,580)		(8,894)
Acquisition of HG Production		—		(2,803,195)
Acquisitions of oil and gas properties		—		(7,631)
Proceeds from asset sales		11,522		756,986
Change in other assets		(2,348)		(24,066)
Net cash used in investing activities		(405,380)		(2,624,723)
Cash flows provided by (used in) financing activities:
Issuances and borrowings of debt		2,291,800		5,521,550
Repayments of debt.		(2,686,733)		(4,295,447)
Repurchases of common stock		(84,966)		(37,890)
Payment of debt issuance costs		—		(10,838)
Distributions to noncontrolling interests in Martica Holdings LLC		(37,481)		(24,996)
Employee tax withholding for settlement of equity-based compensation awards		(26,618)		(34,906)
Other		(719)		(657)
Net cash provided by (used in) financing activities		(544,717)		1,116,816
Net decrease in cash, cash equivalents and restricted cash		—		(210,000)
Cash, cash equivalents and restricted cash, beginning of period		—		210,000
Cash, cash equivalents and restricted cash, end of period	$	—		—

Supplemental disclosure of cash flow information:
Cash paid during the period for interest	$	48,043		69,988
Increase (decrease) in accounts payable, accrued liabilities and other current liabilities for additions to property and equipment	$	(29,581)		34,482
In-kind liquidating distribution to noncontrolling interests	$	—		160,583

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. 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, 2025 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, 2025 consolidated financial statements were included in Antero Resources’ 2025 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, 2025 and June 30, 2026, results of operations for the three and six months ended June 30, 2025 and 2026 and cash flows for the six months ended June 30, 2025 and 2026. The Company has no items of other comprehensive income; therefore, its net income is equal to its comprehensive income. Operating results for the three and six months ended June 30, 2026 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 and its wholly owned subsidiaries, as well as the accounts of Martica Holdings LLC (“Martica”), a variable interest entity for which the Company was the primary beneficiary up to June 30, 2026 when Martica was deconsolidated following its in-kind liquidation and dissolution.

On May 1, 2026, Sixth Street Partners, LLC (“Sixth Street”) achieved its internal rate of return and cash-on-cash return (the “Hurdle”). As such, beginning May 1, 2026, Antero received 85% of the distributions in respect of the overriding royalty interests (“ORRIs”) to which Sixth Street was entitled immediately prior to the Hurdle being achieved (the “Reversion”). On June 30, 2026, following the achievement of the Hurdle and pursuant to the terms of the Amended and Restated Limited Liability Company Agreement of Martica Holdings LLC, Antero elected to dissolve Martica and make in-kind liquidating distributions to Sixth Street and Antero, which included conveyance of the ORRIs to Sixth Street and Antero after giving effect to the Reversion. There was no gain or loss recorded for these distributions in the Company’s unaudited condensed consolidated financial statements. As of June 30, 2026, the Company no longer consolidates Martica in the unaudited condensed consolidated financial statements and accounts for its interest in the ORRIs conveyed by Martica using the proportionate consolidation method of accounting.

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

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

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, 2025, the book overdrafts included within accounts payable and revenue distributions payable were each $18 million. As of June 30, 2026, the book overdrafts included within accounts payable and revenue distributions payable were $26 million and $31 million, respectively.

(d)	Restricted Cash

The Company classifies restricted cash as all cash that is legally or contractually restricted as to withdrawal or usage, including amounts deposited in escrow that are restricted from use. The Company’s restricted cash as of December 31, 2025 was classified as a current asset because the restriction on such cash was released on February 3, 2026 at the closing of the HG Acquisition (as defined in Note 3—Transactions).

(e)	Net Income Per Common Share

Net income per common share—basic for each period is computed by dividing net income attributable to Antero by the basic weighted average number of common shares outstanding during the period. Net income per common share—diluted for each period is computed after giving consideration to the potential dilution from outstanding equity-based awards using the treasury stock method. The Company includes restricted stock unit (“RSU”) awards, performance share unit (“PSU”) awards and stock options in the calculation of diluted 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 are anti-dilutive.

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,
	2025	2026	2025	2026
Basic weighted average number of common shares outstanding	310,323	309,712	310,822	309,325
Add: Dilutive effect of RSUs	911	326	1,305	678
Add: Dilutive effect of PSUs	1,950	605	1,969	928
Diluted weighted average number of common shares outstanding	313,184	310,643	314,096	310,931

Weighted average number of outstanding securities excluded from calculation of diluted net income per common share ⁽¹⁾:
RSUs	—	8	—	4
Stock options	42	—	146	—

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

(f)	Recently Issued Accounting Standard

In November 2024, the FASB issued ASU No. 2024-03, Disaggregation of Income Statement Expenses (“ASU 2024-03”). ASU 2024-03 is intended to improve the disclosure about certain operating expenses primarily through enhanced disclosure of cost of sales and selling, general and administrative expenses. This ASU is effective for annual reporting periods beginning after December 15, 2026, and interim periods within fiscal years beginning after December 15, 2027. Early adoption is permitted. ASU 2024-03 can be applied on either a prospective or a retrospective basis at the Company’s election. The Company is evaluating the impact that ASU 2024-03 will have on the consolidated financial statements and its plans for adoption, including its transition method and adoption date.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(3) Transactions

(a)	2025 Drilling Partnership

On December 11, 2024, the Company entered into a drilling partnership with an unaffiliated third-party (“2025 Drilling Partnership”). Under the terms of the arrangement, the third-party will participate in and fund a share of total development capital expenses for wells spud by the Company during the 2025 calendar year. For each well spud during the 2025 calendar year, the third-party will receive a 15% working interest in such wells and will fund greater than 15% of total development capital expenses for such wells. Subject to the preceding sentence, for any wells spud in the calendar year 2025, the third-party 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. Additionally, for each well in the partnership, the Company will enter into an assignment, bill of sale and conveyance pursuant to which the third-party will be conveyed a proportionate working interest percentage in such well, which conveyances will not be subject to any reversion.

The Company has accounted for the 2025 Drilling Partnership as a conveyance under ASC 932 and such conveyances are recorded in the unaudited condensed consolidated financial statements as the third-party obtains its proportionate working interest in each well. No gain or loss was recognized for any of the interests conveyed during the term of the 2025 Drilling Partnership.

(b)	HG Acquisition

On December 5, 2025, the Company entered into a definitive agreement to acquire 100% of the issued and outstanding equity interests of HG Energy II Production Holdings, LLC (“HG Production”) for total cash consideration of $2.8 billion (the “HG Acquisition”), subject to the terms and conditions thereof. The HG Acquisition included approximately 385,000 net acres in the core of the Marcellus Shale in West Virginia. On December 8, 2025, the Company deposited $210 million into escrow that was credited towards the cash consideration payable at the closing of the HG Acquisition, which was classified as restricted cash on the Company’s consolidated balance sheet as of December 31, 2025. This acquisition closed on February 3, 2026 (the “Closing Date”), with an effective date of January 1, 2026. In light of the nature and location of the assets and operations acquired in the HG Acquisition, the Company and Antero Midstream agreed in principle to certain updates to, and intend to modify, their existing commercial arrangements to provide for well pad compression with respect to certain wells and to provide certain water services. See Note 15—Related Parties for additional information.

The HG Acquisition has been accounted for using the acquisition method of accounting, with the Company identified as the acquirer of HG Production. The Company is still completing its analysis of the final purchase price allocation, including the fair values assigned to oil and gas properties and the deferred income tax liability, among others. Adjustments to the preliminary purchase price allocation recorded during the three months ended June 30, 2026 primarily relate to additional information obtained by the Company between the Closing Date and June 30, 2026 about facts and circumstances that existed on the Closing Date, including the completion of the post-closing settlement statement, among others. The Company expects to complete the purchase price allocation during the 12-month period following the Closing Date. The table below summarizes the preliminary purchase price and estimated fair values of assets acquired and liabilities assumed as of the Closing Date. See Note 10—Fair Value Measurement for additional information on the fair value assumptions and hierarchy used in the HG Acquisition preliminary purchase price allocation.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements


	As Originally
(in thousands)	Reported		Adjustments		As Adjusted
Cash consideration	$	2,804,466		(1,203)		2,803,263

Fair value of assets acquired:
Cash		69		—		69
Accounts receivable		2,635		—		2,635
Accrued revenue		114,755		—		114,755
Unproved properties		318,535		(116)		318,419
Proved properties		2,648,067		(1,368)		2,646,699
Other property and equipment		1,114		—		1,114
Operating lease right-of-use asset		96,002		—		96,002
Derivative instruments		10,082		—		10,082
Total assets acquired	$	3,191,259		(1,484)		3,189,775

Fair value of liabilities assumed:
Accounts payable	$	389		—		389
Accounts payable, related parties		16,671		—		16,671
Accrued liabilities		60,165		343		60,508
Revenue distributions payable		27,961		(624)		27,337
Operating lease liability		96,002		—		96,002
Derivative instruments		90,001		—		90,001
Deferred income tax liability ⁽¹⁾		90,807		—		90,807
Other liabilities		4,797		—		4,797
Total liabilities assumed	$	386,793		(281)		386,512

(1)

The deferred income tax liability recorded for the HG Acquisition relates to Antero Resources’ treatment of certain assets held by HG Production and its subsidiaries as like-kind replacement property in connection with a reverse like-kind exchange transaction conducted pursuant to Section 1031 of the United States Internal Revenue Code of 1986, as amended, the treasury regulations promulgated thereunder, and IRS Revenue Procedure 2000-37, 2000-2 C.B. 308 (as modified by IRS Revenue Procedure 2004-51, 2004-2 C.B. 294).

The Company’s financial statements include $2 million and $24 million of acquisition-related costs associated with the HG Acquisition during the three and six months ended June 30, 2026, respectively, which are recorded in transaction expense in the unaudited condensed consolidated statements of operations and comprehensive income.

The following table summarizes amounts contributed by the assets acquired in the HG Acquisition to the Company’s unaudited condensed consolidated results of operations and comprehensive income upon transaction closing on the Closing Date (in thousands):


	February 3, 2026
	through June 30, 2026
Natural gas sales	$	321,202
Natural gas liquids sales		53,597
Oil sales		12,395
Commodity derivative fair value gains		128,514
Total revenue		515,708

Net income and comprehensive income including noncontrolling interests ⁽¹⁾		221,531
Less: net income and comprehensive income attributable to noncontrolling interests		—
Net income and comprehensive income attributable to Antero Resources Corporation ⁽¹⁾	$	221,531

(1)	Amounts include transaction expense of $24 million related to the HG Acquisition recognized during the six months ended June 30, 2026.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

The table below summarizes the Company's results as though the HG Acquisition had been completed on January 1, 2025 (in thousands, except per share data). Certain historical amounts were reclassified to conform to the Company's current financial presentation in the statements of operations and comprehensive income. Such unaudited pro forma information is provided for informational purposes only and does not represent what consolidated results of operations would have been had the HG Acquisition occurred on January 1, 2025 nor are they indicative of future consolidated results of operations.


	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	2025		2026		2025		2026
Pro forma revenue and other:
Natural gas sales	$	869,408		688,478		1,857,265		2,104,631
Natural gas liquids sales		490,768		587,714		1,068,291		1,100,266
Oil sales		34,058		59,579		85,123		107,449
Commodity derivative fair value gains (losses)		204,529		160,633		(70,968)		51,892
Marketing		33,743		56,066		59,301		97,727
Amortization of deferred revenue, VPP		6,298		5,860		12,528		11,655
Other revenue and income		2,263		1,512		4,570		2,803
Pro forma total revenue		1,641,067		1,559,842		3,016,110		3,476,423

Pro forma net income and comprehensive income including noncontrolling interests		322,868		286,417		434,085		786,092
Less: pro forma net income and comprehensive income attributable to noncontrolling interests		9,988		7,760		21,483		20,757
Pro forma net income and comprehensive income attributable to Antero Resources Corporation	$	312,880		278,657		412,602		765,335

Pro forma net income per common share—basic	$	1.01		0.90		1.33		2.47
Pro forma net income per common share—diluted	$	1.00		0.90		1.31		2.46

(c)	Utica Shale Divestiture

On December 5, 2025, the Company entered into a purchase and sale agreement with two third-party buyers (collectively, the “Buyer Parties”) to sell the Company’s Utica Shale oil and gas assets (the “Utica Shale Properties”) for aggregate cash consideration of $800 million before closing adjustments, subject to the terms and conditions thereof (the “Utica Shale Divestiture”). The Utica Shale Properties included approximately 80,000 gross (70,000 net) acres located in Ohio and proved reserves of approximately 600 Bcfe as of December 31, 2025. The Utica Shale Divestiture closed on February 23, 2026, with an effective date of July 1, 2025.

The Utica Shale Properties and its associated assets and liabilities were classified as held for sale as of December 31, 2025 on the Company’s consolidated balance sheet, which relate to the Company’s exploration and production reportable segment. The Utica Shale Divestiture does not qualify as a discontinued operation under FASB ASC Topic 205, Presentation of Financial Statements, as it does not represent a strategic shift that will have a major effect on the Company's operations or financial results.

The cash consideration received for the Utica Shale Divestiture less costs to sell of approximately $760 million, which includes certain contingent amounts released from escrow during the three months ended June 30, 2026, was greater than the carrying value of the Utica Shale Properties net assets as of February 23, 2026. Accordingly, the Company recorded a gain on sale of assets of $15 million and $61 million during the three and six months ended June 30, 2026, respectively, in its unaudited condensed consolidated statements of operations and comprehensive income.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

The following table sets forth the carrying value of the Utica Shale Properties’ assets and liabilities held for sale as of December 31, 2025 (in thousands):


	December 31, 2025
Current assets:
Accounts receivable	$	782
Accrued revenue		19,399
Other current assets		88
Long-term assets:
Unproved properties		27,720
Proved properties		1,045,145
Gathering systems and facilities		5,802
Other property and equipment		581
Less accumulated depletion, depreciation and amortization		(369,995)
Property and equipment, net		709,253
Operating leases right-of-use assets ⁽¹⁾		44,825
Other assets		659
Total assets	$	775,006

Current liabilities:
Accounts payable	$	2,118
Accounts payable, related parties		4,600
Accrued liabilities		17,650
Revenue distributions payable		17,130
Short-term lease liabilities		20,812
Long-term liabilities:
Long-term lease liabilities		24,210
Other liabilities		15,579
Total liabilities	$	102,099

(1)	Substantially all of these operating leases right-of-use-assets relate to a gas gathering line and compressor stations with Antero Midstream. See Note 12— Leases to the unaudited condensed consolidated financial statements for additional information.

(d)	Subsequent Event

In July 2026, the Company acquired additional working and royalty interests in Antero’s core operating area for a total of approximately $315 million. Substantially all of the cash consideration is expected to be allocated to proved properties in the unaudited condensed consolidated balance sheet.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(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 additional information.


	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2026		2025		2026		Reportable Segment
Revenues from contracts with customers:
Natural gas sales	$	688,753		688,478		1,468,758		1,999,954	Exploration and production
Natural gas liquids sales (ethane)		78,546		99,018		173,026		191,375	Exploration and production
Natural gas liquids sales (C3+ NGLs)		402,211		488,696		869,163		899,988	Exploration and production
Oil sales		33,700		59,579		84,035		106,274	Exploration and production
Marketing		33,743		56,066		59,301		97,727	Marketing
Other revenue		273		1,003		543		1,272	Exploration and production
Total revenue from contracts with customers		1,237,226		1,392,840		2,654,826		3,296,590
Income (loss) from derivatives, deferred revenue and other sources, net		60,267		167,002		(4,626)		208,378
Total revenue	$	1,297,493		1,559,842		2,650,200		3,504,968

(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.

(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, 2025 and June 30, 2026, the Company’s receivables from contracts with customers were $493 million and $458 million, respectively.

(5) Equity Method Investment

As of December 31, 2025 and June 30, 2026, Antero owned 29% 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, 2025 ⁽¹⁾		245,653
Equity in earnings of unconsolidated affiliate		59,497
Dividends from unconsolidated affiliate		(62,628)
Elimination of intercompany profit		16,791
Balance as of June 30, 2026 ⁽¹⁾	$	259,313

(1)	The fair value of the Company’s investment in Antero Midstream as of December 31, 2025 and June 30, 2026 was $2.5 billion and $3.2 billion, respectively, based on the quoted market share price of Antero Midstream.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(6) Accrued Liabilities

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


					(Unaudited)
		December 31,			June 30,
		2025			2026
Capital expenditures		$	32,656			68,559
Gathering, compression, processing and transportation expenses			169,270			162,366
Marketing expenses			12,851			25,348
Interest expense			24,256			29,015
Production and ad valorem taxes			22,770			18,555
General and administrative expense			40,663			29,390
Contingencies and other			36,381			26,039
Total accrued liabilities		$	338,847			359,272

(7) Debt

Total debt consisted of the following items (in thousands):


				(Unaudited)
	December 31,			June 30,
	2025			2026
Short-term:
Commercial paper	$	—			182,000
Long-term:
Credit Facility		438,600			2,700
Term Loan		—			1,100,000
7.625% senior notes due 2029		365,353			—
5.375% senior notes due 2030		600,000			600,000
5.400% senior notes due 2036		—			750,000
Unamortized debt issuance costs		(5,977)			(20,442)
Total long-term debt		1,397,976			2,432,258
Total debt	$	1,397,976			2,614,258

(a)	Commercial Paper

On June 16, 2026, Antero Resources established a commercial paper program (the “Commercial Paper Program”) pursuant to which Antero Resources may issue short-term, unsecured commercial paper notes (the “Commercial Paper”). The Commercial Paper may be issued and redeemed from time to time, with the aggregate face or principal amount of the notes outstanding under the Commercial Paper Program at any time not to exceed $1.65 billion. The Commercial Paper will be sold under customary market terms in the U.S. commercial paper market at a discount from par or at par and bear interest at rates determined at the time of issuance. The maturities of the Commercial Paper may vary, but shall not exceed 397 days from the date of issuance. Antero Resources’ Credit Facility (defined below) will serve as a liquidity backstop for any issuances under the Commercial Paper Program, and therefore, Antero Resources intends to maintain available capacity under the Credit Facility in an amount at least equal to the aggregate outstanding borrowings under the Commercial Paper Program.

During the second quarter of 2026, Antero Resources utilized the Commercial Paper Program to fund various short-term working capital requirements. As of June 30, 2026, Antero Resources had $182 million of outstanding Commercial Paper maturing at various dates in July 2026 with a weighted average interest rate of 4.4%.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(b)	Credit Facility

On July 30, 2024, Antero Resources entered into an amendment and restatement of its senior revolving credit facility with a syndicate of bank lenders (as amended to date, the “Credit Facility”). Borrowings are unsecured and are not guaranteed by any of Antero Resources’ subsidiaries. The Credit Facility was scheduled to mature on July 30, 2030, provided that Antero Resources could request one one-year extension of this maturity date, subject to satisfaction of certain conditions and consent of the extending lenders. However, on July 28, 2026 (the “First Amendment Effective Date”), Antero Resources entered an amendment to the Credit Facility to extend the scheduled maturity date (the “Maturity Date”) to July 30, 2031. Antero Resources may request two one-year extensions of the Maturity Date after the First Amendment Effective Date, subject to satisfaction of certain conditions and consent of the extending lenders. Commitments under the Credit Facility may be increased by up to $500 million subject to the agreement of Antero Resources, the increasing lenders, and with respect to the addition of new lenders, the consent of the Administrative Agent under the Credit Facility and the lenders with commitments to issue letters of credit under the Credit Facility.

The Credit Facility contains one financial covenant requiring Antero Resources to maintain a ratio on a consolidated basis of total indebtedness to capitalization of 65% or less at the end of each fiscal quarter and other affirmative and negative covenants applicable to Antero Resources and its subsidiaries that are customary for credit facilities of this type, including, among other things, limitations on: fundamental changes such as mergers, consolidations, liquidations and dissolutions; liens; certain indebtedness; restricted payments such as dividends, distributions and equity repurchases; and material non-arms’-length transactions with its affiliates. Antero Resources was in compliance with the financial covenant under the Credit Facility as of December 31, 2025 and June 30, 2026.

The Credit Facility provides for borrowing at Secured Overnight Financing Rate (“SOFR”) or an Alternate Base Rate, in each case, plus an Applicable Rate (each as defined in the Credit Facility). The Credit Facility does not amortize. Interest under the Credit Facility is payable at a variable rate based on SOFR or the Alternate Base Rate, determined by election at the time of borrowing and at the end of each applicable interest period in respect of a borrowing, plus an Applicable Rate. The Applicable Rate is determined with reference to Antero Resources’ then-current senior unsecured long-term debt rating ranging from 1.125% to 2.00% for SOFR loans. Commitment fees on the unused portion of the Credit Facility are due quarterly at rates ranging from 0.125% to 0.300%, determined with reference to Antero Resources’ then-current senior unsecured long-term debt ratings.

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

As of December 31, 2025, Antero Resources had an outstanding balance under the Credit Facility of $439 million, with a weighted average interest rate of 5.3%, and outstanding letters of credit of $12 million. As of June 30, 2026, Antero Resources had an outstanding balance under the Credit Facility of $3 million, with a weighted average interest rate of 7.3%, and outstanding letters of credit of $12 million.

(c)	Term Loans

In connection with the signing of the HG Acquisition, Antero Resources entered into a debt commitment letter dated December 5, 2025 with a syndicate of banks (collectively, the “Banks”), pursuant to which the Banks committed, subject to satisfaction of certain customary terms and conditions, to provide Antero Resources with an unsecured 364-day term loan facility in an aggregate principal amount of $800 million (the “Term Loan Bridge Facility”) and an unsecured 3-year term loan facility in an aggregate principal amount of $1.5 billion (the “Term Loan”). As of December 31, 2025, Antero Resources had not entered into definitive agreements with respect to either of the Term Loan Bridge Facility or the Term Loan. In connection with the issuance of the 2036 Notes on January 28, 2026, Antero Resources and the Banks terminated the commitments with respect to the Term Loan Bridge Facility.

On February 3, 2026, substantially concurrently with the consummation of the HG Acquisition, Antero Resources entered into the Term Loan. The Term Loan is unsecured and is not guaranteed by any of Antero Resources’ subsidiaries. The proceeds of the loans made under the Term Loan were used to (i) finance a portion of the consideration for the HG Acquisition and (ii) to pay fees and expenses incurred in connection with the transactions related thereto. On February 3, 2026, Antero

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

Resources borrowed $1.5 billion in a single borrowing to partially fund the HG Acquisition. The Term Loan is scheduled to mature on February 3, 2029.

The Term Loan contains the same financial covenant as our Credit Facility requiring Antero Resources to maintain a ratio on a consolidated basis of total indebtedness to capitalization of 65% or less at the end of each fiscal quarter and other affirmative and negative covenants applicable to Antero Resources that are substantially the same as those covenants in our Credit Facility and otherwise customary for term loans of this type, including, among other things, limitations on: fundamental changes such as mergers, consolidations, liquidations and dissolutions; liens; certain indebtedness; restricted payments such as dividends, distributions and equity repurchases; and material non-arms’-length transactions with its affiliates. Antero Resources was in compliance with the financial covenant under the Term Loan as of June 30, 2026.

The Term Loan provides for borrowings at Term SOFR or an Alternate Base Rate at our option, in each case, plus the Applicable Rate (each, as defined in the Term Loan). There is a 0.10% credit adjustment spread on SOFR and a 0.00% floor. The Term Loan does not amortize. Interest under the Term Loan is payable at a variable rate based on SOFR or the Alternate Base Rate, determined by election at the time of borrowing and at the end of each applicable interest period in respect of a borrowing, plus the Applicable Rate. The Applicable Rate is determined with reference to Antero Resources’ then-current senior unsecured long-term debt rating, ranging from 1.125% to 2.00% for Term SOFR loans.

As of June 30, 2026, Antero Resources had an outstanding balance under the Term Loan of $1.1 billion, with a weighted average interest rate of 5.2%.

(d)	8.375% Senior Notes Due 2026

On January 4, 2021, Antero Resources issued $500 million of 8.375% senior notes due July 15, 2026 (the “2026 Notes”) at par. The Company redeemed $175 million principal amount of the 2026 Notes on July 1, 2021 and redeemed or otherwise repurchased $228 million principal amount of the 2026 Notes during the year ended December 31, 2022. On March 5, 2025, the Company redeemed the remaining $97 million principal amount of the 2026 Notes at 102.094% of the principal amount thereof, plus accrued and unpaid interest, and the 2026 Notes were fully retired on such date. Interest on the 2026 Notes was payable on January 15 and July 15 of each year.

(e)	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. During the year ended December 31, 2025, the Company repurchased $42 million principal amount of the 2029 Notes through open market transactions at a weighted average price of approximately 103% of the principal amount thereof, plus accrued and unpaid interest. On February 24, 2026, the Company redeemed the remaining $365 million principal amount of the 2029 Notes at 101.271% of the principal amount thereof, plus accrued and unpaid interest, and the 2029 Notes were fully retired on such date. Interest on the 2029 Notes was payable on February 1 and August 1 of each year.

(f)	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 rank pari passu to Antero Resources’ Credit Facility, Term Loan and other outstanding senior notes. As of July 30, 2024, the 2030 Notes are not guaranteed by any of Antero Resources’ 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 at redemption prices ranging from 101.792% as of June 30, 2026 to 100.00% on or after March 1, 2028. 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.

(g)	5.400% Senior Notes Due 2036

On January 28, 2026, Antero Resources issued $750 million of 5.400% senior notes due February 1, 2036 (the “2036 Notes”) at a price of 99.869% of par. Interest on the 2036 Notes is payable on February 1 and August 1 of each year, commencing August 1, 2026. The 2036 Notes are unsecured and rank pari passu to Antero Resources’ Credit Facility, Term Loan and other outstanding senior notes. The 2036 Notes are not guaranteed by any of Antero Resources’ subsidiaries. Prior to November 1, 2035 (the “Par Call Date”), Antero Resources may redeem all or part of the 2036 Notes at any time at a

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

redemption price equal to the greater of (i) (a) the sum of the present values of the remaining scheduled payments of principal and interest thereon discounted to the redemption date (assuming the 2036 Notes mature on the Par Call Date) on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Rate (as defined in the indenture governing the 2036 Notes) plus 20 basis points less (b) interest accrued to the date of redemption, and (ii) 100% of the principal amount of the 2036 Notes to be redeemed, plus, in either case, accrued and unpaid interest thereon to the redemption date. On or after the Par Call Date, Antero Resources may redeem the 2036 Notes, in whole or in part, at any time and from time to time, at a redemption price equal to 100% of the principal amount of the 2036 Notes being redeemed plus accrued and unpaid interest thereon to the redemption date.

(8) Asset Retirement Obligations

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


Asset retirement obligations—December 31, 2025	$	57,139
Obligations incurred		1,102
Obligations assumed in acquisition		4,797
Accretion expense		2,046
Settlement of obligations		(110)
Revisions to prior estimates		(45)
Asset retirement obligations—June 30, 2026	$	64,929

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

(9) Equity-Based Compensation

On June 5, 2024, the Company’s stockholders approved the Amended and Restated Antero Resources Corporation 2020 Long Term Incentive Plan (the “AR LTIP”). The 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 (the “Board”). Employees, officers, non-employee directors and other service providers of the Company and its affiliates are eligible to receive awards under the AR LTIP.

The 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 a predecessor plan to the AR LTIP 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 AR LTIP. Further, any shares withheld or surrendered in payment of any taxes relating to awards that were outstanding under a predecessor plan to the AR LTIP as of June 17, 2020 or are granted under the AR LTIP or its predecessor plan (other than stock options and stock appreciation rights), will again be available for new awards under the AR LTIP.

A total of 10,072,378 shares were available for future grant under the AR LTIP as of June 30, 2026.

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,
	2025		2026		2025		2026
RSU awards	$	10,669		8,993		22,138		17,543
PSU awards		4,756		3,878		8,019		6,666
Equity awards issued to directors		430		395		843		790
Total expense	$	15,855		13,266		31,000		24,999

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(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, 2025	2,336,401	$	29.67
Granted	1,025,783		38.83
Vested	(1,185,493)		28.40
Forfeited	(24,696)		33.24
Total awarded and unvested—June 30, 2026	2,151,995	$	34.69

As of June 30, 2026, there was $63 million of unamortized equity-based compensation expense related to unvested RSUs. That expense is expected to be recognized over a weighted average period of 2.1 years.

(b)	Performance Share Unit Awards

Performance Share Unit Awards Based on Total Shareholder Return

In March 2026, the Company granted PSU awards to certain of its senior management and executive officers that vest based on Antero Resources’ absolute TSR determined as of the last day of each of three one-year performance periods ending on March 7, 2027, March 7, 2028 and March 7, 2029, and one cumulative three-year performance period ending on March 7, 2029, in each case, subject to certain continued employment criteria for each performance period (“2026 Absolute TSR PSUs”). The 2026 Absolute TSR PSUs will be settled following the end of each performance period. The aggregate number of shares of common stock that may ultimately be earned with respect to the 2026 Absolute TSR PSUs ranges from zero to 200% of the target number of 2026 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 2026 Absolute TSR PSUs:


Dividend yield		—	%
Volatility		42	%
Risk-free interest rate		3.56	%
Weighted average fair value of awards granted	$	43.84

Performance Share Unit Awards Based on Leverage Ratio

In March 2026, the Company granted PSUs to certain of its senior management and executive officers that vest based on the Company’s Net Debt to EBITDAX (as defined in the award agreement) determined as of the last day of each of three one-year performance periods ending on December 31, 2026, December 31, 2027 and December 31, 2028, in each case, subject to certain continued employment criteria for each performance period (“2026 Leverage Ratio PSUs”). The 2026 Leverage Ratio PSUs will be settled following the end of each performance period. The aggregate number of shares of common stock that may ultimately be earned with respect to the 2026 Leverage Ratio PSUs ranges from zero to 200% of the target number of 2026 Leverage Ratio PSUs originally granted. Expense related to the 2026 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, 2026, the likelihood of achieving the performance conditions related to the 2026 Leverage Ratio PSUs was probable.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

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, 2025	1,359,347	$	33.80
Granted	193,146		40.08
Vested ⁽¹⁾⁽²⁾	(685,313)		35.15
Forfeited ⁽¹⁾	(78,877)		39.90
Total awarded and unvested—June 30, 2026	788,303	$	33.56

(1)	During the six months ended June 30, 2026, the PSUs granted in 2022 and 2023 based on absolute TSR performance criteria achieved vesting at 82% and 75%, respectively, of the target amounts and converted into 0.3 million shares, and the 0.1 million units that did not vest were forfeited.

(2)	During the six months ended June 30, 2026, certain PSUs granted in 2022, 2023 and 2025 based on Net Debt to EBITDAX performance criteria achieved vesting at 194%, 194% and 200%, respectively, of the target amounts and converted into 0.8 million shares.

As of June 30, 2026, there was $16 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.

(10) Fair Value Measurement

(a)	Senior Notes

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


					(Unaudited)
	December 31, 2025				June 30, 2026
	Fair		Carrying		Fair		Carrying
	Value ⁽¹⁾		Value ⁽²⁾		Value ⁽¹⁾		Value ⁽²⁾
2029 Notes	$	370,431		363,204		—		—
2030 Notes		607,500		596,172		604,500		592,139
2036 Notes		—		—		737,625		746,587
Total	$	977,931		959,376		1,342,125		1,338,726

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

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

(b)	Other Assets and Liabilities

The carrying values of restricted cash as of December 31, 2025, accounts receivable and accounts payable as of December 31, 2025 and June 30, 2026 and the amounts outstanding under the Commercial Paper Program as of June 30, 2026 approximated fair value because of their short-term nature. The carrying values of the amounts outstanding under the Credit Facility as of December 31, 2025 and June 30, 2026 and the Term Loan as of June 30, 2026 approximated fair value because the variable interest rates are reflective of current market conditions.

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

(c)	HG Acquisition

The HG Acquisition was accounted for under the acquisition method of accounting, and as such, the Company estimated the fair value of assets acquired and liabilities assumed as of the Closing Date. See Note 3—Transactions to the unaudited condensed consolidated financial statements for additional information.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

The fair value of the derivative instruments acquired in the HG Acquisition were measured using a market approach that uses a third-party pricing service and is based on inputs that are either observable in the market or can be corroborated by market data, whereby it is a Level 2 fair value measurement. The fair values of the developed and undeveloped natural gas properties acquired in the HG Acquisition were measured using discounted cash flow valuation techniques based on inputs that are not observable in the market and, as such, are Level 3 fair value measurements. Significant inputs used in the valuation of developed and undeveloped properties included commodity prices, projected reserve quantities, estimated future rates of production, projected reserve recovery factors, development plans (including timing and amount of development), future development costs, operating costs and a weighted-average cost of capital of 9.0%. The fair value of undeveloped acreage with no future development plans acquired in the HG Acquisition was measured using a cost approach based on inputs that are not observable in the market, whereby it is a Level 3 fair value measurement. The significant input used in the valuation of undeveloped acreage with no future development plans was mineral lease acreage prices evaluated from a market participant perspective.

(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 commodity derivative contracts that settled during the three and six months ended June 30, 2025 and 2026. The Company enters into derivative contracts when management believes that favorable future sales prices for the Company’s production can be secured. 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 unaudited condensed consolidated statements of operations and comprehensive income.

Fixed Price Swaps

As of June 30, 2026, the Company’s fixed price swap positions were as follows:


				Weighted
				Average
Commodity / Settlement Period	Index	Contracted Volume		Price
Natural Gas
July-December 2026	Henry Hub	1,295,000	MMBtu/day		3.91	/MMBtu
July-December 2026	TETCO M2	10,000	MMBtu/day		3.36	/MMBtu
January-December 2027	Henry Hub	915,329	MMBtu/day		3.88	/MMBtu
January-December 2027	Dom South	20,000	MMBtu/day		2.93	/MMBtu
January-December 2028	Henry Hub	174,973	MMBtu/day		3.78	/MMBtu
January-December 2028	Dom South	30,000	MMBtu/day		2.88	/MMBtu
January-December 2028	TETCO M2	60,000	MMBtu/day		2.92	/MMBtu

Under the Company’s fixed price swap agreements, when actual commodity prices upon settlement exceed the fixed price provided by the 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.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

Basis Swaps

As of June 30, 2026, the Company’s basis swap positions were as follows:


				Weighted Average
Commodity / Settlement Period	Index to Basis Differential	Contracted Volume		Price
Natural Gas
July-December 2026	NYMEX to TETCO M2	430,000	MMBtu/day	$	(0.97)	/MMBtu
July-December 2026	NYMEX to Dom South	220,000	MMBtu/day		(0.98)	/MMBtu
July-December 2026	NYMEX to TCO	100,000	MMBtu/day		(0.83)	/MMBtu
January-December 2027	NYMEX to TETCO M2	302,959	MMBtu/day		(0.93)	/MMBtu
January-December 2027	NYMEX to Dom South	154,630	MMBtu/day		(1.00)	/MMBtu
January-December 2027	NYMEX to TCO	74,795	MMBtu/day		(0.78)	/MMBtu
January-December 2028	NYMEX to TETCO M2	104,863	MMBtu/day		(0.88)	/MMBtu
January-December 2028	NYMEX to Dom South	54,973	MMBtu/day		(0.95)	/MMBtu
January-December 2028	NYMEX to TCO	29,945	MMBtu/day		(0.81)	/MMBtu

Under the Company’s basis swap contracts, when actual commodity prices upon settlement are lower than the fixed price provided by the contracts, the Company receives the difference from the counterparty. When actual commodity prices upon settlement are higher than the contractually provided fixed price, the Company pays the difference to the counterparty.

Short Calls

As of June 30, 2026, the Company’s short call contract positions were as follows:


				Weighted
				Average
Commodity / Settlement Period	Index	Contracted Volume		Price
Natural Gas
July-December 2026	Henry Hub	30,000	MMBtu/day	$	7.25	/MMBtu
January-December 2027	Henry Hub	24,959	MMBtu/day		7.10	/MMBtu

Under the Company’s short call contracts, when actual commodity prices upon settlement exceed the fixed price provided by the contracts, the Company pays the difference to the counterparty.

Collars

As of June 30, 2026, the Company’s collar contract positions were as follows:

Weighted

Average

Commodity / Settlement Period

Index

Contracted Volume

Ceiling Price

Floor Price

Natural Gas

July-December 2026 ⁽¹⁾

Henry Hub

587,000

MMBtu/day

5.52

/MMBtu

3.21

/MMBtu

January-December 2027

Henry Hub

57,425

MMBtu/day

4.62

/MMBtu

3.46

/MMBtu

(1)

Includes a call option and an embedded put option for 32,000 MMBtu/day at a strike price of $2.63/MMBtu tied to NYMEX pricing for the production volumes associated with the Company’s retained interest in the volumetric production payment transaction (“VPP”) properties. The Company bifurcated the embedded put option and reflects it at fair value in the unaudited condensed consolidated financial statements.

Under the Company’s collar agreements, when actual commodity prices upon settlement are below the floor price provided by the contract, the Company receives the difference from the counterparty. When actual commodity prices upon settlement are above the ceiling price, the Company pays the difference to the counterparty.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

Three-Way Collars

As of June 30, 2026, the Company’s three-way collar contract positions were as follows:

Weighted

Contracted

Average

Commodity / Settlement Period

Index

Volume

Ceiling Price

Floor Price

Sub-Floor Price

Natural Gas

July-December 2026

Henry Hub

20,000

MMBtu/day

4.88

/MMBtu

3.70

/MMBtu

2.88

/MMBtu

January-December 2027

Henry Hub

22,466

MMBtu/day

4.68

/MMBtu

3.66

/MMBtu

2.55

/MMBtu

Under the Company’s three-way collar agreements, when actual commodity prices upon settlement are below the floor price provided by the contract, the Company receives the difference from the counterparty. When actual commodity prices upon settlement are above the ceiling price, the Company pays the difference to the counterparty. When actual commodity prices are below the sub-floor price, the Company pays the difference to the counterparty.

Martica

During the three months ended March 31, 2025, all of Martica’s derivative contracts expired, and therefore, after March 31, 2025, there were no derivative gains or losses attributable to Martica. Martica was deconsolidated from the condensed consolidated financial statements as of June 30, 2026. See Note 2—Summary of Significant Accounting Policies for additional information.

(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)
		December 31,		June 30,
	Balance Sheet Location	2025		2026
Asset derivatives not designated as hedges for accounting purposes:
Commodity derivatives—current	Derivative instruments	$	68,054		180,648
Embedded derivatives—current	Derivative instruments		859		200
Commodity derivatives—noncurrent	Derivative instruments		12,524		50,767
Total asset derivatives ⁽¹⁾			81,437		231,615

Liability derivatives not designated as hedges for accounting purposes:
Commodity derivatives—current	Derivative instruments		—		1,913
Commodity derivatives—noncurrent	Derivative instruments		—		1,613
Total liability derivatives ⁽¹⁾			—		3,526

Net derivatives asset ⁽¹⁾		$	81,437		228,089

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

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

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, 2025						June 30, 2026
											Net Amounts of
	Gross		Gross		Net Amounts of		Gross		Gross		Assets
	Amounts		Amounts Offset		Assets on		Amounts		Amounts Offset		(Liabilities) on
	Recognized		Recognized		Balance Sheet		Recognized		Recognized		Balance Sheet
Commodity derivative assets	$	162,641		(82,063)		80,578		374,087		(142,672)		231,415
Embedded derivative assets		859		—		859		200		—		200
Commodity derivative liabilities		(82,063)		82,063		—		(146,198)		142,672		(3,526)

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	Three Months Ended June 30,				Six Months Ended June 30,
	Operations Location	2025		2026		2025		2026
Commodity derivative fair value gains (losses) ⁽¹⁾	Revenue	$	53,220		161,186		(17,241)		196,316
Embedded derivative fair value gains (losses) ⁽¹⁾	Revenue		189		(553)		(1,021)		(660)

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

(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 condensed consolidated 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	2025		2026
Operating Leases
Operating lease right-of-use assets:
Processing plants	Operating lease right-of-use assets	$	1,135,203		1,027,181
Drilling rigs and completion services	Operating lease right-of-use assets		54,968		160,370
Gas gathering lines and compressor stations ⁽¹⁾	Operating lease right-of-use assets		912,073		789,992
Office space	Operating lease right-of-use assets		28,400		25,771
Office, field and other equipment	Operating lease right-of-use assets		1,865		2,259
Total operating lease right-of-use assets		$	2,132,509		2,005,573
Operating lease liabilities:
Short-term operating lease liabilities	Short-term lease liabilities	$	514,717		530,520
Long-term operating lease liabilities	Long-term lease liabilities		1,610,341		1,467,889
Total operating lease liabilities		$	2,125,058		1,998,409
Finance Leases
Finance lease right-of-use assets:
Vehicles	Other property and equipment	$	3,486		2,638
Total finance lease right-of-use assets ⁽²⁾		$	3,486		2,638
Finance lease liabilities:
Short-term finance lease liabilities	Short-term lease liabilities	$	1,539		1,149
Long-term finance lease liabilities	Long-term lease liabilities		1,947		1,489
Total finance lease liabilities		$	3,486		2,638

(1)	Gas gathering lines and compressor stations relate to Antero Midstream. See “—‍Related Party Lease Disclosure” for additional discussion.

(2)	Financing lease assets are recorded net of accumulated amortization of $3 million and $2 million as of December 31, 2025 and June 30, 2026, respectively.

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	2025		2026		2025		2026
Operating lease cost	Statement of operations	Gathering, compression, processing and transportation	$	406,240		430,839		801,361		858,037
Operating lease cost	Statement of operations	General and administrative		3,318		2,626		6,459		5,981
Operating lease cost	Statement of operations	Lease operating		302		364		527		736
Operating lease cost	Balance sheet	Proved properties ⁽¹⁾		6,267		31,705		13,666		51,498
Total operating lease cost			$	416,127		465,534		822,013		916,252

Finance lease cost:
Amortization of right-of-use assets	Statement of operations	Depletion, depreciation and amortization	$	422		600		831		1,077
Interest on lease liabilities	Statement of operations	Interest expense, net		127		107		245		231
Total finance lease cost			$	549		707		1,076		1,308

Short-term lease payments			$	47,371		50,717		90,277		81,802

(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,
	2025		2026
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	794,364		1,016,784
Operating cash flows from finance leases		245		231
Investing cash flows from operating leases		8,050		45,622
Financing cash flows from finance leases		710		657

Noncash activities:
Right-of-use assets obtained in exchange for new operating lease obligations	$	127,187		118,168
Decrease to existing right-of-use assets and lease obligations from operating lease modifications, net ⁽¹⁾	$	(14,453)		(6,510)

(1)

During the six months ended June 30, 2025, the weighted average discount rate for remeasured operating leases increased from 5.5% as of December 31, 2024 to 5.8% as of June 30, 2025. During the six months ended June 30, 2026, the weighted average discount rate for remeasured operating leases decreased from 5.1% as of December 31, 2025 to 4.4% as of June 30, 2026.

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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, 2026 (in thousands):


	Operating Leases		Financing Leases		Total
Remainder of 2026	$	332,852		837		333,689
2027		568,835		1,003		569,838
2028		409,252		868		410,120
2029		322,117		364		322,481
2030		248,972		—		248,972
Thereafter		408,821		—		408,821
Total lease payments		2,290,849		3,072		2,293,921
Less: imputed interest		(292,440)		(434)		(292,874)
Total	$	1,998,409		2,638		2,001,047

(e)	Lease Term and Discount Rate

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


					(Unaudited)
	December 31, 2025				June 30, 2026
	Operating Leases		Finance Leases		Operating Leases		Finance Leases
Weighted average remaining lease term	5.4 years		2.8 years		5.0 years		2.6 years
Weighted average discount rate	5.6	%	8.5	%	5.5	%	8.5	%

(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, including the updates agreed to in principle as it relates to the HG Acquisition (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 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”). The Company also had a compression agreement from Antero Midstream’s acquisition in 2022 of certain Utica compressors that was divested at the closing of the Utica Shale Divestiture on February 23, 2026 (the “Utica compression agreement” and together with the 2019 gathering and compression agreement, the Marcellus gathering and compression agreement and the Mountaineer gathering and 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. Upon expiration of the Marcellus gathering and compression agreement and 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 gathering fee per Mcf, a centralized compression fee per Mcf and high pressure gathering fee per Mcf, as applicable, subject to annual Consumer Price Index (“CPI”)-based adjustments. In addition, Antero Midstream receives fees for well pad compression that include (i) reimbursement of Antero Midstream’s third-party out-of-pocket costs plus 3% for well pad compression services provided by third-party-owned equipment and (ii) a cost of service fee that allows Antero Midstream to earn a return on capital invested of 13% per annum over a period of seven years for well pad compression services provided by Antero Midstream-owned assets. If and to the extent the Company requests that Antero Midstream construct gathering lines, centralized compressor stations and/or high pressure lines, 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 70% of the centralized compression capacity and 75% of the high pressure gathering capacity of the requested capacity of such new construction for 10 years or (ii) a cost of service fee that allows Antero Midstream to earn a return on capital invested of 13% per annum over a

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

period of 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 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, 2026, the minimum volume commitments for the 2019 gathering and compression agreement end in 2035, and the minimum gathering fees for the Mountaineer gathering and compression agreement end in 2026. As of January 1, 2025, there were no minimum volume commitments under the Marcellus gathering and compression agreement.

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 $212 million and $237 million for the three months ended June 30, 2025 and 2026, respectively. For the six months ended June 30, 2025 and 2026, gathering and compression fees paid by the Company related to this agreement were $417 million and $468 million, respectively. As of December 31, 2025 and June 30, 2026, $85 million and $94 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, 2026 (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 2026	$	627,965		34,918		281,826		51,863		9,143		1,005,715
2027		1,234,442		92,386		487,242		82,596		7,919		1,904,585
2028		1,171,053		113,723		350,756		59,365		4,491		1,699,388
2029		809,946		113,097		281,005		41,475		1,192		1,246,715
2030		739,252		112,144		221,800		27,172		1,110		1,101,478
Thereafter		3,162,038		559,088		378,418		30,403		2,414		4,132,361
Total	$	7,744,696		1,025,356		2,001,047		292,874		26,269		11,090,242

(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 additional information.

(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, loss contingency and settlements in the unaudited condensed consolidated statements of operations and comprehensive income. There are no remaining payment obligations related to any delayed or cancelled contracts as of June 30, 2026.

(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. On February 13, 2026, the Company entered into a Consent Decree with the DOJ and WVDEP resolving the alleged violations. The Consent Decree requires Antero to pay a total penalty of approximately $3.8 million (split between the U.S. and West Virginia) and take certain other actions. The federal district court approved the Consent Decree on March 31, 2026, and this matter is now resolved. The penalty and any additional obligations pursuant to the Consent Decree are not expected 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 were recorded in the consolidated statement of operations and comprehensive net loss during the year ended December 31, 2024; however, the Company has filed an appeal with regard to such assessments. The Company’s production tax filings in West Virginia for 2022 to 2024 tax years are currently under audit by the State of West Virginia. At this time, the Company believes the outcome of this matter will not have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows.

(c)

Other

The Company is party to various legal proceedings and claims in the ordinary course of its business. The Company evaluates its legal proceedings on a regular basis and accrues a liability for such matters when the Company believes that a loss is probable and the amount of the loss can be reasonably estimated. Any such accruals are adjusted thereafter to reflect changed circumstances. In the event the Company determines that (i) a loss to the Company is probable but the amount of the loss cannot be reasonably estimated, or (ii) a loss to the Company is less likely than probable but is reasonably possible, then the Company is required to disclose the matter herein, although the Company is not required to accrue such loss.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

When able, the Company determines an estimate of reasonably possible losses or ranges of reasonably possible losses, whether in excess of any related accrued liability or where there is no accrued liability, for legal proceedings. In instances where such estimates can be made, any such estimates are based on the Company's analysis of currently available information and are subject to significant judgment and a variety of assumptions and uncertainties and may change as new information is obtained. The Company could also be responsible for interest on any amount the Company may be determined to owe, the amount of which is not determinable or estimable. The ultimate outcome of the matters described above, such as whether the likelihood of loss is remote, reasonably possible, or probable, or if and when the range of loss is reasonably estimable, is inherently uncertain. Furthermore, due to the inherent subjectivity of the assessments and unpredictability of outcomes of legal proceedings, any amounts accrued or estimated as possible losses may not represent the ultimate loss to the Company from the legal proceedings in question and the Company's exposure and ultimate losses may be higher than the amounts accrued or estimated.

The Company has been named in various lawsuits alleging royalty underpayments, some of which seek class action certification. Pending litigation against the Company and other peer operators could have an impact on the methods for determining royalty payments due to lessors under oil and gas leases, including 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, many of these proceedings are in early stages, involve multiple lease forms with varying royalty provisions and seek or may seek damages the amount of which is currently indeterminate. In a class action lawsuit to which the Company is a party, Jacklin Romeo, et al. v. Antero Resources Corporation, the U.S. District Court for the Northern District of West Virginia certified certain questions to the West Virginia Supreme Court (the “WVSC”) with respect to the interpretation of West Virginia’s implied duty to market gas where a lease lacks any express language regarding the allocation of post-production costs and the treatment of NGLs. The WVSC answered the certified questions in November 2024; however, in December 2024, Antero petitioned the WVSC for rehearing on the certified questions, which stayed the issuance of the mandate required for the November 2024 opinion to take effect. The petition for rehearing was granted by the WVSC on December 31, 2024, and oral argument on the matter was held before the WVSC on April 22, 2025. On June 11, 2025, the WVSC answered the certified questions, the effect of which broadens the scope of products for which the Company will pay royalties and limits the amount of post-production costs the Company deducts from royalty payments, in each case, under leases that do not contain language to the contrary. With respect to the Romeo matter, the Company has accrued an immaterial amount as of December 31, 2025 and June 30, 2026 for estimated damages that is recorded in contract termination, loss contingency and settlements in the unaudited condensed consolidated statements of operations and comprehensive income.

The WVSC’s answers to the certified questions in the Romeo matter could also impact past royalty payments made by the Company, as well as royalty payments owed in the future, under certain of the Company’s other leases that are not at issue in the Romeo matter. While the Company cannot predict with certainty the timing and ultimate outcome of any other currently pending claims or potential other claims relating to royalty payments under such other leases, the Company currently estimates the amount of losses that are reasonably possible associated with such other leases, could be up to $400 million.

Rulings were also previously received in two other 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 based on interpretation of specific language in the applicable leases: 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, 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 and when the foregoing issues may ultimately be resolved, and therefore is also unable to estimate potential damages, if any, that may result.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(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.

In light of the nature and location of the assets and operations acquired in the HG Acquisition, the Company and Antero Midstream agreed in principle to certain updates to, and intend to modify, their existing commercial arrangements to provide for well pad compression with respect to certain wells and to provide certain water services. For well pad compression services provided by third-party-owned equipment, the Company will reimburse Antero Midstream’s third-party out-of-pocket costs plus 3%. For well pad compression services provided by Antero Midstream-owned assets, Antero Midstream will charge the Company a cost of service fee that allows Antero Midstream to earn a return on capital invested of 13% per annum over a period of seven years. For certain fresh water services provided by Antero Midstream related to the HG Production assets, the Company will reimburse Antero Midstream’s third-party out-of-pocket costs plus 3%.

(16) 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 (“exploration and production”); (ii) midstream services through our equity method investment in Antero Midstream (“equity method investment in Antero Midstream”) and (iii) marketing of excess firm transportation capacity (“marketing”).

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


	Three Months Ended June 30, 2025
					Equity Method
	Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream ⁽¹⁾		Affiliate		Total
Sales and revenues:
Third-party	$	1,263,190		33,743		466		(466)		1,296,933
Intersegment		560		—		305,006		(305,006)		560
Total revenue		1,263,750		33,743		305,472		(305,472)		1,297,493

Operating expenses:
Lease operating		37,244		—		—		—		37,244
Gathering and compression		236,830		—		25,662		(25,662)		236,830
Processing		284,040		—		—		—		284,040
Transportation		180,852		—		—		—		180,852
Water handling		—		—		37,452		(37,452)		—
Production and ad valorem taxes		34,830		—		—		—		34,830
Marketing		—		51,988		—		—		51,988
General and administrative (excluding equity-based compensation)		41,328		—		10,718		(10,718)		41,328
Equity-based compensation		15,855		—		11,407		(11,407)		15,855
Facility idling		—		—		375		(375)		—
Depletion, depreciation and amortization		187,589		—		33,364		(33,364)		187,589
Impairment of property and equipment		6,297		—		—		—		6,297
Other ⁽²⁾		15,757		—		50		(50)		15,757
Total operating expenses		1,040,622		51,988		119,028		(119,028)		1,092,610
Operating income (loss)	$	223,128		(18,245)		186,444		(186,444)		204,883
Equity in earnings of unconsolidated affiliates	$	30,563		—		30,016		(30,016)		30,563
Capital expenditures for segment assets	$	208,409		—		36,734		(36,734)		208,409

(1)	Amounts reflect those recorded in Antero Midstream’s unaudited condensed consolidated financial statements.

(2)

Amounts include charges for exploration, accretion of asset retirement obligations, loss on settlement of asset retirement obligations, contract termination, loss contingency and settlements and other operating expenses, as applicable, which represent segment operating expenses that are not considered significant.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements


	Three Months Ended June 30, 2026
					Equity Method
	Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream ⁽¹⁾		Affiliate		Total
Sales and revenues:
Third-party	$	1,503,267		56,066		—		—		1,559,333
Intersegment		509		—		327,244		(327,244)		509
Total revenue		1,503,776		56,066		327,244		(327,244)		1,559,842

Operating expenses:
Lease operating		48,148		—		—		—		48,148
Gathering and compression		270,225		—		36,533		(36,533)		270,225
Processing		292,745		—		—		—		292,745
Transportation		185,211		—		—		—		185,211
Water handling		—		—		47,993		(47,993)		—
Production and ad valorem taxes		37,535		—		—		—		37,535
Marketing		—		72,059		—		—		72,059
General and administrative (excluding equity-based compensation)		44,529		—		11,729		(11,729)		44,529
Equity-based compensation		13,266		—		10,828		(10,828)		13,266
Facility idling		—		—		287		(287)		—
Depletion, depreciation and amortization		227,254		—		37,378		(37,378)		227,254
Impairment of property and equipment		4,455		—		133		(133)		4,455
Other ⁽²⁾		(11,044)		—		454		(454)		(11,044)
Total operating expenses		1,112,324		72,059		145,335		(145,335)		1,184,383
Operating income (loss)	$	391,452		(15,993)		181,909		(181,909)		375,459
Equity in earnings of unconsolidated affiliates	$	29,379		—		28,525		(28,525)		29,379
Capital expenditures for segment assets	$	340,716		—		52,743		(52,743)		340,716

(1)	Amounts reflect those recorded in Antero Midstream’s unaudited condensed consolidated financial statements.

(2)

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements


	Six Months Ended June 30, 2025
					Equity Method
	Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream ⁽¹⁾		Affiliate		Total
Sales and revenues:
Third-party	$	2,589,791		59,301		971		(971)		2,649,092
Intersegment		1,108		—		595,630		(595,630)		1,108
Total revenue		2,590,899		59,301		596,601		(596,601)		2,650,200

Operating expenses:
Lease operating		71,230		—		—		—		71,230
Gathering and compression		472,964		—		51,855		(51,855)		472,964
Processing		545,195		—		—		—		545,195
Transportation		378,580		—		—		—		378,580
Water handling		—		—		68,089		(68,089)		—
Production and ad valorem taxes		90,129		—		—		—		90,129
Marketing		—		94,758		—		—		94,758
General and administrative (excluding equity-based compensation)		88,628		—		21,340		(21,340)		88,628
Equity-based compensation		31,000		—		23,809		(23,809)		31,000
Facility idling		—		—		818		(818)		—
Depletion, depreciation and amortization		373,941		—		66,112		(66,112)		373,941
Impairment of property and equipment		11,915		—		817		(817)		11,915
Other ⁽²⁾		15,505		—		94		(94)		15,505
Total operating expenses		2,079,087		94,758		232,934		(232,934)		2,173,845
Operating income (loss)	$	511,812		(35,457)		363,667		(363,667)		476,355
Equity in earnings of unconsolidated affiliates	$	59,224		—		58,036		(58,036)		59,224
Capital expenditures for segment assets	$	414,554		—		67,262		(67,262)		414,554

(1)	Amounts reflect those recorded in Antero Midstream’s unaudited condensed consolidated financial statements.

(2)

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements


	Six Months Ended June 30, 2026
					Equity Method
	Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream ⁽¹⁾		Affiliate		Total
Sales and revenues:
Third-party	$	3,406,174		97,727		606		(606)		3,503,901
Intersegment		1,067		—		640,849		(640,849)		1,067
Total revenue		3,407,241		97,727		641,455		(641,455)		3,504,968

Operating expenses:
Lease operating		92,677		—		—		—		92,677
Gathering and compression		539,338		—		66,563		(66,563)		539,338
Processing		580,513		—		—		—		580,513
Transportation		417,436		—		—		—		417,436
Water handling		—		—		88,660		(88,660)		—
Production and ad valorem taxes		118,532		—		—		—		118,532
Marketing		—		134,612		—		—		134,612
General and administrative (excluding equity-based compensation)		96,136		—		23,497		(23,497)		96,136
Equity-based compensation		24,999		—		21,407		(21,407)		24,999
Facility idling		—		—		832		(832)		—
Depletion, depreciation and amortization		433,493		—		72,013		(72,013)		433,493
Impairment of property and equipment		5,403		—		133		(133)		5,403
Gain on sale of assets		(60,566)		—		(2,658)		2,658		(60,566)
Other ⁽²⁾		17,484		—		488		(488)		17,484
Total operating expenses		2,265,445		134,612		270,935		(270,935)		2,400,057
Operating income (loss)	$	1,141,796		(36,885)		370,520		(370,520)		1,104,911
Equity in earnings of unconsolidated affiliates	$	59,497		—		58,537		(58,537)		59,497
Capital expenditures for segment assets	$	546,817		—		90,649		(90,649)		546,817

(1)	Amounts reflect those recorded in Antero Midstream’s unaudited condensed consolidated financial statements.

(2)

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


	As of December 31, 2025
					Equity Method
	Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream ⁽¹⁾		Affiliate		Total
Investments in unconsolidated affiliates	$	245,653		—		585,778		(585,778)		245,653
Total assets		13,238,013		7,394		5,884,116		(5,884,116)		13,245,407

(1)	Amounts reflect those recorded in Antero Midstream’s condensed consolidated financial statements.

(Unaudited)

As of June 30, 2026

Equity Method

Exploration

Investment in

Elimination of

and

Antero

Unconsolidated

Consolidated

Production

Marketing

Midstream ⁽¹⁾

Affiliate

Total

Investments in unconsolidated affiliates

259,313

—

574,215

(574,215)

259,313

Total assets

15,212,556

20,078

6,363,815

(6,363,815)

15,232,634

(1)	Amounts reflect those recorded in Antero Midstream’s unaudited condensed consolidated financial statements.

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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 have assembled a portfolio of long-lived properties that are characterized by what we believe to be high repeatability and low geologic risk. 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 in the Appalachian Basin. As of June 30, 2026, we held approximately 858,000 net acres in the Appalachian Basin.

HG Acquisition

On December 5, 2025, we entered into a definitive agreement to acquire 100% of the issued and outstanding equity interests of HG Production for total cash consideration of $2.8 billion, subject to the terms and conditions thereof. The HG Acquisition included approximately 385,000 net acres in the core of the Marcellus Shale in West Virginia. This acquisition closed on the Closing Date. The HG Acquisition was funded with borrowings under the Term Loan, net proceeds of the 2036 Notes, borrowings under the Credit Facility and restricted cash. See Note 3—Transactions to our unaudited condensed consolidated financial statements for additional information. The Company’s condensed consolidated statement of operations for the six months ended June 30, 2026 included results of operations from the assets and operations acquired in the HG Acquisition from the Closing Date through June 30, 2026.

In light of the nature and location of the assets and operations acquired in the HG Acquisition, we and Antero Midstream agreed in principle to certain updates to, and intend to modify, our existing commercial arrangements to provide for well pad compression with respect to certain wells and to provide certain water services. See Note 15—Related Parties to our unaudited condensed consolidated financial statements for additional information.

Utica Shale Divestiture

On December 5, 2025, we entered into a purchase and sale agreement with the Buyer Parties to sell our Utica Shale Properties for aggregate cash consideration of $800 million, subject to the terms and conditions thereof. The Utica Shale Properties included approximately 80,000 gross (70,000 net) acres located in Ohio and proved reserves of approximately 600 Bcfe as of December 31, 2025. The Utica Shale Divestiture closed on February 23, 2026, with an effective date of July 1, 2025. The net proceeds from the Utica Shale Divestiture were used for the repayment of long-term debt. See Note 3—Transactions to our unaudited condensed consolidated financial statements for additional information.

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Martica Hurdle Achievement and Dissolution

On May 1, 2026, Sixth Street achieved its Hurdle for Martica. As such, beginning May 1, 2026, 85% of the distributions in respect of the ORRIs to which Sixth Street was entitled immediately prior to the Hurdle being achieved reverted to us. On June 30, 2026, we elected to dissolve Martica and make in-kind liquidating distributions to Sixth Street and ourselves, which included conveyance of the ORRIs to Sixth Street and Antero Resources after giving effect to the Reversion, after which Martica was deconsolidated for our condensed consolidated financial statements. On July 1, 2026, after the deconsolidation of Martica, our condensed consolidated financial statements will reflect the ORRIs conveyed to us by Martica after giving effect to the Reversion, including the related earnings and cash flows. See Note 2—Summary of Significant Accounting Policies for additional information.

Financing Highlights

Issuance of 2036 Notes

On January 28, 2026, we issued $750 million of 5.400% senior notes due February 1, 2036 at a price of 99.869% of par. The 2036 Notes are unsecured and rank pari passu to our Credit Facility, Term Loan and other outstanding senior notes. The 2036 Notes are not guaranteed by any of our subsidiaries. The net proceeds from this offering were used to partially fund the HG Acquisition. See Note 3—Transactions and Note 7—Debt to our unaudited condensed consolidated financial statements for additional information.

Term Loan

On February 3, 2026, substantially concurrently with the consummation of the HG Acquisition, we entered into an unsecured three year term loan facility in an aggregate principal amount of $1.5 billion with the lenders party thereto and Royal Bank of Canada, as administrative agent. Borrowings are unsecured and are not guaranteed by any of our subsidiaries. On February 3, 2026, we borrowed $1.5 billion in a single borrowing to partially fund the HG Acquisition. The Term Loan is scheduled to mature on February 3, 2029. As of June 30, 2026, we have $1.1 billion outstanding on the Term Loan. See Note 3—Transactions and Note 7—Debt to our unaudited condensed consolidated financial statements for additional information.

Redemption of 2029 Notes

On February 24, 2026, we redeemed the remaining $365 million principal amount of the 2029 Notes at 101.271% of the principal amount thereof, plus accrued and unpaid interest, and the 2029 Notes were fully retired on such date. See Note 7—Debt to our unaudited condensed consolidated financial statements for additional information.

Commercial Paper Program

On June 16, 2026, we established the Commercial Paper Program pursuant to which we may issue short-term, unsecured commercial paper notes. The Commercial Paper may be issued and redeemed from time to time, with the aggregate face or principal amount of the notes outstanding under the Commercial Paper Program at any time not to exceed $1.65 billion. Our Credit Facility will serve as a liquidity backstop for any issuances under the Commercial Paper Program, and we intend to maintain available capacity under the Credit Facility in an amount at least equal to the aggregate outstanding borrowings under the Commercial Paper Program. See Note 7—Debt to our unaudited condensed consolidated financial statements for additional information.

Share Repurchase Program

During 2022, our Board of Directors authorized a share repurchase program that allows us to repurchase up to $2.0 billion of outstanding common stock. During the three and six months ended June 30, 2026, we repurchased approximately 1.1 million shares of our common stock at a total cost of $38 million through our share repurchase program. As of June 30, 2026, we have approximately $877 million of capacity remaining under our share repurchase program. The shares may be repurchased from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws. The timing, as well as the number and value of shares repurchased under the program, will be determined by us at our discretion and will depend on a variety of factors, including the market price of our common stock, general market and economic conditions and applicable legal requirements.

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Market Conditions and Business Trends

Commodity Markets

Prices for natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. Benchmark prices for C3+ NGLs and oil increased significantly, while benchmark prices for natural gas and ethane decreased during the three months ended June 30, 2026 as compared to the same period of 2025. Benchmark prices for natural gas and oil increased significantly, while benchmark prices for ethane decreased and C3+ NGLs remained consistent during the six months ended June 30, 2026 as compared to the same period of 2025. 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, Venezuela 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. However, we use derivative instruments when circumstances warrant to manage our exposure to commodity price risk. See “—Hedge Position” and Note 11—Derivative Instruments to our unaudited condensed consolidated financial statements for additional information on our derivative instruments.

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2026		2025		2026
Henry Hub ($/Mcf) ⁽¹⁾	$	3.44		2.90	$	3.55		3.97
Mont Belvieu Ethane ($/Bbl) ⁽²⁾		10.11		8.96		10.78		9.41
Mont Belvieu C3+ NGLs ($/Bbl) ⁽³⁾		38.07		45.26		41.03		41.07
West Texas Intermediate ($/Bbl) ⁽⁴⁾		63.74		93.00		67.58		82.46

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

(2)	Intercontinental Exchange, Inc. (“ICE”) settlement ethane Oil Price Information Service (“OPIS”) futures average price for the front month contract as published on the last trading day of the month.

(3)

ICE settlement propane, isobutane, normal butane and natural gasoline OPIS futures average price for the front month contract as published on the last trading day of the month. Propane and isobutane reflect TET prices, and normal butane and natural gasoline reflect non-TET prices. Propane, isobutane, normal butane and natural gasoline futures prices are weighted to approximate Antero Resources’ average C3+ NGLs composition.

(4)	NYMEX calendar month average settled futures price.

Hedge Position

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. For the three months ended June 30, 2025 and 2026, 4% and 47%, respectively, of our production was hedged through commodity derivatives, excluding basis swaps. For the six months ended June 30, 2025 and 2026, 4% and 44%, respectively, of our production was hedged through commodity derivatives, excluding basis swaps. Assuming our 2026 production is the same as our production in 2025, approximately 54% of our total production for 2026 is hedged through commodity derivatives, excluding basis swaps. In addition, for the three and six months ended June 30, 2026, 18% and 15%, respectively, of our production was hedged with basis swap commodity derivatives. We did not have any basis swap commodity derivatives for the three and six months ended June 30, 2025. Assuming our 2026 production is the same as our production in 2025, approximately 20% of our total production for 2026 is hedged with basis swap commodity derivatives. As of June 30, 2026, the estimated fair value of our commodity derivative contracts was a net asset of $228 million. See Note 11—Derivative Instruments to our unaudited condensed consolidated financial statements for additional 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 2026. During the second half of 2024, inflation rates began to approach the Federal Reserve’s stated goal of 2%, and the Federal Reserve decreased the federal funds rate by 1.75% in 2024 and 2025. Annual inflation rates have remained generally consistent at approximately 3% since 2023.

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, tariffs, other global trade restrictions and conflicts,

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including those in the Middle East and Venezuela, among others. While our supply chain has not experienced any significant interruptions as a result of such events, there can be no assurance that we will not experience interruptions in the future.

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 reportable segments: exploration and production, our equity method investment in Antero Midstream and marketing. 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 our unaudited condensed consolidated financial statements for additional information.

Three Months Ended June 30, 2025 Compared to Three Months Ended June 30, 2026

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


	Three Months Ended June 30, 2025
					Equity Method
	Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream ⁽¹⁾		Affiliate		Total
Revenue and other:
Natural gas sales	$	688,753		—		—		—		688,753
Natural gas liquids sales		480,757		—		—		—		480,757
Oil sales		33,700		—		—		—		33,700
Commodity derivative fair value gains		53,409		—		—		—		53,409
Gathering, compression and water handling		—		—		305,472		(305,472)		—
Marketing		—		33,743		—		—		33,743
Amortization of deferred revenue, VPP		6,298		—		—		—		6,298
Other revenue and income		833		—		—		—		833
Total revenue		1,263,750		33,743		305,472		(305,472)		1,297,493

Operating expenses:
Lease operating		37,244		—		—		—		37,244
Gathering and compression		236,830		—		25,662		(25,662)		236,830
Processing		284,040		—		—		—		284,040
Transportation		180,852		—		—		—		180,852
Water handling		—		—		37,452		(37,452)		—
Production and ad valorem taxes		34,830		—		—		—		34,830
Marketing		—		51,988		—		—		51,988
Exploration		648		—		—		—		648
General and administrative (excluding equity-based compensation)		41,328		—		10,718		(10,718)		41,328
Equity-based compensation		15,855		—		11,407		(11,407)		15,855
Depletion, depreciation and amortization		187,589		—		33,364		(33,364)		187,589
Impairment of property and equipment		6,297		—		—		—		6,297
Accretion of asset retirement obligations		942		—		—		—		942
Loss on sale of assets		546		—		—		—		546
Contract termination, loss contingency, settlements and other operating expenses		13,621		—		425		(425)		13,621
Total operating expenses		1,040,622		51,988		119,028		(119,028)		1,092,610
Operating income (loss)	$	223,128		(18,245)		186,444		(186,444)		204,883

Equity in earnings of unconsolidated affiliates	$	30,563		—		30,016		(30,016)		30,563

(1)	Amounts reflect those recorded in Antero Midstream’s unaudited condensed consolidated financial statements.

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	Three Months Ended June 30, 2026
					Equity Method
	Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream ⁽¹⁾		Affiliate		Total
Revenue and other:
Natural gas sales	$	688,478		—		—		—		688,478
Natural gas liquids sales		587,714		—		—		—		587,714
Oil sales		59,579		—		—		—		59,579
Commodity derivative fair value gains		160,633		—		—		—		160,633
Gathering, compression and water handling		—		—		327,244		(327,244)		—
Marketing		—		56,066		—		—		56,066
Amortization of deferred revenue, VPP		5,860		—		—		—		5,860
Other revenue and income		1,512		—		—		—		1,512
Total revenue		1,503,776		56,066		327,244		(327,244)		1,559,842

Operating expenses:
Lease operating		48,148		—		—		—		48,148
Gathering and compression		270,225		—		36,533		(36,533)		270,225
Processing		292,745		—		—		—		292,745
Transportation		185,211		—		—		—		185,211
Water handling		—		—		47,993		(47,993)		—
Production and ad valorem taxes		37,535		—		—		—		37,535
Marketing		—		72,059		—		—		72,059
Exploration		904		—		—		—		904
General and administrative (excluding equity-based compensation)		44,529		—		11,729		(11,729)		44,529
Equity-based compensation		13,266		—		10,828		(10,828)		13,266
Depletion, depreciation and amortization		227,254		—		37,378		(37,378)		227,254
Impairment of property and equipment		4,455		—		133		(133)		4,455
Accretion of asset retirement obligations		983		—		—		—		983
Gain on sale of assets		(14,616)		—		—		—		(14,616)
Contract termination, loss contingency, settlements and other operating expenses		1,685		—		741		(741)		1,685
Total operating expenses		1,112,324		72,059		145,335		(145,335)		1,184,383
Operating income (loss)	$	391,452		(15,993)		181,909		(181,909)		375,459

Equity in earnings of unconsolidated affiliates	$	29,379		—		28,525		(28,525)		29,379

(1)	Amounts reflect those recorded in Antero Midstream’s unaudited condensed consolidated financial statements.

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


	Three Months Ended				Amount of
	June 30,				Increase		Percent
	2025		2026		(Decrease)		Change
Production data ^{(1) (2)}:
Natural gas (Bcf)		203		259		56	28	%
C2 Ethane (MBbl)		6,924		7,896		972	14	%
C3+ NGLs (MBbl)		10,608		11,023		415	4	%
Oil (MBbl)		672		758		86	13	%
Combined (Bcfe)		312		377		65	21	%
Daily combined production (MMcfe/d)		3,430		4,144		714	21	%
Average prices before effects of derivative settlements ⁽³⁾:
Natural gas (per Mcf)	$	3.39		2.66		(0.73)	(22)	%
C2 Ethane (per Bbl) ⁽⁴⁾	$	11.34		12.54		1.20	11	%
C3+ NGLs (per Bbl)	$	37.92		44.33		6.41	17	%
Oil (per Bbl)	$	50.15		78.60		28.45	57	%
Weighted Average Combined (per Mcfe)	$	3.85		3.54		(0.31)	(8)	%
Average realized prices after effects of derivative settlements⁽³⁾:
Natural gas (per Mcf)	$	3.36		3.18		(0.18)	(5)	%
C2 Ethane (per Bbl) ⁽⁴⁾	$	11.34		12.54		1.20	11	%
C3+ NGLs (per Bbl)	$	37.92		44.32		6.40	17	%
Oil (per Bbl)	$	50.15		78.60		28.45	57	%
Weighted Average Combined (per Mcfe)	$	3.83		3.90		0.07	2	%
Average costs (per Mcfe):
Lease operating	$	0.12		0.13		0.01	8	%
Gathering and compression	$	0.76		0.72		(0.04)	(5)	%
Processing	$	0.91		0.78		(0.13)	(14)	%
Transportation	$	0.58		0.49		(0.09)	(16)	%
Production and ad valorem taxes	$	0.11		0.10		(0.01)	(9)	%
Marketing expense, net	$	0.06		0.04		(0.02)	(33)	%
General and administrative (excluding equity-based compensation)	$	0.13		0.12		(0.01)	(8)	%
Depletion, depreciation, amortization and accretion	$	0.60		0.61		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, 2025 includes $0.5 million of proceeds related to a take-or-pay contract. Excluding the effect of these proceeds, the average realized price for ethane before and after the effects of derivatives for the three months ended June 30, 2025 would have been $11.27 per Bbl.

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Exploration and Production Segment

Natural gas sales. Revenues from sales of natural gas remained relatively consistent at $689 million and $688 million for the three months ended June 30, 2025 and 2026, respectively, primarily due to $143 million of natural gas sales revenue attributable to the HG Acquisition properties and higher natural gas production volumes between periods, partially offset by the Utica Shale Divestiture and lower natural gas commodity prices between periods. Higher natural gas production volumes accounted for an approximate $190 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). Lower commodity prices (excluding the effects of derivative settlements) during the three months ended June 30, 2026 accounted for an approximate $189 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).

NGLs sales. Revenues from sales of NGLs increased from $481 million for the three months ended June 30, 2025 to $588 million for the three months ended June 30, 2026, an increase of $107 million, or 22%, primarily due to an additional $38 million of NGLs revenue attributable to the HG Acquisition properties and higher NGLs commodity prices and production volumes between periods, partially offset by the Utica Shale Divestiture. Higher commodity prices (excluding the effects of derivative settlements) during the three months ended June 30, 2026 accounted for an approximate $80 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 $27 million increase in year-over-year revenues (calculated as the change in year-to-year volumes times the prior year average price).

Oil sales. Revenues from sales of oil increased from $34 million for the three months ended June 30, 2025 to $60 million for the three months ended June 30, 2026, an increase of $26 million, or 77%, primarily due to an additional $10 million of oil revenue attributable to the HG Acquisition properties and higher oil commodity prices between periods, partially offset by the Utica Shale Divestiture. Higher commodity prices (excluding the effects of derivative settlements) during the three months ended June 30, 2026 accounted for an approximate $22 million increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). Higher oil production volumes during the three months ended June 30, 2026 accounted for an approximate $4 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 fixed price swaps, collars, basis swaps and three-way collars, among others. 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 unaudited condensed consolidated statements of operations and comprehensive income. For the three months ended June 30, 2025 and 2026, our commodity hedges resulted in derivative fair value gains of $53 million and $161 million, respectively. For the three months ended June 30, 2025, commodity derivative fair value gains included $6 million of net cash payments for settled commodity derivative losses. For the three months ended June 30, 2026, commodity derivative fair value gains included $134 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. 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 remained consistent at $6 million for the three months ended June 30, 2025 and 2026. 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 per Mcfe increased 8% from $0.12 per Mcfe for the three months ended June 30, 2025 to $0.13 per Mcfe for the three months ended June 30, 2026 primarily due to higher wastewater trucking and disposal costs due to the timing of well completions activity between periods. Lease operating expense increased from $37 million for the three months ended June 30, 2025 to $48 million for the three months ended June 30, 2026, an increase of $11 million, or 29%, primarily due to incremental expense of $8 million related to the HG Acquisition properties and higher wastewater trucking and disposal costs due to the timing of well completions activity between periods, partially offset by the Utica Shale Divestiture.

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Gathering, compression, processing and transportation expense. Gathering, compression, processing and transportation expense per Mcfe decreased 12% from $2.25 per Mcfe for the three months ended June 30, 2025 to $1.99 per Mcfe, for the three months ended June 30, 2026 primarily due to the HG Acquisition properties that have a lower compression, processing and transportation costs. Gathering, compression, processing and transportation expense increased from $702 million for the three months ended June 30, 2025 to $748 million for the three months ended June 30, 2026, an increase of $46 million, or 7%, primarily due to incremental expense of $70 million related to the HG Acquisition properties and higher production volumes between periods, partially offset the Utica Shale Divestiture. The fluctuation of our gathering, compression, processing and transportation expense on a per unit basis was primarily a result of the following:

●

Gathering and compression costs decreased from $0.76 per Mcfe for the three months ended June 30, 2025 to $0.72 per Mcfe for the three months ended June 30, 2026, primarily due to lower gathering and compression expense on a per unit basis for the HG Acquisition properties and decreased fuel costs as a result of lower natural gas prices, partially offset by annual CPI-based adjustments between periods.

●

Processing costs decreased from $0.91 per Mcfe for the three months ended June 30, 2025 to $0.78 per Mcfe for the three months ended June 30, 2026, primarily due to lower NGLs transportation fees related to the HG Acquisition properties between periods.

●

Transportation costs decreased from $0.58 per Mcfe for the three months ended June 30, 2025 to $0.49 per Mcfe for the three months ended June 30, 2026, primarily due to lower fuel costs as a result of lower natural gas prices between periods and lower demand fees for certain pipelines during the three months ended June 30, 2026.

Production and ad valorem tax expense. Production and ad valorem taxes as a percentage of natural gas revenues remained consistent at 5% for the three months ended June 30, 2025 and 2026. Production and ad valorem taxes increased from $35 million for the three months ended June 30, 2025 to $38 million for the three months ended June 30, 2026, an increase of $3 million, or 8%, primarily due to incremental expense of $6 million related to the HG Acquisition properties and higher production volumes between periods, partially offset by the Utica Shale Divestiture and lower natural gas prices during the three months ended June 30, 2026.

General and administrative expense. General and administrative expense (excluding equity-based compensation expense) per Mcfe decreased 8% from $0.13 per Mcfe for the three months ended June 30, 2025 to $0.12 per Mcfe for the three months ended June 30, 2026 primarily due to higher production volumes from our HG Acquisition, partially offset by higher overall general and administrative costs between periods. General and administrative expense (excluding equity-based compensation expense) increased from $41 million for the three months ended June 30, 2025 to $45 million for the three months ended June 30, 2026, an increase of $4 million, or 8%, primarily due to higher salary and wage expense, software license costs and professional service fees between periods.

Equity-based compensation expense. Non-cash equity-based compensation expense decreased from $16 million for the three months ended June 30, 2025 to $13 million for the three months ended June 30, 2026, a decrease of $3 million or 16%. This decrease was primarily due to lower RSU and PSU award expense of $2 million and $1 million, respectively, between periods. See Note 9—Equity-Based Compensation to the unaudited condensed consolidated financial statements for additional information.

Depletion, depreciation and amortization expense (“DD&A expense”). DD&A expense per Mcfe remained relatively consistent at $0.60 per Mcfe and $0.61 per Mcfe for the three months ended June 30, 2025 and 2026, respectively. DD&A expense increased from $188 million for the three months ended June 30, 2025 to $227 million for the three months ended June 30, 2026, an increase of $39 million, or 21%, primarily due to higher production volumes between periods related to our HG Acquisition properties, partially offset by the Utica Shale Divestiture.

Impairment of property and equipment. Impairment of oil and gas properties decreased from $6 million for the three months ended June 30, 2025 to $4 million for the three months ended June 30, 2026, 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 settlements. Contract termination, loss contingency and settlements decreased from $14 million for the three months ended June 30, 2025 to $2 million for the three months ended June 30, 2026, a decrease of $12 million. This decrease was primarily due to lower loss contingencies recorded. See Note 14—Contingencies to the unaudited condensed consolidated financial statements for additional information.

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Loss (gain) on sale of assets. Loss on sale of assets was less than $1 million for the three months ended June 30, 2025. Gain on sale of assets was $15 million for the three months ended June 30, 2026 primarily due to the release of certain proceeds from the Utica Shale Divestiture that were held in escrow at closing. See Note 3—Transactions to the unaudited condensed consolidated financial statements for additional information.

Marketing Segment

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

Net marketing expense decreased from $0.06 per Mcfe, or $18 million, for the three months ended June 30, 2025 to $0.04 per Mcfe, or $16 million, for the three months ended June 30, 2026, primarily due to higher pipeline utilization and lower fuel costs between periods, partially offset by higher demand fees on certain pipelines.

Marketing revenue. Marketing revenue increased from $34 million for the three months ended June 30, 2025 to $56 million for the three months ended June 30, 2026, an increase of $22 million, or 66%. This fluctuation primarily resulted from the following:

●

Natural gas marketing revenue decreased by $5 million between periods primarily due to lower natural gas marketing volumes.

●

Oil marketing revenue increased by $28 million between periods primarily due to higher oil prices and marketing volumes. Higher oil prices accounted for a $17 million increase in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes), and higher oil marketing volumes accounted for an $11 million increase in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price).

●

NGLs marketing revenues increased by $3 million for the three months ended June 30, 2026 primarily due to higher C3+ NGLs marketing volumes.

Marketing expense. Marketing expense increased from $52 million for the three months ended June 30, 2025 to $72 million for the three months ended June 30, 2026, an increase of $20 million, or 39%. 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 purchases increased $23 million between periods primarily due to higher oil marketing prices and volumes during the three months ended June 30, 2026, partially offset by lower natural gas marketing volumes during the three months ended June 30, 2026. Firm transportation costs decreased $3 million between periods primarily due to higher pipeline utilization between periods and lower fuel costs during the three months ended June 30, 2026.

Antero Midstream Segment

Antero Midstream revenue. Revenue from the Antero Midstream segment increased from $305 million for the three months ended June 30, 2025 to $327 million for the three months ended June 30, 2026, an increase of $22 million. This increase is primarily due to higher gathering and processing revenues of $18 million and higher water handling revenues of $4 million. The increased gathering and processing revenues between periods is primarily due to higher low pressure gathering and compression volumes from the HG Acquisition and 80 wells connected to their system between periods and increased gathering and centralized compression rates as a result of annual CPI-based adjustments, partially offset by the Utica Shale Divestiture and natural production decline of the wells connected to their system between periods. The increased water handling revenues between periods is primarily due to fresh water delivery volumes for our acreage acquired in the HG Acquisition that are charged at cost plus 3% during the three months ended June 30, 2026, as well as higher blending cost of service fees, increased costs for wastewater trucking and disposal volumes and an increase to the fresh water delivery rate as a result of an annual CPI-based rate adjustment between periods.

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Antero Midstream operating expense. Total operating expense related to the Antero Midstream segment increased from $119 million for the three months ended June 30, 2025 to $145 million for the three months ended June 30, 2026, an increase of $26 million. This increase is primarily due to higher direct operating expenses as a result of gathering and well pad compression costs related to assets acquired with the HG Acquisition during the three months ended June 30, 2026, as well as increased fresh water delivery services on our acreage acquired in the HG Acquisition during the three month ended June 30, 2026, increased wastewater trucking and disposal volumes between periods and increased blending volumes and costs between periods, partially offset by the Utica Shale Divestiture.

Items Not Allocated to Segments

Interest expense. Interest expense increased from $20 million for the three months ended June 30, 2025 to $38 million for the three months ended June 30, 2026, an increase of $18 million, or 88%, primarily due to borrowings to fund our HG Acquisition under the Term Loan and issuance of the 2036 Notes during the first quarter of 2026, partially offset by the redemption of the 2029 Notes on February 24, 2026 and lower Credit Facility borrowings and rates between periods. See Note 7—Debt to the unaudited condensed consolidated financial statements for more information.

Loss on early extinguishment of debt. During the three months ended June 30, 2025, we repurchased $23 million aggregate principal amount of our 2029 Notes through open market transactions at a weighted average premium of approximately 102% of the principal amount thereof, plus accrued and unpaid interest, and recognized a loss on early debt extinguishment of $1 million. There was no loss on early extinguishment of debt for the three months ended June 30, 2026. See Note 7—Debt to the unaudited condensed consolidated financial statements for more information.

Income tax expense. Income tax expense increased from $48 million, with an effective tax rate of 22%, for the three months ended June 30, 2025 to $79 million, with an effective tax rate of 22%, for the three months ended June 30, 2026 primarily due to the increase in income before income taxes between periods.

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Six Months Ended June 30, 2025 Compared to Six Months Ended June 30, 2026

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


	Six Months Ended June 30, 2025
					Equity Method
	Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream ⁽¹⁾		Affiliate		Total
Revenue and other:
Natural gas sales	$	1,468,758		—		—		—		1,468,758
Natural gas liquids sales		1,042,189		—		—		—		1,042,189
Oil sales		84,035		—		—		—		84,035
Commodity derivative fair value losses		(18,262)		—		—		—		(18,262)
Gathering, compression and water handling		—		—		596,601		(596,601)		—
Marketing		—		59,301		—		—		59,301
Amortization of deferred revenue, VPP		12,528		—		—		—		12,528
Other revenue and income		1,651		—		—		—		1,651
Total revenue		2,590,899		59,301		596,601		(596,601)		2,650,200

Operating expenses:
Lease operating		71,230		—		—		—		71,230
Gathering and compression		472,964		—		51,855		(51,855)		472,964
Processing		545,195		—		—		—		545,195
Transportation		378,580		—		—		—		378,580
Water handling		—		—		68,089		(68,089)		—
Production and ad valorem taxes		90,129		—		—		—		90,129
Marketing		—		94,758		—		—		94,758
Exploration		1,316		—		—		—		1,316
General and administrative (excluding equity-based compensation)		88,628		—		21,340		(21,340)		88,628
Equity-based compensation		31,000		—		23,809		(23,809)		31,000
Depletion, depreciation and amortization		373,941		—		66,112		(66,112)		373,941
Impairment of property and equipment		11,915		—		817		(817)		11,915
Accretion of asset retirement obligations		1,881		—		—		—		1,881
Gain on sale of assets		(29)		—		—		—		(29)
Contract termination, loss contingency, settlements and other operating expenses		12,337		—		912		(912)		12,337
Total operating expenses		2,079,087		94,758		232,934		(232,934)		2,173,845
Operating income (loss)	$	511,812		(35,457)		363,667		(363,667)		476,355

Equity in earnings of unconsolidated affiliates	$	59,224		—		58,036		(58,036)		59,224

(1)	Amounts reflect those recorded in Antero Midstream’s unaudited condensed consolidated financial statements.

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	Six Months Ended June 30, 2026
					Equity Method
	Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream ⁽¹⁾		Affiliate		Total
Revenue and other:
Natural gas sales	$	1,999,954		—		—		—		1,999,954
Natural gas liquids sales		1,091,363		—		—		—		1,091,363
Oil sales		106,274		—		—		—		106,274
Commodity derivative fair value gains		195,656		—		—		—		195,656
Gathering, compression and water handling		—		—		641,455		(641,455)		—
Marketing		—		97,727		—		—		97,727
Amortization of deferred revenue, VPP		11,655		—		—		—		11,655
Other revenue and income		2,339		—		—		—		2,339
Total revenue		3,407,241		97,727		641,455		(641,455)		3,504,968

Operating expenses:
Lease operating		92,677		—		—		—		92,677
Gathering and compression		539,338		—		66,563		(66,563)		539,338
Processing		580,513		—		—		—		580,513
Transportation		417,436		—		—		—		417,436
Water handling		—		—		88,660		(88,660)		—
Production and ad valorem taxes		118,532		—		—		—		118,532
Marketing		—		134,612		—		—		134,612
Exploration		1,696		—		—		—		1,696
General and administrative (excluding equity-based compensation)		96,136		—		23,497		(23,497)		96,136
Equity-based compensation		24,999		—		21,407		(21,407)		24,999
Depletion, depreciation and amortization		433,493		—		72,013		(72,013)		433,493
Impairment of property and equipment		5,403		—		133		(133)		5,403
Accretion of asset retirement obligations		2,046		—		—		—		2,046
Gain on sale of assets		(60,566)		—		(2,658)		2,658		(60,566)
Contract termination, loss contingency, settlements and other operating expenses		13,742		—		1,320		(1,320)		13,742
Total operating expenses		2,265,445		134,612		270,935		(270,935)		2,400,057
Operating income (loss)	$	1,141,796		(36,885)		370,520		(370,520)		1,104,911

Equity in earnings of unconsolidated affiliates	$	59,497		—		58,537		(58,537)		59,497

(1)	Amounts reflect those recorded in Antero Midstream’s unaudited condensed consolidated financial statements.

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


	Six Months Ended				Amount of
	June 30,				Increase		Percent
	2025		2026		(Decrease)		Change
Production data ^{(1) (2)}:
Natural gas (Bcf)		398		495		97	24	%
C2 Ethane (MBbl)		14,366		14,732		366	3	%
C3+ NGLs (MBbl)		20,837		21,895		1,058	5	%
Oil (MBbl)		1,524		1,574		50	3	%
Combined (Bcfe)		618		724		106	17	%
Daily combined production (MMcfe/d)		3,414		3,999		585	17	%
Average prices before effects of derivative settlements⁽³⁾:
Natural gas (per Mcf)	$	3.69		4.04		0.35	9	%
C2 Ethane (per Bbl) ⁽⁴⁾	$	12.04		12.99		0.95	8	%
C3+ NGLs (per Bbl)	$	41.71		41.10		(0.61)	(1)	%
Oil (per Bbl)	$	55.14		67.52		12.38	22	%
Weighted Average Combined (per Mcfe)	$	4.20		4.42		0.22	5	%
Average realized prices after effects of derivative settlements⁽³⁾:
Natural gas (per Mcf)	$	3.65		3.98		0.33	9	%
C2 Ethane (per Bbl) ⁽⁴⁾	$	12.04		12.99		0.95	8	%
C3+ NGLs (per Bbl)	$	41.71		41.13		(0.58)	(1)	%
Oil (per Bbl)	$	55.08		67.52		12.44	23	%
Weighted Average Combined (per Mcfe)	$	4.17		4.38		0.21	5	%
Average costs (per Mcfe):
Lease operating	$	0.12		0.13		0.01	8	%
Gathering and compression	$	0.77		0.75		(0.02)	(3)	%
Processing	$	0.88		0.80		(0.08)	(9)	%
Transportation	$	0.61		0.58		(0.03)	(5)	%
Production and ad valorem taxes	$	0.15		0.16		0.01	7	%
Marketing expense, net	$	0.06		0.05		(0.01)	(17)	%
General and administrative (excluding equity-based compensation)	$	0.14		0.13		(0.01)	(7)	%
Depletion, depreciation, amortization and accretion	$	0.61		0.60		(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 or 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 six months ended June 30, 2025 includes $0.5 million of proceeds related to a take-or-pay contract. Excluding the effect of these proceeds, the average realized price for ethane before and after the effects of derivatives for the six months ended June 30, 2025 would have been $12.01 per Bbl.

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Exploration and Production Segment

Natural gas sales. Revenues from sales of natural gas increased from $1.5 billion for the six months ended June 30, 2025 to $2.0 billion for the six months ended June 30, 2026, an increase of $0.5 billion, or 36%, primarily due to an additional $321 million of natural gas revenue attributable to the HG Acquisition properties and higher natural gas production volumes and commodity prices between periods, partially offset by the Utica Shale Divestiture. Higher natural gas production volumes accounted for an approximate $358 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). Higher commodity prices (excluding the effects of derivative settlements) during the six months ended June 30, 2026 accounted for an approximate $173 million increase in year-over-year natural gas sales revenue (calculated as the change in the year-to-year average price times current year production volumes).

NGLs sales. Revenues from sales of NGLs increased from $1.0 billion for the six months ended June 30, 2025 to $1.1 billion for the six months ended June 30, 2026, an increase of $0.1 billion, or 5%, primarily due to an additional $54 million of NGLs revenue attributable to the HG Acquisition properties, higher NGLs production volumes and higher ethane commodity prices between periods, partially offset by the Utica Shale Divestiture and lower C3+ NGLs commodity prices during the six months ended June 30, 2026. Higher NGLs production volumes during the six months ended June 30, 2026 accounted for an approximate $49 million increase in year-over-year NGLs revenues (calculated as the change in year-to-year volumes times the prior year average price). Higher ethane commodity prices (excluding the effects of derivative settlements) during the six months ended June 30, 2026 accounted for an approximate $14 million increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). Lower C3+ NGLs commodity prices (excluding the effects of derivative settlements) during the six months ended June 30, 2026 accounted for an approximate $13 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

Oil sales. Revenues from sales of oil increased from $84 million for the six months ended June 30, 2025 to $106 million for the six months ended June 30, 2026, an increase of $22 million, or 26%, primarily due to an additional $12 million of oil revenue attributable to the HG Acquisition properties and higher oil prices between periods, partially offset by the Utica Shale Divestiture. Higher oil prices (excluding the effects of derivative settlements) accounted for an approximate $19 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 accounted for an approximate $3 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 (losses). Our commodity derivatives included fixed price swaps, collars, basis swaps and three-way collars, among others. 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 unaudited condensed consolidated statements of operations and comprehensive income. For the six months ended June 30, 2025 and 2026, our commodity hedges resulted in derivative fair value losses of $18 million and fair value gains of $196 million, respectively. For the six months ended June 30, 2025, commodity derivative fair value losses included $17 million of net cash payments for settled derivative losses. For the six months ended June 30, 2026, commodity derivative fair value gains included $31 million of net cash payments for settled derivative losses.

Amortization of deferred revenue, VPP. Amortization of deferred revenues associated with the VPP remained relatively consistent at $13 million and $12 million for the six months ended June 30, 2025 and 2026, respectively. 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 per Mcfe increased 8% from $0.12 per Mcfe for the six months ended June 30, 2025 to $0.13 per Mcfe for the six months ended June 30, 2026 primarily due to higher wastewater trucking and disposal costs due to the timing of well completions activity between periods. Lease operating expense increased from $71 million for the six months ended June 30, 2025 to $93 million for the six months ended June 30, 2026, an increase of $22 million, or 30%, primarily due to incremental expense of $14 million related to the HG Acquisition properties and higher wastewater trucking and disposal costs due to the timing of well completions activity between periods, partially offset by the Utica Shale Divestiture.

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Gathering, compression, processing and transportation expense. Gathering, compression, processing and transportation expense per Mcfe decreased 6% from $2.26 per Mcfe for the six months ended June 30, 2025 to $2.13 per Mcfe for the six months ended June 30, 2026 primarily due to the HG Acquisition properties that have a lower compression, processing and transportation costs. Gathering, compression, processing and transportation expense increased from $1.4 billion for the six months ended June 30, 2025 to $1.5 billion for the six months ended June 30, 2026, an increase of $0.1 billion, or 10%, primarily due to incremental expense of $109 million related to the HG Acquisition properties and higher production volumes between periods, partially offset the Utica Shale Divestiture. The fluctuation of our gathering, compression, processing and transportation expense on a per unit basis was primarily a result of the following:

●

Gathering and compression costs on a per unit basis decreased from $0.77 per Mcfe for the six months ended June 30, 2025 to $0.75 per Mcfe for the six months ended June 30, 2026, primarily due to lower gathering and compression expense on a per unit basis for the HG Acquisition properties, partially offset by increased fuel costs as a result of higher natural gas prices and annual CPI-based adjustments between periods.

●

Processing costs on a per unit basis decreased from $0.88 per Mcfe for the six months ended June 30, 2025 to $0.80 per Mcfe for the six months ended June 30, 2026, primarily due to lower NGLs transportation fees related to the HG Acquisition properties between periods.

●

Transportation costs on a per unit basis decreased from $0.61 per Mcfe for the six months ended June 30, 2025 to $0.58 per Mcfe for the six months ended June 30, 2026, primarily due to lower transportation expense on a per unit basis for the HG Acquisition properties, partially offset by increased fuel costs as a result of higher natural gas prices between periods.

Production and ad valorem tax expense. Production and ad valorem taxes as a percentage of natural gas revenues remained consistent at 6% for each of the six months ended June 30, 2025 and 2026. Production and ad valorem taxes increased from $90 million for the six months ended June 30, 2025 to $119 million for the six months ended June 30, 2026, an increase of $29 million, or 32%, primarily due to higher natural gas prices between periods and incremental expense of $15 million related to the HG Acquisition properties, partially offset by the Utica Shale Divestiture.

General and administrative expense. General and administrative expense (excluding equity-based compensation) per Mcfe decreased 7% from $0.14 per Mcfe for the six months ended June 30, 2025 to $0.13 per Mcfe for the six months ended June 30, 2026 primarily due to increased production volumes related to our HG Acquisition, partially offset by higher overall general and administrative costs between periods. General and administrative expense (excluding equity-based compensation expense) increased from $89 million for the six months ended June 30, 2025 to $96 million for the six months ended June 30, 2026, an increase of $7 million, or 8%, primarily due to higher salary and wage expense, software license costs and professional service fees between periods.

Equity-based compensation expense. Non-cash equity-based compensation expense decreased from $31 million for the six months ended June 30, 2025 to $25 million for the six months ended June 30, 2026, a decrease of $6 million or 19%. This decrease was primarily due to lower RSU and PSU award expense of $5 million and $1 million, respectively, between periods. See Note 9—Equity-Based Compensation to the unaudited condensed consolidated financial statements for additional information.

Depletion, depreciation and amortization expense. DD&A expense per Mcfe remained relatively consistent at $0.61 per Mcfe and $0.60 per Mcfe for the six months ended June 30, 2025 and 2026, respectively. DD&A expense increased from $374 million for the six months ended June 30, 2025 to $433 million for the six months ended June 30, 2026, an increase of $59 million, or 16%, primarily due to higher production volumes between periods related to our HG Acquisition properties, partially offset by the Utica Shale Divestiture.

Impairment of property and equipment. Impairment of oil and gas properties decreased from $12 million for the six months ended June 30, 2025 to $5 million for the six months ended June 30, 2026, 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 utilize.

Contract termination, loss contingency and settlements. Contract termination, loss contingency, settlements and other operating expenses increased from $12 million for the six months ended June 30, 2025 to $14 million for the six months ended June 30, 2026, an increase of $2 million. This increase was primarily due to contract termination expense related to certain HG Acquisition contracts during the six months ended June 30, 2026. See Note 14—Contingencies to the unaudited condensed consolidated financial statements for additional information.

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Gain on sale of assets. Gain on sale of assets was less than $1 million for the six months ended June 30, 2025. Gain on sale of assets was $61 million for the six months ended June 30, 2026 primarily due to the Utica Shale Divestiture that closed on February 23, 2026. See Note 3—Transactions to the unaudited condensed consolidated financial statements for additional information.

Marketing Segment

Net marketing expense decreased from $0.06 per Mcfe for the six months ended June 30, 2025 to $0.05 per Mcfe for the six months ended June 30, 2026, primarily due higher production volumes from our HG Acquisition, partially offset by higher net marketing expense between periods. Net marketing expense increased from $35 million for the six months ended June 30, 2025 to $37 million for the six months ended June 30, 2026 primarily due to higher demand fees on certain pipelines and lower pipeline utilization due to maintenance between periods.

Marketing revenue. Marketing revenue increased from $59 million for the six months ended June 30, 2025 to $98 million for the six months ended June 30, 2026, an increase of $39 million, or 65%. This fluctuation primarily resulted from the following:

●

Natural gas marketing revenue decreased by $5 million between periods primarily due to lower natural gas marketing volumes.

●

Oil marketing revenue increased by $42 million between periods primarily due to higher oil marketing volumes and prices. Higher oil marketing volumes accounted for a $23 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 $19 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 revenue increased by $4 million between periods primarily due to higher ethane marketing volumes and prices for the six months ended June 30, 2026.

Marketing expense. Marketing expense increased from $95 million for the six months ended June 30, 2025 to $135 million for the six months ended June 30, 2026, an increase of $40 million, or 42%. 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 purchases increased $34 million between periods primarily due to higher oil marketing prices and volumes during the six months ended June 30, 2026, partially offset by lower natural gas marketing volumes during the six months ended June 30, 2026. Firm transportation costs increased $7 million between periods primarily due to lower pipeline utilization as a result of higher pricing in the Appalachian Basin and a pipeline force majeure during the six months ended June 30, 2026.

Antero Midstream Segment

Antero Midstream revenue. Revenue from the Antero Midstream segment increased from $597 million for the six months ended June 30, 2025 to $641 million for the six months ended June 30, 2026, an increase of $44 million. This increase is primarily due to higher gathering and processing revenues of $39 million and higher water handling revenues of $5 million. The increased gathering and processing revenues between periods is primarily due to higher low pressure gathering and compression volumes from the HG Acquisition and 80 wells connected to their system between periods and increased gathering and centralized compression rates as a result of annual CPI-based adjustments, partially offset by the Utica Shale Divestiture and natural production decline of wells connected to their system between periods. The increased water handling revenues between periods is primarily due to fresh water delivery volumes for our acreage acquired in the HG Acquisition that are charged at cost plus 3% during the six months ended June 30, 2026, higher blending cost of service fees, increased wastewater trucking and disposal volumes and costs and a higher fresh water delivery fee as a result of an annual CPI-based adjustment, partially offset by decreased fresh water delivery volumes between periods due to the timing and location of our completions activity.

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Antero Midstream operating expense. Total operating expense related to the Antero Midstream segment increased from $233 million for the six months ended June 30, 2025 to $271 million for the six months ended June 30, 2026, an increase of $38 million. This increase is primarily due to higher direct operating expenses as a result of increased gathering and well pad compression costs between periods related to assets acquired with the HG Acquisition, fresh water delivery services on our acreage acquired in the HG Acquisition and increased wastewater trucking and disposal volumes and higher blending costs between periods, partially offset by the Utica Shale Divestiture.

Items Not Allocated to Segments

Interest expense, net. Interest expense, net increased from $43 million for the six months ended June 30, 2025 to $74 million for the six months ended June 30, 2026, an increase of $31 million or 72%, primarily due to borrowings to fund our HG Acquisition under the Term Loan and issuance of the 2036 Notes during the first quarter of 2026, partially offset by the redemption of the 2029 Notes on February 24, 2026 and lower Credit Facility borrowings and rates between periods. See Note 7—Debt to our unaudited condensed consolidated financial statements for more information.

Loss on early extinguishment of debt. During the six months ended June 30, 2025, we recognized a loss on early debt extinguishment of $4 million related to the redemption of the remaining $97 million aggregate principal amount of our 2026 Notes at a redemption price of 102.094% of the principal amount thereof, plus accrued and unpaid interest, and the repurchase of $42 million aggregate principal amount of our 2029 Notes through open market transactions at a weighted average price of approximately 103% of the principal amount thereof, plus accrued and unpaid interest. During the six months ended June 30, 2026, we recognized a loss on early debt extinguishment of $7 million related to the redemption of the remaining $365 million principal amount of our 2029 Notes at 101.271% of the principal amount thereof, plus accrued and unpaid interest. See Note 7—Debt to our unaudited condensed consolidated financial statements for more information.

Transaction expense. There were no transaction expenses incurred during the six months ended June 30, 2025. During the six months ended June 30, 2026, we incurred $24 million of transaction expense related to the HG Acquisition. See Note 3—Transactions to our unaudited condensed consolidated financial statements for more information.

Income tax expense. Income tax expense increased from $103 million, with an effective tax rate of 21%, for the six months ended June 30, 2025 to $225 million, with an effective tax rate of 21%, for the six months ended June 30, 2026 primarily due to the increase in income before income taxes between periods.

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 and Term Loan, issuances of debt and equity securities, including issuances of notes under our Commercial Paper Program, and additional contributions from our asset sales, including our drilling partnerships. 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, 2026, we believe that net cash provided by operating activities, issuances of notes under our Commercial Paper Program and available borrowings under the Credit Facility will be sufficient to meet our cash requirements, including normal operating needs, debt service obligations, capital expenditures and commitments and contingencies for at least the next 12 months.

Cash Flows

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


	Six Months Ended June 30,
	2025		2026
Net cash provided by operating activities	$	950,097		1,297,907
Net cash used in investing activities		(405,380)		(2,624,723)
Net cash provided by (used in) financing activities		(544,717)		1,116,816
Net decrease in cash, cash equivalents and restricted cash	$	—		(210,000)

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Operating activities. Net cash provided by operating activities was $950 million and $1.3 billion for the six months ended June 30, 2025 and 2026, respectively. Net cash provided by operating activities increased between periods primarily due to higher natural gas, NGLs and oil revenues for our HG Acquisition properties, lower lease operating, gathering, compression, processing, transportation, production and ad valorem taxes for the Utica Shale Divestiture and changes in working capital, partially offset by higher lease operating, gathering, compression, processing, transportation and production and ad valorem taxes for our HG Acquisition properties, lower natural gas, NGLs and oil revenues for the Utica Shale Divestiture and higher marketing and interest expense during the six months ended June 30, 2026.

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 increased from $405 million for the six months ended June 30, 2025 to $2.6 billion for the six months ended June 30, 2026, primarily due to cash paid for our HG Acquisition of $2.8 billion during the six months ended June 30, 2026, increased drilling and completions activity of $136 million between periods and acquisitions of oil and gas properties during the six months ended June 30, 2026 of $8 million, partially offset by proceeds from the Utica Shale Divestiture of $757 million during the six months ended June 30, 2026 and decreased oil and gas leasing activity of $11 million between periods.

Financing activities. Net cash used in financing activities was $545 million for the six months ended June 30, 2025. Net cash provided by financing activities was $1.1 billion for the six months ended June 30, 2026. The increase in net cash provided by financing activities between periods is primarily due to borrowings to fund our HG Acquisition on the Term Loan of $1.5 billion, the issuance of our 2036 Notes of $750 million and net borrowings on our Commercial Paper Program of $182 million during the six months ended June 30, 2026, partially offset by higher net repayments on our Credit Facility of $183 million between periods, repayments on the Term Loan of $400 million during the six months ended June 30, 2026, higher repayments and redemptions of our senior notes of $228 million between periods and increased payments of employee tax withholdings for the settlement of equity-based compensation awards of $8 million between periods.

2026 Capital Budget, Capital Spending and Acquisitions

On February 11, 2026, we announced our capital budget for 2026 is $1.1 billion to $1.3 billion and includes: $1.0 billion for drilling and completions, $100 million for leasehold expenditures and up to $200 million for discretionary growth capital that is dependent on commodity prices. Our capital budget reflects the closing of the HG Acquisition on the Closing Date and the closing of the Utica Shale Divestiture on February 23, 2026. We do not budget for acquisitions. During 2026, we plan to complete 70 to 80 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, 2026, our total consolidated capital expenditures were $332 million, including drilling and completion costs of $297 million, leasehold acquisitions of $29 million, and other capital expenditures of $6 million. For the six months ended June 30, 2026, our total consolidated capital expenditures were $584 million, including drilling and completion costs of $518 million, leasehold acquisitions of $54 million, and other capital expenditures of $12 million.

Debt Agreements

See Note 7—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 2025 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 affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure of contingent liabilities. Accounting

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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 2025 Form 10-K for information on our critical accounting estimates.

Business Combinations

We recognize and measure the assets acquired and liabilities assumed in a business combination based on their estimated fair values at the acquisition date, with any remaining difference recorded as goodwill. For acquisitions, management engages an independent valuation specialist to assist with the determination of fair value of the assets acquired, liabilities assumed, and goodwill, based on recognized valuation methodologies, including but not limited to income and cost approaches as circumstances warrant. If the initial accounting for the business combination is incomplete by the end of the reporting period in which the acquisition occurs, an estimate will be recorded. Subsequent to the acquisition, and not later than one year from the Closing Date, we will record any material adjustments to the initial estimate based on new information obtained that would have existed as of the Closing Date. An adjustment that arises from information obtained that did not exist as of the date of the acquisition will be recorded in the period of the adjustment.

The valuation of the assets acquired and liabilities assumed in a business combination requires significant judgement about commodity prices, projected reserve quantities, estimated future rates of production, projected reserve recovery factors, development plans (including timing and amount of development), future development costs, operating costs, among others, and such fair value approaches may rely on significant inputs that are not observable in the market. These assumptions affect the fair value of assets acquired and liabilities assumed and, if changed, could have a material effect on the Company’s financial position or results of operations. See Note 3—Transactions and Note 10—Fair Value Measurement to our unaudited condensed consolidated financial statements for more information.

Impairment of Proved Properties

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, 2026, 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 six months ended June 30, 2025 and 2026.

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 our unaudited condensed consolidated financial statements for information on new accounting pronouncements.

Off-Balance Sheet Arrangements

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

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Commodity Hedging Activities

Our primary market risk exposure is in the price we receive for our natural gas, NGLs and oil production. Pricing is primarily driven by spot regional market prices applicable to our U.S. natural gas production and the prevailing worldwide price for oil. Pricing for natural gas, NGLs and oil has, historically, been volatile and unpredictable, and we expect this volatility to continue in the future. The prices we receive for our production depend on many factors outside of our control, including volatility in the differences between commodity prices at sales points and the applicable index price.

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. For the three months ended June 30, 2025 and 2026, 4% and 47%, respectively, of our production was hedged through commodity derivatives, excluding basis swaps. For the six months ended June 30, 2025 and 2026, 4% and 44%, respectively, of our production was hedged through commodity derivatives, excluding basis swaps. In addition, for the three and six months ended June 30, 2026, 18% and 15%, respectively, of our production was hedged through basis swap commodity derivatives. We did not have any basis swap commodity derivatives for the three and six months ended June 30, 2025.

Our financial hedging activities may include commodity derivative instruments that are intended to support natural gas, NGLs and oil prices at targeted levels and to manage our exposure to price risk associated with our production. 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 three-way collars, among others. These contracts are financial instruments and do not require or allow for physical delivery of the hedged commodity. As of June 30, 2026, our commodity derivatives included fixed swaps, basis swaps, collars and three-way collars, among others at index-based pricing for a portion of our production. See Note 11—Derivative Instruments to our unaudited condensed consolidated financial statements for additional information.

Based on our production and our derivative instruments that settled during the six months ended June 30, 2026, our revenues would have decreased by $55 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, 2026.

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 unaudited condensed consolidated 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 (losses) in the unaudited condensed consolidated statements of operations and comprehensive income.

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, 2025 and June 30, 2026, the estimated fair value of our commodity derivative instruments was a net asset of $81 million and $228 million, respectively, comprised of current and noncurrent assets and liabilities, as applicable.

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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 ($458 million as of June 30, 2026), which we market to energy companies, end users and refineries, and commodity derivative contracts ($232 million as of June 30, 2026).

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, 2026, we have commodity hedges in place with 12 different counterparties, 10 of which are lenders under the Credit Facility. We had derivative assets of $231 million with bank counterparties under our Credit Facility as of June 30, 2026. 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, 2026. We believe that all of the counterparties to our derivative instruments are acceptable credit risks as of June 30, 2026. We are not required to provide credit support or collateral to any of our counterparties under our derivative contracts, nor are they required to provide credit support to us. As of June 30, 2026, 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 and Term Loan, which have floating interest rates. The average annualized interest rate incurred on the Credit Facility and the Term Loan for borrowings during the six months ended June 30, 2026 was 5.2% and 5.0%, respectively. We estimate that a 1.0% increase in the applicable average interest rates for the six months ended June 30, 2026 would have resulted in an estimated $7 million increase in interest expense. Additional short-term or variable-rate debt may be issued in the future, including under the Credit Facility or Commercial Paper Program, which may provide further exposure to interest rate risk.

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, 2026 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, 2026 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

We are subject to certain risks and hazards due to the nature of the business activities we conduct. For a discussion of these risks, see “Item 1A. Risk Factors” in the 2025 Form 10-K. There have been no material changes to the risks described in such report. We may experience additional risks and uncertainties not currently known to us. Furthermore, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also materially and adversely affect us.

Item 2. Unregistered Sales of Equity Securities

Issuer Purchases of Equity Securities

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


				Total Number	Approximate
				of Shares	Dollar Value
				Repurchased	of Shares
				as Part of	that May
	Total Number			Publicly	Yet be Purchased
	of Shares	Average Price		Announced	Under the Plan
Period	Purchased ⁽¹⁾	Paid Per Share		Plans	($ in thousands)⁽²⁾
April 1, 2026 - April 30, 2026	166	$	36.34	—		914,497
May 1, 2026 - May 31, 2026	3,641		39.13	—		914,497
June 1, 2026 - June 30, 2026	1,107,641		34.23	1,106,900		876,607
Total	1,111,448	$	34.25	1,106,900

(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.

(2)

On February 15, 2022, our Board of Directors authorized a share repurchase program to opportunistically repurchase up to $1.0 billion of shares of our outstanding common stock. On October 25, 2022, our Board of Directors authorized a $1.0 billion increase to our share repurchase program to allow us to repurchase up to an aggregate of $2.0 billion of our outstanding common stock.

Item 4. MINE SAFETY DISCLOSURES

Not applicable.

Item 5. Other Information

On May 5, 2026, Michael N. Kennedy, our Chief Executive Officer and President and a Director, terminated the Rule 10b5-1 trading arrangement, dated as of November 6, 2025, for the sale of up to 200,000 shares of the Company’s common stock, of which 185,826 shares had been sold prior to the termination.

On July 28, 2026 (the “First Amendment Effective Date”), we entered an amendment to our Credit Facility (the “Credit Facility Amendment”), pursuant to which the Maturity Date was extended to July 30, 2031 and the 0.10% credit adjustment spread on SOFR was removed. We may request two more one-year extensions of the Maturity Date after the First Amendment Effective Date, subject to satisfaction of certain conditions and consent of the extending lenders. A description of the Credit Facility Amendment is included in Note 7—Debt to the unaudited condensed consolidated financial statements and is incorporated into this Item 5. The description of the Credit Facility Amendment is a summary and is qualified in its entirety by the terms of the Credit Facility Amendment. A copy of the Credit Facility Amendment is filed as Exhibit 10.3 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		Third Amended and Restated Bylaws of Antero Resources Corporation, dated August 14, 2025 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-36120) filed on August 14, 2025).
4.1		Base Indenture, dated January 28, 2026, among Antero Resources Corporation and Computershare Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-36120) filed on January 28, 2026).
4.2		First Supplemental Indenture, dated January 28, 2026, among Antero Resources Corporation and Computershare Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K (Commission File No. 001-36120) filed on January 28, 2026).
10.1†		Credit Agreement, by and among Antero Resources Corporation, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent, dated February 3, 2026 (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-36120) filed on February 3, 2026).
10.2		Form of Commercial Paper Dealer Agreement between Antero Resources Corporation, as Issuer and the Dealer party thereto (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 17, 2026).
10.3*		First Amendment to Amended and Restated Credit Agreement, dated as of July 28, 2026, 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).
101*		The following financial information from this Quarterly Report on Form 10-Q of Antero Resources Corporation for the quarter ended June 30, 2026 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.

† Certain of the annexes, schedules and exhibits to this Exhibit have been omitted pursuant to Item 601(a)(5) of Regulation S-K. A copy of any omitted annex, schedule or exhibit will be furnished to the U.S. Securities and Exchange Commission upon request. Certain personally identifiable information has also been omitted from this Exhibit pursuant to Item 601(a)(6) of Regulation S-K.

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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/ Brendan E. Krueger
	Brendan E. Krueger
	Chief Financial Officer, Senior Vice President – Finance and Treasurer

Date:	July 29, 2026