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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

​

FORM 10-Q

​

(Mark One)

​

​ | ​
☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

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For the quarterly period ended June 30, 2025

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OR

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​ | ​
☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

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For the transition period from to

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Commission file number: 001-36120

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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 25, 2025 (in thousands): 308,931

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Table of Contents

TABLE OF CONTENTS

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|  |  | ​ |
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 | ​ | 34
Item 3. | ​ | Quantitative and Qualitative Disclosures about Market Risk | ​ | 50
Item 4. | ​ | Controls and Procedures | ​ | 52
PART II—OTHER INFORMATION | ​ | 52
Item 1. | ​ | Legal Proceedings | ​ | 52
Item 1A. | ​ | Risk Factors | ​ | 52
Item 2. | ​ | Unregistered Sales of Equity Securities | ​ | 53
Item 5 | ​ | Other Information | ​ | 53
Item 6. | ​ | Exhibits | ​ | 54
SIGNATURES | ​ | 55

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Table of Contents

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, 2024. 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, NGLs and oil prices;

| ● | our ability to execute our business strategy;

| ● | our production and natural gas, natural gas liquids (“NGLs”) and oil reserves;

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

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

| ● | 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 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;

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

| ● | general economic conditions;

1

Table of Contents

| ● | 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, 2024 (the “2024 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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2

Table of Contents

PART I—FINANCIAL INFORMATION

ANTERO RESOURCES CORPORATION

Condensed Consolidated Balance Sheets

(In thousands, except per share amounts)

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | (Unaudited) | ​
​ | ​ | December 31, | ​ | June 30, | ​
​ |  | 2024 |  | 2025 | ​
Assets | ​
Current assets: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Accounts receivable | ​ | $ | 34,413 | ​ | ​ | 31,650 | ​
Accrued revenue | ​ | ​ | 453,613 | ​ | ​ | 367,895 | ​
Derivative instruments | ​ | ​ | 1,050 | ​ | ​ | 1,137 | ​
Prepaid expenses | ​ | ​ | 12,423 | ​ | ​ | 9,591 | ​
Other current assets | ​ | ​ | 6,047 | ​ | ​ | 17,261 | ​
Total current assets | ​ | ​ | 507,546 | ​ | ​ | 427,534 | ​
Property and equipment: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil and gas properties, at cost (successful efforts method): | ​ | ​ | ​ | ​ | ​ | ​ | ​
Unproved properties | ​ | ​ | 879,483 | ​ | ​ | 883,170 | ​
Proved properties | ​ | ​ | 14,395,680 | ​ | ​ | 14,540,908 | ​
Gathering systems and facilities | ​ | ​ | 5,802 | ​ | ​ | 5,802 | ​
Other property and equipment | ​ | ​ | 105,871 | ​ | ​ | 109,318 | ​
​ | ​ | ​ | 15,386,836 | ​ | ​ | 15,539,198 | ​
Less accumulated depletion, depreciation and amortization | ​ | ​ | (5,699,286) | ​ | ​ | (5,883,318) | ​
Property and equipment, net | ​ | ​ | 9,687,550 | ​ | ​ | 9,655,880 | ​
Operating leases right-of-use assets | ​ | ​ | 2,549,398 | ​ | ​ | 2,397,054 | ​
Derivative instruments | ​ | ​ | 1,296 | ​ | ​ | 947 | ​
Investment in unconsolidated affiliate | ​ | ​ | 231,048 | ​ | ​ | 249,163 | ​
Other assets | ​ | ​ | 33,212 | ​ | ​ | 35,495 | ​
Total assets | ​ | $ | 13,010,050 | ​ | ​ | 12,766,073 | ​
Liabilities and Equity | ​
Current liabilities: | ​ | ​ | ​ | ​ |  | ​ | ​
Accounts payable | ​ | $ | 62,213 | ​ | ​ | 39,901 | ​
Accounts payable, related parties | ​ | ​ | 111,066 | ​ | ​ | 107,293 | ​
Accrued liabilities | ​ | ​ | 402,591 | ​ | ​ | 312,832 | ​
Revenue distributions payable | ​ | ​ | 315,932 | ​ | ​ | 364,053 | ​
Derivative instruments | ​ | ​ | 31,792 | ​ | ​ | 34,019 | ​
Short-term lease liabilities | ​ | ​ | 493,894 | ​ | ​ | 514,292 | ​
Deferred revenue, VPP | ​ | ​ | 25,264 | ​ | ​ | 24,390 | ​
Other current liabilities | ​ | ​ | 3,175 | ​ | ​ | 7,949 | ​
Total current liabilities | ​ | ​ | 1,445,927 | ​ | ​ | 1,404,729 | ​
Long-term liabilities: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Long-term debt | ​ | ​ | 1,489,230 | ​ | ​ | 1,098,669 | ​
Deferred income tax liability, net | ​ | ​ | 693,341 | ​ | ​ | 795,816 | ​
Derivative instruments | ​ | ​ | 17,233 | ​ | ​ | 15,635 | ​
Long-term lease liabilities | ​ | ​ | 2,050,337 | ​ | ​ | 1,878,718 | ​
Deferred revenue, VPP | ​ | ​ | 35,448 | ​ | ​ | 23,794 | ​
Other liabilities | ​ | ​ | 62,001 | ​ | ​ | 64,205 | ​
Total liabilities | ​ | ​ | 5,793,517 | ​ | ​ | 5,281,566 | ​
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; 311,165 and 309,869 shares issued and outstanding as of December 31, 2024 and June 30, 2025, respectively | ​ | ​ | 3,111 | ​ | ​ | 3,098 | ​
Additional paid-in capital | ​ | ​ | 5,909,373 | ​ | ​ | 5,867,226 | ​
Retained earnings | ​ | ​ | 1,109,166 | ​ | ​ | 1,435,298 | ​
Total stockholders' equity | ​ | ​ | 7,021,650 | ​ | ​ | 7,305,622 | ​
Noncontrolling interests | ​ | ​ | 194,883 | ​ | ​ | 178,885 | ​
Total equity | ​ | ​ | 7,216,533 | ​ | ​ | 7,484,507 | ​
Total liabilities and equity | ​ | $ | 13,010,050 | ​ | ​ | 12,766,073 | ​

​

See accompanying notes to unaudited condensed consolidated financial statements.

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ANTERO RESOURCES CORPORATION

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

(In thousands, except per share amounts)

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Three Months Ended June 30, | ​
​ |  | 2024 |  | 2025 |
Revenue and other: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Natural gas sales | ​ | $ | 374,568 | ​ | ​ | 688,753 | ​
Natural gas liquids sales | ​ | ​ | 489,191 | ​ | ​ | 480,757 | ​
Oil sales | ​ | ​ | 63,458 | ​ | ​ | 33,700 | ​
Commodity derivative fair value gains (losses) | ​ | ​ | (5,585) | ​ | ​ | 53,409 | ​
Marketing | ​ | ​ | 49,418 | ​ | ​ | 33,743 | ​
Amortization of deferred revenue, VPP | ​ | ​ | 6,739 | ​ | ​ | 6,298 | ​
Other revenue and income | ​ | ​ | 865 | ​ | ​ | 833 | ​
Total revenue | ​ | ​ | 978,654 | ​ | ​ | 1,297,493 | ​
Operating expenses: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Lease operating | ​ | ​ | 29,759 | ​ | ​ | 37,244 | ​
Gathering, compression, processing and transportation | ​ | ​ | 663,442 | ​ | ​ | 701,722 | ​
Production and ad valorem taxes | ​ | ​ | 41,933 | ​ | ​ | 34,830 | ​
Marketing | ​ | ​ | 70,807 | ​ | ​ | 51,988 | ​
Exploration | ​ | ​ | 643 | ​ | ​ | 648 | ​
General and administrative (including equity-based compensation expense of $17,151 and $15,855 in 2024 and 2025, respectively) | ​ | ​ | 59,428 | ​ | ​ | 57,183 | ​
Depletion, depreciation and amortization | ​ | ​ | 188,633 | ​ | ​ | 187,589 | ​
Impairment of property and equipment | ​ | ​ | 313 | ​ | ​ | 6,297 | ​
Accretion of asset retirement obligations | ​ | ​ | 780 | ​ | ​ | 942 | ​
Contract termination, loss contingency and settlements | ​ | ​ | 3,009 | ​ | ​ | 13,596 | ​
Loss (gain) on sale of assets | ​ | ​ | (18) | ​ | ​ | 546 | ​
Other operating expense | ​ | ​ | 11 | ​ | ​ | 25 | ​
Total operating expenses | ​ | ​ | 1,058,740 | ​ | ​ | 1,092,610 | ​
Operating income (loss) | ​ | ​ | (80,086) | ​ | ​ | 204,883 | ​
Other income (expense): | ​ | ​ | ​ | ​ | ​ | ​ | ​
Interest expense, net | ​ | ​ | (32,681) | ​ | ​ | (19,954) | ​
Equity in earnings of unconsolidated affiliate | ​ | ​ | 20,881 | ​ | ​ | 30,563 | ​
Loss on early extinguishment of debt | ​ | ​ | — | ​ | ​ | (729) | ​
Total other income (expense) | ​ | ​ | (11,800) | ​ | ​ | 9,880 | ​
Income (loss) before income taxes | ​ | ​ | (91,886) | ​ | ​ | 214,763 | ​
Income tax benefit (expense) | ​ | ​ | 17,288 | ​ | ​ | (48,190) | ​
Net income (loss) and comprehensive income (loss) including noncontrolling interests | ​ | ​ | (74,598) | ​ | ​ | 166,573 | ​
Less: net income and comprehensive income attributable to noncontrolling interests | ​ | ​ | 5,208 | ​ | ​ | 9,988 | ​
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation | ​ | $ | (79,806) | ​ | ​ | 156,585 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net income (loss) per common share—basic | ​ | $ | (0.26) | ​ | ​ | 0.50 | ​
Net income (loss) per common share—diluted | ​ | $ | (0.26) | ​ | ​ | 0.50 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Weighted average number of common shares outstanding: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Basic | ​ | ​ | 310,806 | ​ | ​ | 310,323 | ​
Diluted | ​ | ​ | 310,806 | ​ | ​ | 313,184 | ​

​

See accompanying notes to unaudited condensed consolidated financial statements.

​

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ANTERO RESOURCES CORPORATION

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

(In thousands, except per share amounts)

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Six Months Ended June 30, | ​
​ |  | 2024 |  | 2025 | ​
Revenue and other: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Natural gas sales | ​ | $ | 848,701 | ​ | ​ | 1,468,758 | ​
Natural gas liquids sales | ​ | ​ | 1,007,053 | ​ | ​ | 1,042,189 | ​
Oil sales | ​ | ​ | 128,175 | ​ | ​ | 84,035 | ​
Commodity derivative fair value gains (losses) | ​ | ​ | 3,861 | ​ | ​ | (18,262) | ​
Marketing | ​ | ​ | 97,938 | ​ | ​ | 59,301 | ​
Amortization of deferred revenue, VPP | ​ | ​ | 13,477 | ​ | ​ | 12,528 | ​
Other revenue and income | ​ | ​ | 1,720 | ​ | ​ | 1,651 | ​
Total revenue | ​ | ​ | 2,100,925 | ​ | ​ | 2,650,200 | ​
Operating expenses: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Lease operating | ​ | ​ | 58,880 | ​ | ​ | 71,230 | ​
Gathering, compression, processing and transportation | ​ | ​ | 1,335,723 | ​ | ​ | 1,396,739 | ​
Production and ad valorem taxes | ​ | ​ | 100,101 | ​ | ​ | 90,129 | ​
Marketing | ​ | ​ | 130,620 | ​ | ​ | 94,758 | ​
Exploration | ​ | ​ | 1,245 | ​ | ​ | 1,316 | ​
General and administrative (including equity-based compensation expense of $33,228 and $31,000 in 2024 and 2025, respectively) | ​ | ​ | 115,290 | ​ | ​ | 119,628 | ​
Depletion, depreciation and amortization | ​ | ​ | 379,108 | ​ | ​ | 373,941 | ​
Impairment of property and equipment | ​ | ​ | 5,503 | ​ | ​ | 11,915 | ​
Accretion of asset retirement obligations | ​ | ​ | 1,556 | ​ | ​ | 1,881 | ​
Contract termination, loss contingency and settlements | ​ | ​ | 5,048 | ​ | ​ | 12,288 | ​
Loss (gain) on sale of assets | ​ | ​ | 170 | ​ | ​ | (29) | ​
Other operating expense | ​ | ​ | 28 | ​ | ​ | 49 | ​
Total operating expenses | ​ | ​ | 2,133,272 | ​ | ​ | 2,173,845 | ​
Operating income (loss) | ​ | ​ | (32,347) | ​ | ​ | 476,355 | ​
Other income (expense): | ​ | ​ | ​ | ​ | ​ | ​ | ​
Interest expense, net | ​ | ​ | (62,868) | ​ | ​ | (43,322) | ​
Equity in earnings of unconsolidated affiliate | ​ | ​ | 44,228 | ​ | ​ | 59,224 | ​
Loss on early extinguishment of debt | ​ | ​ | — | ​ | ​ | (3,628) | ​
Total other income (expense) | ​ | ​ | (18,640) | ​ | ​ | 12,274 | ​
Income (loss) before income taxes | ​ | ​ | (50,987) | ​ | ​ | 488,629 | ​
Income tax benefit (expense) | ​ | ​ | 11,061 | ​ | ​ | (102,590) | ​
Net income (loss) and comprehensive income (loss) including noncontrolling interests | ​ | ​ | (39,926) | ​ | ​ | 386,039 | ​
Less: net income and comprehensive income attributable to noncontrolling interests | ​ | ​ | 17,150 | ​ | ​ | 21,483 | ​
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation | ​ | $ | (57,076) | ​ | ​ | 364,556 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net income (loss) per common share—basic | ​ | $ | (0.19) | ​ | ​ | 1.17 | ​
Net income (loss) per common share—diluted | ​ | $ | (0.19) | ​ | ​ | 1.16 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Weighted average number of common shares outstanding: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Basic | ​ | ​ | 307,875 | ​ | ​ | 310,822 | ​
Diluted | ​ | ​ | 307,875 | ​ | ​ | 314,096 | ​

​

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, 2023 | ​ | ​ | 303,544 | ​ | $ | 3,035 | ​ | ​ | 5,846,541 | ​ | ​ | 1,051,940 | ​ | ​ | 232,698 | ​ | ​ | 7,134,214 | ​
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes | ​ | ​ | 552 | ​ | ​ | 6 | ​ | ​ | (9,030) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (9,024) | ​
Conversion of 2026 Convertible Notes | ​ | ​ | 6,074 | ​ | ​ | 61 | ​ | ​ | 25,990 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 26,051 | ​
Equity-based compensation | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 16,077 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 16,077 | ​
Distributions to noncontrolling interests | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (23,617) | ​ | ​ | (23,617) | ​
Net income and comprehensive income | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 22,730 | ​ | ​ | 11,942 | ​ | ​ | 34,672 | ​
Balances, March 31, 2024 | ​ | ​ | 310,170 | ​ | ​ | 3,102 | ​ | ​ | 5,879,578 | ​ | ​ | 1,074,670 | ​ | ​ | 221,023 | ​ | ​ | 7,178,373 | ​
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes | ​ | ​ | 818 | ​ | ​ | 8 | ​ | ​ | (17,339) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (17,331) | ​
Equity-based compensation | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 17,151 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 17,151 | ​
Distributions to noncontrolling interests | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (19,282) | ​ | ​ | (19,282) | ​
Net income (loss) and comprehensive income (loss) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (79,806) | ​ | ​ | 5,208 | ​ | ​ | (74,598) | ​
Balances, June 30, 2024 | ​ | ​ | 310,988 | ​ | $ | 3,110 | ​ | ​ | 5,879,390 | ​ | ​ | 994,864 | ​ | ​ | 206,949 | ​ | ​ | 7,084,313 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
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 | ​

​

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, | ​
​ | ​ | 2024 |  | 2025 |
Cash flows provided by (used in) operating activities: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net income (loss) including noncontrolling interests | ​ | $ | (39,926) | ​ | ​ | 386,039 | ​
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Depletion, depreciation, amortization and accretion | ​ | ​ | 380,664 | ​ | ​ | 375,822 | ​
Impairments | ​ | ​ | 5,503 | ​ | ​ | 11,915 | ​
Commodity derivative fair value losses (gains) | ​ | ​ | (3,861) | ​ | ​ | 18,262 | ​
Gains (losses) on settled commodity derivatives | ​ | ​ | 7,262 | ​ | ​ | (17,371) | ​
Deferred income tax expense (benefit) | ​ | ​ | (11,202) | ​ | ​ | 102,475 | ​
Equity-based compensation expense | ​ | ​ | 33,228 | ​ | ​ | 31,000 | ​
Equity in earnings of unconsolidated affiliate | ​ | ​ | (44,228) | ​ | ​ | (59,224) | ​
Dividends of earnings from unconsolidated affiliate | ​ | ​ | 62,569 | ​ | ​ | 62,628 | ​
Amortization of deferred revenue | ​ | ​ | (13,477) | ​ | ​ | (12,528) | ​
Amortization of debt issuance costs and other | ​ | ​ | 1,328 | ​ | ​ | 823 | ​
Settlement of asset retirement obligations | ​ | ​ | (1,680) | ​ | ​ | (71) | ​
Contract termination, loss contingency and settlements | ​ | ​ | 3,006 | ​ | ​ | 12,001 | ​
Loss (gain) on sale of assets | ​ | ​ | 170 | ​ | ​ | (29) | ​
Loss on early extinguishment of debt | ​ | ​ | — | ​ | ​ | 3,628 | ​
Changes in current assets and liabilities: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Accounts receivable | ​ | ​ | 19,067 | ​ | ​ | 2,763 | ​
Accrued revenue | ​ | ​ | 38,354 | ​ | ​ | 85,718 | ​
Prepaid expenses and other current assets | ​ | ​ | 6,547 | ​ | ​ | (8,382) | ​
Accounts payable including related parties | ​ | ​ | 6,616 | ​ | ​ | (15,139) | ​
Accrued liabilities | ​ | ​ | (14,830) | ​ | ​ | (85,528) | ​
Revenue distributions payable | ​ | ​ | (32,406) | ​ | ​ | 48,121 | ​
Other current liabilities | ​ | ​ | 2,405 | ​ | ​ | 7,174 | ​
Net cash provided by operating activities | ​ | ​ | 405,109 | ​ | ​ | 950,097 | ​
Cash flows provided by (used in) investing activities: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Additions to unproved properties | ​ | ​ | (43,571) | ​ | ​ | (56,640) | ​
Drilling and completion costs | ​ | ​ | (362,228) | ​ | ​ | (356,334) | ​
Additions to other property and equipment | ​ | ​ | (9,035) | ​ | ​ | (1,580) | ​
Proceeds from asset sales | ​ | ​ | 418 | ​ | ​ | 11,522 | ​
Change in other assets | ​ | ​ | 291 | ​ | ​ | (2,348) | ​
Net cash used in investing activities | ​ | ​ | (414,125) | ​ | ​ | (405,380) | ​
Cash flows provided by (used in) financing activities: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Repurchases of common stock | ​ | ​ | — | ​ | ​ | (84,966) | ​
Repayment of senior notes | ​ | ​ | — | ​ | ​ | (141,733) | ​
Borrowings on Credit Facility | ​ | ​ | 1,950,000 | ​ | ​ | 2,291,800 | ​
Repayments on Credit Facility | ​ | ​ | (1,871,200) | ​ | ​ | (2,545,000) | ​
Distributions to noncontrolling interests in Martica Holdings LLC | ​ | ​ | (42,899) | ​ | ​ | (37,481) | ​
Employee tax withholding for settlement of equity-based compensation awards | ​ | ​ | (26,355) | ​ | ​ | (26,618) | ​
Other | ​ | ​ | (530) | ​ | ​ | (719) | ​
Net cash provided by (used in) financing activities | ​ | ​ | 9,016 | ​ | ​ | (544,717) | ​
Net increase in cash and cash equivalents | ​ | ​ | — | ​ | ​ | — | ​
Cash and cash equivalents, beginning of period | ​ | ​ | — | ​ | ​ | — | ​
Cash and cash equivalents, end of period | ​ | $ | — | ​ | ​ | — | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Supplemental disclosure of cash flow information: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Cash paid during the period for interest | ​ | $ | 63,512 | ​ | ​ | 48,043 | ​
Decrease in accounts payable and accrued liabilities for additions to property and equipment | ​ | $ | (2,967) | ​ | ​ | (29,581) | ​

​

See accompanying notes to unaudited condensed consolidated financial statements.

​

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(1) Organization

Antero Resources Corporation (individually referred to as “Antero” and together with its consolidated subsidiaries “Antero Resources,” or the “Company”) is engaged in the development, production, exploration and acquisition of natural gas, NGLs and oil properties in the Appalachian Basin in West Virginia and Ohio. The Company targets large, repeatable resource plays where horizontal drilling and advanced fracture stimulation technologies provide the means to economically develop and produce natural gas, NGLs and oil from unconventional formations. The Company’s corporate headquarters is located in Denver, Colorado.

​

(2) Summary of Significant Accounting Policies

(a) | Basis of Presentation

These unaudited condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC applicable to interim financial information and should be read in the context of the Company’s December 31, 2024 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, 2024 consolidated financial statements were included in Antero Resources’ 2024 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, 2024 and June 30, 2025, results of operations for the three and six months ended June 30, 2024 and 2025 and cash flows for the six months ended June 30, 2024 and 2025. The Company has no items of other comprehensive income or loss; therefore, its net income or loss is equal to its comprehensive income or loss. Operating results for the three and six months ended June 30, 2025 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.

In the course of preparing our consolidated financial statements for the year ended December 31, 2024, the Company identified an error in the quarterly calculations related to depletion expense of the Company’s proved oil and gas properties. See Note 17—Immaterial Correction of Prior Period Error to the unaudited condensed consolidated financial statements for additional information.

(b) | Principles of Consolidation

The accompanying unaudited condensed consolidated financial statements include the accounts of Antero Resources Corporation, its wholly owned subsidiaries and its variable interest entity (“VIE”), Martica Holdings LLC, (“Martica”), for which the Company is the primary beneficiary. All significant intercompany accounts and transactions have been eliminated in the Company’s unaudited condensed consolidated financial statements.

(c) | Cash and Cash Equivalents

The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments. From time to time, the Company may be in the position of a “book overdraft” in which outstanding checks exceed cash and cash equivalents. The Company classifies book overdrafts in accounts payable and revenue distributions payable within its condensed consolidated balance sheets, and classifies the change in accounts payable associated with book overdrafts as an operating activity within its unaudited condensed consolidated statements of cash flows. As of December 31, 2024, the book overdrafts included within accounts payable and revenue distributions payable were $14 million and $17 million, respectively. As of June 30, 2025, the book overdrafts included within accounts payable and revenue distributions payable were $4 million and $23 million, respectively.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(d) | Net Income (Loss) Per Common Share

Net income (loss) 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 (loss) per common share—diluted for each period is computed after giving consideration to the potential dilution from (i) outstanding equity-based awards using the treasury stock method and (ii) shares of common stock issuable upon conversion of the 2026 Convertible Notes (as defined below in Note 7—Long-Term Debt) using the if-converted method. The Company includes restricted stock unit (“RSU”) awards, performance share unit (“PSU”) awards and stock options in the calculation of diluted weighted average common shares outstanding based on the number of common shares that would be issuable if the end of the period was also the end of the performance period required for the vesting of the awards. During periods in which the Company incurs a net loss, diluted weighted average common shares outstanding are equal to basic weighted average common shares outstanding because the effects of all equity-based awards and the 2026 Convertible Notes are anti-dilutive.

​

The following is a reconciliation of the Company’s 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, | ​
​ |  | 2024 |  | 2025 |  | 2024 |  | 2025 |
Basic weighted average number of common shares outstanding | ​ | 310,806 | ​ | 310,323 | ​ | 307,875 | ​ | 310,822 | ​
Add: Dilutive effect of RSUs | ​ | — | ​ | 911 | ​ | — | ​ | 1,305 | ​
Add: Dilutive effect of PSUs | ​ | — | ​ | 1,950 | ​ | — | ​ | 1,969 | ​
Diluted weighted average number of common shares outstanding | ​ | 310,806 | ​ | 313,184 | ​ | 307,875 | ​ | 314,096 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Weighted average number of outstanding securities excluded from calculation of diluted net income (loss) per common share (1): | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
RSUs | ​ | 3,537 | ​ | — | ​ | 3,654 | ​ | — | ​
PSUs | ​ | 2,010 | ​ | — | ​ | 2,032 | ​ | — | ​
Stock options | ​ | 259 | ​ | 42 | ​ | 259 | ​ | 146 | ​
2026 Convertible Notes | ​ | — | ​ | — | ​ | 2,432 | ​ | — | ​

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

(e) | Income Taxes

On July 4, 2025, Public Law No. 119-21, commonly referred to as the One Big Beautiful Bill Act (the “OBBB”), was enacted. The OBBB contains a broad range of changes to U.S. federal income tax laws and makes permanent or modifies certain provisions of Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act. These changes include, among others, permanently restoring an EBITDA-based business interest deduction limitation, 100% bonus depreciation for certain property and immediate expensing for certain domestic research and experimental expenditures. All effects of changes in tax laws are recognized in the condensed consolidated financial statements during the period of enactment. As such, the effects of the OBBB are not reflected in the Company's provision for income taxes as of and for the three and six months ended June 30, 2025. The Company is evaluating the impact of the OBBB on its condensed consolidated financial statements.

(f) | Recently Adopted or Issued Accounting Standards

Reportable Segments

​

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

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

after December 15, 2024. The Company adopted ASU 2023-07 in the 2024 Form 10-K for the year ended December 31, 2024, and it did not have a material impact on the Company’s consolidated financial statements.

​

Income Taxes

​

In December 2023, the FASB issued ASU No. 2023-09, Improvements to Income Tax Disclosures (“ASU 2023-09”). ASU 2023-09 is intended to improve income tax disclosures primarily through enhanced disclosure of income tax rate reconciliation items, and disaggregation of income (loss) from continuing operations, income tax (expense) benefit and income taxes paid, net disclosures by federal, state and foreign jurisdictions, among others. This ASU is effective for annual reporting periods beginning after December 15, 2024, although early adoption is permitted. ASU 2023-09 should be applied on a prospective basis, although retrospective application is permitted. The Company is evaluating the impact that ASU 2023-09 will have on the consolidated financial statements and the transition method it plans to use for adoption. The Company plans to adopt ASU 2023-09 in the Annual Report on Form 10-K for the year ending December 31, 2025.

​

Disaggregation of Income Statement Expenses

​

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.

​

​

(3) Transactions

(a) | 2021-2024 Drilling Partnership

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

Under the terms of the arrangement, QL funded development capital of 20% for wells spud in 2021 and 2024 and 15% for wells spud in 2022 and 2023, which funding amounts represent QL’s proportionate working interest in such wells. Additionally, the Company may receive a carry in the form of a one-time payment from QL for each annual tranche if the IRR for such tranche exceeds certain specified returns, which will be determined no earlier than October 31 and no later than December 1 following the end of each tranche year. The Company received a carry of $29 million for each of the 2021 and 2022 tranches during the years ended December 31, 2022 and 2023 and a carry of $32 million for the 2023 tranche during the year ended December 31, 2024. Capital costs in excess of, and cost savings below, a specified percentage of budgeted amounts for each annual tranche will be for the Company’s account. Subject to the preceding sentence, for any wells included in a tranche, QL is obligated and responsible for its working interest share of costs and liabilities, and is entitled to its working interest share of revenues, associated with such wells for the life of such wells.

The Company has accounted for the 2021-2024 Drilling Partnership as a conveyance under FASB Accounting Standards Codification (“ASC”) Topic 932, Extractive Activities—Oil and Gas, (“ASC 932”) and such conveyances are recorded in the unaudited condensed consolidated financial statements as QL obtains its proportionate working interest in each well. No gain or loss was recognized for any of the interests conveyed to QL during the term of the 2021-2024 Drilling Partnership.

​

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(b) | 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 three and six months ended June 30, 2025.

​

(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, | ​ | ​
​ |  | 2024 |  | 2025 | ​ | 2024 | ​ | 2025 |  | Reportable Segment
Revenues from contracts with customers: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Natural gas sales | ​ | $ | 374,568 | ​ | ​ | 688,753 | ​ | ​ | 848,701 | ​ | ​ | 1,468,758 | ​ | Exploration and production
Natural gas liquids sales (ethane) | ​ | ​ | 65,764 | ​ | ​ | 78,546 | ​ | ​ | 128,794 | ​ | ​ | 173,026 | ​ | Exploration and production
Natural gas liquids sales (C3+ NGLs) | ​ | ​ | 423,427 | ​ | ​ | 402,211 | ​ | ​ | 878,259 | ​ | ​ | 869,163 | ​ | Exploration and production
Oil sales | ​ | ​ | 63,458 | ​ | ​ | 33,700 | ​ | ​ | 128,175 | ​ | ​ | 84,035 | ​ | Exploration and production
Marketing | ​ | ​ | 49,418 | ​ | ​ | 33,743 | ​ | ​ | 97,938 | ​ | ​ | 59,301 | ​ | Marketing
Other revenue | ​ | ​ | 273 | ​ | ​ | 273 | ​ | ​ | 546 | ​ | ​ | 543 | ​ | Exploration and production
Total revenue from contracts with customers | ​ | ​ | 976,908 | ​ | ​ | 1,237,226 | ​ | ​ | 2,082,413 | ​ | ​ | 2,654,826 | ​ | ​
Income (loss) from derivatives, deferred revenue and other sources, net | ​ | ​ | 1,746 | ​ | ​ | 60,267 | ​ | ​ | 18,512 | ​ | ​ | (4,626) | ​ | ​
Total revenue | ​ | $ | 978,654 | ​ | ​ | 1,297,493 | ​ | ​ | 2,100,925 | ​ | ​ | 2,650,200 | ​ | ​

​

(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, 2024 and June 30, 2025, the Company’s receivables from contracts with customers were $454 million and $368 million, respectively.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(5) Equity Method Investment

As of December 31, 2024 and June 30, 2025, 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, 2024 (1) | ​ | $ | 231,048 | ​
Equity in earnings of unconsolidated affiliate | ​ | ​ | 59,224 | ​
Dividends from unconsolidated affiliate | ​ | ​ | (62,628) | ​
Elimination of intercompany profit | ​ | ​ | 21,519 | ​
Balance as of June 30, 2025 (1) | ​ | $ | 249,163 | ​

(1) | The fair value of the Company’s investment in Antero Midstream as of December 31, 2024 and June 30, 2025 was $2.1 billion and $2.6 billion, respectively, based on the quoted market share price of Antero Midstream.

​

​

(6) Accrued Liabilities

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

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | (Unaudited) | ​
​ | ​ | December 31, | ​ | June 30, | ​
​ |  | 2024 |  | 2025 | ​
Capital expenditures | ​ | $ | 42,474 |  | ​ | 32,601 | ​
Gathering, compression, processing and transportation expenses | ​ | ​ | 167,915 | ​ | ​ | 152,059 | ​
Marketing expenses | ​ | ​ | 16,891 | ​ | ​ | 19,284 | ​
Interest expense, net | ​ |  | 29,014 |  | ​ | 23,627 | ​
Production and ad valorem taxes | ​ | ​ | 78,980 | ​ | ​ | 16,973 | ​
General and administrative expense | ​ | ​ | 37,516 | ​ | ​ | 26,310 | ​
Derivative settlements payable | ​ | ​ | 1,597 | ​ | ​ | 845 | ​
Other | ​ |  | 28,204 |  | ​ | 41,133 | ​
Total accrued liabilities | ​ | $ | 402,591 |  | ​ | 312,832 | ​

​

​

​

(7) Long-Term Debt

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

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | (Unaudited) | ​
​ | ​ | December 31, | ​ | June 30, | ​
​ |  | 2024 |  | 2025 | ​
Credit Facility (a) | ​ | $ | 393,200 | ​ | ​ | 140,000 | ​
8.375% senior notes due 2026 (b) | ​ | ​ | 96,870 | ​ | ​ | — | ​
7.625% senior notes due 2029 (c) | ​ | ​ | 407,115 | ​ | ​ | 365,353 | ​
5.375% senior notes due 2030 (d) | ​ | ​ | 600,000 | ​ | ​ | 600,000 | ​
Total principal | ​ | ​ | 1,497,185 | ​ | ​ | 1,105,353 | ​
Unamortized debt issuance costs | ​ | ​ | (7,955) | ​ | ​ | (6,684) | ​
Long-term debt | ​ | $ | 1,489,230 | ​ | ​ | 1,098,669 | ​

​

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(a) | Credit Facility

Antero Resources has a senior revolving credit facility with a syndicate of bank lenders. References to the (i) “Secured Credit Facility” (defined below) refer to the credit facility in effect for periods prior to July 30, 2024, (ii) “Unsecured Credit Facility” (defined below) refer to the credit facility in effect on or after July 30, 2024 and (iii) “Credit Facility” refer to the Secured Credit Facility and Unsecured Credit Facility, collectively.

Senior Unsecured Revolving 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 (“Unsecured Credit Facility”). Borrowings are unsecured and are not guaranteed by any of Antero Resources’ subsidiaries. As of June 30, 2025, the Unsecured Credit Facility had lender commitments of $1.65 billion and available borrowing capacity of $1.5 billion. The Unsecured Credit Facility was originally scheduled to mature on July 30, 2029 (the “Maturity Date”), provided that Antero Resources may request two one-year extensions of the Maturity Date, subject to satisfaction of certain conditions and consent of the extending lenders. Effective July 30, 2025, Antero Resources obtained the consent of each of the lenders party to the Unsecured Credit Facility to extend the Maturity Date to July 30, 2030. Commitments under the Unsecured 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 Unsecured Credit Facility and the lenders with commitments to issue letters of credit under the Unsecured Credit Facility.

The Unsecured 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 Unsecured Credit Facility as of June 30, 2025.

The Unsecured 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 Unsecured Credit Facility). There is a 0.10% credit adjustment spread on SOFR and a 0.00% floor. The Unsecured Credit Facility does not amortize. Interest under the Unsecured 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 Unsecured 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 Unsecured 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, 2024, Antero Resources had an outstanding balance under the Unsecured Credit Facility of $393 million, with a weighted average interest rate of 5.9%, and outstanding letters of credit of $13 million. As of June 30, 2025, Antero Resources had an outstanding balance under the Unsecured Credit Facility of $140 million, with a weighted average interest rate of 5.9%, and outstanding letters of credit of $13 million.

Senior Secured Revolving Credit Facility

​

On October 26, 2021, Antero Resources entered into an amended and restated senior secured revolving credit facility with a syndicate of bank lenders (“Secured Credit Facility”). Borrowings were secured by substantially all of the assets of Antero Resources and certain of its subsidiaries, were subject to borrowing base limitations based on the collateral value of Antero Resources’ assets and were subject to regular semi-annual redeterminations. The Secured Credit Facility was refinanced in full and terminated upon the closing of the Unsecured Credit Facility on July 30, 2024.

​

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

The Secured Credit Facility provided for borrowing at either an Adjusted Term SOFR, an Adjusted Daily Simple SOFR or an Alternate Base Rate, in each case, plus an Applicable Margin (each as defined in the Secured Credit Facility). The Secured Credit Facility provided for interest only payments until maturity at which time all outstanding borrowings would be due. Interest was payable at a variable rate based on SOFR or the Alternate Base Rate, determined by election at the time of borrowing, plus an Applicable Margin under the Secured Credit Facility. The Applicable Margin was determined with reference to Antero Resources’ then-current leverage ratio subject to certain exceptions, which for SOFR loans ranged from 1.75% to 2.75% during a non-investment grade period (based on utilization of the Secured Credit Facility) and 1.25% and 1.875% during an investment grade period (based on a ratings grid). Commitment fees on the unused portion of the Secured Credit Facility were due quarterly at rates ranging from 0.375% to 0.500% with respect to the Secured Credit Facility, determined with reference to borrowing base utilization, subject to certain exceptions based on the leverage ratio then in effect. The Secured Credit Facility included fall away covenants, lower interest rates and reduced collateral requirements that Antero Resources could elect if Antero Resources was assigned an Investment Grade Rating (as defined in the Secured Credit Facility).

​

(b) | 8.375% Senior Notes Due 2026

On January 4, 2021, Antero Resources issued $500 million of 8.375% senior notes due July 15, 2026 (the “2026 Notes”) at par. The Company redeemed $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.

(c) | 7.625% Senior Notes Due 2029

On January 26, 2021, Antero Resources issued $700 million of 7.625% senior notes due February 1, 2029 (the “2029 Notes”) at par. The Company redeemed or otherwise repurchased $293 million principal amount of the 2029 Notes during 2021 and 2022. During the six months ended June 30, 2025, the Company repurchased $42 million principal amount of the 2029 Notes through open market transactions at a weighted average price of 102.569% of the principal amount thereof, plus accrued and unpaid interest. As of June 30, 2025, $365 million principal amount of the 2029 Notes remained outstanding. The 2029 Notes are unsecured and rank pari passu to Antero Resources’ Unsecured Credit Facility and other outstanding senior notes. As of July 30, 2024, the 2029 Notes are not guaranteed by any of Antero Resources’ subsidiaries. Interest on the 2029 Notes is payable on February 1 and August 1 of each year. Antero Resources may redeem all or part of the 2029 Notes at any time at redemption prices ranging from 102.542% as of June 30, 2025 to 100.00% on or after February 1, 2027. If Antero Resources undergoes a change of control followed by a rating decline, the holders of the 2029 Notes will have the right to require Antero Resources to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the 2029 Notes, plus accrued and unpaid interest.

​

(d) | 5.375% Senior Notes Due 2030

On June 1, 2021, Antero Resources issued $600 million of 5.375% senior notes due March 1, 2030 (the “2030 Notes”) at par. The 2030 Notes are unsecured and rank pari passu to Antero Resources’ Unsecured Credit Facility 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 102.688% as of June 30, 2025 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.

​

(e) | 4.25% Convertible Senior Notes Due 2026

On August 21, 2020, Antero Resources issued $250 million in aggregate principal amount of 4.25% convertible senior notes due September 1, 2026 (the “2026 Convertible Notes”). On September 2, 2020, Antero Resources issued an additional $37.5 million of the 2026 Convertible Notes. Proceeds from the issuance of the 2026 Convertible Notes totaled $278.5 million, net of initial purchasers’ fees and issuance cost of $9 million. Transaction costs related to the 2026 Convertible Notes were recorded within debt issuance costs on the condensed consolidated balance sheet and were amortized over the term of the 2026 Convertible Notes using the effective interest method.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

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

The 2026 Convertible Notes bore interest at a fixed rate of 4.25% per annum, payable semi-annually in arrears on March 1 and September 1 of each year, commencing on March 1, 2021. The initial conversion rate was 230.2026 shares of Antero Resources’ common stock per $1,000 principal amount of 2026 Convertible Notes, and such conversion rate was not adjusted during the term for which the 2026 Convertible Notes were outstanding. The noteholders had the right to convert their 2026 Convertible Notes only upon the occurrence of certain events pursuant to the terms and conditions provided in the indenture governing the 2026 Convertible Notes. Upon conversion, Antero Resources could satisfy its conversion obligation by paying and/or delivering, as the case may be, cash, shares of Antero Resources’ common stock or a combination of cash and shares of Antero Resources’ common stock, at Antero Resources’ election, in the manner and subject to the terms and conditions provided in the indenture governing the 2026 Convertible Notes.

Conversions

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

(8) Asset Retirement Obligations

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

​ | ​ | ​ | ​ | ​
Asset retirement obligations—December 31, 2024 |  | $ | 62,001 | ​
Obligations incurred | ​ | ​ | 313 | ​
Accretion expense | ​ | ​ | 1,881 | ​
Settlement of obligations | ​ | ​ | (71) | ​
Revisions to prior estimates | ​ | ​ | 80 | ​
Asset retirement obligations—June 30, 2025 | ​ | $ | 64,204 | ​

​

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 10,326,506 shares were available for future grant under the AR LTIP as of June 30, 2025.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

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

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Three Months Ended June 30, | ​ | Six Months Ended June 30, | ​
​ |  | 2024 | ​ | 2025 |  | 2024 | ​ | 2025 | ​
RSU awards | ​ | $ | 11,148 | ​ | ​ | 10,669 | ​ | ​ | 20,409 | ​ | ​ | 22,138 | ​
PSU awards | ​ | ​ | 5,627 | ​ | ​ | 4,756 | ​ | ​ | 12,067 | ​ | ​ | 8,019 | ​
Equity awards issued to directors | ​ | ​ | 376 | ​ | ​ | 430 | ​ | ​ | 752 | ​ | ​ | 843 | ​
Total expense | ​ | $ | 17,151 | ​ | ​ | 15,855 | ​ | ​ | 33,228 | ​ | ​ | 31,000 | ​

​

(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, 2024 | ​ | 3,035,362 | ​ | $ | 26.05 | ​
Granted | ​ | 1,115,463 | ​ | ​ | 33.66 | ​
Vested | ​ | (1,482,499) | ​ | ​ | 24.55 | ​
Forfeited | ​ | (97,401) | ​ | ​ | 29.81 | ​
Total awarded and unvested—June 30, 2025 | ​ | 2,570,925 | ​ | $ | 30.07 | ​

​

As of June 30, 2025, there was $62 million of unamortized equity-based compensation expense related to unvested RSUs. That expense is expected to be recognized over a weighted average period of 2.0 years.

(b) | Performance Share Unit Awards

Performance Share Unit Awards Based on Total Shareholder Return

In April 2022, the Company granted PSU awards to certain of its senior management and executive officers that vest based on Antero Resources’ absolute total shareholder return (“TSR”) determined as of the last day of each of three one-year performance periods ending on April 15, 2023, April 15, 2024 and April 15, 2025, and one cumulative three-year performance period ending on April 15, 2025, in each case, subject to certain continued employment criteria (“2022 Absolute TSR PSUs”). The number of shares of common stock that could ultimately be earned following the end of the cumulative three-year performance period with respect to the 2022 Absolute TSR PSUs ranged from zero to 200% of the target number of 2022 Absolute TSR PSUs originally granted. The performance conditions for the performance periods ended April 15, 2023, 2024 and 2025 were met cumulatively at 110% of target. During the second quarter of 2025, the 2022 Absolute TSR PSUs vested and converted into approximately 0.2 million shares of common stock.

In March 2025, 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, 2026, March 7, 2027 and March 7, 2028, and one cumulative three-year performance period ending on March 7, 2028, in each case, subject to certain continued employment criteria for each performance period (“2025 Absolute TSR PSUs”). The 2025 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 2025 Absolute TSR PSUs ranges from zero to 200% of the target number of 2025 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 2025 Absolute TSR PSUs:

​ | ​ | ​ | ​ | ​ | ​
Dividend yield | ​ | ​ | — | % | ​
Volatility | ​ | ​ | 48 | % | ​
Risk-free interest rate | ​ | ​ | 3.97 | % | ​
Weighted average fair value of awards granted | ​ | $ | 35.01 | ​ | ​

​

16

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

Performance Share Unit Awards Based on Leverage Ratio

In April 2022, the Company granted PSUs to certain of its senior management and executive officers that vest based on the Company’s total debt less cash and cash equivalents divided by the Company’s Adjusted EBITDAX (as defined in the award agreement) (“Net Debt to EBITDAX”) determined as of the last day of each of three one-year performance periods ended on December 31, 2022, December 31, 2023, and December 31, 2024, in each case, subject to certain continued employment criteria (“2022 Leverage Ratio PSUs”). The number of shares of common stock that could ultimately be earned ranged from zero to 200% of the target number of PSUs granted. The performance conditions for the performance periods ended December 31, 2022, 2023 and 2024 were met cumulatively at 194% of target. During the first quarter of 2025, the 2022 Leverage Ratio PSUs vested and converted into approximately 0.3 million shares of common stock.

In March 2025, 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, 2025, December 31, 2026 and December 31, 2027, in each case, subject to certain continued employment criteria for each performance period (“2025 Leverage Ratio PSUs”). The 2025 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 2025 Leverage Ratio PSUs ranges from zero to 200% of the target number of 2025 Leverage Ratio PSUs originally granted. Expense related to the 2025 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, 2025, the likelihood of achieving the performance conditions related to the 2025 Leverage Ratio PSUs was probable.

Summary Information for Performance Share Unit Awards

A summary of PSU activity is as follows:

​

​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | Weighted | ​
​ | ​ | ​ | ​ | Average | ​
​ | ​ | Number | ​ | Grant Date | ​
​ |  | of Units |  | Fair Value |
Total awarded and unvested—December 31, 2024 | ​ | 1,351,295 | ​ | $ | 35.27 | ​
Granted | ​ | 289,370 | ​ | ​ | 34.33 | ​
Vested | ​ | (281,318) | ​ | ​ | 41.41 | ​
Total awarded and unvested—June 30, 2025 | ​ | 1,359,347 | ​ | $ | 33.80 | ​

​

As of June 30, 2025, there was $19 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.

(c) | Stock Options

A summary of the stock option activity is as follows:

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | Weighted | ​ | ​ | ​
​ | ​ | ​ | ​ | Weighted | ​ | Average | ​ | ​ | ​
​ | ​ | ​ | ​ | Average | ​ | Remaining | ​ | Intrinsic | ​
​ | ​ | Number | ​ | Exercise | ​ | Contractual | ​ | Value | ​
​ |  | of Options |  | Price |  | Life |  | (in thousands) (1) | ​
Outstanding—December 31, 2024 | ​ | 252,451 | ​ | $ | 50.00 | ​ | 0.3 | ​ | $ | — | ​
Expired | ​ | (252,451) | ​ | ​ | 50.00 | ​ | — | ​ | ​ | — | ​
Outstanding—June 30, 2025 | ​ | — | ​ | $ | — | ​ | — | ​ | ​ | — | ​
Vested—June 30, 2025 | ​ | — | ​ | $ | — | ​ | — | ​ | $ | — | ​
Exercisable—June 30, 2025 | ​ | — | ​ | $ | — | ​ | — | ​ | $ | — | ​

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

​

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(10) Fair Value

The carrying values of accounts receivable and accounts payable as of December 31, 2024 and June 30, 2025 approximated market values because of their short-term nature. The carrying values of the amounts outstanding under the Credit Facility as of December 31, 2024 and June 30, 2025 approximated fair value because the variable interest rates are reflective of current market conditions.

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

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (Unaudited) | ​
​ | ​ | December 31, 2024 | ​ | June 30, 2025 | ​
​ |  | Fair |  | Carrying |  | Fair |  | Carrying | ​
​ | ​ | Value (1) | ​ | Value (2) | ​ | Value (1) | ​ | Value (2) | ​
2026 Notes | ​ | $ | 98,924 | ​ | ​ | 96,599 | ​ | ​ | — | ​ | ​ | — | ​
2029 Notes | ​ | ​ | 417,211 | ​ | ​ | 404,055 | ​ | ​ | 373,573 | ​ | ​ | 362,901 | ​
2030 Notes | ​ | ​ | 579,660 | ​ | ​ | 595,376 | ​ | ​ | 603,900 | ​ | ​ | 595,768 | ​
Total | ​ | $ | 1,095,795 | ​ | ​ | 1,096,030 | ​ | ​ | 977,473 | ​ | ​ | 958,669 | ​

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

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

See Note 9—Equity-Based Compensation 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.

​

(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, 2024 and 2025. The Company enters derivative contracts when management believes that favorable future sales prices for the Company’s production can be secured. Under the Company’s swap agreements, when actual commodity prices upon settlement exceed the fixed price provided by the swap contracts, the Company pays the difference to the counterparty. When actual commodity prices upon settlement are less than the contractually provided fixed price, the Company receives the difference from the counterparty. 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.

The Company’s derivative contracts have not been designated as hedges for accounting purposes; therefore, all gains and losses are recognized in the Company’s statements of operations and comprehensive income (loss).

​

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

As of June 30, 2025, the Company’s fixed price swap positions excluding Martica, the Company’s consolidated VIE, were as follows:

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | Weighted | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | Average | ​
Commodity / Settlement Period |  | Index |  | Contracted Volume |  | Price |
Natural Gas | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
July-December 2025 | ​ | Henry Hub | ​ | 100,000 | MMBtu/day | ​ | $ | 3.12 | /MMBtu | ​

​

As of June 30, 2025, the Company’s collar contract positions excluding Martica, the Company’s consolidated VIE, were as follows:

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | Weighted | ​ | Weighted | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | Average | ​ | Average | ​
Commodity / Settlement Period |  | Index |  | Contracted Volume |  | Ceiling Price |  | Floor Price | ​
Natural Gas | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
January-December 2026 | ​ | Henry Hub | ​ | 500,000 | MMBtu/day | ​ | $ | 6.31 | /MMBtu | ​ | $ | 3.14 | /MMBtu | ​

​

The Company has a call option and an embedded put option tied to NYMEX pricing for the production volumes associated with the Company’s retained interest in the volumetric production payment transaction (“VPP”) properties. The put option was embedded within another contract, and since the embedded put option was not clearly and closely related to its host contract, the Company bifurcated this derivative instrument and reflects it at fair value in the unaudited condensed consolidated financial statements. As of June 30, 2025, the Company’s call option and embedded put option arrangements were as follows:

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Embedded | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | Call Option | ​ | Put Option | ​
Commodity / Settlement Period |  | Index |  | Contracted Volume |  | Strike Price |  | Strike Price |
Natural Gas | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
July-December 2025 | ​ | Henry Hub | ​ | 44,000 | MMBtu/day | ​ | $ | 2.564 | /MMBtu | ​ | $ | 2.564 | /MMBtu | ​
January-December 2026 | ​ | Henry Hub | ​ | 32,000 | MMBtu/day | ​ | ​ | 2.629 | /MMBtu | ​ | ​ | 2.629 | /MMBtu | ​

​

During the three months ended March 31, 2025, all of Martica’s derivative contracts expired, and as a result, Martica had no derivative instruments as of March 31, 2025 or June 30, 2025.

​

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(b) | Summary

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

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | (Unaudited) | ​
​ | ​ | ​ | ​ | December 31, | ​ | June 30, | ​
​ |  | Balance Sheet Location |  | 2024 | ​ | 2025 | ​
Asset derivatives not designated as hedges for accounting purposes: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Commodity derivatives—current | ​ | Derivative instruments | ​ | $ | — | ​ | ​ | 387 | ​
Embedded derivatives—current | ​ | Derivative instruments | ​ | ​ | 1,050 | ​ | ​ | 750 | ​
Commodity derivatives—noncurrent | ​ | Derivative instruments | ​ | ​ | — | ​ | ​ | 371 | ​
Embedded derivatives—noncurrent | ​ | Derivative instruments | ​ | ​ | 1,296 | ​ | ​ | 576 | ​
Total asset derivatives (1) | ​ | ​ | ​ | ​ | 2,346 | ​ | ​ | 2,084 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Liability derivatives not designated as hedges for accounting purposes: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Commodity derivatives—current (2) | ​ | Derivative instruments | ​ | ​ | 31,792 | ​ | ​ | 34,019 | ​
Commodity derivatives—noncurrent | ​ | Derivative instruments | ​ | ​ | 17,233 | ​ | ​ | 15,635 | ​
Total liability derivatives (1) | ​ | ​ | ​ | ​ | 49,025 | ​ | ​ | 49,654 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net derivatives liability (1) | ​ | ​ | ​ | $ | (46,679) | ​ | ​ | (47,570) | ​

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

(2) | As of December 31, 2024, $2 million of current commodity derivative liabilities are attributable to the Company’s consolidated VIE, Martica.

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

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (Unaudited) | ​
​ | ​ | December 31, 2024 | ​ | June 30, 2025 | ​
​ | ​ | ​ | ​ | ​ | ​ | Net Amounts of | ​ | ​ | ​ | ​ | ​ | Net Amounts of | ​
​ | ​ | Gross | ​ | Gross | ​ | Assets | ​ | Gross | ​ | Gross | ​ | Assets | ​
​ | ​ | Amounts | ​ | Amounts Offset | ​ | (Liabilities) on | ​ | Amounts | ​ | Amounts Offset | ​ | (Liabilities) on | ​
​ |  | Recognized |  | Recognized |  | Balance Sheet |  | Recognized |  | Recognized |  | Balance Sheet | ​
Commodity derivative assets | ​ | $ | 3,482 | ​ | ​ | (3,482) | ​ | ​ | — | ​ | ​ | 36,917 | ​ | ​ | (36,159) | ​ | ​ | 758 | ​
Embedded derivative assets | ​ | ​ | 2,346 | ​ | ​ | — | ​ | ​ | 2,346 | ​ | ​ | 1,326 | ​ | ​ | — | ​ | ​ | 1,326 | ​
Commodity derivative liabilities | ​ | ​ | (52,507) | ​ | ​ | 3,482 | ​ | ​ | (49,025) | ​ | ​ | (85,813) | ​ | ​ | 36,159 | ​ | ​ | (49,654) | ​

​

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 (loss) (in thousands):

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Statement of | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Operations | ​ | Three Months Ended June 30, | ​ | Six Months Ended June 30, | ​
​ |  | Location | ​ | 2024 | ​ | 2025 | ​ | 2024 | ​ | 2025 | ​
Commodity derivative fair value gains (losses) (1) | ​ | Revenue | ​ | $ | (3,545) | ​ | ​ | 53,220 | ​ | ​ | 4,721 | ​ | ​ | (17,241) | ​
Embedded derivative fair value gains (losses) (1) | ​ | Revenue | ​ | ​ | (2,040) | ​ | ​ | 189 | ​ | ​ | (860) | ​ | ​ | (1,021) | ​

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

​

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

​

(12) Leases

The Company leases certain office space, processing plants, drilling rigs and completion services, gas gathering lines, compressor stations, and other office and field equipment. Leases with an initial term of 12 months or less are considered short-term and are not recorded on the balance sheet. Instead, the short-term leases are recognized in expense on a straight-line basis over the lease term.

Most leases include one or more options to renew, with renewal terms that can extend the lease from one to 20 years or more. The exercise of the lease renewal options is at the Company’s sole discretion. The depreciable lives of the leased assets are limited by the expected lease term, unless there is a transfer of title or purchase option reasonably certain of exercise.

Certain of the Company’s lease agreements include minimum payments based on a percentage of produced volumes over contractual levels and others include rental payments adjusted periodically for inflation.

The Company considers all contracts that have assets specified in the contract, either explicitly or implicitly, that the Company has substantially all of the capacity of the asset, and has the right to obtain substantially all of the economic benefits of that asset, without the lessor’s ability to have a substantive right to substitute that asset, as leased assets. For any contract deemed to include a leased asset, that asset is capitalized on the 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 |  | 2024 |  | 2025 | ​
Operating Leases | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Operating lease right-of-use assets: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Processing plants | ​ | Operating lease right-of-use assets | ​ | $ | 1,365,582 | ​ | ​ | 1,247,535 | ​
Drilling rigs and completion services | ​ | Operating lease right-of-use assets | ​ | ​ | — | ​ | ​ | 26,306 | ​
Gas gathering lines and compressor stations (1) | ​ | Operating lease right-of-use assets | ​ | ​ | 1,149,981 | ​ | ​ | 1,089,807 | ​
Office space | ​ | Operating lease right-of-use assets | ​ | ​ | 33,345 | ​ | ​ | 30,955 | ​
Office, field and other equipment | ​ | Operating lease right-of-use assets | ​ | ​ | 490 | ​ | ​ | 2,451 | ​
Total operating lease right-of-use assets | ​ | ​ | ​ | $ | 2,549,398 | ​ | ​ | 2,397,054 | ​
Operating lease liabilities: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Short-term operating lease liabilities | ​ | Short-term lease liabilities | ​ | $ | 492,624 | ​ | ​ | 512,654 | ​
Long-term operating lease liabilities | ​ | Long-term lease liabilities | ​ | ​ | 2,048,942 | ​ | ​ | 1,876,660 | ​
Total operating lease liabilities | ​ | ​ | ​ | $ | 2,541,566 | ​ | ​ | 2,389,314 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Finance Leases | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Finance lease right-of-use assets: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Vehicles | ​ | Other property and equipment | ​ | $ | 2,665 | ​ | ​ | 3,695 | ​
Total finance lease right-of-use assets (2) | ​ | ​ | ​ | $ | 2,665 | ​ | ​ | 3,695 | ​
Finance lease liabilities: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Short-term finance lease liabilities | ​ | Short-term lease liabilities | ​ | $ | 1,270 | ​ | ​ | 1,638 | ​
Long-term finance lease liabilities | ​ | Long-term lease liabilities | ​ | ​ | 1,395 | ​ | ​ | 2,058 | ​
Total finance lease liabilities | ​ | ​ | ​ | $ | 2,665 | ​ | ​ | 3,696 | ​

(1) | Gas gathering lines and compressor stations includes $1.1 billion related to Antero Midstream as of December 31, 2024 and June 30, 2025. See “—‍Related party lease disclosure” for additional discussion.

(2) | Financing lease assets are recorded net of accumulated amortization of $3 million as of December 31, 2024 and June 30, 2025.

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 (loss) (in thousands):

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | Three Months Ended June 30, | ​ | Six Months Ended June 30, | ​
Cost |  | Classification |  | Location |  | 2024 |  | 2025 |  | 2024 |  | 2025 | ​
Operating lease cost | ​ | Statement of operations | ​ | Gathering, compression, processing and transportation | ​ | $ | 425,926 | ​ | ​ | 406,240 | ​ | ​ | 847,994 | ​ | ​ | 801,361 | ​
Operating lease cost | ​ | Statement of operations | ​ | General and administrative | ​ | ​ | 2,986 | ​ | ​ | 3,318 | ​ | ​ | 6,069 | ​ | ​ | 6,459 | ​
Operating lease cost | ​ | Statement of operations | ​ | Lease operating | ​ | ​ | 27 | ​ | ​ | 302 | ​ | ​ | 48 | ​ | ​ | 527 | ​
Operating lease cost | ​ | Balance sheet | ​ | Proved properties (1) | ​ | ​ | 28,714 | ​ | ​ | 6,267 | ​ | ​ | 62,126 | ​ | ​ | 13,666 | ​
Total operating lease cost | ​ | ​ | ​ | ​ | ​ | $ | 457,653 | ​ | ​ | 416,127 | ​ | ​ | 916,237 | ​ | ​ | 822,013 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Finance lease cost: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Amortization of right-of-use assets | ​ | Statement of operations | ​ | Depletion, depreciation and amortization | ​ | $ | 418 | ​ | ​ | 422 | ​ | ​ | 848 | ​ | ​ | 831 | ​
Interest on lease liabilities | ​ | Statement of operations | ​ | Interest expense | ​ | ​ | 137 | ​ | ​ | 127 | ​ | ​ | 285 | ​ | ​ | 245 | ​
Total finance lease cost | ​ | ​ | ​ | ​ | ​ | $ | 555 | ​ | ​ | 549 | ​ | ​ | 1,133 | ​ | ​ | 1,076 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Short-term lease payments | ​ | ​ | ​ | ​ | ​ | $ | 28,228 | ​ | ​ | 47,371 | ​ | ​ | 57,671 | ​ | ​ | 90,277 | ​

(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, | ​
​ |  | 2024 |  | 2025 | ​
Cash paid for amounts included in the measurement of lease liabilities: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Operating cash flows from operating leases | ​ | $ | 709,807 | ​ | ​ | 794,364 | ​
Operating cash flows from finance leases | ​ | ​ | 285 | ​ | ​ | 245 | ​
Investing cash flows from operating leases | ​ | ​ | 55,704 | ​ | ​ | 8,050 | ​
Financing cash flows from finance leases | ​ | ​ | 529 | ​ | ​ | 710 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Noncash activities: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Right-of-use assets obtained in exchange for new operating lease obligations | ​ | $ | 97,720 | ​ | ​ | 127,187 | ​
Decrease to existing right-of-use assets and lease obligations from operating lease modifications, net (1) | ​ | $ | (1,472) | ​ | ​ | (14,453) | ​

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

​

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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, 2025 (in thousands):

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Operating Leases | ​ | Financing Leases | ​ | Total | ​
Remainder of 2025 | ​ | $ | 322,885 | ​ | ​ | 1,048 | ​ | ​ | 323,933 | ​
2026 | ​ | ​ | 602,332 | ​ | ​ | 1,793 | ​ | ​ | 604,125 | ​
2027 | ​ | ​ | 487,023 | ​ | ​ | 780 | ​ | ​ | 487,803 | ​
2028 | ​ | ​ | 406,177 | ​ | ​ | 607 | ​ | ​ | 406,784 | ​
2029 | ​ | ​ | 322,109 | ​ | ​ | 167 | ​ | ​ | 322,276 | ​
Thereafter | ​ | ​ | 657,786 | ​ | ​ | — | ​ | ​ | 657,786 | ​
Total lease payments | ​ | ​ | 2,798,312 | ​ | ​ | 4,395 | ​ | ​ | 2,802,707 | ​
Less: imputed interest | ​ | ​ | (408,998) | ​ | ​ | (699) | ​ | ​ | (409,697) | ​
Total | ​ | $ | 2,389,314 | ​ | ​ | 3,696 | ​ | ​ | 2,393,010 | ​

​

(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, 2024 | ​ | June 30, 2025 | ​ | ​
​ | ​ | Operating Leases | ​ | Finance Leases | ​ | Operating Leases | ​ | Finance Leases | ​ | ​
Weighted average remaining lease term | ​ | 6.0 years | ​ | 2.1 years | ​ | 5.8 years | ​ | 2.7 years | ​ | ​
Weighted average discount rate | ​ | 5.5 | % | 8.4 | % | 5.6 | % | 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 (the “2019 gathering and compression agreement”), (ii) a gathering and compression agreement from Antero Midstream’s acquisition in 2022 of certain Marcellus gathering and compression assets in an area of dedication (the “Marcellus gathering and compression agreement”) and (iii) a compression agreement from Antero Midstream’s acquisition in 2022 of certain Utica compressors (the “Utica compression agreement”) and (iv) a gathering and compression agreement from Antero Midstream’s acquisition in the second quarter of 2024 of certain central Marcellus gathering and compression assets (the “Mountaineer gathering and compression agreement,” and together with the 2019 gathering and compression agreement, Marcellus gathering and compression agreement and the Utica compression agreement, the “gathering and compression agreements”). Pursuant to the gathering and compression agreements with Antero Midstream, the Company has dedicated substantially all of its current and future acreage in West Virginia, Ohio and Pennsylvania to Antero Midstream for gathering and compression services. The 2019 gathering and compression agreement, Marcellus gathering and compression agreement and Mountaineer gathering and compression agreement have initial terms through 2038, 2031 and 2026, respectively, and the Utica compression agreement has one remaining acreage dedication that expires in 2030. Upon expiration of the Marcellus gathering and compression agreement, Utica 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 low pressure gathering fee per Mcf, a high pressure gathering fee per Mcf and a compression fee per Mcf, as applicable, subject to annual Consumer Price Index (“CPI”)-based adjustments. If and to the extent the Company requests that Antero Midstream construct new low pressure lines, high pressure lines and compressor stations, the 2019 gathering and compression agreement contains options at Antero Midstream’s election for either (i) minimum volume commitments that require Antero Resources to utilize or pay for 75% of the high pressure gathering capacity and 70% of the compression capacity of the requested capacity of such new construction for 10 years or (ii) a cost of service fee that allows the Antero Midstream to earn a 13% rate of return on such new construction over seven years. The Marcellus gathering and compression agreement provides for a minimum volume commitment that requires the Company to utilize or pay for 25% of the compression capacity for a period of 10 years from the in-service date. The Mountaineer gathering and compression agreement provides for monthly minimum compression and gathering fees for each compressor station or high pressure gathering line, respectively, for a period of 12 years commencing 90 days after such

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asset’s in-service date. As of June 30, 2025, the minimum volume commitments for the 2019 gathering and compression agreement end in 2035, and the minimum compression and 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 $202 million and $212 million for the three months ended June 30, 2024 and 2025, respectively. For the six months ended June 30, 2024 and 2025, gathering and compression fees paid by the Company related to this agreement were $401 million and $417 million, respectively. As of December 31, 2024 and June 30, 2025, $79 million and $82 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, 2025 (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 2025 | ​ | $ | 606,277 | ​ | ​ | 26,625 | ​ | ​ | 259,821 | ​ | ​ | 64,111 | ​ | ​ | 6,158 | ​ | ​ | 962,992 | ​
2026 | ​ | ​ | 1,201,515 | ​ | ​ | 26,872 | ​ | ​ | 497,534 | ​ | ​ | 106,592 | ​ | ​ | 4,043 | ​ | ​ | 1,836,556 | ​
2027 | ​ | ​ | 1,195,960 | ​ | ​ | 25,583 | ​ | ​ | 407,118 | ​ | ​ | 80,685 | ​ | ​ | 443 | ​ | ​ | 1,709,789 | ​
2028 | ​ | ​ | 1,134,203 | ​ | ​ | 24,251 | ​ | ​ | 347,498 | ​ | ​ | 59,286 | ​ | ​ | 68 | ​ | ​ | 1,565,306 | ​
2029 | ​ | ​ | 783,964 | ​ | ​ | 23,741 | ​ | ​ | 280,827 | ​ | ​ | 41,449 | ​ | ​ | 68 | ​ | ​ | 1,130,049 | ​
Thereafter | ​ | ​ | 3,681,817 | ​ | ​ | 65,651 | ​ | ​ | 600,212 | ​ | ​ | 57,574 | ​ | ​ | — | ​ | ​ | 4,405,254 | ​
Total | ​ | $ | 8,603,736 | ​ | ​ | 192,723 | ​ | ​ | 2,393,010 | ​ | ​ | 409,697 | ​ | ​ | 10,780 | ​ | ​ | 11,609,946 | ​

​

(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.

(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

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Notes to Unaudited Condensed Consolidated Financial Statements

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 statements of operations and comprehensive income (loss). There are no remaining payment obligations related to any delayed or cancelled contracts as of June 30, 2025.

​

(14) Contingencies

(a) | Environmental

In June 2018, the Company received a Notice of Violation (“NOV”) from the U.S. Environmental Protection Agency (“EPA”) Region III for alleged violations of the federal Clean Air Act and the West Virginia State Implementation Plan. The NOV alleges that combustion devices at these facilities did not meet applicable air permitting requirements. Separately, in June 2018, the Company received an information request from the EPA Region III pursuant to Section 114(a) of the Clean Air Act relating to the facilities that were inspected in September 2017 as well as additional Antero Resources facilities for the purpose of determining if the additional facilities have the same alleged compliance issues that were identified during the September 2017 inspections. Subsequently, the West Virginia Department of Environmental Protection (“WVDEP”) and the EPA Region V (covering Ohio facilities) each conducted its own inspections, and the Company has separately received NOVs from WVDEP and EPA Region V related to similar issues being investigated by the EPA Region III. The Company continues to negotiate with the EPA and WVDEP to resolve the issues alleged in the NOVs and the information request. The Company’s operations at these facilities are not suspended, and management does not expect these matters to have a material adverse effect on the Company’s financial condition, results of operations or cash flows.

(b) | Production Taxes

The Company is subject to production taxes in the states in which it operates. The Company’s production tax filings in West Virginia for 2018 to 2020 tax years were subject to audit by the State of West Virginia. All assessments received in conjunction with this audit were recorded in the consolidated statement of operations and comprehensive income during the year ended December 31, 2024; however, the Company has filed an appeal with regard to such assessments. At this time, the Company believes the outcome of this matter will not have a material adverse effect on the Company’s unaudited condensed consolidated financial position, results of operations or cash flows.

(c) | Other

The Company is party to various 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.

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

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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 June 30, 2025 for estimated damages that is recorded in contract termination, loss contingency and settlements in the condensed consolidated statements of operations and comprehensive income (loss).

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.

(15) Related Parties

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

​

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​

​

(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; (ii) marketing and utilization of excess firm transportation capacity and (iii) midstream services through the Company’s equity method investment in Antero Midstream.

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

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Three Months Ended June 30, 2024 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Equity Method | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Exploration | ​ | ​ | ​ | ​ | Investment in | ​ | Elimination of | ​ | ​ | ​ | ​
​ | ​ | and | ​ | ​ | ​ | ​ | Antero | ​ | Unconsolidated | ​ | Consolidated | ​
​ |  | Production |  | Marketing |  | Midstream (1) |  | Affiliate |  | Total | ​
Sales and revenues: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Third-party | ​ | $ | 928,644 | ​ | ​ | 49,418 | ​ | ​ | 414 | ​ | ​ | (414) | ​ | ​ | 978,062 | ​
Intersegment | ​ | ​ | 592 | ​ | ​ | — | ​ | ​ | 269,381 | ​ | ​ | (269,381) | ​ | ​ | 592 | ​
Total revenue | ​ | ​ | 929,236 | ​ | ​ | 49,418 | ​ | ​ | 269,795 | ​ | ​ | (269,795) | ​ | ​ | 978,654 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Operating expenses: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Lease operating | ​ | ​ | 29,759 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 29,759 | ​
Gathering and compression | ​ | ​ | 222,139 | ​ | ​ | — | ​ | ​ | 26,190 | ​ | ​ | (26,190) | ​ | ​ | 222,139 | ​
Processing | ​ | ​ | 269,985 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 269,985 | ​
Transportation | ​ | ​ | 171,318 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 171,318 | ​
Water handling | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 30,219 | ​ | ​ | (30,219) | ​ | ​ | — | ​
Production and ad valorem taxes | ​ | ​ | 41,933 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 41,933 | ​
Marketing | ​ | ​ | — | ​ | ​ | 70,807 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 70,807 | ​
General and administrative (excluding equity-based compensation) | ​ | ​ | 42,277 | ​ | ​ | — | ​ | ​ | 9,620 | ​ | ​ | (9,620) | ​ | ​ | 42,277 | ​
Equity-based compensation | ​ | ​ | 17,151 | ​ | ​ | — | ​ | ​ | 11,599 | ​ | ​ | (11,599) | ​ | ​ | 17,151 | ​
Facility idling | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 412 | ​ | ​ | (412) | ​ | ​ | — | ​
Depletion, depreciation and amortization | ​ | ​ | 188,633 | ​ | ​ | — | ​ | ​ | 37,576 | ​ | ​ | (37,576) | ​ | ​ | 188,633 | ​
Impairment of property and equipment | ​ | ​ | 313 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 313 | ​
Other (2) | ​ | ​ | 4,425 | ​ | ​ | — | ​ | ​ | 1,426 | ​ | ​ | (1,426) | ​ | ​ | 4,425 | ​
Total operating expenses | ​ | ​ | 987,933 | ​ | ​ | 70,807 | ​ | ​ | 117,042 | ​ | ​ | (117,042) | ​ | ​ | 1,058,740 | ​
Operating income (loss) | ​ | $ | (58,697) | ​ | ​ | (21,389) | ​ | ​ | 152,753 | ​ | ​ | (152,753) | ​ | ​ | (80,086) | ​
Equity in earnings of unconsolidated affiliates | ​ | $ | 20,881 | ​ | ​ | — | ​ | ​ | 27,597 | ​ | ​ | (27,597) | ​ | ​ | 20,881 | ​
Capital expenditures for segment assets | ​ | $ | 192,385 | ​ | ​ | — | ​ | ​ | 43,399 | ​ | ​ | (43,399) | ​ | ​ | 192,385 | ​

(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, loss (gain) on sale of assets and other operating expenses, as applicable, which represent segment operating expenses that are not considered significant.

​

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​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | 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, loss (gain) on sale of assets and other operating expenses, as applicable, which represent segment operating expenses that are not considered significant.

​

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​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Six Months Ended June 30, 2024 | ​
​ | ​ | ​ | ​ | ​ | ​ | Equity Method | ​ | ​ | ​ | ​ | ​
​ | ​ | Exploration | ​ | ​ | ​ | Investment in | ​ | Elimination of | ​ | ​ | ​
​ | ​ | and | ​ | ​ | ​ | Antero | ​ | Unconsolidated | ​ | Consolidated | ​
​ |  | Production |  | Marketing |  | Midstream (1) |  | Affiliate |  | Total |
Sales and revenues: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Third-party | ​ | $ | 2,001,813 | ​ | ​ | 97,938 | ​ | ​ | 1,085 | ​ | ​ | (1,085) | ​ | ​ | 2,099,751 | ​
Intersegment | ​ |  | 1,174 | ​ | ​ | — | ​ | ​ | 547,761 | ​ | ​ | (547,761) | ​ | ​ | 1,174 | ​
Total revenue | ​ | ​ | 2,002,987 | ​ | ​ | 97,938 | ​ | ​ | 548,846 | ​ | ​ | (548,846) | ​ | ​ | 2,100,925 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Operating expenses: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Lease operating | ​ | ​ | 58,880 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 58,880 | ​
Gathering and compression | ​ | ​ | 445,669 | ​ | ​ | — | ​ | ​ | 52,333 | ​ | ​ | (52,333) | ​ | ​ | 445,669 | ​
Processing | ​ | ​ | 525,780 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 525,780 | ​
Transportation | ​ | ​ | 364,274 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 364,274 | ​
Water handling | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 57,994 | ​ | ​ | (57,994) | ​ | ​ | — | ​
Production and ad valorem taxes | ​ | ​ | 100,101 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 100,101 | ​
Marketing | ​ | ​ | — | ​ | ​ | 130,620 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 130,620 | ​
General and administrative (excluding equity-based compensation) | ​ | ​ | 82,062 | ​ | ​ | — | ​ | ​ | 21,514 | ​ | ​ | (21,514) | ​ | ​ | 82,062 | ​
Equity-based compensation | ​ | ​ | 33,228 | ​ | ​ | — | ​ | ​ | 20,926 | ​ | ​ | (20,926) | ​ | ​ | 33,228 | ​
Facility idling | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 934 | ​ | ​ | (934) | ​ | ​ | — | ​
Depletion, depreciation and amortization | ​ | ​ | 379,108 | ​ | ​ | — | ​ | ​ | 74,671 | ​ | ​ | (74,671) | ​ | ​ | 379,108 | ​
Impairment of property and equipment | ​ | ​ | 5,503 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 5,503 | ​
Other (2) | ​ | ​ | 8,047 | ​ | ​ | — | ​ | ​ | 1,470 | ​ | ​ | (1,470) | ​ | ​ | 8,047 | ​
Total operating expenses | ​ | ​ | 2,002,652 | ​ | ​ | 130,620 | ​ | ​ | 229,842 | ​ | ​ | (229,842) | ​ | ​ | 2,133,272 | ​
Operating income (loss) | ​ | $ | 335 | ​ | ​ | (32,682) | ​ | ​ | 319,004 | ​ | ​ | (319,004) | ​ | ​ | (32,347) | ​
Equity in earnings of unconsolidated affiliates | ​ | $ | 44,228 | ​ | ​ | — | ​ | ​ | 55,127 | ​ | ​ | (55,127) | ​ | ​ | 44,228 | ​
Capital expenditures for segment assets | ​ | $ | 414,834 | ​ | ​ | — | ​ | ​ | 78,472 | ​ | ​ | (78,472) | ​ | ​ | 414,834 | ​

(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, loss (gain) on sale of assets and other operating expenses, as applicable, which represent segment operating expenses that are not considered significant.

​

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

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

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | As of December 31, 2024 | ​
​ | ​ | ​ | ​ | ​ | ​ | Equity Method | ​ | ​ | ​ | ​ | ​
​ | ​ | Exploration | ​ | ​ | ​ | Investment in | ​ | Elimination of | ​ | ​ | ​
​ | ​ | and | ​ | ​ | ​ | Antero | ​ | Unconsolidated | ​ | Consolidated | ​
​ |  | Production |  | Marketing |  | Midstream (1) |  | Affiliate |  | Total | ​
Investments in unconsolidated affiliates | ​ | $ | 231,048 | ​ | ​ | — | ​ | ​ | 603,956 | ​ | ​ | (603,956) | ​ | ​ | 231,048 | ​
Total assets | ​ | ​ | 12,999,930 | ​ | ​ | 10,120 | ​ | ​ | 5,761,748 | ​ | ​ | (5,761,748) | ​ | ​ | 13,010,050 | ​

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

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | (Unaudited) | ​
​ | ​ | As of June 30, 2025 | ​
​ | ​ | ​ | ​ | ​ | ​ | Equity Method | ​ | ​ | ​ | ​ | ​
​ | ​ | Exploration | ​ | ​ | ​ | Investment in | ​ | Elimination of | ​ | ​ | ​
​ | ​ | and | ​ | ​ | ​ | Antero | ​ | Unconsolidated | ​ | Consolidated | ​
​ |  | Production |  | Marketing |  | Midstream (1) |  | Affiliate |  | Total |
Investments in unconsolidated affiliates | ​ | $ | 249,163 | ​ | ​ | — | ​ | ​ | 598,340 | ​ | ​ | (598,340) | ​ | ​ | 249,163 | ​
Total assets | ​ | ​ | 12,757,424 | ​ | ​ | 8,649 | ​ | ​ | 5,728,681 | ​ | ​ | (5,728,681) | ​ | ​ | 12,766,073 | ​

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

​

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(17) Immaterial Correction of Prior Period Error

In the course of preparing our consolidated financial statements for the year ended December 31, 2024, the Company identified an error in the quarterly calculations related to depletion expense of the Company’s proved oil and gas properties. This error had the effect of incorrectly reporting depletion expense amounts in prior periods, which resulted in incorrectly reporting depletion, depreciation and amortization expense and income tax (expense) benefit in prior periods.

After considering the guidance in Staff Accounting Bulletin (“SAB”) No. 99, Materiality, and FASB ASC Topic 250, Accounting Changes and Error Corrections, the Company evaluated the materiality of these amounts quantitatively and qualitatively and concluded that the error was not material to any of the Company’s prior annual or interim period financial statements. The unaudited condensed consolidated financial statements for the three and six months ended June 30, 2024 in this Quarterly Report on Form 10-Q, have been revised in accordance with SAB No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, in order to reflect these corrections. The corrections reflect the adjustments to depletion, depreciation and amortization expense and income tax (expense) benefit described above, as well as the resulting adjustments to accumulated depletion, depreciation and amortization, deferred income tax liabilities, net and retained earnings (accumulated deficit). Retained earnings as of December 31, 2023 reflected in the accompanying consolidated statements of equity has been decreased by $80 million from its previously reported balance of $1.1 billion to the corrected balance of $1.1 billion to reflect the impact of correcting this error for the years ended December 31, 2021, 2022 and 2023. The correction of this error also impacted certain non-cash line items within the operating activities section of the consolidated statements of cash flows; however, these corrections did not change previously reported net cash provided by operating activities for any period.

In addition to correcting the unaudited condensed consolidated financial statements, we have also corrected the following notes to the unaudited condensed consolidated financial statements for the effects of this error: (i) Note 2 — Summary of Significant Accounting Policies and (ii) Note 16 — Reportable Segments.

The following table presents the effect of the corrections on selected line items from the previously reported unaudited condensed consolidated financial statements as of June 30, 2024 (in thousands, except per share amounts):

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Statement of Operations and Comprehensive Loss | ​
​ | ​ | Three Months Ended June 30, 2024 | ​
​ | ​ | As Previously | ​ | ​ | ​ | As | ​
​ | ​ | Reported | ​ | Corrections | ​ | Corrected | ​
Depletion, depreciation and amortization | ​ | $ | 170,536 | ​ | ​ | 18,097 | ​ | ​ | 188,633 | ​
Total operating expenses | ​ | ​ | 1,040,643 | ​ | ​ | 18,097 | ​ | ​ | 1,058,740 | ​
Operating loss | ​ | ​ | (61,989) | ​ | ​ | (18,097) | ​ | ​ | (80,086) | ​
Loss before income taxes | ​ | ​ | (73,789) | ​ | ​ | (18,097) | ​ | ​ | (91,886) | ​
Income tax benefit | ​ | ​ | 13,334 | ​ | ​ | 3,954 | ​ | ​ | 17,288 | ​
Net loss, including noncontrolling interest | ​ | ​ | (60,455) | ​ | ​ | (14,143) | ​ | ​ | (74,598) | ​
Net loss and comprehensive loss attributable to Antero Resources Corporation | ​ | ​ | (65,663) | ​ | ​ | (14,143) | ​ | ​ | (79,806) | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Loss per common share—basic | ​ | $ | (0.21) | ​ | ​ | (0.05) | ​ | ​ | (0.26) | ​
Loss per common share—diluted | ​ | $ | (0.21) | ​ | ​ | (0.05) | ​ | ​ | (0.26) | ​

​

​

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Statement of Operations and Comprehensive Loss | ​
​ | ​ | Six Months Ended June 30, 2024 | ​
​ | ​ | As Previously | ​ | ​ | ​ | As | ​
​ | ​ | Reported | ​ | Corrections | ​ | Corrected | ​
Depletion, depreciation and amortization | ​ | $ | 343,590 | ​ | ​ | 35,518 | ​ | ​ | 379,108 | ​
Total operating expenses | ​ | ​ | 2,097,754 | ​ | ​ | 35,518 | ​ | ​ | 2,133,272 | ​
Operating income (loss) | ​ | ​ | 3,171 | ​ | ​ | (35,518) | ​ | ​ | (32,347) | ​
Loss before income taxes | ​ | ​ | (15,469) | ​ | ​ | (35,518) | ​ | ​ | (50,987) | ​
Income tax benefit | ​ | ​ | 3,301 | ​ | ​ | 7,760 | ​ | ​ | 11,061 | ​
Net loss, including noncontrolling interest | ​ | ​ | (12,168) | ​ | ​ | (27,758) | ​ | ​ | (39,926) | ​
Net loss and comprehensive loss attributable to Antero Resources Corporation | ​ | ​ | (29,318) | ​ | ​ | (27,758) | ​ | ​ | (57,076) | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Loss per common share—basic | ​ | $ | (0.10) | ​ | ​ | (0.09) | ​ | ​ | (0.19) | ​
Loss per common share—diluted | ​ | $ | (0.10) | ​ | ​ | (0.09) | ​ | ​ | (0.19) | ​

​

​

​

​

​

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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, 2025, we held approximately 526,000 net acres in the Appalachian Basin.

Financing Highlights

Credit Facility Maturity Date Extension

Effective July 30, 2025, we obtained the consent of each of the lenders under our Unsecured Credit Facility to extend the Maturity Date from July 30, 2029 to July 30, 2030. The terms of the Credit Facility otherwise remain unchanged. Under the terms of the Unsecured Credit Agreement, we may request two one-year extensions of the Maturity Date, subject to the satisfaction of certain conditions. This is the first such extension.

Debt Repurchase Program

During the six months ended June 30, 2025, we redeemed 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. In addition, we repurchased $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. See Note 7—Long-Term Debt to the 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, 2025, we repurchased approximately 2.2 million shares of our common stock at a total cost of $75 million and approximately 2.5 million shares of our common stock at a total cost of $85 million, respectively, through our share repurchase program. As of June 30, 2025, we have approximately $966 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 natural gas and ethane increased significantly, while benchmark prices for C3+ NGLs remained relatively consistent and benchmark prices for oil decreased during the three and six months ended June 30, 2025 as compared to the same periods of 2024. As a result of the higher benchmark natural gas prices during the three and six months ended June 30, 2025, we experienced an increase in price realization for natural gas products, partially offset by the effects of decreased benchmark NGLs and oil prices as compared to the three and six months ended June 30, 2024. We monitor the economic factors that impact natural gas, NGLs and oil prices, including domestic and foreign supply and demand indicators, domestic and foreign commodity inventories, the actions of Organization of Petroleum Exporting Countries and other large producing nations and the current conflicts in Ukraine and in the Middle East, among others. In the current economic environment, we expect that commodity prices for some or all of the commodities we produce could remain volatile. This volatility is beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows.

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

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Three Months Ended June 30, | ​ | Six Months Ended June 30, | ​
​ |  | 2024 |  | 2025 |  | 2024 |  | 2025 | ​
Henry Hub ($/Mcf) (1) | ​ | $ | 1.89 | ​ | ​ | 3.44 | ​ | ​ | 2.07 | ​ | ​ | 3.55 | ​
Mont Belvieu Ethane ($/Bbl) (2) | ​ | ​ | 8.07 | ​ | ​ | 10.11 | ​ | ​ | 8.07 | ​ | ​ | 10.78 | ​
Mont Belvieu C3+ NGLs ($/Bbl) (3) | ​ | ​ | 40.33 | ​ | ​ | 38.07 | ​ | ​ | 41.54 | ​ | ​ | 41.03 | ​
West Texas Intermediate ($/Bbl) (4) | ​ | ​ | 80.57 | ​ | ​ | 63.74 | ​ | ​ | 78.77 | ​ | ​ | 67.58 | ​

(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

Antero Resources (Excluding Martica)

We are exposed to certain commodity price risks relating to our ongoing business operations, and we use derivative instruments when circumstances warrant to manage such risks. In addition, we periodically enter into contracts that contain embedded features that are required to be bifurcated and accounted for separately as derivatives. For the three months ended June 30, 2024 and 2025, 2% and 4%, respectively, of our production was hedged through commodity derivatives. For the six months ended June 30, 2024 and 2025, 4% of our production was hedged through commodity derivatives. Assuming our 2025 production is the same as our production in 2024, approximately 4% of our total production for 2025 is hedged through commodity derivatives. As of June 30, 2025, the estimated fair value of our commodity derivative contracts was a net liability of $48 million. See Note 11—Derivative Instruments to the unaudited condensed consolidated financial statements for additional information.

Martica

Our consolidated VIE, Martica, also maintained a portfolio of fixed swap natural gas, NGLs and oil derivatives for the benefit of the noncontrolling interests in Martica. As such, all gains and losses attributable to Martica’s derivative portfolio were fully attributable to the noncontrolling interests in Martica. During the three months ended March 31, 2025, all of Martica’s derivative contracts expired, and as a result Martica had no derivative instruments as of March 31, 2025 or June 30, 2025. See Note 11—Derivative Instruments to the unaudited condensed consolidated financial statements for additional information.

​

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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 2024. In order to manage the inflation risk present in the United States’ economy, the Federal Reserve utilized monetary policy in the form of interest rate increases beginning in March 2022 in an effort to bring the inflation rate in line with its stated goal of 2% on a long-term basis. Between March 2022 and July 2023, the Federal Reserve increased the federal funds interest rate by 5.25%. 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 1.0% between September and December 2024. However, recent tariff activity by the United States government has caused the Federal Reserve to keep the federal funds rate steady in the first half of 2025. While inflationary pressures in the United States’ economy have begun to subside, it is uncertain what impact recent tariff activity by the United States and foreign governments will have on inflation.

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 the outbreak of armed conflict, including in the Middle East and Iran, 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: (i) the exploration, development and production of natural gas, NGLs and oil; (ii) marketing and utilization of excess firm transportation capacity; and (iii) midstream services through our equity method investment in Antero Midstream. Revenues from Antero Midstream’s operations were primarily derived from intersegment transactions for services provided to our exploration and production operations by Antero Midstream. All intersegment transactions were eliminated upon consolidation, including revenues from water handling services provided by Antero Midstream, which we capitalized as proved property development costs. Marketing revenues are primarily derived from activities to purchase and sell third-party natural gas and NGLs and to market and utilize excess firm transportation capacity. See Note 16—Reportable Segments to our unaudited condensed consolidated financial statements for additional information.

​

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Three Months Ended June 30, 2024 Compared to Three Months Ended June 30, 2025

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

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Three Months Ended June 30, 2024 | ​
​ | ​ | ​ | ​ | ​ | ​ | Equity Method | ​ | ​ | ​ | ​ | ​
​ | ​ | Exploration | ​ | ​ | ​ | Investment in | ​ | Elimination of | ​ | ​ | ​
​ | ​ | and | ​ | ​ | ​ | Antero | ​ | Unconsolidated | ​ | Consolidated | ​
​ |  | Production |  | Marketing |  | Midstream (1) |  | Affiliate |  | Total | ​
Revenue and other: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Natural gas sales | ​ | $ | 374,568 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 374,568 | ​
Natural gas liquids sales | ​ | ​ | 489,191 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 489,191 | ​
Oil sales | ​ | ​ | 63,458 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 63,458 | ​
Commodity derivative fair value losses | ​ | ​ | (5,585) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (5,585) | ​
Gathering, compression and water handling | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 269,795 | ​ | ​ | (269,795) | ​ | ​ | — | ​
Marketing | ​ | ​ | — | ​ | ​ | 49,418 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 49,418 | ​
Amortization of deferred revenue, VPP | ​ | ​ | 6,739 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 6,739 | ​
Other revenue and income | ​ | ​ | 865 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 865 | ​
Total revenue | ​ | ​ | 929,236 | ​ | ​ | 49,418 | ​ | ​ | 269,795 | ​ | ​ | (269,795) | ​ | ​ | 978,654 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Operating expenses: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Lease operating | ​ | ​ | 29,759 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 29,759 | ​
Gathering and compression | ​ | ​ | 222,139 | ​ | ​ | — | ​ | ​ | 26,190 | ​ | ​ | (26,190) | ​ | ​ | 222,139 | ​
Processing | ​ | ​ | 269,985 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 269,985 | ​
Transportation | ​ | ​ | 171,318 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 171,318 | ​
Water handling | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 30,219 | ​ | ​ | (30,219) | ​ | ​ | — | ​
Production and ad valorem taxes | ​ | ​ | 41,933 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 41,933 | ​
Marketing | ​ | ​ | — | ​ | ​ | 70,807 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 70,807 | ​
Exploration and mine expenses | ​ | ​ | 643 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 643 | ​
General and administrative (excluding equity-based compensation) | ​ | ​ | 42,277 | ​ | ​ | — | ​ | ​ | 9,620 | ​ | ​ | (9,620) | ​ | ​ | 42,277 | ​
Equity-based compensation | ​ | ​ | 17,151 | ​ | ​ | — | ​ | ​ | 11,599 | ​ | ​ | (11,599) | ​ | ​ | 17,151 | ​
Depletion, depreciation and amortization | ​ | ​ | 188,633 | ​ | ​ | — | ​ | ​ | 37,576 | ​ | ​ | (37,576) | ​ | ​ | 188,633 | ​
Impairment of property and equipment | ​ | ​ | 313 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 313 | ​
Accretion of asset retirement obligations | ​ | ​ | 780 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 780 | ​
Gain on sale of assets | ​ | ​ | (18) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (18) | ​
Contract termination, loss contingency, settlements and other operating expenses | ​ | ​ | 3,020 | ​ | ​ | — | ​ | ​ | 1,838 | ​ | ​ | (1,838) | ​ | ​ | 3,020 | ​
Total operating expenses | ​ | ​ | 987,933 | ​ | ​ | 70,807 | ​ | ​ | 117,042 | ​ | ​ | (117,042) | ​ | ​ | 1,058,740 | ​
Operating income (loss) | ​ | $ | (58,697) | ​ | ​ | (21,389) | ​ | ​ | 152,753 | ​ | ​ | (152,753) | ​ | ​ | (80,086) | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Equity in earnings of unconsolidated affiliates | ​ | $ | 20,881 | ​ | ​ | — | ​ | ​ | 27,597 | ​ | ​ | (27,597) | ​ | ​ | 20,881 | ​

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

​

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​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | 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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Exploration and Production Segment

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

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Three Months Ended | ​ | Amount of | ​ | ​ | ​
​ | ​ | June 30, | ​ | Increase | ​ | Percent | ​
​ | ​ | 2024 | ​ | 2025 | ​ | (Decrease) | ​ | Change | ​
Production data (1) (2): | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Natural gas (Bcf) | ​ | ​ | 196 | ​ | ​ | 203 | ​ | ​ | 7 | ​ | 4 | %
C2 Ethane (MBbl) | ​ | ​ | 7,811 | ​ | ​ | 6,924 | ​ | ​ | (887) | ​ | (11) | %
C3+ NGLs (MBbl) | ​ | ​ | 10,514 | ​ | ​ | 10,608 | ​ | ​ | 94 | ​ | 1 | %
Oil (MBbl) | ​ | ​ | 952 | ​ | ​ | 672 | ​ | ​ | (280) | ​ | (29) | %
Combined (Bcfe) | ​ | ​ | 311 | ​ | ​ | 312 | ​ | ​ | 1 | ​ | * | ​
Daily combined production (MMcfe/d) | ​ | ​ | 3,420 | ​ | ​ | 3,430 | ​ | ​ | 10 | ​ | * | ​
Average prices before effects of derivative settlements (3): | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Natural gas (per Mcf) | ​ | $ | 1.92 | ​ | ​ | 3.39 | ​ | ​ | 1.47 | ​ | 77 | %
C2 Ethane (per Bbl) (4) | ​ | $ | 8.42 | ​ | ​ | 11.34 | ​ | ​ | 2.92 | ​ | 35 | %
C3+ NGLs (per Bbl) | ​ | $ | 40.27 | ​ | ​ | 37.92 | ​ | ​ | (2.35) | ​ | (6) | %
Oil (per Bbl) | ​ | $ | 66.66 | ​ | ​ | 50.15 | ​ | ​ | (16.51) | ​ | (25) | %
Weighted Average Combined (per Mcfe) | ​ | $ | 2.98 | ​ | ​ | 3.85 | ​ | ​ | 0.87 | ​ | 29 | %
Average realized prices after effects of derivative settlements (3): | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Natural gas (per Mcf) | ​ | $ | 1.94 | ​ | ​ | 3.36 | ​ | ​ | 1.42 | ​ | 73 | %
C2 Ethane (per Bbl) (4) | ​ | $ | 8.42 | ​ | ​ | 11.34 | ​ | ​ | 2.92 | ​ | 35 | %
C3+ NGLs (per Bbl) | ​ | $ | 40.44 | ​ | ​ | 37.92 | ​ | ​ | (2.52) | ​ | (6) | %
Oil (per Bbl) | ​ | $ | 66.50 | ​ | ​ | 50.15 | ​ | ​ | (16.35) | ​ | (25) | %
Weighted Average Combined (per Mcfe) | ​ | $ | 3.00 | ​ | ​ | 3.83 | ​ | ​ | 0.83 | ​ | 28 | %
Average costs (per Mcfe): | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Lease operating | ​ | $ | 0.10 | ​ | ​ | 0.12 | ​ | ​ | 0.02 | ​ | 20 | %
Gathering and compression | ​ | $ | 0.71 | ​ | ​ | 0.76 | ​ | ​ | 0.05 | ​ | 7 | %
Processing | ​ | $ | 0.87 | ​ | ​ | 0.91 | ​ | ​ | 0.04 | ​ | 5 | %
Transportation | ​ | $ | 0.55 | ​ | ​ | 0.58 | ​ | ​ | 0.03 | ​ | 5 | %
Production and ad valorem taxes | ​ | $ | 0.13 | ​ | ​ | 0.11 | ​ | ​ | (0.02) | ​ | (15) | %
Marketing expense, net | ​ | $ | 0.07 | ​ | ​ | 0.06 | ​ | ​ | (0.01) | ​ | (14) | %
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 (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, 2024 and 2025 includes $0.1 million and $0.5 million, respectively, of proceeds related to a take-or-pay contract. Excluding the effect of these proceeds, the average realized price for ethane before and after the effects of derivatives for the three months ended June 30, 2024 and 2025 would have been $8.41 per Bbl and $11.27 per Bbl, respectively.

​

Natural gas sales. Revenues from sales of natural gas increased from $375 million for the three months ended June 30, 2024 to $689 million for the three months ended June 30, 2025, an increase of $314 million, or 84%. Higher commodity prices (excluding the effects of derivative settlements) during the three months ended June 30, 2025 accounted for an approximate $299 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). Higher natural gas production volumes accounted for an approximate $15 million increase in year-over-year natural gas sales revenue (calculated as the change in year-to-year volumes times the prior year average price).

NGLs sales. Revenues from sales of NGLs decreased from $489 million for the three months ended June 30, 2024 to $481 million for the three months ended June 30, 2025, a decrease of $8 million, or 2%. Lower commodity prices (excluding the effects of derivative settlements) during the three months ended June 30, 2025 accounted for an approximate $4 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). Lower ethane production volumes accounted for an approximate $8 million decrease in year-over-year NGLs revenues (calculated as the change in year-to-year volumes times the prior year average price), partially offset by higher C3+

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NGLs production volumes that accounted for an approximate $4 million increase in year-over-year NGLs revenues (calculated as the change in year-to-year volumes times the prior year average price).

Oil sales. Revenues from sales of oil decreased from $63 million for the three months ended June 30, 2024 to $34 million for the three months ended June 30, 2025, a decrease of $29 million, or 47%. Lower commodity prices (excluding the effects of derivative settlements) during the three months ended June 30, 2025 accounted for an approximate $11 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). Lower oil production volumes during the three months ended June 30, 2025 accounted for an approximate $18 million decrease in year-over-year oil revenues (calculated as the change in year-to-year volumes times the prior year average price).

Commodity derivative fair value gains (losses). Our commodity derivatives included fixed price swaps, collars, basis swaps, call options and embedded put options. Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment. Consequently, all mark-to-market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our statements of operations and comprehensive income (loss). For the three months ended June 30, 2024 and 2025, our commodity hedges resulted in derivative fair value losses of $6 million and fair value gains of $53 million, respectively. For the three months ended June 30, 2024, commodity derivative fair value losses included $6 million of net cash proceeds on settled commodity derivative gains. For the three months ended June 30, 2025, commodity derivative fair gains included $6 million of net cash payments for settled derivative losses.

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. Additionally, the substantial majority of our expected production is currently unhedged for 2025 and beyond, which limits our exposure to volatility in the fair value of our derivative instruments related to commodity price changes in the future.

Amortization of deferred revenue, VPP. Amortization of deferred revenues associated with the VPP decreased from $7 million for the three months ended June 30, 2024 to $6 million for the three months ended June 30, 2025, a decrease of $1 million, or 7%, primarily due to lower production volumes attributable to the VPP properties between periods. Amortization of the deferred revenues associated with the VPP are recognized as the production volumes are delivered at $1.61 per MMBtu over the contractual term.

Lease operating expense. Lease operating expense increased from $30 million, or $0.10 per Mcfe, for the three months ended June 30, 2024 to $37 million, or $0.12 per Mcfe, for the three months ended June 30, 2025, an increase of $7 million primarily due to higher oilfield service and produced water trucking and disposal costs as a result of our completion activity timing during the three months ended June 30, 2025.

Gathering, compression, processing and transportation expense. Gathering, compression, processing and transportation expense increased from $663 million for the three months ended June 30, 2024 to $702 million for the three months ended June 30, 2025, an increase of $39 million, or 6%. This was primarily a result of the following:

| ● | Gathering and compression costs increased from $0.71 per Mcfe for the three months ended June 30, 2024 to $0.76 per Mcfe for the three months ended June 30, 2025, primarily due to increased fuel costs as a result of higher natural gas prices and annual CPI-based adjustments between periods.

| ● | Processing costs increased from $0.87 per Mcfe for the three months ended June 30, 2024 to $0.91 per Mcfe for the three months ended June 30, 2025, primarily due to increased costs for NGLs processing, which includes an annual CPI-based adjustment during the first quarter of 2024 and higher NGLs transportation fees.

| ● | Transportation costs increased from $0.55 per Mcfe for the three months ended June 30, 2024 to $0.58 per Mcfe for the three months ended June 30, 2025, primarily due to higher fuel costs as a result of higher natural gas prices between periods and higher demand fees for certain pipelines during the three months ended June 30, 2025.

Production and ad valorem tax expense. Production and ad valorem taxes decreased from $42 million for the three months ended June 30, 2024 to $35 million for the three months ended June 30, 2025, a decrease of $7 million, or 17%, primarily due to lower ad valorem taxes, partially offset by higher severance taxes as a result of increased natural gas prices during the three months ended June 30, 2025. Production and ad valorem taxes as a percentage of natural gas revenues

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decreased from 11% for the three months ended June 30, 2024 to 5% for the three months ended June 30, 2025, primarily as a result of lower ad valorem taxes. West Virginia ad valorem taxes in 2024 were based on commodity prices during 2022, and West Virginia ad valorem taxes in 2025 are based on commodity prices during 2023.

General and administrative expense. General and administrative expense (excluding equity-based compensation expense) remained relatively consistent at $42 million, or $0.14 per Mcfe, for the three months ended June 30, 2024 and $41 million, or $0.13 per Mcfe for the three months ended June 30, 2025.

Equity-based compensation expense. Non-cash equity-based compensation expense remained relatively consistent at $17 million and $16 million for the three months ended June 30, 2024 and 2025, respectively. 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 remained relatively consistent at $189 million, or $0.61 per Mcfe, and $188 million, or $0.60 per Mcfe, for the three months ended June 30, 2024 and 2025, respectively.

Impairment of property and equipment. Impairment of oil and gas properties of $6 million for the three months ended June 30, 2025 primarily related to expiring leases. 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, settlements and other operating expenses. Contract termination, loss contingency, settlements and other operating expenses increased from $3 million for the three months ended June 30, 2024 to $14 million for the three months ended June 30, 2025, an increase of $11 million. This increase was primarily due to a loss contingency recorded during the three months ended June 30, 2025. See Note 14—Contingencies 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 $21 million, or $0.07 per Mcfe, for the three months ended June 30, 2024 to $18 million, or $0.06 per Mcfe, for the three months ended June 30, 2025, primarily due to lower firm transportation commitments between periods.

Marketing revenue. Marketing revenue decreased from $49 million for the three months ended June 30, 2024 to $34 million for the three months ended June 30, 2025, a decrease of $15 million, or 32%. This fluctuation primarily resulted from the following:

| ● | Natural gas marketing revenue decreased by $2 million between periods primarily due to lower natural gas marketing volumes, partially offset by higher natural gas prices. Lower natural gas marketing volumes accounted for a $4 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and higher natural gas prices accounted for a $2 million increase in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes).

| ● | Oil marketing revenue decreased by $21 million between periods primarily due to lower oil marketing volumes and prices. Lower oil marketing volumes accounted for a $15 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and lower oil prices accounted for a $6 million decrease in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes).

| ● | NGLs marketing revenues increased by $3 million for the three months ended June 30, 2025 due to higher C3+ NGLs marketing volumes.

Marketing expense. Marketing expense decreased from $71 million for the three months ended June 30, 2024 to $52 million for the three months ended June 30, 2025, a decrease of $19 million, or 27%. 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

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firm capacity. The cost of third-party oil purchases decreased $20 million between periods, primarily due to lower marketing volumes during the three months ended June 30, 2025. The cost of third-party natural gas and NGLs remained relatively consistent between periods. Firm transportation costs also remained relatively consistent between periods at $27 million for the three months ended June 30, 2024 and $26 million for the three months ended June 30, 2025.

Antero Midstream Segment

Antero Midstream revenue. Revenue from the Antero Midstream segment increased from $270 million for the three months ended June 30, 2024 to $305 million for the three months ended June 30, 2025, an increase of $35 million. This increase is primarily due to higher gathering and processing revenues of $19 million and higher water handling revenues of $16 million. The increased gathering and processing revenues between periods is primarily a result of increased throughput and annual CPI-based gathering and compression rate adjustments between periods. The increased water handling revenues between periods is primarily due to higher wastewater trucking and disposal volumes, increased wastewater trucking and disposal costs that are billed at cost plus 3% and higher fresh water delivery volumes during the three months ended June 30, 2025, as well as increased blending cost of service fees and an increase to the fresh water delivery rate as a result of an annual CPI-based rate adjustment between periods.

Antero Midstream operating expense. Total operating expense related to the Antero Midstream segment increased from $117 million for the three months ended June 30, 2024 to $119 million for the three months ended June 30, 2025, an increase of $2 million. This increase is primarily due to higher direct operating expenses as a result of increased water handling volumes and costs, as well as increased blending costs during the three months ended June 30, 2025, partially offset by lower depreciation expense associated with Antero Midstream’s program to repurpose underutilized compressor units to expand existing or construct new compressor stations between periods.

Items Not Allocated to Segments

Interest expense. Interest expense decreased from $33 million for the three months ended June 30, 2024 to $20 million for the three months ended June 30, 2025, a decrease of $13 million, or 39%, primarily due to the redemption or repurchase of $139 million aggregate principal amount of our Senior Notes during the six months ended June 30, 2025 and lower average Credit Facility borrowings and interest rates during the three months ended June 30, 2025. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information.

Loss on early extinguishment of debt. There was no loss on early extinguishment of debt for the three months ended June 30, 2024. 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. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information.

Income tax expense. For the three months ended June 30, 2024, we had an income tax benefit of $17 million, with an effective tax rate of 19%, due to a loss before income taxes of $92 million. For the three months ended June 30, 2025, we had an income tax expense of $48 million, with an effective tax rate of 22%, due to income before income taxes of $215 million. The increase in the effective tax rate between periods was primarily due to the effects of noncontrolling interests and stock compensation expense. See Note 2—Summary of Significant Accounting Policies to the unaudited condensed consolidated financial statements for additional information on the effects of the OBBB.

​

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Six Months Ended June 30, 2024 Compared to Six Months Ended June 30, 2025

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

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Six Months Ended June 30, 2024 | ​
​ | ​ | ​ | ​ | ​ | ​ | Equity Method | ​ | ​ | ​ | ​ | ​
​ | ​ | Exploration | ​ | ​ | ​ | Investment in | ​ | Elimination of | ​ | ​ | ​
​ | ​ | and | ​ | ​ | ​ | Antero | ​ | Unconsolidated | ​ | Consolidated | ​
​ |  | Production |  | Marketing |  | Midstream (1) |  | Affiliate |  | Total |
Revenue and other: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Natural gas sales | ​ | $ | 848,701 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 848,701 | ​
Natural gas liquids sales | ​ | ​ | 1,007,053 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 1,007,053 | ​
Oil sales | ​ | ​ | 128,175 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 128,175 | ​
Commodity derivative fair value gains | ​ | ​ | 3,861 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 3,861 | ​
Gathering, compression and water handling | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 548,846 | ​ | ​ | (548,846) | ​ | ​ | — | ​
Marketing | ​ | ​ | — | ​ | ​ | 97,938 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 97,938 | ​
Amortization of deferred revenue, VPP | ​ | ​ | 13,477 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 13,477 | ​
Other revenue and income | ​ | ​ | 1,720 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 1,720 | ​
Total revenue | ​ | ​ | 2,002,987 | ​ | ​ | 97,938 | ​ | ​ | 548,846 | ​ | ​ | (548,846) | ​ | ​ | 2,100,925 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Operating expenses: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Lease operating | ​ | ​ | 58,880 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 58,880 | ​
Gathering and compression | ​ | ​ | 445,669 | ​ | ​ | — | ​ | ​ | 52,333 | ​ | ​ | (52,333) | ​ | ​ | 445,669 | ​
Processing | ​ | ​ | 525,780 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 525,780 | ​
Transportation | ​ | ​ | 364,274 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 364,274 | ​
Water handling | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 57,994 | ​ | ​ | (57,994) | ​ | ​ | — | ​
Production and ad valorem taxes | ​ | ​ | 100,101 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 100,101 | ​
Marketing | ​ | ​ | — | ​ | ​ | 130,620 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 130,620 | ​
Exploration | ​ | ​ | 1,245 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 1,245 | ​
General and administrative (excluding equity-based compensation) | ​ | ​ | 82,062 | ​ | ​ | — | ​ | ​ | 21,514 | ​ | ​ | (21,514) | ​ | ​ | 82,062 | ​
Equity-based compensation | ​ | ​ | 33,228 | ​ | ​ | — | ​ | ​ | 20,926 | ​ | ​ | (20,926) | ​ | ​ | 33,228 | ​
Depletion, depreciation and amortization | ​ | ​ | 379,108 | ​ | ​ | — | ​ | ​ | 74,671 | ​ | ​ | (74,671) | ​ | ​ | 379,108 | ​
Impairment of property and equipment | ​ | ​ | 5,503 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 5,503 | ​
Accretion of asset retirement obligations | ​ | ​ | 1,556 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 1,556 | ​
Loss on sale of assets | ​ | ​ | 170 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 170 | ​
Contract termination, loss contingency, settlements and other operating expenses | ​ | ​ | 5,076 | ​ | ​ | — | ​ | ​ | 2,404 | ​ | ​ | (2,404) | ​ | ​ | 5,076 | ​
Total operating expenses | ​ | ​ | 2,002,652 | ​ | ​ | 130,620 | ​ | ​ | 229,842 | ​ | ​ | (229,842) | ​ | ​ | 2,133,272 | ​
Operating income (loss) | ​ | $ | 335 | ​ | ​ | (32,682) | ​ | ​ | 319,004 | ​ | ​ | (319,004) | ​ | ​ | (32,347) | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Equity in earnings of unconsolidated affiliates | ​ | $ | 44,228 | ​ | ​ | — | ​ | ​ | 55,127 | ​ | ​ | (55,127) | ​ | ​ | 44,228 | ​

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

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​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | 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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Exploration and Production Segment

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

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Six Months Ended | ​ | Amount of | ​ | ​ | ​ | ​
​ | ​ | June 30, | ​ | Increase | ​ | Percent | ​ | ​
​ |  | 2024 |  | 2025 |  | (Decrease) |  | Change | ​ | ​
Production data (1) (2): | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Natural gas (Bcf) | ​ | ​ | 397 | ​ | ​ | 398 | ​ | ​ | 1 | ​ | * | ​ | ​
C2 Ethane (MBbl) | ​ | ​ | 14,571 | ​ | ​ | 14,366 | ​ | ​ | (205) | ​ | (1) | % | ​
C3+ NGLs (MBbl) | ​ | ​ | 21,078 | ​ | ​ | 20,837 | ​ | ​ | (241) | ​ | (1) | % | ​
Oil (MBbl) | ​ | ​ | 1,987 | ​ | ​ | 1,524 | ​ | ​ | (463) | ​ | (23) | % | ​
Combined (Bcfe) | ​ | ​ | 623 | ​ | ​ | 618 | ​ | ​ | (5) | ​ | (1) | % | ​
Daily combined production (MMcfe/d) | ​ | ​ | 3,423 | ​ | ​ | 3,414 | ​ | ​ | (9) | ​ | * | ​ | ​
Average prices before effects of derivative settlements (3): | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Natural gas (per Mcf) | ​ | $ | 2.14 | ​ | ​ | 3.69 | ​ | ​ | 1.55 | ​ | 72 | % | ​
C2 Ethane (per Bbl) (4) | ​ | $ | 8.84 | ​ | ​ | 12.04 | ​ | ​ | 3.20 | ​ | 36 | % | ​
C3+ NGLs (per Bbl) | ​ | $ | 41.67 | ​ | ​ | 41.71 | ​ | ​ | 0.04 | ​ | * | ​ | ​
Oil (per Bbl) | ​ | $ | 64.51 | ​ | ​ | 55.14 | ​ | ​ | (9.37) | ​ | (15) | % | ​
Weighted Average Combined (per Mcfe) | ​ | $ | 3.18 | ​ | ​ | 4.20 | ​ | ​ | 1.02 | ​ | 32 | % | ​
Average realized prices after effects of derivative settlements (3): | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Natural gas (per Mcf) | ​ | $ | 2.15 | ​ | ​ | 3.65 | ​ | ​ | 1.50 | ​ | 70 | % | ​
C2 Ethane (per Bbl) (4) | ​ | $ | 8.84 | ​ | ​ | 12.04 | ​ | ​ | 3.20 | ​ | 36 | % | ​
C3+ NGLs (per Bbl) | ​ | $ | 41.74 | ​ | ​ | 41.71 | ​ | ​ | (0.03) | ​ | * | ​ | ​
Oil (per Bbl) | ​ | $ | 64.36 | ​ | ​ | 55.08 | ​ | ​ | (9.28) | ​ | (14) | % | ​
Weighted Average Combined (per Mcfe) | ​ | $ | 3.20 | ​ | ​ | 4.17 | ​ | ​ | 0.97 | ​ | 30 | % | ​
Average costs (per Mcfe): | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Lease operating | ​ | $ | 0.09 | ​ | ​ | 0.12 | ​ | ​ | 0.03 | ​ | 33 | % | ​
Gathering and compression | ​ | $ | 0.72 | ​ | ​ | 0.77 | ​ | ​ | 0.05 | ​ | 7 | % | ​
Processing | ​ | $ | 0.84 | ​ | ​ | 0.88 | ​ | ​ | 0.04 | ​ | 5 | % | ​
Transportation | ​ | $ | 0.58 | ​ | ​ | 0.61 | ​ | ​ | 0.03 | ​ | 5 | % | ​
Production and ad valorem taxes | ​ | $ | 0.16 | ​ | ​ | 0.15 | ​ | ​ | (0.01) | ​ | (6) | % | ​
Marketing expense, net | ​ | $ | 0.05 | ​ | ​ | 0.06 | ​ | ​ | 0.01 | ​ | 20 | % | ​
General and administrative (excluding equity-based compensation) | ​ | $ | 0.13 | ​ | ​ | 0.14 | ​ | ​ | 0.01 | ​ | 8 | % | ​
Depletion, depreciation, amortization and accretion | ​ | $ | 0.61 | ​ | ​ | 0.61 | ​ | ​ | — | ​ | * | ​ | ​

*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 six months ended June 30, 2024 and 2025 includes $2 million and $0.5 million, respectively, of proceeds related to a take-or-pay contract. Excluding the effect of these proceeds, the average realized price for ethane before and after the effects of derivatives for the six months ended June 30, 2024 and 2025 would have been $8.72 per Bbl and $12.01 per Bbl.

​

Natural gas sales. Revenues from sales of natural gas increased from $849 million for the six months ended June 30, 2024 to $1.5 billion for the six months ended June 30, 2025, an increase of $620 million, or 73%. Higher commodity prices (excluding the effects of derivative settlements) during the six months ended June 30, 2025 accounted for an approximate $619 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). Higher natural gas production volumes accounted for an approximate $1 million increase in year-over-year natural gas sales revenue (calculated as the change in year-to-year volumes times the prior year average price).

NGLs sales. Revenues from sales of NGLs remained consistent at $1.0 billion for the six months ended June 30, 2024 and 2025. Higher commodity prices (excluding the effects of derivative settlements) during the six months ended June 30, 2025 accounted for an approximate $47 million increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). Lower NGLs production volumes accounted for an approximate $12 million decrease in year-over-year NGLs revenues, respectively (calculated as the change in year-to-year volumes times the prior year average price).

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Oil sales. Revenues from sales of oil decreased from $128 million for the six months ended June 30, 2024 to $84 million for the six months ended June 30, 2025, a decrease of $44 million, or 34%. Lower oil production volumes during the six months ended June 30, 2025 accounted for an approximate $30 million decrease in year-over-year oil revenues (calculated as the change in year-to-year volumes times the prior year average price). Lower oil prices, excluding the effects of derivative settlements, accounted for an approximate $14 million decrease in year-over-year oil revenues (calculated as the change in the year-to-year average price times current year production volumes).

Commodity derivative fair value gains (losses). Our commodity derivatives included fixed price swaps, collars, basis swaps, call options and embedded put options. Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment. Consequently, all mark-to-market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our statements of operations and comprehensive income (loss). For the six months ended June 30, 2024 and 2025, our commodity hedges resulted in derivative fair value gains of $4 million and fair value losses of $18 million, respectively. For the six months ended June 30, 2024, commodity derivative fair value gains included $7 million of net cash proceeds for settled derivative gains. For the six months ended June 30, 2025, commodity derivative fair value losses included $17 million of net cash payments for settled derivative losses.

Commodity derivative fair value gains or losses vary based on future commodity prices and have no cash flow impact until the derivative contracts are settled or monetized prior to settlement. Derivative asset or liability positions at the end of any accounting period may reverse to the extent future commodity prices increase or decrease from their levels at the end of the accounting period, or as gains or losses are realized through settlement. Additionally, the substantial majority of our expected production is currently unhedged for 2025 and beyond, which limits our exposure to volatility in the fair value of our derivative instruments related to commodity price changes in the future.

Amortization of deferred revenue, VPP. Amortization of deferred revenues associated with the VPP remained consistent at $13 million for the six months ended June 30, 2024 and 2025. Amortization of the deferred revenues associated with the VPP are recognized as the production volumes are delivered at $1.61 per MMBtu over the contractual term.

Lease operating expense. Lease operating expense increased from $59 million, or $0.09 per Mcfe, for the six months ended June 30, 2024 to $71 million, or $0.12 per Mcfe, for the six months ended June 30, 2025, an increase of $12 million primarily due to higher oilfield service and workover costs between periods, as well as increased produced water trucking and disposal costs as a result of our completion activity timing during the six months ended June 30, 2025.

Gathering, compression, processing and transportation expense. Gathering, compression, processing and transportation expense increased from $1.3 billion for the six months ended June 30, 2024 to $1.4 billion for the six months ended June 30, 2025, an increase of $0.1 billion, or 5%. This fluctuation was primarily a result of the following:

| ● | Gathering and compression costs on a per unit basis increased from $0.72 per Mcfe for the six months ended June 30, 2024 to $0.77 per Mcfe for the six months ended June 30, 2025, primarily due to 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 increased from $0.84 per Mcfe for the six months ended June 30, 2024 to $0.88 per Mcfe for the six months ended June 30, 2025, primarily due to increased costs for NGLs processing and transportation, which includes an annual CPI-based adjustment during the first quarter of 2025, and higher NGLs transportation fees between periods.

| ● | Transportation costs on a per unit basis increased from $0.58 per Mcfe for the six months ended June 30, 2024 to $0.61 per Mcfe for the six months ended June 30, 2025, primarily due to higher fuel costs as a result of higher natural gas prices between periods and higher demand fees for certain pipelines during the six months ended June 30, 2025.

Production and ad valorem tax expense. Production and ad valorem taxes decreased from $100 million for the six months ended June 30, 2024 to $90 million for the six months ended June 30, 2025, a decrease of $10 million, or 10%, primarily due to lower ad valorem taxes, partially offset by higher severance taxes as a result of increased natural gas prices during the six months ended June 30, 2025. Production and ad valorem taxes as a percentage of natural gas revenues decreased from 12% for the six months ended June 30, 2024 to 6% for the six months ended June 30, 2025, primarily as a result of lower ad valorem taxes. West Virginia ad valorem taxes in 2024 were based on commodity prices during 2022, and West Virginia ad valorem taxes in 2025 are based on commodity prices during 2023.

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General and administrative expense. General and administrative expense (excluding equity-based compensation expense) increased from $82 million for the six months ended June 30, 2024 to $89 million for six months ended June 30, 2025, an increase of $7 million, or 8%, primarily due to higher professional service fees between periods. General and administrative expense on a per unit basis (excluding equity-based compensation) increased from $0.13 per Mcfe for the six months ended June 30, 2024 to $0.14 per Mcfe for the six months ended June 30, 2025 primarily as a result of higher overall costs between periods.

Equity-based compensation expense. Non-cash equity-based compensation expense remained relatively consistent at $33 million and $31 million for the six months ended June 30, 2024 and 2025, respectively. See Note 9—Equity-Based Compensation to the unaudited condensed consolidated financial statements for additional information.

Depletion, depreciation and amortization expense. DD&A expense remained relatively consistent at $379 million, or $0.61 per Mcfe, and $374 million, or $0.61 per Mcfe, for the six months ended June 30, 2024 and 2025, respectively.

Impairment of property and equipment. Impairment of oil and gas properties increased from $6 million for the six months ended June 30, 2024 to $12 million for the six months ended June 30, 2025, primarily due to higher impairments of expiring leases between periods. During both periods, we recognized impairments primarily related to expiring leases as well as design and initial costs related to pads we no longer plan to place into service.

Contract termination, loss contingency, settlements and other operating expenses. Contract termination, loss contingency, settlements and other operating expenses increased from $5 million for the six months ended June 30, 2024 to $12 million for the six months ended June 30, 2025, an increase of $7 million. This increase was primarily due to a loss contingency recorded during the three months ended June 30, 2025. See Note 14—Contingencies 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 increased from $33 million, or $0.05 per Mcfe, for the six months ended June 30, 2024 to $35 million, or $0.06 per Mcfe, for the six months ended June 30, 2025, primarily due to higher firm transportation tariffs and pipeline maintenance between periods.

M arketing revenue. Marketing revenue decreased from $98 million for the six months ended June 30, 2024 to $59 million for the six months ended June 30, 2025, a decrease of $39 million, or 39%. This fluctuation primarily resulted from the following:

| ● | Natural gas marketing revenue decreased by $10 million between periods primarily due to lower natural gas marketing volumes, partially offset by higher natural gas prices. Lower natural gas marketing volumes accounted for a $12 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and higher natural gas prices accounted for a $2 million increase in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes).

| ● | Oil marketing revenue decreased by $34 million between periods primarily due to lower oil marketing volumes and prices. Lower oil marketing volumes accounted for a $23 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and lower oil prices accounted for an $11 million decrease 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 $2 million between periods primarily due to higher ethane and C3+ NGLs marketing volumes and prices.

Marketing expense. Marketing expense decreased from $131 million for the six months ended June 30, 2024 to $95 million for the six months ended June 30, 2025, a decrease of $36 million, or 27%. Marketing expense includes the cost of third-party purchased natural gas, NGLs and oil as well as firm transportation costs, including costs related to current excess firm capacity. The cost of third-party natural gas and oil purchases decreased $8 million and $33 million between periods,

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respectively, and the cost of third-party NGLs purchases increased $2 million between periods. The total cost of third-party commodity purchases decreased primarily due to lower marketing volumes between periods, partially offset by higher natural gas prices during the six months ended June 30, 2025. Firm transportation costs increased from $43 million for the six months ended June 30, 2024 to $47 million for the six months ended June 30, 2025, an increase of $4 million, or 9%, primarily due to the increase in firm transportation tariffs between periods.

Antero Midstream Segment

Antero Midstream revenue. Revenue from the Antero Midstream segment increased from $549 million for the six months ended June 30, 2024 to $597 million for the six months ended June 30, 2025, an increase of $48 million. This increase is primarily due to higher gathering and processing revenues of $31 million and higher water handling revenues of $17 million. The increased gathering and processing revenues between periods is primarily a result of increased throughput and annual CPI-based gathering and compression rate adjustments between periods. The increased water handling revenues between periods is primarily due to higher wastewater trucking and disposal volumes, increased wastewater trucking and disposal costs that are billed at cost plus 3% and higher fresh water delivery volumes during the six months ended June 30, 2025, as well as increased blending cost of service fees and an increase to the fresh water delivery rate as a result of the annual CPI-based rate adjustment between periods.

Antero Midstream operating expense. Total operating expense related to the Antero Midstream segment increased from $230 million for the six months ended June 30, 2024 to $233 million for the six months ended June 30, 2025, an increase of $3 million. This increase is primarily due to higher direct operating expenses as a result of increased water handling volumes and costs, as well as increased blending costs during the six months ended June 30, 2025, partially offset by lower depreciation expense associated with Antero Midstream’s program to repurpose underutilized compressor units to expand existing or construct new compressor stations between periods.

Items Not Allocated to Segments

Interest expense. Interest expense decreased from $63 million for the six months ended June 30, 2024 to $43 million for the six months ended June 30, 2025, a decrease of $20 million or 31%, primarily due to the redemption or repurchase of $139 million aggregate principal amount of our Senior Notes and lower average Credit Facility borrowings and interest rates during the six months ended June 30, 2025.

Loss on early extinguishment of debt. There was no loss on early extinguishment of debt for the six months ended June 30, 2024. 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. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information.

Income tax expense. For the six months ended June 30, 2024, we had an income tax benefit of $11 million, with an effective tax rate of 22%, related to our loss before income taxes of $51 million. For the six months ended June 30, 2025, we had an income tax expense of $103 million, with an effective tax rate of 21%, related to our income before income taxes of $489 million. The increase in the effective tax rate between periods was primarily due to the effects of noncontrolling interests and stock compensation expense. See Note 2—Summary of Significant Accounting Policies to the unaudited condensed consolidated financial statements for additional information on the effects of the OBBB.

Capital Resources and Liquidity

Sources and Uses of Cash

Our primary sources of liquidity have been through net cash provided by operating activities, borrowings under our Credit Facility, issuances of debt and equity securities and additional contributions from our asset sales, including our drilling 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.

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Based on strip prices as of June 30, 2025, we believe that net cash provided by operating activities and available borrowings under the Credit Facility will be sufficient to meet our cash requirements, including normal operating needs, debt service obligations, capital expenditures and commitments and contingencies for at least the next 12 months.

Cash Flows

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

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Six Months Ended June 30, | ​
​ | ​ | 2024 |  | 2025 |
Net cash provided by operating activities | ​ | $ | 405,109 | ​ | ​ | 950,097 | ​
Net cash used in investing activities | ​ | ​ | (414,125) | ​ | ​ | (405,380) | ​
Net cash provided by (used in) financing activities | ​ | ​ | 9,016 | ​ | ​ | (544,717) | ​
Net increase in cash and cash equivalents | ​ | $ | — | ​ | ​ | — | ​

​

Operating activities. Net cash provided by operating activities was $405 million and $950 million for the six months ended June 30, 2024 and 2025, respectively. Net cash provided by operating activities increased between periods primarily due to higher natural gas and NGLs prices, lower interest expense and changes in working capital, partially offset by lower oil revenues between periods and higher gathering, compression, processing and transportation expenses.

Our net operating cash flows are sensitive to many variables, the most significant of which is the volatility of natural gas, NGLs and oil prices, as well as volatility in the cash flows attributable to settlement of our commodity derivatives. Prices for natural gas, NGLs and oil are primarily determined by prevailing market conditions. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets, storage capacity and other variables influence the market conditions for these products. These factors are beyond our control and are difficult to predict.

Investing activities. Net cash used in investing activities decreased from $414 million for the six months ended June 30, 2024 to $405 million for the six months ended June 30, 2025, primarily due to slightly decreased drilling activity during the six months ended June 30, 2025.

Financing activities. Net cash provided by financing activities was $9 million for the six months ended June 30, 2024. Net cash used in financing activities was $545 million for the six months ended June 30, 2025. The increase in net cash used in financing activities between periods is primarily due to higher net repayments on our Credit Facility of $332 million, redemptions and repurchases of $139 million principal amount of our Senior Notes during the six months ended June 30, 2025, and share repurchases of $85 million during the six months ended June 30, 2025, partially offset by decreased distributions to the noncontrolling interests in Martica of $5 million between periods.

2025 Capital Budget and Capital Spending

On February 12, 2025, we announced a net capital budget for 2025 of $725 million to $800 million. On July 30, 2025, we announced a decrease in our net capital budget to reflect our drilling and completion operational efficiencies. Our revised net capital budget for 2025 is $725 million to $775 million. Our revised budget includes: a range of $650 million to $675 million for drilling and completion and $75 million to $100 million for leasehold expenditures. We do not budget for acquisitions. During 2025, we plan to complete 60 to 65 net horizontal wells in the Appalachian Basin. We periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, drilling results, leasehold acquisition opportunities and commodity prices.

For the three months ended June 30, 2025, our total consolidated capital expenditures were $199 million, including drilling and completion costs of $171 million, leasehold acquisitions of $26 million and other capital expenditures of $2 million. For the six months ended June 30, 2025, our total consolidated capital expenditures were $387 million, including drilling and completion costs of $328 million, leasehold acquisitions of $56 million and other capital expenditures of $3 million.

Debt Agreements

See Note 7—Long Term Debt to the unaudited condensed consolidated financial statements included in this Quarterly Report on Form 10-Q and to “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in the 2024 Form 10-K for information on our debt agreements.

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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 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 2024 Form 10-K for information on our critical accounting estimates.

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, 2025, 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, 2024 and 2025.

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

New Accounting Pronouncements

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

Off-Balance Sheet Arrangements

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

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Commodity Hedging Activities

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

We may enter into financial derivative instruments for a portion of our natural gas, NGLs and oil production when circumstances warrant and management believes that favorable future prices can be secured in order to mitigate some of the potential negative impact on our cash flows caused by changes in commodity prices. Due to our improved liquidity and leverage position as compared to historical levels, the substantial majority of our expected production is unhedged. For the three months ended June 30, 2024 and 2025, 2% and 4%, respectively, of our production was hedged through commodity derivatives. For the six months ended June 30, 2024 and 2025, 4% of our production was hedged through commodity derivatives.

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 call or embedded put options, among others. These contracts are financial instruments and do not require or allow for physical delivery of the hedged commodity. As of June 30, 2025, our commodity derivatives included fixed swaps, collars, call options and embedded put options at index-based pricing for a nominal 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, 2025, our revenues would have decreased by $74 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, 2025.

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

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, 2024 and June, 2025, the estimated fair value of our commodity derivative instruments was a net liability of $47 million and $48 million, respectively, comprised of current and noncurrent assets and liabilities.

Counterparty and Customer Credit Risk

Our principal exposures to credit risk are through receivables resulting from the following: the sale of our natural gas, NGLs and oil production ($368 million as of June 30, 2025), which we market to energy companies, end users and refineries, and commodity derivative contracts ($2 million as of June 30, 2025).

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

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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, 2025, we have commodity hedges in place with seven different counterparties, six of which are lenders under the Unsecured Credit Facility. We had derivative assets of $1 million with bank counterparties under our Unsecured Credit Facility as of June 30, 2025. 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, 2025. We believe that all of the counterparties to our derivative instruments are acceptable credit risks as of June 30, 2025. 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, 2025, we did not have any past-due receivables from, or payables to, any of the counterparties to our derivative contracts.

Interest Rate Risks

Our primary exposure to interest rate risk results from outstanding borrowings under the Credit Facility, which has a floating interest rate. The average annualized interest rate incurred on the Credit Facility for borrowings during the six months ended June 30, 2025 was 6.0%. We estimate that a 1.0% increase in the applicable average interest rates for the six months ended June 30, 2025 would have resulted in an estimated $1 million increase in interest expense.

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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, 2025 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, 2025 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 2024 Form 10-K. There have been no material changes to the risks described in such report. We may experience additional risks and uncertainties not currently known to us. Furthermore, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also materially and adversely affect us.

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Item 2. Unregistered Sales of Equity Securities

Issuer Purchases of Equity Securities

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

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | Total Number | ​ | Approximate | ​
​ | ​ | ​ | ​ | ​ | ​ | of Shares | ​ | Dollar Value | ​
​ | ​ | ​ | ​ | ​ | ​ | Repurchased | ​ | of Shares | ​
​ | ​ | ​ | ​ | ​ | ​ | as Part of | ​ | that May | ​
​ | ​ | Total Number | ​ | ​ | ​ | Publicly | ​ | Yet be Purchased | ​
​ | ​ | of Shares | ​ | Average Price | ​ | Announced | ​ | Under the Plan (2) | ​
Period |  | Purchased (1) | ​ | Paid Per Share |  | Plans |  | ($ in thousands) | ​
April 1, 2025 - April 30, 2025 | ​ | 1,826,936 | ​ | $ | 33.76 | ​ | 1,593,290 | ​ | $ | 986,867 | ​
May 1, 2025 - May 31, 2025 | ​ | 486,570 | ​ | ​ | 35.70 | ​ | 415,077 | ​ | ​ | 972,034 | ​
June 1, 2025 - June 30, 2025 | ​ | 165,155 | ​ | ​ | 37.29 | ​ | 163,771 | ​ | ​ | 965,935 | ​
Total | ​ | 2,478,661 | ​ | $ | 34.37 | ​ | 2,172,138 | ​ | ​ | ​ | ​

(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.

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Item 5. Other Information

Credit Facility Maturity Date Extension

Effective July 30, 2025, we obtained the consent of each of the lenders under our Unsecured Credit Facility to extend the Maturity Date from July 30, 2029 to July 30, 2030. The terms of the Credit Facility otherwise remain unchanged. Under the terms of the Unsecured Credit Agreement, we may request two one-year extensions of the Maturity Date, subject to the satisfaction of certain conditions. This is the first such extension.

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Item 6. Exhibits

​ | ​ | ​ | ​
Exhibit Number | ​ | Description of Exhibit | ​
3.1 | ​ | Amended and Restated Certificate of Incorporation of Antero Resources Corporation (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-36120) filed on October 17, 2013). | ​
3.2 | ​ | Certificate of Amendment to Second Amended and Restated Certificate of Incorporation of Antero Resources Corporation, dated June 8, 2023 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-36120) filed on June 8, 2023). | ​
3.3 | ​ | Second Amended and Restated Bylaws of Antero Resources Corporation, dated February 14, 2023 (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 10-K (Commission File No. 001-36120) filed on February 15, 2023). | ​
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, 2025 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations and Comprehensive Income (Loss), (iii) Condensed Consolidated Statements of Equity, (iv) Condensed Consolidated Statements of Cash Flows and (v) Notes to the Condensed Consolidated Financial Statements, tagged as blocks of text. | ​
104 | ​ | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101). | ​

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

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SIGNATURES

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

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​ | ​
ANTERO RESOURCES CORPORATION
​ | ​
By: | /s/ MICHAEL N. KENNEDY
​ | Michael N. Kennedy
​ | Chief Financial Officer and Senior Vice President – Finance
​ | ​
Date: | July 30, 2025

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