Antero Resources (AR) 10-Q 2023 Q3 Quarterly report

Fee

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2023

OR

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

For the transition period from                    to                   

Commission file number: 001-36120

ANTERO RESOURCES CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	80-0162034
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)
1615 Wynkoop Street, Denver, Colorado	80202
(Address of principal executive offices)	(Zip Code)

(303) 357-7310

(Registrant’s telephone number, including area code)

Securities registered pursuant to section 12(b) of the Act:
Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, par value $0.01	AR	New York Stock Exchange

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes  ☐ No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☒ Yes  ☐ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer ☒	Accelerated Filer ☐
Non-accelerated Filer ☐	Smaller Reporting Company ☐
Emerging Growth Company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act) ☐ Yes  ☒ No

Number of shares of the registrant’s common stock outstanding as of October 20, 2023 (in thousands): 300,544

TABLE OF CONTENTS

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS		1
PART I—FINANCIAL INFORMATION		3
Item 1.	Financial Statements (Unaudited)	3
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	52
Item 4.	Controls and Procedures	53
PART II—OTHER INFORMATION		54
Item 1.	Legal Proceedings	54
Item 1A.	Risk Factors	54
Item 2.	Unregistered Sales of Equity Securities	54
Item 4.	Mine Safety Disclosures	54
Item 5	Other Information	54
Item 6.	Exhibits	55
SIGNATURES		56

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, 2022. These forward-looking statements are based on management’s current beliefs, based on currently available information, as to the outcome and timing of future events. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

● our ability to execute our business strategy;

● our production and oil and gas reserves;

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

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

● our ability to execute our return of capital program;

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

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

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

● our hedging strategy and results;

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

● our future drilling plans;

● our projected well costs;

● competition;

● government regulations and changes in laws;

● pending legal or environmental matters;

● marketing of natural gas, NGLs and oil;

● leasehold or business acquisitions;

● costs of developing our properties;

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

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

● general economic conditions;

● credit markets;

1

● uncertainty regarding our future operating results; and

● our other plans, objectives, expectations and intentions contained in this Quarterly Report on Form 10-Q.

We caution investors that these forward-looking statements are subject to all of the risks and uncertainties incidental to our business, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, commodity price volatility, inflation, supply chain or other disruption, availability and cost of drilling, completion and production equipment and services, environmental risks, drilling and completion and other operating risks, marketing and transportation risks, regulatory changes or changes in law, the uncertainty inherent in estimating natural gas, NGLs and oil reserves and in projecting future rates of production, cash flows and access to capital, the timing of development expenditures, conflicts of interest among our stockholders, impacts of geopolitical and world health events, cybersecurity risks, the state of markets for, and availability of, verified quality carbon offsets and the other risks described or referenced under the heading “Item 1A. Risk Factors” herein, including the risk factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2022 (the “2022 Form 10-K”), which is on file with the Securities and Exchange Commission (“SEC”).

Reserve engineering is a process of estimating underground accumulations of natural gas, NGLs and oil that cannot be measured in an exact manner. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data, and the price and cost assumptions made by reservoir engineers. In addition, the results of drilling, testing and production activities, or changes in commodity prices, may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of natural gas, NGLs and oil that are ultimately recovered.

Should one or more of the risks or uncertainties described or referenced in this Quarterly Report on Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this Quarterly Report on Form 10-Q are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements to reflect events or circumstances after the date of this Quarterly Report on Form 10-Q.

2

PART I—FINANCIAL INFORMATION

ANTERO RESOURCES CORPORATION

Condensed Consolidated Balance Sheets

(In thousands, except per share amounts)

			(Unaudited)
	December 31,		September 30,
	2022		2023
Assets
Current assets:
Accounts receivable	$	35,488		36,928
Accrued revenue		707,685		373,391
Derivative instruments		1,900		2,563
Prepaid expenses and other current assets		42,452		9,537
Total current assets		787,525		422,419
Property and equipment:
Oil and gas properties, at cost (successful efforts method):
Unproved properties		997,715		1,020,394
Proved properties		13,234,777		13,773,718
Gathering systems and facilities		5,802		5,802
Other property and equipment		83,909		95,317
		14,322,203		14,895,231
Less accumulated depletion, depreciation and amortization		(4,683,399)		(4,957,449)
Property and equipment, net		9,638,804		9,937,782
Operating leases right-of-use assets		3,444,331		3,128,584
Derivative instruments		9,844		6,627
Investment in unconsolidated affiliate		220,429		220,110
Other assets		17,106		21,035
Total assets	$	14,118,039		13,736,557
Liabilities and Equity
Current liabilities:
Accounts payable	$	77,543		81,904
Accounts payable, related parties		80,708		89,350
Accrued liabilities		461,788		335,093
Revenue distributions payable		468,210		338,244
Derivative instruments		97,765		31,134
Short-term lease liabilities		556,636		551,037
Deferred revenue, VPP		30,552		27,990
Other current liabilities		1,707		6,302
Total current liabilities		1,774,909		1,461,054
Long-term liabilities:
Long-term debt		1,183,476		1,606,895
Deferred income tax liability, net		759,861		805,775
Derivative instruments		345,280		52,584
Long-term lease liabilities		2,889,854		2,581,323
Deferred revenue, VPP		87,813		67,524
Other liabilities		59,692		63,214
Total liabilities		7,100,885		6,638,369
Commitments and contingencies
Equity:
Stockholders' equity:
Preferred stock, $0.01 par value; authorized - 50,000 shares; none issued		—		—
Common stock, $0.01 par value; authorized - 1,000,000 shares; 297,393 shares issued and 297,359 outstanding as of December 31, 2022, and 300,386 shares issued and outstanding as of September 30, 2023		2,974		3,004
Additional paid-in capital		5,838,848		5,822,013
Retained earnings		913,896		1,037,064
Treasury stock, at cost; 34 shares and zero shares as of December 31, 2022 and September 30, 2023, respectively		(1,160)		—
Total stockholders' equity		6,754,558		6,862,081
Noncontrolling interests		262,596		236,107
Total equity		7,017,154		7,098,188
Total liabilities and equity	$	14,118,039		13,736,557

See accompanying notes to unaudited condensed consolidated financial statements.

3

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Operations and Comprehensive Income (Unaudited)

(In thousands, except per share amounts)

	Three Months Ended September 30,
	2022		2023
Revenue and other:
Natural gas sales	$	1,736,039		516,214
Natural gas liquids sales		620,816		482,570
Oil sales		67,025		62,629
Commodity derivative fair value gains (losses)		(530,523)		3,448
Marketing		159,985		53,068
Amortization of deferred revenue, VPP		9,478		7,701
Other revenue and income		1,804		546
Total revenue		2,064,624		1,126,176
Operating expenses:
Lease operating		27,453		33,484
Gathering, compression, processing and transportation		716,388		671,886
Production and ad valorem taxes		92,998		32,258
Marketing		185,377		69,542
Exploration and mine expenses		2,975		591
General and administrative (including equity-based compensation expense of $10,402 and $18,458 in 2022 and 2023, respectively)		42,903		58,425
Depletion, depreciation and amortization		169,607		176,259
Impairment of property and equipment		33,924		13,476
Accretion of asset retirement obligations		630		889
Contract termination and loss contingency		17,995		13,659
Loss (gain) on sale of assets		214		(136)
Other operating expense		—		111
Total operating expenses		1,290,464		1,070,444
Operating income		774,160		55,732
Other income (expense):
Interest expense, net		(28,326)		(31,634)
Equity in earnings of unconsolidated affiliate		14,972		22,207
Loss on early extinguishment of debt		(30,307)		—
Loss on convertible note inducement		(169)		—
Total other expense		(43,830)		(9,427)
Income before income taxes		730,330		46,305
Income tax expense		(135,823)		(13,663)
Net income and comprehensive income including noncontrolling interests		594,507		32,642
Less: net income and comprehensive income attributable to noncontrolling interests		34,748		14,834
Net income and comprehensive income attributable to Antero Resources Corporation	$	559,759		17,808
Income per share—basic	$	1.83		0.06
Income per share—diluted	$	1.72		0.06
Weighted average number of shares outstanding:
Basic		305,343		300,141
Diluted		325,997		311,534

See accompanying notes to unaudited condensed consolidated financial statements.

4

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Operations and Comprehensive Income (Unaudited)

(In thousands, except per share amounts)

	Nine Months Ended September 30,
	2022		2023
Revenue and other:
Natural gas sales	$	4,290,825		1,621,659
Natural gas liquids sales		1,983,509		1,375,738
Oil sales		219,504		172,402
Commodity derivative fair value gains (losses)		(1,807,565)		137,924
Marketing		335,173		155,390
Amortization of deferred revenue, VPP		28,125		22,852
Other revenue and income		3,578		1,864
Total revenue		5,053,149		3,487,829
Operating expenses:
Lease operating		70,486		91,553
Gathering, compression, processing and transportation		1,962,878		1,981,033
Production and ad valorem taxes		227,648		117,692
Marketing		415,571		217,078
Exploration and mine expenses		5,267		2,097
General and administrative (including equity-based compensation expense of $23,222 and $44,988 in 2022 and 2023, respectively)		123,033		169,587
Depletion, depreciation and amortization		511,390		515,247
Impairment of property and equipment		79,749		44,746
Accretion of asset retirement obligations		3,878		2,971
Contract termination and loss contingency		20,099		47,650
Loss (gain) on sale of assets		2,071		(447)
Other operating expense		—		336
Total operating expenses		3,422,070		3,189,543
Operating income		1,631,079		298,286
Other income (expense):
Interest expense, net		(100,252)		(85,262)
Equity in earnings of unconsolidated affiliate		54,863		58,986
Loss on early extinguishment of debt		(45,375)		—
Loss on convertible note inducement		(169)		(86)
Total other expense		(90,933)		(26,362)
Income before income taxes		1,540,146		271,924
Income tax expense		(308,302)		(46,013)
Net income and comprehensive income including noncontrolling interests		1,231,844		225,911
Less: net income and comprehensive income attributable to noncontrolling interests		63,369		77,756
Net income and comprehensive income attributable to Antero Resources Corporation	$	1,168,475		148,155
Income per share—basic	$	3.77		0.50
Income per share—diluted	$	3.51		0.48
Weighted average number of shares outstanding:
Basic		309,954		298,461
Diluted		333,738		310,958

See accompanying notes to unaudited condensed consolidated financial statements.

5

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)

(In thousands)

					Additional		Retained Earnings
	Common Stock				Paid-in		(Accumulated		Treasury Stock				Noncontrolling		Total
	Shares		Amount		Capital		Deficit)		Shares		Amount		Interests		Equity
Balances, December 31, 2021		313,930	$	3,139		6,371,398		(617,377)		—	$	—		308,932		6,066,092
Equity component of 2026 Convertible Notes, net		—		—		(24,411)		3,229		—		—		—		(21,182)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		780		8		(10,385)		—		—		—		—		(10,377)
Repurchases and retirements of common stock		(3,690)		(37)		(74,745)		(25,263)		—		—				(100,045)
Equity-based compensation		—		—		4,649		—		—		—		—		4,649
Distributions to noncontrolling interests		—		—		—		—		—		—		(35,757)		(35,757)
Net loss and comprehensive loss		—		—		—		(156,419)				—		(18,277)		(174,696)
Balances, March 31, 2022		311,020		3,110		6,266,506		(795,830)		—		—		254,898		5,728,684
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		2,112		21		(54,463)		—		—		—		—		(54,442)
Conversion of 2026 Convertible Notes		921		9		3,955		—		—		—		—		3,964
Repurchases and retirements of common stock		(5,241)		(52)		(104,524)		(88,430)		—		—		—		(193,006)
Equity-based compensation		—		—		8,171		—		—		—		—		8,171
Distributions to noncontrolling interests		—		—		—		—		—		—		(31,541)		(31,541)
Net income and comprehensive income		—		—		—		765,135		—		—		46,898		812,033
Balances, June 30, 2022		308,812		3,088		6,119,645		(119,125)		—		—		270,255		6,273,863
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		25		—		(210)		—		—		—		—		(210)
Conversion of 2026 Convertible Notes		4,751		48		20,230		—		—		—		—		20,278
Repurchases and retirements of common stock		(10,457)		(105)		(208,090)		(174,166)		—		—		—		(382,361)
Equity-based compensation		—		—		10,402		—		—		—		—		10,402
Distributions to noncontrolling interests		—		—		—		—		—		—		(46,217)		(46,217)
Net income and comprehensive income		—		—		—		559,759		—		—		34,748		594,507
Balances, September 30, 2022		303,131	$	3,031		5,941,977		266,468		—	$	—		258,786		6,470,262

See accompanying notes to unaudited condensed consolidated financial statements.

6

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)

(In thousands)

					Additional
	Common Stock				Paid-in		Retained		Treasury Stock				Noncontrolling		Total
	Shares		Amount		Capital		Earnings		Shares		Amount		Interests		Equity
Balances, December 31, 2022		297,393	$	2,974		5,838,848		913,896		(34)	$	(1,160)		262,596		7,017,154
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		514		5		(11,464)		—		—		—		—		(11,459)
Conversion of 2026 Convertible Notes		4,030		40		17,132		—								17,172
Repurchases and retirements of common stock		(2,616)		(26)		(51,503)		(24,987)		34		1,160		—		(75,356)
Equity-based compensation		—		—		13,018		—		—		—		—		13,018
Distributions to noncontrolling interests		—		—		—		—		—		—		(51,339)		(51,339)
Net income and comprehensive income		—		—		—		213,431		—		—		47,771		261,202
Balances, March 31, 2023		299,321		2,993		5,806,031		1,102,340		—		—		259,028		7,170,392
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		1,038		11		(15,909)		—		—		—		—		(15,898)
Equity-based compensation		—		—		13,512		—		—		—		—		13,512
Distributions to noncontrolling interests		—		—		—		—		—		—		(31,745)		(31,745)
Net income (loss) and comprehensive income (loss)		—		—		—		(83,084)		—		—		15,151		(67,933)
Balances, June 30, 2023		300,359		3,004		5,803,634		1,019,256		—		—		242,434		7,068,328
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		25		—		(86)		—		—		—		—		(86)
Conversion of 2026 Convertible Notes		2		—		7		—		—		—		—		7
Equity-based compensation		—		—		18,458		—		—		—		—		18,458
Distributions to noncontrolling interest		—		—		—		—		—		—		(21,161)		(21,161)
Net income and comprehensive income		—		—		—		17,808		—		—		14,834		32,642
Balances, September 30, 2023		300,386	$	3,004		5,822,013		1,037,064		—	$	—		236,107		7,098,188

See accompanying notes to unaudited condensed consolidated financial statements.

7

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Cash Flows (Unaudited)

(In thousands)

	Nine Months Ended September 30,
	2022		2023
Cash flows provided by (used in) operating activities:
Net income including noncontrolling interests	$	1,231,844		225,911
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion		515,268		518,218
Impairments		79,749		44,746
Commodity derivative fair value losses (gains)		1,807,565		(137,924)
Losses on settled commodity derivatives		(1,484,660)		(16,511)
Payments for derivative monetizations		—		(202,339)
Deferred income tax expense		307,326		45,914
Equity-based compensation expense		23,222		44,988
Equity in earnings of unconsolidated affiliate		(54,863)		(58,986)
Dividends of earnings from unconsolidated affiliate		93,854		93,854
Amortization of deferred revenue		(28,125)		(22,852)
Amortization of debt issuance costs, debt discount and debt premium		3,458		2,601
Settlement of asset retirement obligations		(946)		(633)
Contract termination and loss contingency		—		11,901
Loss (gain) on sale of assets		2,071		(447)
Loss on early extinguishment of debt		45,375		—
Loss on convertible note inducement		169		86
Changes in current assets and liabilities:
Accounts receivable		55,229		(1,440)
Accrued revenue		(332,900)		334,294
Other current assets		(13,664)		32,584
Accounts payable including related parties		59,222		12,236
Accrued liabilities		36,632		(118,316)
Revenue distributions payable		237,453		(129,966)
Other current liabilities		(7,222)		4,627
Net cash provided by operating activities		2,576,057		682,546
Cash flows provided by (used in) investing activities:
Additions to unproved properties		(120,139)		(139,121)
Drilling and completion costs		(589,093)		(759,852)
Additions to other property and equipment		(12,188)		(13,073)
Proceeds from asset sales		1,147		447
Change in other assets		1,910		(2,538)
Net cash used in investing activities		(718,363)		(914,137)
Cash flows provided by (used in) financing activities:
Repurchases of common stock		(675,412)		(75,356)
Repayment of senior notes		(1,011,313)		—
Borrowings on bank credit facilities, net		9,000		439,300
Payment of debt issuance costs		(814)		—
Convertible note inducement		(169)		(86)
Distributions to noncontrolling interests in Martica Holdings LLC		(113,515)		(104,245)
Employee tax withholding for settlement of equity compensation awards		(65,029)		(27,443)
Other		(442)		(579)
Net cash provided by (used in) financing activities		(1,857,694)		231,591
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	$	148,668		100,067
Increase (decrease) in accounts payable and accrued liabilities for additions to property and equipment	$	23,633		(22,300)

See accompanying notes to unaudited condensed consolidated financial statements.

8

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(1) Organization

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

(2) Summary of Significant Accounting Policies

(a) Basis of Presentation

These unaudited condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”) applicable to interim financial information and should be read in the context of the Company’s December 31, 2022 consolidated financial statements and notes thereto for a more complete understanding of the Company’s operations, financial position and accounting policies. The Company’s December 31, 2022 consolidated financial statements were included in Antero Resources’ 2022 Annual Report on Form 10-K, which was filed with the SEC.

These unaudited condensed consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information, and, accordingly, do not include all of the information and footnotes required by GAAP for complete consolidated financial statements. In the opinion of management, these unaudited condensed consolidated financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly the Company’s financial position as of December 31, 2022 and September 30, 2023, results of operations for the three and nine months ended September 30, 2022 and 2023 and cash flows for the nine months ended September 30, 2022 and 2023. The Company has no items of other comprehensive income or loss; therefore, its net income or loss is equal to its comprehensive income or loss. Operating results for the period ended September 30, 2023 are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received for natural gas, NGLs and oil, natural production declines, the uncertainty of exploration and development drilling results, fluctuations in the fair value of derivative instruments and other factors.

(b) Principles of Consolidation

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

(c) Cash and Cash Equivalents

The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments. From time to time, the Company may be in the position of a “book overdraft” in which outstanding checks exceed cash and cash equivalents. The Company classifies book overdrafts in accounts payable and revenue distributions payable within its condensed consolidated balance sheets, and classifies the change in accounts payable associated with book overdrafts as an operating activity within its unaudited condensed consolidated statements of cash flows. As of December 31, 2022, the book overdrafts included within accounts payable and revenue distributions payable were $28 million and $43 million, respectively. As of September 30, 2023, the book overdrafts included within accounts payable and revenue distributions payable were $35 million and $19 million, respectively.

(d) Income (Loss) Per Common Share

Income (loss) per common share—basic for each period is computed by dividing net income (loss) attributable to Antero by the basic weighted average number of shares outstanding during the period. Income (loss) per common share—diluted for each period is computed after giving consideration to the potential dilution from (i) outstanding equity awards using the treasury stock method and (ii) shares of common stock issuable upon conversion of the 2026 Convertible Notes (as defined below in Note 7—Long-Term Debt) using the if-converted method. The Company includes restricted stock unit (“RSU”)

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

awards, performance share unit (“PSU”) awards and stock options in the calculation of diluted weighted average shares outstanding based on the number of common shares that would be issuable if the end of the period was also the end of the performance period required for the vesting of the awards. During periods in which the Company incurs a net loss, diluted weighted average shares outstanding are equal to basic weighted average shares outstanding because the effects of all equity awards and the 2026 Convertible Notes are anti-dilutive.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2023		2022		2023
Net income attributable to Antero Resources Corporation—common shareholders	$	559,759		17,808		1,168,475		148,155
Add: Interest expense for 2026 Convertible Notes		830		470		2,764		1,555
Less: Tax-effect of interest expense for 2026 Convertible Notes		(193)		(101)		(642)		(334)
Net income attributable to Antero Resources Corporation—common shareholders and assumed conversions	$	560,396		18,177		1,170,597		149,376
Income per share—basic	$	1.83		0.06		3.77		0.50
Income per share—diluted	$	1.72		0.06		3.51		0.48
Weighted average common shares outstanding—basic		305,343		300,141		309,954		298,461
Weighted average common shares outstanding—diluted		325,997		311,534		333,738		310,958

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

	Three Months Ended September 30,		Nine Months Ended September 30,
	2022	2023	2022	2023
Basic weighted average number of shares outstanding	305,343	300,141	309,954	298,461
Add: Dilutive effect of RSUs	3,041	1,213	3,444	1,419
Add: Dilutive effect of PSUs	1,486	1,105	2,462	1,080
Add: Dilutive effect of 2026 Convertible Notes	16,127	9,075	17,878	9,998
Diluted weighted average number of shares outstanding	325,997	311,534	333,738	310,958
Weighted average number of outstanding securities excluded from calculation of diluted income (loss) per common share (1):
RSUs	—	1,128	—	1,267
PSUs	—	100	—	199
Stock options	349	323	350	324

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

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(e) Recently Issued Accounting Standard

Convertible Debt Instruments

In August 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2020-06, Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity, which eliminates the cash conversion model in Accounting Standards Codification (“ASC”) 470-20, Debt with Conversion and Other Options, that require separate accounting for conversion features, and instead, allows the debt instrument and conversion features to be accounted for as a single debt instrument. It is effective for interim and annual reporting periods beginning after December 31, 2021. The Company adopted the standard effective January 1, 2022 under the modified retrospective transition method, which impacts only the debt instruments outstanding on the adoption date.

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

(3) Transactions

(a) Conveyance of Overriding Royalty Interest

On June 15, 2020, the Company announced the consummation of a transaction with an affiliate of Sixth Street Partners, LLC (“Sixth Street”) relating to certain overriding royalty interests across the Company’s existing asset base (the “ORRIs”).

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

The ORRIs also include an additional overriding royalty interest of 2.00% of the Company’s working interest in the properties underlying the Initial PDP Override (the “Incremental Override”). The Incremental Override (or a portion thereof, as applicable) may be re-conveyed to the Company (at the Company’s election) if certain production targets attributable to the ORRIs are achieved through March 31, 2023. Any portion of the Incremental Override that may not be re-conveyed to the Company based on the Company failing to achieve such production volumes through March 31, 2023 will remain with Martica. As of March 31, 2023, the portion of the Incremental Override that may be re-conveyed to the Company as a result of achieving certain production targets was 76% and the portion that will remain with Martica was 24%.

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

(b) Drilling Partnership

On February 17, 2021, Antero Resources announced the formation of a drilling partnership with QL Capital Partners (“QL”), an affiliate of Quantum Energy Partners, for the Company’s 2021 through 2024 drilling program. Under the terms of the arrangement, each year in which QL participates represents an annual tranche, and QL will be conveyed a working interest in any wells spud by Antero Resources during such tranche year. For 2021, 2022 and 2023, Antero Resources and QL agreed to the estimated internal rate of return (“IRR”) of the Company’s capital budget for each annual tranche, and QL agreed to participate in the 2021, 2022, and 2023 tranches. For 2024, Antero Resources will propose a capital budget and estimated IRR

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

for all wells to be spud during such year and, subject to the mutual agreement of the parties that the estimated IRR for the year exceeds a specified return, QL will be obligated to participate in such tranche. Antero Resources develops and manages the drilling program associated with each tranche, including the selection of wells. Additionally, for each annual tranche in which QL participates, Antero Resources and QL will enter into assignments, bills of sale and conveyances pursuant to which QL will be conveyed a proportionate working interest percentage in each well spud in that year, which conveyances will not be subject to any reversion.

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

The Company has accounted for the drilling partnership as a conveyance under ASC 932, Extractive Activities—Oil and Gas, and such conveyances are recorded in the unaudited condensed consolidated financial statements as QL obtains its proportionate working interest in each well. No gain or loss was recognized for the interests conveyed during the three and nine months ended September 30, 2022 and 2023.

(4) Revenue

(a) Disaggregation of Revenue

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2023		2022		2023		Reportable Segment
Revenues from contracts with customers:
Natural gas sales	$	1,736,039		516,214		4,290,825		1,621,659	Exploration and production
Natural gas liquids sales (ethane)		117,253		78,551		274,546		200,764	Exploration and production
Natural gas liquids sales (C3+ NGLs)		503,563		404,019		1,708,963		1,174,974	Exploration and production
Oil sales		67,025		62,629		219,504		172,402	Exploration and production
Marketing		159,985		53,068		335,173		155,390	Marketing
Other revenue		—		—		—		540	Exploration and production
Total revenue from contracts with customers		2,583,865		1,114,481		6,829,011		3,325,729
Income (loss) from derivatives, deferred revenue and other sources, net		(519,241)		11,695		(1,775,862)		162,100
Total revenue	$	2,064,624		1,126,176		5,053,149		3,487,829

(b) Transaction Price Allocated to Remaining Performance Obligations

For the Company’s product sales that have a contract term greater than one year, the Company utilized the practical expedient in ASC 606, Revenue from Contracts with Customers (“ASC 606”), which does not require the disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under the Company’s product sales contracts, each unit of product delivered to the customer represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. For the Company’s product sales that have a contract term of one year or less, the Company utilized the practical expedient in ASC 606, which does not require the

12

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

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, 2022 and September 30, 2023, the Company’s receivables from contracts with customers were $708 million and $373 million, respectively.

(5) Equity Method Investment

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

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

Balance as of December 31, 2022 (1)	$	220,429
Equity in earnings of unconsolidated affiliate		58,986
Dividends from unconsolidated affiliate		(93,854)
Elimination of intercompany profit		34,549
Balance as of September 30, 2023 (1)	$	220,110

(1) The fair value of the Company’s investment in Antero Midstream as of December 31, 2022 and September 30, 2023 was $1.5 billion and $1.7 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,			September 30,
	2022			2023
Capital expenditures	$	57,361			43,418
Gathering, compression, processing and transportation expenses		162,783			153,634
Marketing expenses		61,118			39,336
Interest expense, net		31,892			15,090
Production and ad valorem taxes		32,536	`		29,349
General and administrative expense		32,477			31,803
Derivative settlements payable		53,732			712
Other		29,889			21,751
Total accrued liabilities	$	461,788			335,093

13

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(7) Long-Term Debt

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

			(Unaudited)
	December 31,		September 30,
	2022		2023
Credit Facility (a)	$	34,800		474,100
8.375% senior notes due 2026 (c)		96,870		96,870
7.625% senior notes due 2029 (d)		407,115		407,115
5.375% senior notes due 2030 (e)		600,000		600,000
4.25% convertible senior notes due 2026 (f)		56,932		39,418
Total principal		1,195,717		1,617,503
Unamortized debt issuance costs		(12,241)		(10,608)
Long-term debt	$	1,183,476		1,606,895

(a) Senior Secured Revolving Credit Facility

Antero Resources has a senior secured revolving credit facility (the “Credit Facility”) with a consortium of banks. Borrowings under the Credit Facility are subject to borrowing base limitations based on the collateral value of Antero Resources’ assets and are subject to regular semi-annual redeterminations. As of December 31, 2022 and September 30, 2023, the Credit Facility had a borrowing base of $3.5 billion and lender commitments of $1.5 billion. During the semi-annual redetermination in October 2023, the borrowing base was re-affirmed at $3.5 billion and lender commitments increased to $1.6 billion. The maturity date of the Credit Facility is the earlier of (i) October 26, 2026 and (ii) the date that is 180 days prior to the earliest stated redemption date of any series of the Company’s then outstanding senior notes. As of September 30, 2023, the Credit Facility had an available borrowing capacity of $524 million.

The Credit Facility contains requirements with respect to leverage and current ratios, and certain covenants, including restrictions on our ability to incur debt and limitations on our ability to pay dividends unless certain customary conditions are met, in each case, subject to customary carve-outs and exceptions. Antero Resources was in compliance with all of the financial covenants under the Credit Facility as of December 31, 2022 and September 30, 2023.

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

As of December 31, 2022, Antero Resources had an outstanding balance under the Credit Facility of $35 million, with a weighted average interest rate of 6.42%, and outstanding letters of credit of $504 million. As of September 30, 2023, Antero Resources had an outstanding balance under the Credit Facility of $474 million, with a weighted average interest rate of 7.68%, and outstanding letters of credit of $502 million.

(b) 5.00% Senior Notes Due 2025

On December 21, 2016, Antero Resources issued $600 million of 5.00% senior notes due March 1, 2025 (the “2025 Notes”) at par. The Company repurchased or otherwise redeemed all of the 2025 Notes between 2020 and the first quarter of 2022, and the 2025 Notes were fully retired as of March 1, 2022. Interest on the 2025 Notes was payable on March 1 and September 1 of each year. See “—Debt Repurchase Program” below for more information.

14

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(c) 8.375% Senior Notes Due 2026

On January 4, 2021, Antero Resources issued $500 million of 8.375% senior notes due July 15, 2026 (the “2026 Notes”) at par. The Company redeemed or otherwise repurchased $403 million principal amount of the 2026 Notes during 2021 and 2022, and as of September 30, 2023, $97 million principal amount of the 2026 Notes remained outstanding. See “—Debt Repurchase Program” below for more information. The 2026 Notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2026 Notes rank pari passu to Antero Resources’ other outstanding senior notes. The 2026 Notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by Antero Resources’ existing subsidiaries that guarantee the Credit Facility and certain of its future restricted subsidiaries. Interest on the 2026 Notes is payable on January 15 and July 15 of each year. Antero Resources may redeem all or part of the 2026 Notes at any time on or after January 15, 2024 at redemption prices ranging from 104.188% on or after January 15, 2024 to 100.00% on or after January 15, 2026. At any time prior to January 15, 2024, Antero Resources may also redeem the 2026 Notes, in whole or in part, at a price equal to 100% of the principal amount of the 2026 Notes plus a “make-whole” premium and accrued and unpaid interest. If Antero Resources undergoes a change of control followed by a rating decline, the holders of the 2026 Notes will have the right to require Antero Resources to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the 2026 Notes, plus accrued and unpaid interest.

(d) 7.625% Senior Notes Due 2029

On January 26, 2021, Antero Resources issued $700 million of 7.625% senior notes due February 1, 2029 (the “2029 Notes”) at par. The Company redeemed or otherwise repurchased $293 million principal amount of the 2029 Notes during 2021 and 2022, and as of September 30, 2023, $407 million principal amount of the 2029 Notes remained outstanding. See “—Debt Repurchase Program” below for more information. The 2029 Notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2029 Notes rank pari passu to Antero Resources’ other outstanding senior notes. The 2029 Notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by Antero Resources’ existing subsidiaries that guarantee the Credit Facility and certain of its future restricted subsidiaries. Interest on the 2029 Notes is payable on February 1 and August 1 of each year. Antero Resources may redeem all or part of the 2029 Notes at any time on or after February 1, 2024 at redemption prices ranging from 103.813% on or after February 1, 2024 to 100.00% on or after February 1, 2027. In addition, on or before February 1, 2024, Antero Resources may redeem up to 35% of the aggregate principal amount of the 2029 Notes, but in an amount not greater than the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 107.625% of the principal amount of the 2029 Notes, plus accrued and unpaid interest, which option the Company partially exercised on October 18, 2021 with its notice to redeem $116 million aggregate principal amount of outstanding 2029 Notes. At any time prior to February 1, 2024, Antero Resources may also redeem the 2029 Notes, in whole or in part, at a price equal to 100% of the principal amount of the 2029 Notes plus a “make-whole” premium and accrued and unpaid interest. If Antero Resources undergoes a change of control followed by a rating decline, the holders of the 2029 Notes will have the right to require Antero Resources to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the 2029 Notes, plus accrued and unpaid interest.

(e) 5.375% Senior Notes Due 2030

On June 1, 2021, Antero Resources issued $600 million of 5.375% senior notes due March 1, 2030 (the “2030 Notes”) at par. The 2030 Notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2030 Notes rank pari passu to Antero Resources’ other outstanding senior notes. The 2030 Notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by Antero Resources’ existing subsidiaries that guarantee the Credit Facility and certain of its future restricted subsidiaries. Interest on the 2030 Notes is payable on March 1 and September 1 of each year. Antero Resources may redeem all or part of the 2030 Notes at any time on or after March 1, 2025 at redemption prices ranging from 102.688% on or after March 1, 2025 to 100.00% on or after March 1, 2028. In addition, on or before March 1, 2025, Antero Resources may redeem up to 35% of the aggregate principal amount of the 2030 Notes, but in an amount not greater than the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 105.375% of the principal amount of the 2030 Notes, plus accrued and unpaid interest. At any time prior to March 1, 2025, Antero Resources may also redeem the 2030 Notes, in whole or in part, at a price equal to 100% of the principal amount of the 2030 Notes plus a “make-whole” premium and accrued and unpaid interest. If Antero Resources undergoes a change of control followed by a rating decline, the holders of the 2030 Notes will have the right to require Antero Resources to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the 2030 Notes, plus accrued and unpaid interest.

15

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(f) 4.25% Convertible Senior Notes Due 2026

On August 21, 2020, Antero Resources issued $250 million in aggregate principal amount of 4.25% convertible senior notes due September 1, 2026 (the “2026 Convertible Notes”). On September 2, 2020, Antero Resources issued an additional $37.5 million of the 2026 Convertible Notes. Proceeds from the issuance of the 2026 Convertible Notes totaled $278.5 million, net of initial purchasers’ fees and issuance cost of $9 million. The Company extinguished $206 million principal amount of the 2026 Convertible Notes in 2021. In addition, between 2022 and the third quarter of 2023, $43 million aggregate principal amount of the 2026 Convertible Notes were converted pursuant to their terms or induced into conversion by the Company. See “—Conversions and Inducements,” for more information. As of September 30, 2023, $39 million principal amount of the 2026 Convertible Notes remained outstanding. The 2026 Convertible Notes were issued pursuant to an indenture and are senior, unsecured obligations of Antero Resources. The 2026 Convertible Notes bear interest at a fixed rate of 4.25% per annum, payable semi-annually in arrears on March 1 and September 1 of each year, commencing on March 1, 2021. Each capitalized term used in this subsection but not otherwise defined in this Quarterly Report on Form 10-Q has the meaning as set forth in the indenture governing the 2026 Convertible Notes.

The initial conversion rate is 230.2026 shares of Antero Resources’ common stock per $1,000 principal amount of 2026 Convertible Notes, subject to adjustment upon the occurrence of specified events. As of September 30, 2023, the if-converted value of the 2026 Convertible Notes was $230 million, which exceeded the principal amount of the 2026 Convertible Notes by $191 million. The 2026 Convertible Notes will mature on September 1, 2026, unless earlier repurchased, redeemed or converted. Before May 1, 2026, noteholders will have the right to convert their 2026 Convertible Notes only upon the occurrence of the following events:

● during any calendar quarter (and only during such calendar quarter) commencing after the calendar quarter ending on September 30, 2020, if the Last Reported Sale Price per share of Antero Resources’ common stock exceeds 130% of the Conversion Price for each of at least 20 Trading Days (whether or not consecutive) during the 30 consecutive Trading Days ending on, and including, the last Trading Day of the immediately preceding calendar quarter (the “Stock Price Condition”);

● during the five consecutive Business Days immediately after any 10 consecutive Trading Day period (such 10 consecutive Trading Day period, the “Measurement Period”) if the Trading Price per $1,000 principal amount of 2026 Convertible Notes, as determined following a request by a noteholder in accordance with the procedures set forth below, for each Trading Day of the Measurement Period was less than 98% of the product of the Last Reported Sales Price per share of common stock on such Trading Day and the conversion rate on such Trading Day;

● if Antero Resources calls any or all of the 2026 Convertible Notes for redemption, at any time prior to the close of business on the scheduled Trading Day immediately preceding the redemption date; or

● upon the occurrence of certain specified corporate events as set forth in the indenture governing the 2026 Convertible Notes.

From and after May 1, 2026, noteholders may convert their 2026 Convertible Notes at any time at their election until the close of business on the second scheduled Trading Day immediately before the maturity date.

Upon conversion, Antero Resources may satisfy its conversion obligation by paying and/or delivering, as the case may be, cash, shares of Antero Resources’ common stock or a combination of cash and shares of Antero Resources’ common stock, at Antero Resources’ election, in the manner and subject to the terms and conditions provided in the indenture governing the 2026 Convertible Notes. The 2026 Convertible Notes have met the Stock Price Condition allowing holders of the 2026 Convertible Notes to exercise their conversion right as of September 30, 2023.

The conversion rate is subject to adjustment under certain circumstances in accordance with the terms of the indenture governing the 2026 Convertible Notes. In addition, following certain corporate events, as described in the indenture governing the 2026 Convertible Notes, that occur prior to the maturity date, Antero Resources will increase the conversion rate for a holder who elects to convert its 2026 Convertible Notes in connection with such a corporate event.

If certain corporate events that constitute a Fundamental Change occur, then noteholders may require Antero Resources to repurchase their 2026 Convertible Notes at a cash repurchase price equal to the principal amount of the 2026

16

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

Convertible Notes to be repurchased, plus accrued and unpaid interest, if any, to, but excluding, the Fundamental Change Repurchase Date. The definition of Fundamental Change includes certain business combination transactions involving Antero Resources and certain de-listing events with respect to Antero Resources’ common stock.

Upon issuance, the Company separately accounted for the liability and equity components of the 2026 Convertible Notes.  The liability component was recorded at the estimated fair value of a similar debt instrument without the conversion feature.  The difference between the principal amount of the 2026 Convertible Notes and the estimated fair value of the liability component was recorded as a debt discount and was amortized to interest expense, together with debt issuance costs, over the term of the 2026 Convertible Notes using the effective interest method, with an effective interest rate of 15.1% per annum.  As of the issuance date, the fair value of the 2026 Convertible Notes was estimated at $172 million, resulting in a debt discount at inception of $116 million.  The equity component, representing the value of the conversion option, was computed by deducting the fair value of the liability component from the initial proceeds of the 2026 Convertible Notes issuance.  This equity component was recorded, net of deferred taxes and issuance costs, in additional paid-in capital within the condensed consolidated balance sheet and statement of stockholders’ equity.

Transaction costs related to the 2026 Convertible Notes issuance were allocated to the liability and equity components based on their relative fair values.  Issuance costs attributable to the liability component were recorded within debt issuance costs on the condensed consolidated balance sheet and were amortized over the term of the 2026 Convertible Notes using the effective interest method.  Issuance costs attributable to the equity component were recorded as a charge to additional paid-in capital within the condensed consolidated balance sheet and statement of stockholders’ equity.

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

Conversions and Inducements

During the nine months ended September 30, 2023, $9 million aggregate principal amount of the 2026 Convertible Notes were converted pursuant to their terms, and an additional $9 million aggregate principal amount of the 2026 Convertible Notes were induced into conversion by the Company. The Company elected to settle these conversions by issuing 4 million shares of common stock to the noteholders together with a cash inducement premium of $0.1 million. There were no conversions of the 2026 Convertible Notes during the nine months ended September 30, 2022.

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

			(Unaudited)
	December 31,		September 30,
	2022		2023
Principal	$	56,932		39,418
Less: unamortized debt issuance costs		(1,159)		(651)
Net carrying value	$	55,773		38,767

Interest expense recognized on the 2026 Convertible Notes related to the stated interest rate and debt issuance costs totaled $1 million and $0.5 million for the three months ended September 30, 2022 and 2023, respectively, and $3 million and $2 million for the nine months ended September 30, 2022 and 2023, respectively.

(g) Debt Repurchase Program

During the first quarter of 2022, the Company redeemed the remaining $585 million aggregate principal amount of its 2025 Notes at a redemption price of 101.25% of the principal amount thereof, plus accrued and unpaid interest and recognized a loss on early debt extinguishment of $11 million. During the second quarter of 2022, the Company repurchased $13 million of its 2026 Notes and $50 million of its 2029 Notes at a weighted average premium of 106% and recognized a loss on early debt extinguishment of $4 million. During the third quarter of 2022, the Company repurchased, through its previously disclosed tender offer and open market transactions, (i) $208 million aggregate principal amount of its 2026 Notes at a weighted average of 109% of the principal amount thereof, plus accrued and unpaid interest and (ii) $118 million aggregate principal amount of its 2029 Notes at a weighted average of 107% of the principal amount thereof, plus accrued and unpaid interest. For the three and nine months ended September 30, 2022, the Company recognized a loss on early debt

17

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

extinguishment from these repurchases of $30 million and $45 million, respectively. There were no debt repurchases or redemptions during the three and nine months ended September 30, 2023.

(8) Asset Retirement Obligations

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

Asset retirement obligations—December 31, 2022	$	59,485
Obligations incurred		924
Accretion expense		2,971
Settlement of obligations		(633)
Revisions to prior estimates		301
Asset retirement obligations—September 30, 2023	$	63,048

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

(9) Equity-Based Compensation and Cash Awards

On June 17, 2020, Antero Resources’ stockholders approved the Antero Resources Corporation 2020 Long-Term Incentive Plan (the “2020 Plan”), which replaced the Antero Resources Corporation Long-Term Incentive Plan (the “2013 Plan”), and the 2020 Plan became effective as of such date. The 2020 Plan provides for grants of stock options (including incentive stock options), stock appreciation rights, restricted stock awards, RSU awards, vested stock awards, dividend equivalent awards and other stock-based and cash awards. The terms and conditions of the awards granted are established by the Compensation Committee of Antero Resources’ Board of Directors. Employees, officers, non-employee directors and other service providers of the Company and its affiliates are eligible to receive awards under the 2020 Plan. No further awards will be granted under the 2013 Plan on or after June 17, 2020.

The 2020 Plan provides for the reservation of 10,050,000 shares of the Company’s common stock, plus the number of certain shares that become available again for delivery from the 2013 Plan in accordance with the share recycling provisions described below. The share recycling provisions allow for all or any portion of an award (including an award granted under the 2013 Plan that was outstanding as of June 17, 2020) that expires or is cancelled, forfeited, exchanged, settled for cash or otherwise terminated without actual delivery of the shares to be considered not delivered and thus, available for new awards under the 2020 Plan. Further, any shares withheld or surrendered in payment of any taxes relating to awards that were outstanding under either the 2013 Plan as of June 17, 2020 or are granted under the 2020 Plan (other than stock options and stock appreciation rights), will again be available for new awards under the 2020 Plan.

A total of 6,896,996 shares were available for future grant under the 2020 Plan as of September 30, 2023.

Antero Midstream Partners LP’s (“Antero Midstream Partners”) general partner was authorized to grant up to 10,000,000 common units representing limited partner interests in Antero Midstream Partners under the Antero Midstream Partners LP Long-Term Incentive Plan (the “AMP Plan”) to non-employee directors of its general partner and certain officers, employees and consultants of Antero Midstream Partners and its affiliates (which includes Antero Resources). Antero Resources deconsolidated Antero Midstream Partners on March 12, 2019, and on such date, each outstanding phantom unit award under the AMP Plan was assumed by Antero Midstream and converted into 1.8926 RSUs (all such RSUs, the “Converted AM RSU Awards”) under the Antero Midstream Corporation Long Term Incentive Plan (the “AM Plan”). Each RSU award under the AM Plan represented a right to receive one share of Antero Midstream common stock. As of September 30, 2023, all Converted AM RSU Awards were fully vested.

18

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 September 30,				Nine Months Ended September 30,
	2022		2023		2022		2023
RSU awards	$	4,974		8,286		12,468		24,268
PSU awards		5,070		9,796		9,501		19,643
Converted AM RSU Awards (1)		8		—		203		1
Equity awards issued to directors		350		376		1,050		1,076
Total expense	$	10,402		18,458		23,222		44,988

(1) Antero Resources recognized compensation expense for equity awards granted under both the 2013 Plan and the AMP Plan because the awards under the AMP Plan are accounted for as if they are distributed by Antero Midstream Partners to Antero Resources. Antero Resources allocates a portion of equity-based compensation expense related to grants prior to March 12, 2019 (date of deconsolidation) to Antero Midstream Partners based on its proportionate share of Antero Resources’ labor costs. As of September 30, 2023, all Converted AM RSU Awards were fully vested, and there is no remaining unamortized expense attributable to these awards.

(a) Restricted Stock Unit Awards

A summary of RSU activity is as follows:

		Weighted
		Average
	Number of	Grant Date
	Shares	Fair Value
Total awarded and unvested—December 31, 2022	4,676,219	$	15.29
Granted	1,469,162		25.88
Vested	(2,214,806)		9.07
Forfeited	(153,402)		24.02
Total awarded and unvested—September 30, 2023	3,777,173	$	22.71

As of September 30, 2023, there was $65 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 March 2023, the Company granted PSU awards to certain of its senior management and executive officers that vest based on Antero Resources’ absolute total shareholder return (“TSR”) determined as of the last day of each of three one-year performance periods ending on March 7, 2024, March 7, 2025 and March 7, 2026, and one cumulative three-year performance period ending on March 7, 2026, in each case, subject to certain continued employment criteria (“2023 Absolute TSR PSUs”). The number of shares of common stock that may ultimately be earned following the end of the cumulative three-year performance period with respect to the 2023 Absolute TSR PSUs ranges from zero to 200% of the target number of 2023 Absolute TSR PSUs originally granted. Expense related to these PSUs is recognized on a graded-vested basis over the term of each performance period. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period.

The following table presents the assumptions used in the Monte Carlo valuation model and the grant date fair value information for the 2023 Absolute TSR PSUs:

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

19

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

Performance Share Unit Awards Based on Leverage Ratio

In March 2023, the Company granted PSUs to certain of its senior management and executive officers that vest based on the Company’s total debt less cash and cash equivalents divided by the Company’s Adjusted EBITDAX (as defined in the award agreement) determined as of the last day of each of three one-year performance periods ending on December 31, 2023, December 31, 2024 and December 31, 2025, in each case, subject to certain continued employment criteria (“2023 Leverage Ratio PSUs”). The number of shares of common stock that may ultimately be earned following the end of the third performance period with respect to the 2023 Leverage Ratio PSUs ranges from zero to 200% of the target number of 2023 Leverage Ratio PSUs originally granted. Expense related to the 2023 Leverage Ratio PSUs is recognized on a graded-vested basis over the term of each performance period that reflects the number of shares of common stock that are expected to be issued at the end of each measurement period, and such expense is reversed if the likelihood of achieving the performance condition becomes improbable. As of September 30, 2023, the likelihood of achieving the performance conditions related to the 2023 Leverage Ratio PSUs was probable.

Summary Information for Performance Share Unit Awards

A summary of PSU activity is as follows:

		Weighted
		Average
	Number of	Grant Date
	Units	Fair Value
Total awarded and unvested—December 31, 2022	1,329,725	$	23.18
Granted	417,466		28.51
Vested (1)	(335,000)		2.97
Total awarded and unvested—September 30, 2023	1,412,191	$	29.54

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

As of September 30, 2023, there was $26 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) Converted AM RSU Awards

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

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

As of September 30, 2023, all Converted AM RSU Awards were fully vested resulting in no unamortized equity-based compensation expense.

20

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(d) Stock Options

A summary of the stock option activity is as follows:

				Weighted
		Weighted		Average
		Average		Remaining	Intrinsic
	Stock	Exercise		Contractual	Value
	Options	Price		Life	(in thousands) (1)
Outstanding—December 31, 2022	323,960	$	50.86	2.0	$	—
Expired	(833)		50.00	—		—
Outstanding—September 30, 2023	323,127	$	50.86	1.2		—
Vested—September 30, 2023	323,127	$	50.86	1.2	$	—
Exercisable—September 30, 2023	323,127	$	50.86	1.2	$	—

(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.

(e) Cash Awards

In January 2020, the Company granted cash awards of $3 million to certain executives under the 2013 Plan, and compensation expense for these awards was recognized ratably over the vesting period for each of three tranches through January 20, 2023. In July 2020, the Company granted additional cash awards in the aggregate of $3 million to certain non-executive employees under the 2020 Plan that vest ratably over four years. As of December 31, 2022 and September 30, 2023, the Company has recorded $1 million and $0.4 million, respectively, in accrued liabilities in the condensed consolidated balance sheets related to unvested cash awards.

(10) Fair Value

The carrying values of accounts receivable and accounts payable as of December 31, 2022 and September 30, 2023 approximated market values because of their short-term nature. The carrying values of the amounts outstanding under the Credit Facility as of December 31, 2022 and September 30, 2023 approximated fair value because the variable interest rates are reflective of current market conditions.

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

					(Unaudited)
	December 31, 2022				September 30, 2023
	Fair		Carrying		Fair		Carrying
	Value (1)		Value (2)		Value (1)		Value (2)
2026 Notes	$	100,987		96,123		99,534		96,293
2029 Notes		410,860		402,872		410,657		403,295
2030 Notes		556,260		593,908		552,720		594,440
2026 Convertible Notes		406,039		55,773		231,163		38,767
Total	$	1,474,146		1,148,676		1,294,074		1,132,795

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

21

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(11) Derivative Instruments

The Company is exposed to certain risks relating to its ongoing business operations, and it may use derivative instruments to manage its commodity price risk.  In addition, the Company periodically enters into contracts that contain embedded features that are required to be bifurcated and accounted for separately as derivatives.

(a) Commodity Derivative Positions

The Company periodically enters into natural gas, NGLs and oil derivative contracts with counterparties to hedge the price risk associated with its production. These derivatives are not entered into for trading purposes. To the extent that changes occur in the market prices of natural gas, NGLs and oil, the Company is exposed to market risk on these open contracts. This market risk exposure is generally offset by the change in market prices of natural gas, NGLs and oil recognized upon the ultimate sale of the Company’s production.

The Company was party to various fixed price commodity swap contracts that settled during the three and nine months ended September 30, 2022 and 2023. The Company enters into these swap contracts when management believes that favorable future sales prices for the Company’s production can be secured. Under these swap agreements, when actual commodity prices upon settlement exceed the fixed price provided by the swap contracts, the Company pays the difference to the counterparty. When actual commodity prices upon settlement are less than the contractually provided fixed price, the Company receives the difference from the counterparty. In addition, the Company has entered into basis swap contracts in order to hedge the difference between the New York Mercantile Exchange (“NYMEX”) index price and a local index price. Under these basis swap agreements, when actual commodity prices upon settlement exceed the fixed price provided by the swap contracts, the Company receives the difference from the counterparty. When actual commodity prices upon settlement are less than the contractually provided fixed price, the Company pays the difference to the counterparty.

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

As of September 30, 2023, the Company’s fixed price swap positions excluding Martica, the Company’s consolidated VIE, were as follows:

				Weighted
				Average
Commodity / Settlement Period	Index	Contracted Volume		Price
Natural Gas
October-December 2023	Henry Hub	43,000	MMBtu/day	$	2.37	/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 September 30, 2023, the Company’s call option and embedded put option arrangements were as follows:

							Embedded
				Call Option			Put Option
Commodity / Settlement Period	Index	Contracted Volume		Strike Price			Strike Price
Natural Gas
October-December 2023	Henry Hub	55,000	MMBtu/day	$	2.466	/MMBtu	$	2.466	/MMBtu
January-December 2024	Henry Hub	53,000	MMBtu/day		2.477	/MMBtu		2.527	/MMBtu
January-December 2025	Henry Hub	44,000	MMBtu/day		2.564	/MMBtu		2.614	/MMBtu
January-December 2026	Henry Hub	32,000	MMBtu/day		2.629	/MMBtu		2.679	/MMBtu

22

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

As of September 30, 2023, the Company’s natural gas basis swap positions, which settle on the pricing index to basis differential of the Columbia Gas Transmission pipeline (“TCO”) to the NYMEX Henry Hub natural gas price were as follows:

				Weighted Average
Commodity / Settlement Period	Index to Basis Differential	Contracted Volume		Hedged Differential
Natural Gas
October-December 2023	NYMEX to TCO	50,000	MMBtu/day	$	0.525	/MMBtu
January-December 2024	NYMEX to TCO	50,000	MMBtu/day		0.530	/MMBtu

As of September 30, 2023, the Company’s fixed price swap positions for Martica, the Company’s consolidated VIE, were as follows:

				Weighted
				Average
Commodity / Settlement Period	Index	Contracted Volume		Price
Natural Gas
October-December 2023	Henry Hub	31,366	MMBtu/day	$	2.35	/MMBtu
January-December 2024	Henry Hub	23,885	MMBtu/day		2.33	/MMBtu
January-March 2025	Henry Hub	18,021	MMBtu/day		2.53	/MMBtu
Natural Gasoline
October-December 2023	Mont Belvieu Natural Gasoline-OPIS Non-TET	217	Bbl/day		40.74	/Bbl
Oil
October-December 2023	West Texas Intermediate	71	Bbl/day		44.66	/Bbl
January-December 2024	West Texas Intermediate	43	Bbl/day		44.02	/Bbl
January-March 2025	West Texas Intermediate	39	Bbl/day		45.06	/Bbl

(b) Summary

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

				(Unaudited)
	Balance Sheet	December 31,		September 30,
	Location	2022		2023
Asset derivatives not designated as hedges for accounting purposes:
Embedded derivatives—current	Derivative instruments	$	1,900		2,563
Embedded derivatives—noncurrent	Derivative instruments		9,844		6,627
Total asset derivatives (1)			11,744		9,190
Liability derivatives not designated as hedges for accounting purposes:
Commodity derivatives—current (2)	Derivative instruments		97,765		31,134
Commodity derivatives—noncurrent (2)	Derivative instruments		345,280		52,584
Total liability derivatives (1)			443,045		83,718
Net derivatives liability (1)		$	(431,301)		(74,528)

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

(2) As of December 31, 2022, $47 million of commodity derivative liabilities, including $28 million of current commodity derivatives and $19 million of noncurrent commodity derivatives, are attributable to the Company’s consolidated VIE, Martica. As of September 30, 2023, $15 million of commodity derivative liabilities, including $9 million of current commodity derivatives and $6 million of noncurrent commodity derivatives, are attributable to the Company’s consolidated VIE, Martica.

23

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

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

							(Unaudited)
	December 31, 2022						September 30, 2023
					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	$	276		(276)		—		495		(495)		—
Embedded derivative assets		11,744		—		11,744		9,190		—		9,190
Commodity derivative liabilities		(443,321)		276		(443,045)		(84,213)		495		(83,718)

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

	Statement of
	Operations	Three Months Ended September 30,				Nine Months Ended September 30,
	Location	2022		2023		2022		2023
Commodity derivative fair value gains (losses) (1)	Revenue	$	(500,557)		5,290		(1,732,720)		138,602
Embedded derivative fair value losses (1)	Revenue	$	(29,966)		(1,842)		(74,845)		(678)

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

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

(12) Leases

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

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

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

The Company considers all contracts that have assets specified in the contract, either explicitly or implicitly, that the Company has substantially all of the capacity of the asset, and has the right to obtain substantially all of the economic benefits of that asset, without the lessor’s ability to have a substantive right to substitute that asset, as leased assets. For any contract deemed to include a leased asset, that asset is capitalized on the balance sheet as a right-of-use asset and a corresponding lease liability is recorded at the present value of the known future minimum payments of the contract using a discount rate on the date of commencement. The leased asset classification is determined at the date of recording as either operating or financing, depending upon certain criteria of the contract.

The discount rate used for present value calculations is the discount rate implicit in the contract. If an implicit rate is not determinable, a collateralized incremental borrowing rate is used at the date of commencement. As new leases commence or previous leases are modified the discount rate used in the present value calculation is the current period applicable discount rate.

24

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

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

(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,		September 30,
Leases	Balance Sheet Classification	2022		2023
Operating Leases
Operating lease right-of-use assets:
Processing plants	Operating lease right-of-use assets	$	1,849,116		1,672,429
Drilling rigs and completion services	Operating lease right-of-use assets		85,405		45,406
Gas gathering lines and compressor stations (1)	Operating lease right-of-use assets		1,463,756		1,371,508
Office space	Operating lease right-of-use assets		41,822		38,736
Vehicles	Operating lease right-of-use assets		756		—
Other office and field equipment	Operating lease right-of-use assets		3,476		505
Total operating lease right-of-use assets		$	3,444,331		3,128,584
Operating lease liabilities:
Short-term operating lease liabilities	Short-term lease liabilities	$	556,137		550,028
Long-term operating lease liabilities	Long-term lease liabilities		2,888,194		2,578,556
Total operating lease liabilities		$	3,444,331		3,128,584
Finance Leases
Finance lease right-of-use assets:
Vehicles	Other property and equipment	$	2,159		3,776
Total finance lease right-of-use assets (2)		$	2,159		3,776
Finance lease liabilities:
Short-term finance lease liabilities	Short-term lease liabilities	$	499		1,009
Long-term finance lease liabilities	Long-term lease liabilities		1,660		2,767
Total finance lease liabilities		$	2,159		3,776

(1) Gas gathering lines and compressor stations includes $1.4 billion and $1.3 billion related to Antero Midstream as of December 31, 2022 and September 30, 2023, respectively. See “—Related party lease disclosure” for additional discussion.

(2) Financing lease assets are recorded net of accumulated amortization of $1 million as of December 31, 2022 and September 30, 2023.

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

25

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(b) Supplemental Information Related to Leases

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

			Three Months Ended September 30,				Nine Months Ended September 30,
Cost	Classification	Location	2022		2023		2022		2023
Operating lease cost	Statement of operations	Gathering, compression, processing and transportation	$	378,246		418,005		1,109,422		1,206,733
Operating lease cost	Statement of operations	General and administrative		2,855		3,105		8,509		9,072
Operating lease cost	Statement of operations	Contract termination		12,000		297		12,000		4,227
Operating lease cost	Statement of operations	Lease operating		44		21		133		63
Operating lease cost	Balance sheet	Proved properties (1)		34,288		40,543		83,146		111,915
Total operating lease cost			$	427,433		461,971		1,213,210		1,332,010
Finance lease cost:
Amortization of right-of-use assets	Statement of operations	Depletion, depreciation and amortization	$	94		464		319		1,102
Interest on lease liabilities	Statement of operations	Interest expense		44		165		78		441
Total finance lease cost			$	138		629		397		1,543
Short-term lease payments			$	38,690		31,324		115,798		103,732

(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):

	Nine Months Ended September 30,
	2022		2023
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	1,067,786		1,023,385
Operating cash flows from finance leases		—		441
Investing cash flows from operating leases		70,654		95,480
Financing cash flows from finance leases		441		580
Noncash activities:
Right-of-use assets obtained in exchange for new operating lease obligations	$	366,194		80,969
Increase to existing right-of-use assets and lease obligations from operating lease modifications, net (1)	$	119,290		12,640

(1) During the nine months ended September 30, 2022, the weighted average discount rate for remeasured operating leases decreased from 5.6% as of December 31, 2021 to 5.2% as of September 30, 2022. During the nine months ended September 30, 2023, the weighted average discount rate for remeasured operating leases increased from 5.1% as of December 31, 2022 to 5.8% as of September 30, 2023.

26

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 September 30, 2023 (in thousands):

	Operating Leases		Financing Leases		Total
Remainder of 2023	$	178,611		386		178,997
2024		703,136		1,546		704,682
2025		609,747		1,504		611,251
2026		556,196		1,148		557,344
2027		457,972		128		458,100
Thereafter		1,252,713		33		1,252,746
Total lease payments		3,758,375		4,745		3,763,120
Less: imputed interest		(629,791)		(969)		(630,760)
Total	$	3,128,584		3,776		3,132,360

(e) Lease Term and Discount Rate

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

	December 31, 2022				September 30, 2023
	Operating Leases		Finance Leases		Operating Leases		Finance Leases
Weighted average remaining lease term	7.2 years		3.5 years		6.7 years		3.2 years
Weighted average discount rate	5.3	%	7.4	%	5.6	%	8.2	%

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

Under the gathering and compression agreements, Antero Midstream receives a low-pressure gathering fee per Mcf, a high-pressure gathering fee per Mcf and a compression fee per Mcf, as applicable, subject to annual adjustments based on the consumer price index. If and to the extent the Company requests that Antero Midstream construct new low pressure lines, high pressure lines 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. In addition, certain of the Marcellus gathering and compression agreements provide for a minimum volume commitment that requires the Company to utilize or pay for 25% of the capacity of new compressor station construction for 10 years.

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

27

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

anniversary of the effective date of the agreement, by either the Company or Antero Midstream on or before the 180th day prior to the anniversary of such effective date. The Company achieved the first threshold volumetric target during each of the first, second and third quarters of 2022 and 2023, and earned fee rebates of $12 million for the three months ended September 30, 2022 and 2023 and $36 million for the nine months ended September 30, 2022 and 2023.

Gathering and compression fees paid by Antero related to these agreements were $164 million and $189 million for the three months ended September 30, 2022 and 2023, respectively. For the nine months ended September 30, 2022 and 2023, gathering and compression fees paid by Antero related to this agreement were $492 million and $550 million, respectively. As of December 31, 2022 and September 30, 2023, $59 million and $63 million, respectively, was included within Accounts payable, related parties on the condensed consolidated balance sheet 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 September 30, 2023 (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 2023	$	297,341		16,820		135,547		43,450		1,961		495,119
2024		1,147,772		63,358		550,237		154,445		8,354		1,924,166
2025		1,134,296		52,011		486,448		124,803		4,875		1,802,433
2026		1,131,882		18,834		459,311		98,033		2,250		1,710,310
2027		1,127,234		17,546		384,444		73,656		—		1,602,880
Thereafter		5,444,784		80,914		1,116,373		136,373		—		6,778,444
Total	$	10,283,309		249,483		3,132,360		630,760		17,440		14,313,352

(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 amounts that Antero Resources is committed to pay; however, the Company will record in its financial statements its proportionate share of costs based on its working interests. See Note 12—Leases to the unaudited condensed consolidated financial statements for more information on the Company’s operating and finance leases.

28

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(d) Other

The Company has entered into various land acquisition and sand supply agreements. Certain of these agreements contain minimum payment obligations over various terms. The values in the table represent the minimum payments due under these arrangements. None of these agreements were determined to be leases.

(e) Contract Terminations

The Company incurs costs associated with the delay or cancellation of certain contracts with third-parties. These costs are recorded in Contract termination and included in the statement of operations and comprehensive income (loss). During the third quarter of 2022, the Company cancelled the construction of the Smithburg 2 gas processing plant and made a cash payment of $12 million. During the first quarter of 2023, the Company executed an early termination of its firm transportation commitment of 200,000 MMBtu per day on the Equitrans pipeline and made a cash payment of $24 million. There are no remaining payment obligations related to any delayed or cancelled contracts as of September 30, 2023.

(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) Other

The Company is party to various other legal proceedings and claims in the ordinary course of its business. The Company believes that certain of these matters will be covered by insurance and that the outcome of other matters will not have a material adverse effect on the Company’s unaudited condensed consolidated financial position, results of operations or cash flows.

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

(15) Related Parties

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

29

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(16) Reportable Segments

(a) Summary of Reportable Segments

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

Exploration and Production

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

Marketing

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

Equity Method Investment in Antero Midstream

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

30

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(b) Reportable Segments Financial Information

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

	Three Months Ended September 30, 2022
					Equity Method
	Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream		Affiliate		Total
Sales and revenues:
Third-party	$	1,904,302		159,985		1,651		(1,651)		2,064,287
Intersegment		337		—		229,383		(229,383)		337
Total revenue		1,904,639		159,985		231,034		(231,034)		2,064,624
Operating expenses:
Lease operating		27,453		—		—		—		27,453
Gathering, compression, processing, transportation and water handling		716,388		—		46,648		(46,648)		716,388
General and administrative		42,903		—		13,587		(13,587)		42,903
Depletion, depreciation and amortization		169,607		—		34,206		(34,206)		169,607
Impairment of property and equipment		33,924		—		—		—		33,924
Other		114,812		185,377		(1,177)		1,177		300,189
Total operating expenses		1,105,087		185,377		93,264		(93,264)		1,290,464
Operating income (loss)	$	799,552		(25,392)		137,770		(137,770)		774,160
Equity in earnings of unconsolidated affiliates	$	14,972		—		24,411		(24,411)		14,972
Capital expenditures for segment assets	$	244,680		—		74,120		(74,120)		244,680

	Three Months Ended September 30, 2023
					Equity Method
	Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream		Affiliate		Total
Sales and revenues:
Third-party	$	1,072,562		53,068		383		(383)		1,125,630
Intersegment		546		—		263,456		(263,456)		546
Total revenue		1,073,108		53,068		263,839		(263,839)		1,126,176
Operating expenses:
Lease operating		33,484		—		—		—		33,484
Gathering, compression, processing, transportation and water handling		671,886		—		51,914		(51,914)		671,886
General and administrative		58,425		—		17,633		(17,633)		58,425
Depletion, depreciation and amortization		176,259		—		30,745		(30,745)		176,259
Impairment of property and equipment		13,476		—		—		—		13,476
Other		47,372		69,542		1,234		(1,234)		116,914
Total operating expenses		1,000,902		69,542		101,526		(101,526)		1,070,444
Operating income (loss)	$	72,206		(16,474)		162,313		(162,313)		55,732
Equity in earnings of unconsolidated affiliates	$	22,207		—		27,397		(27,397)		22,207
Capital expenditures for segment assets	$	912,046		—		45,286		(45,286)		912,046

31

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

	Nine Months Ended September 30, 2022
					Equity Method
	Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream		Affiliate		Total
Sales and revenues:
Third-party	$	4,716,827		335,173		2,288		(2,288)		5,052,000
Intersegment		1,149		—		676,144		(676,144)		1,149
Total revenue		4,717,976		335,173		678,432		(678,432)		5,053,149
Operating expenses:
Lease operating		70,486		—		—		—		70,486
Gathering, compression, processing, transportation and water handling		1,962,878		—		131,959		(131,959)		1,962,878
General and administrative		123,033		—		47,597		(47,597)		123,033
Depletion, depreciation and amortization		511,390		—		98,181		(98,181)		511,390
Impairment of property and equipment		79,749		—		—		—		79,749
Other		258,963		415,571		5,375		(5,375)		674,534
Total operating expenses		3,006,499		415,571		283,112		(283,112)		3,422,070
Operating income (loss)	$	1,711,477		(80,398)		395,320		(395,320)		1,631,079
Equity in earnings of unconsolidated affiliates	$	54,863		—		70,467		(70,467)		54,863
Capital expenditures for segment assets	$	721,420		—		236,154		(236,154)		721,420

	Nine Months Ended September 30, 2023
					Equity Method
	Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream		Affiliate		Total
Sales and revenues:
Third-party	$	3,331,130		155,390		929		(929)		3,486,520
Intersegment		1,309		—		780,672		(780,672)		1,309
Total revenue		3,332,439		155,390		781,601		(781,601)		3,487,829
Operating expenses:
Lease operating		91,553		—		—		—		91,553
Gathering, compression, processing, transportation and water handling		1,981,033		—		162,382		(162,382)		1,981,033
General and administrative		169,587		—		53,142		(53,142)		169,587
Depletion, depreciation and amortization		515,247		—		101,174		(101,174)		515,247
Impairment of property and equipment		44,746		—		—		—		44,746
Other		146,536		240,841		8,722		(8,722)		387,377
Total operating expenses		2,948,702		240,841		325,420		(325,420)		3,189,543
Operating income (loss)	$	383,737		(85,451)		456,181		(456,181)		298,286
Equity in earnings of unconsolidated affiliates	$	58,986		—		77,825		(77,825)		58,986
Capital expenditures for segment assets	$	912,046		—		130,025		(130,025)		912,046

32

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

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

	As of December 31, 2022
					Equity Method
	Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream		Affiliate		Total
Investments in unconsolidated affiliates	$	220,429		—		652,767		(652,767)		220,429
Total assets		14,081,077		36,962		5,791,320		(5,791,320)		14,118,039

	(Unaudited)
	As of September 30, 2023
					Equity Method
	Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream		Affiliate		Total
Investments in unconsolidated affiliates	$	220,110		—		635,954		(635,954)		220,110
Total assets		13,716,306		20,251		5,758,711		(5,758,711)		13,736,557

(17) Subsidiary Guarantors

Antero Resources’ senior notes are fully and unconditionally guaranteed by Antero Resources’ existing subsidiaries that guarantee the Credit Facility.  In the event a subsidiary guarantor is sold or disposed of (whether by merger, consolidation, the sale of a sufficient amount of its capital stock so that it no longer qualifies as a “Subsidiary” of Antero (as defined in the indentures governing the notes) or the sale of all or substantially all of its assets (other than by lease)) and whether or not the subsidiary guarantor is the surviving entity in such transaction to a person that is not Antero or a restricted subsidiary of Antero, such subsidiary guarantor will be released from its obligations under its subsidiary guarantee if the sale or other disposition does not violate the covenants set forth in the indentures governing the notes.

In addition, a subsidiary guarantor will be released from its obligations under the indentures and its guarantee, upon the release or discharge of the guarantee of other Indebtedness (as defined in the indentures governing the notes) that resulted in the creation of such guarantee, except a release or discharge by or as a result of payment under such guarantee; if Antero designates such subsidiary as an unrestricted subsidiary and such designation complies with the other applicable provisions of the indentures governing the notes or in connection with any covenant defeasance, legal defeasance or satisfaction and discharge of the notes.

The tables set forth below present summarized financial information of Antero, as parent, and its guarantor subsidiaries (in thousands). The Company’s wholly owned subsidiaries are not restricted from making distributions to the Company.

33

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

Balance Sheet
			(Unaudited)
	December 31, 2022		September 30, 2023
Current assets	$	739,104		399,586
Noncurrent assets		12,663,911		12,720,679
Total assets	$	13,403,015		13,120,265
Accounts payable, related parties	$	80,708		89,350
Other current liabilities		1,668,426		1,361,552
Total current liabilities		1,749,134		1,450,902
Noncurrent liabilities		5,306,539		5,171,893
Total liabilities	$	7,055,673		6,622,795
Statement of Operations
			Nine Months Ended
			September 30, 2023
Revenues			$	3,376,215
Operating expenses				3,155,685
Income from operations				220,530
Net income and comprehensive income including noncontrolling interests				148,155
Net income and comprehensive income attributable to Antero Resources Corporation			$	148,155

34

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our unaudited condensed consolidated financial statements and related notes included elsewhere in this Quarterly Report on Form 10-Q. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results, and the differences can be material. Some of the key factors that could cause actual results to vary from our expectations include changes in natural gas, NGLs and oil prices, the timing of planned capital expenditures, our ability to fund our development programs, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, impacts of world health events and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Statement Regarding Forward-Looking Statements.” Also, see the risk factors and other cautionary statements described under the heading “Item 1A. Risk Factors.” We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

In this section, references to “Antero,” the “Company,” “we,” “us,” and “our” refer to Antero Resources Corporation and its subsidiaries, unless otherwise indicated or the context otherwise requires.

Our Company

We are an independent oil and natural gas company engaged in the development, production, exploration and acquisition of natural gas, NGLs and oil properties located in the Appalachian Basin. We focus on unconventional reservoirs, which can generally be characterized as fractured shale formations. Our management team has worked together for many years and has a successful track record of reserve and production growth as well as significant expertise in unconventional resource plays. Our strategy is to leverage our team’s experience delineating and developing natural gas resource plays to develop our reserves and production, primarily on our existing multi-year inventory of drilling locations.

We have assembled a portfolio of long-lived properties that are characterized by what we believe to be low geologic risk and repeatability. Our drilling opportunities are focused in the Appalachian Basin. As of September 30, 2023, we held approximately 515,000 net acres in the Appalachian Basin.

Market Conditions and Business Trends

Commodity Markets

Prices for natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. Natural gas, NGLs and oil benchmark prices decreased significantly during the three and nine months ended September 30, 2023 as compared to the same periods of 2022. As a result, we experienced a decrease in price realizations during the three and nine months ended September 30, 2023. We monitor the economic factors that impact natural gas, NGLs and oil prices, including domestic and foreign supply and demand indicators, domestic and foreign commodity inventories, the actions of 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 and oil prices:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2023		2022		2023
Henry Hub (1) ($/Mcf)	$	8.20		2.55		6.77		2.69
West Texas Intermediate (2) ($/Bbl)		91.55		82.26		98.09		77.39

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

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

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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 as we deem necessary to manage such risks. In addition, we periodically enter into contracts that contain embedded features that are required to be bifurcated and accounted for separately as derivatives. Due to our improved liquidity and leverage position as compared to past levels, the percentage of our expected production that we hedge has decreased. For the three and nine months ended September 30, 2022, 31% and 34%, respectively, of our production was hedged through fixed price commodity swaps as compared to 1% for both the three and nine months ended September 30, 2023, respectively. Assuming our 2023 production is the same as our production in 2022, 1% of our production for 2023 will be hedged through fixed price commodity swaps. The tables and narrative below exclude derivative instruments attributable to Martica, our consolidated VIE, since all gains or losses from such contracts are fully attributable to the noncontrolling interests in Martica.

As of September 30, 2023, our fixed price natural gas swap positions excluding Martica were as follows:

				Weighted
				Average
Commodity / Settlement Period	Index	Contracted Volume		Price
Natural Gas
October-December 2023	Henry Hub	4	Bcf	$	2.37	/MMBtu

As of September 30, 2023, our natural gas basis swap positions settle on the pricing index to basis differential of the Columbia Gas Transmission pipeline (“TCO”) to the NYMEX Henry Hub natural gas price were as follows:

				Weighted Average
Commodity / Settlement Period	Index to Basis Differential	Contracted Volume		Hedged Differential
Natural Gas
October-December 2023	NYMEX to TCO	5	Bcf	$	0.525	/MMBtu
January-December 2024	NYMEX to TCO	18	Bcf		0.530	/MMBtu
		23	Bcf		0.529	/MMBtu

We have a call option and an embedded put option tied to NYMEX pricing for the production volumes associated with the Company’s retained interest in the VPP properties. As of September 30, 2023, our call option and embedded put option arrangements were as follows:

							Embedded
				Call Option			Put Option
Commodity / Settlement Period	Index	Contracted Volume		Strike Price			Strike Price
Natural Gas
October-December 2023	Henry Hub	5	Bcf	$	2.466	/MMBtu	$	2.466	/MMBtu
January-December 2024	Henry Hub	19	Bcf		2.477	/MMBtu		2.527	/MMBtu
January-December 2025	Henry Hub	16	Bcf		2.564	/MMBtu		2.614	/MMBtu
January-December 2026	Henry Hub	12	Bcf		2.629	/MMBtu		2.679	/MMBtu
		52	Bcf		2.537	/MMBtu		2.582	/MMBtu

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

As of September 30, 2023, the estimated fair value of our commodity derivative contracts, excluding Martica, was a net liability of $60 million. See Note 11—Derivative Instruments to the unaudited condensed consolidated financial statements for more information.

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Martica

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

				Weighted
				Average
Commodity / Settlement Period	Index	Contracted Volume		Price
Natural Gas
October-December 2023	Henry Hub	3	Bcf	$	2.35	/MMBtu
January-December 2024	Henry Hub	9	Bcf		2.33	/MMBtu
January-March 2025	Henry Hub	1	Bcf		2.53	/MMBtu
		13	Bcf		2.36	/MMBtu
Natural Gasoline
October-December 2023	Mont Belvieu Natural Gasoline-OPIS Non-TET	20	MBbl		40.74	/Bbl
Oil
October-December 2023	West Texas Intermediate	7	MBbl		44.66	/Bbl
January-December 2024	West Texas Intermediate	16	MBbl		44.02	/Bbl
January-March 2025	West Texas Intermediate	3	MBbl		45.06	/Bbl
		26	MBbl		44.32	/Bbl

As of September 30, 2023, the estimated fair value of Martica’s commodity derivative contracts was a net liability of $15 million. See Note 11—Derivative Instruments to the unaudited condensed consolidated financial statements for more information.

Economic Indicators

The economy experienced elevated inflation levels as a result of global supply and demand imbalances, where global demand outpaced supplies beginning in 2021 and continuing through the first three quarters of 2023. For example, the Consumer Price Index (“CPI”) for all urban consumers increased 8% from September 2021 to September 2022 and an additional 4% from September 2022 to September 2023 as compared to the Federal Reserve’s stated goal of 2%. In order to manage the inflation risk present in the United States’ economy, the Federal Reserve utilized monetary policy in the form of interest rate increases beginning in March 2022 in an effort to bring the inflation rate in line with its stated goal of 2% on a long-term basis. Between March 2022 and July 2023, the Federal Reserve increased the federal funds interest rate by 5.25%. While inflationary pressures in the United States’ economy have begun to subside, we continue to be impacted by the increased federal funds interest rate. See “—Results of Operations” for more information.

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

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

Results of Operations

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

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activities to purchase and sell third-party natural gas and NGLs and to market and utilize excess firm transportation capacity. See Note 16—Reportable Segments to the unaudited condensed consolidated financial statements for more information.

Three Months Ended September 30, 2022 Compared to Three Months Ended September 30, 2023

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

	Three Months Ended September 30, 2022
					Equity Method
	Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream		Affiliate		Total
Revenue and other:
Natural gas sales	$	1,736,039		—		—		—		1,736,039
Natural gas liquids sales		620,816		—		—		—		620,816
Oil sales		67,025		—		—		—		67,025
Commodity derivative fair value losses		(530,523)		—		—		—		(530,523)
Gathering, compression and water handling		—		—		231,034		(231,034)		—
Marketing		—		159,985		—		—		159,985
Amortization of deferred revenue, VPP		9,478		—		—		—		9,478
Other revenue and income		1,804		—		—		—		1,804
Total revenue		1,904,639		159,985		231,034		(231,034)		2,064,624
Operating expenses:
Lease operating		27,453		—		—		—		27,453
Gathering and compression		239,868		—		19,813		(19,813)		239,868
Processing		241,347		—		—		—		241,347
Transportation		235,173		—		—		—		235,173
Water handling		—		—		26,835		(26,835)		—
Production and ad valorem taxes		92,998		—		—		—		92,998
Marketing		—		185,377		—		—		185,377
Exploration and mine expenses		2,975		—		—		—		2,975
General and administrative (excluding equity-based compensation)		32,501		—		8,034		(8,034)		32,501
Equity-based compensation		10,402		—		5,553		(5,553)		10,402
Depletion, depreciation and amortization		169,607		—		34,206		(34,206)		169,607
Impairment of property and equipment		33,924		—		—		—		33,924
Accretion of asset retirement obligations		630		—		50		(50)		630
Contract termination, loss contingency and other operating expenses		17,995		—		865		(865)		17,995
Loss (gain) on sale of assets		214		—		(2,092)		2,092		214
Total operating expenses		1,105,087		185,377		93,264		(93,264)		1,290,464
Operating income (loss)	$	799,552		(25,392)		137,770		(137,770)		774,160
Equity in earnings of unconsolidated affiliates	$	14,972		—		24,411		(24,411)		14,972

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	Three Months Ended September 30, 2023
					Equity Method
	Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream		Affiliate		Total
Revenue and other:
Natural gas sales	$	516,214		—		—		—		516,214
Natural gas liquids sales		482,570		—		—		—		482,570
Oil sales		62,629		—		—		—		62,629
Commodity derivative fair value gains		3,448		—		—		—		3,448
Gathering, compression and water handling		—		—		263,839		(263,839)		—
Marketing		—		53,068		—		—		53,068
Amortization of deferred revenue, VPP		7,701		—		—		—		7,701
Other revenue and income		546		—		—		—		546
Total revenue		1,073,108		53,068		263,839		(263,839)		1,126,176
Operating expenses:
Lease operating		33,484		—		—		—		33,484
Gathering and compression		216,435		—		23,547		(23,547)		216,435
Processing		264,391		—		—		—		264,391
Transportation		191,060		—		—		—		191,060
Water handling		—		—		28,367		(28,367)		—
Production and ad valorem taxes		32,258		—		—		—		32,258
Marketing		—		69,542		—		—		69,542
Exploration and mine expenses		591		—		—		—		591
General and administrative (excluding equity-based compensation)		39,967		—		9,284		(9,284)		39,967
Equity-based compensation		18,458		—		8,349		(8,349)		18,458
Depletion, depreciation and amortization		176,259		—		30,745		(30,745)		176,259
Impairment of property and equipment		13,476		—		—		—		13,476
Accretion of asset retirement obligations		889		—		45		(45)		889
Loss (gain) on sale of assets		(136)		—		467		(467)		(136)
Contract termination, loss contingency and other operating expenses		13,770		—		722		(722)		13,770
Total operating expenses		1,000,902		69,542		101,526		(101,526)		1,070,444
Operating income (loss)	$	72,206		(16,474)		162,313		(162,313)		55,732
Equity in earnings of unconsolidated affiliates	$	22,207		—		27,397		(27,397)		22,207

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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
	September 30,				Increase		Percent
	2022		2023		(Decrease)		Change
Production data (1) (2):
Natural gas (Bcf)		200		208		8	4	%
C2 Ethane (MBbl)		5,010		6,696		1,686	34	%
C3+ NGLs (MBbl)		9,950		10,977		1,027	10	%
Oil (MBbl)		804		918		114	14	%
Combined (Bcfe)		294		320		26	9	%
Daily combined production (MMcfe/d)		3,200		3,474		274	9	%
Average prices before effects of derivative settlements (3):
Natural gas (per Mcf)	$	8.69		2.48		(6.21)	(71)	%
C2 Ethane (per Bbl) (4)	$	23.40		11.73		(11.67)	(50)	%
C3+ NGLs (per Bbl)	$	50.61		36.81		(13.80)	(27)	%
Oil (per Bbl)	$	83.41		68.22		(15.19)	(18)	%
Weighted Average Combined (per Mcfe)	$	8.23		3.32		(4.91)	(60)	%
Average realized prices after effects of derivative settlements (3):
Natural gas (per Mcf)	$	5.51		2.46		(3.05)	(55)	%
C2 Ethane (per Bbl) (4)	$	23.40		11.73		(11.67)	(50)	%
C3+ NGLs (per Bbl)	$	50.27		36.76		(13.51)	(27)	%
Oil (per Bbl)	$	82.76		67.91		(14.85)	(18)	%
Weighted Average Combined (per Mcfe)	$	6.06		3.30		(2.76)	(46)	%
Average costs (per Mcfe):
Lease operating	$	0.09		0.10		0.01	11	%
Gathering and compression	$	0.81		0.68		(0.13)	(16)	%
Processing	$	0.82		0.83		0.01	1	%
Transportation	$	0.80		0.60		(0.20)	(25)	%
Production and ad valorem taxes	$	0.32		0.10		(0.22)	(69)	%
Marketing expense, net	$	0.09		0.05		(0.04)	(44)	%
General and administrative (excluding equity-based compensation)	$	0.11		0.13		0.02	18	%
Depletion, depreciation, amortization and accretion	$	0.58		0.55		(0.03)	(5)	%

(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 September 30, 2023 includes $6 million of proceeds related to a take-or-pay contract. Excluding the effect of these proceeds, the average realized price for ethane before and after the effects of derivatives would have been $10.88 per Bbl.

Natural gas sales. Revenues from sales of natural gas decreased from $1.7 billion for the three months ended September 30, 2022 to $516 million for the three months ended September 30, 2023, a decrease of $1.2 billion, or 70%. Lower commodity prices (excluding the effects of derivative settlements) during the three months ended September 30, 2023 accounted for an approximate $1.3 billion decrease in year-over-year natural gas sales revenue (calculated as the change in the year-to-year average price times current year production volumes). Higher natural gas production volumes accounted for an approximate $71 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 $621 million for the three months ended September 30, 2022 to $483 million for the three months ended September 30, 2023, a decrease of $138 million, or 22%. Lower commodity prices (excluding the effects of derivative settlements) during the three months ended September 30, 2023 accounted for an approximate $230 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). Higher NGLs production volumes accounted for an approximate $92 million increase in year-over-year NGLs revenues (calculated as the change in year-to-year volumes times the prior year average price).

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Oil sales. Revenues from sales of oil decreased from $67 million for the three months ended September 30, 2022 to $63 million for the three months ended September 30, 2023, a decrease of $4 million, or 7%. 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). Higher oil production volumes during the three months ended September 30, 2023 accounted for an approximate $10 million increase in year-over-year oil revenues (calculated as the change in year-to-year volumes times the prior year average price).

Commodity derivative fair value gains (losses). Our commodity derivatives included variable price swap contracts, basis swap contracts, call options and embedded put options. Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment. Consequently, all mark-to-market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our statements of operations. For the three months ended September 30, 2022 and 2023, our commodity hedges resulted in derivative fair value losses of $531 million and fair value gains of $3 million, respectively. For the three months ended September 30, 2022, commodity derivative fair value losses included $640 million of cash payments on settled commodity derivatives losses. For the three months ended September 30, 2023, commodity derivative fair value gains included $6 million of cash payments on settled commodity derivatives 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.

Amortization of deferred revenue, VPP. Amortization of deferred revenues associated with the VPP decreased from $9 million for the three months ended September 30, 2022 to $8 million for the three months ended September 30, 2023, a decrease of $1 million, or 19%, 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 $27 million, or $0.09 per Mcfe, for the three months ended September 30, 2022 to $33 million, or $0.10 per Mcfe, for the three months ended September 30, 2023, an increase of $6 million, primarily due to higher water disposal costs and workover expense between periods.

Gathering, compression, processing and transportation expense. Gathering, compression, processing and transportation expense decreased from $716 million for the three months ended September 30, 2022 to $672 million for the three months ended September 30, 2023, a decrease of $44 million, or 6%. This fluctuation primarily resulted from the following:

● Gathering and compression costs decreased from $0.81 per Mcfe for the three months ended September 30, 2022 to $0.68 per Mcfe for the three months ended September 30, 2023, primarily due to due to lower fuel costs as a result of decreased commodity prices, partially offset by annual CPI-based adjustments between periods.

● Processing costs increased from $0.82 per Mcfe for the three months ended September 30, 2022 to $0.83 per Mcfe for the three months ended September 30, 2023, primarily due to increased costs for NGLs processing, which includes an annual CPI-based adjustment during the first quarter of 2023, and higher NGLs transportation fees.

● Transportation costs decreased from $0.80 per Mcfe for the three months ended September 30, 2022 to $0.60 per Mcfe for the three months ended September 30, 2023 primarily due to lower fuel costs as a result of lower commodity prices and demand fees between periods.

Production and ad valorem tax expense.  Total production and ad valorem taxes decreased from $93 million for the three months ended September 30, 2022 to $32 million for the three months ended September 30, 2023, a decrease of $61 million, or 65%, primarily due to lower commodity prices between periods, partially offset by higher production volumes between periods. Production and ad valorem taxes as a percentage of natural gas revenues increased from 5% for the three months ended September 30, 2022 to 6% for the three months ended September 30, 2023, primarily as a result of higher ad valorem taxes, which 2023 West Virginia ad valorem taxes are based on commodity prices during 2021.

General and administrative expense. General and administrative expense (excluding equity-based compensation expense) increased from $33 million for the three months ended September 30, 2022 to $40 million for the three months ended

41

September 30, 2023, an increase of $7 million, or 23%, primarily due to higher salary and wage expense and software license costs between periods. We had 554 and 605 employees as of September 30, 2022 and 2023, respectively. General and administrative expense on a per unit basis (excluding equity-based compensation) increased from $0.11 per Mcfe for the three months ended September 30, 2022 to $0.13 per Mcfe for the three months ended September 30, 2023 as a result of our higher overall general and administrative costs, partially offset by increased production volumes between periods.

Equity-based compensation expense. Noncash equity-based compensation expense increased from $10 million for the three months ended September 30, 2022 to $18 million for the three months ended September 30, 2023, an increase of $8 million, or 77%, primarily due to an increase in the annual equity awards granted during the fourth quarter of 2022 and the first half of 2023 as compared to prior years, which were temporarily and significantly reduced during 2020 and supplemented by our cash awards program. Our equity awards vest over three or four year service periods, and our equity incentive program began returning to normal levels during 2021. See Note 9—Equity Based Compensation and Cash Awards to the unaudited condensed consolidated financial statements for more information.

Depletion, depreciation, and amortization expense (“DD&A expense”). DD&A expense increased from $170 million, or $0.58 per Mcfe, to $176 million, or $0.55 per Mcfe, for the three months ended September 30, 2022 and 2023, respectively. This increase in DD&A expense was primarily due to higher production volumes between periods, partially offset by higher reserve volumes during the three months ended September 30, 2023.

Impairment of property and equipment. Impairment of oil and gas properties decreased from $34 million for the three months ended September 30, 2022 to $13 million for the three months ended September 30, 2023, a decrease of $21 million, or 60%, primarily related to lower impairments of expiring leases between periods. During both periods, we recognized impairments primarily related to expiring leases as well as design and initial costs related to pads we no longer plan to place into service.

Contract termination, loss contingency and other operating expenses. Contract termination, loss contingency and other operating expenses of $18 million for the three months ended September 30, 2022 were primarily due to a payment for the cancellation of the Smithburg 2 gas processing plant. Contract termination, loss contingency and other operating expenses of $14 million for the three months ended September 30, 2023 were primarily due to a loss contingency.

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 $25 million, or $0.09 per Mcfe, for the three months ended September 30, 2022 to $16 million, or $0.05 per Mcfe, for the three months ended September 30, 2023, primarily due to lower firm transportation commitments.

Marketing revenue. Marketing revenue decreased from $160 million for the three months ended September 30, 2022 to $53 million for the three months ended September 30, 2023, a decrease of $107 million, or 67%. This fluctuation primarily resulted from the following:

● Natural gas marketing revenue decreased by $102 million between periods primarily due to lower natural gas prices and marketing volumes. Lower natural gas prices accounted for a $100 million decrease in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes), and lower natural gas marketing volumes accounted for an approximate $2 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price).

● Ethane marketing revenues were $5 million for the three months ended September 30, 2022. There were no ethane marketing revenues for the three months ended September 30, 2023.

Marketing expense. Marketing expense decreased from $185 million for the three months ended September 30, 2022 to $70 million for the three months ended September 30, 2023, a decrease of $115 million, or 62%. 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, ethane and oil purchases decreased $100 million, $5 million and $1 million, respectively, between periods. The total cost of third-party commodity purchases decreased primarily

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due to lower commodity prices and marketing volumes between periods. Firm transportation costs were $35 million for the three months ended September 30, 2022 and $26 million for the three months ended September 30, 2023, a decrease of $9 million due to the reduction in firm transportation commitments between periods.

Antero Midstream Segment

Antero Midstream revenue.  Revenue from the Antero Midstream segment increased from $231 million for the three months ended September 30, 2022 to $264 million for the three months ended September 30, 2023, an increase of $33 million, primarily due to higher low pressure gathering, compression and fresh water delivery revenues as a result of increased throughput and higher rates from annual CPI-based adjustments between periods.

Antero Midstream operating expense. Total operating expense related to the Antero Midstream segment increased from $93 million for the three months ended September 30, 2022 to $102 million for the three months ended September 30, 2023, an increase of $9 million. This increase was primarily due to gathering, compression and water handling expenses (“direct operating expenses”) for 12 compressor stations that were acquired during the fourth quarter of 2022 and higher fresh water delivery volumes between periods.

Discussion of Items Not Allocated to Segments

Interest expense. Interest expense increased from $28 million for the three months ended September 30, 2022 to $32 million for the three months ended September 30, 2023, an increase of $4 million, or 12%, primarily due to higher benchmark interest rates during the three months ended September 30, 2023 and higher Credit Facility borrowings between periods, partially offset by the reduction in debt as a result of the repurchase of certain of our unsecured senior notes between periods.

Loss on early extinguishment of debt. During the three months ended September 30, 2022, we repurchased $208 million of our 2026 Notes at a weighted average of 109% of the principal amount thereof, plus accrued and unpaid interest, and $118 million of our 2029 Notes at a weighted average of 107% of the principal amount thereof, plus accrued and unpaid interest, which resulted in a loss on early debt extinguishment of $30 million. There were no debt redemptions or repurchases during the three months ended September 30, 2023. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information.

Income tax expense. For the three months ended September 30, 2022, we had an income tax expense of $136 million, with an effective tax rate of 19%, due to income before income taxes of $730 million. For the three months ended September 30, 2023, we had an income tax expense of $14 million, with an effective tax rate of 30%, due to income before income taxes of $46 million. The increase in the effective tax rate between periods was primarily due to the net loss before income taxes during the three months ended June 30, 2023 that, when taken together with net income before taxes during each of the three months ended March 31, 2023 and September 30, 2023, resulted in a 17% effective tax rate for the nine months ended September 30, 2023.

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Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2023

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

	Nine Months Ended September 30, 2022
					Equity Method
	Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream		Affiliate		Total
Revenue and other:
Natural gas sales	$	4,290,825		—		—		—		4,290,825
Natural gas liquids sales		1,983,509		—		—		—		1,983,509
Oil sales		219,504		—		—		—		219,504
Commodity derivative fair value losses		(1,807,565)		—		—		—		(1,807,565)
Gathering, compression and water handling		—		—		678,432		(678,432)		—
Marketing		—		335,173		—		—		335,173
Amortization of deferred revenue, VPP		28,125		—		—		—		28,125
Other revenue and income		3,578		—		—		—		3,578
Total revenue		4,717,976		335,173		678,432		(678,432)		5,053,149
Operating expenses:
Lease operating		70,486		—		—		—		70,486
Gathering and compression		664,980		—		56,338		(56,338)		664,980
Processing		651,048		—		—		—		651,048
Transportation		646,850		—		—		—		646,850
Water handling		—		—		75,621		(75,621)		—
Production and ad valorem taxes		227,648		—		—		—		227,648
Marketing		—		415,571		—		—		415,571
Exploration and mine expenses		5,267		—		—		—		5,267
General and administrative (excluding equity-based compensation)		99,811		—		33,571		(33,571)		99,811
Equity-based compensation		23,222		—		14,026		(14,026)		23,222
Depletion, depreciation and amortization		511,390		—		98,181		(98,181)		511,390
Impairment of property and equipment		79,749		—		—		—		79,749
Accretion of asset retirement obligations		3,878		—		178		(178)		3,878
Contract termination, loss contingency and other operating expenses		20,099		—		7,439		(7,439)		20,099
Loss (gain) on sale of assets		2,071		—		(2,242)		2,242		2,071
Total operating expenses		3,006,499		415,571		283,112		(283,112)		3,422,070
Operating income (loss)	$	1,711,477		(80,398)		395,320		(395,320)		1,631,079
Equity in earnings of unconsolidated affiliates	$	54,863		—		70,467		(70,467)		54,863

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	Nine Months Ended September 30, 2023
					Equity Method
	Exploration				Investment in		Elimination of
	and				Antero		Unconsolidated		Consolidated
	Production		Marketing		Midstream		Affiliate		Total
Revenue and other:
Natural gas sales	$	1,621,659		—		—		—		1,621,659
Natural gas liquids sales		1,375,738		—		—		—		1,375,738
Oil sales		172,402		—		—		—		172,402
Commodity derivative fair value gains		137,924		—		—		—		137,924
Gathering, compression and water handling		—		—		781,601		(781,601)		—
Marketing		—		155,390		—		—		155,390
Amortization of deferred revenue, VPP		22,852		—		—		—		22,852
Other revenue and income		1,864		—		—		—		1,864
Total revenue		3,332,439		155,390		781,601		(781,601)		3,487,829
Operating expenses:
Lease operating		91,553		—		—		—		91,553
Gathering and compression		640,730		—		72,819		(72,819)		640,730
Processing		764,301		—		—		—		764,301
Transportation		576,002		—		—		—		576,002
Water handling		—		—		89,563		(89,563)		—
Production and ad valorem taxes		117,692		—		—		—		117,692
Marketing		—		217,078		—		—		217,078
Exploration and mine expenses		2,097		—		—		—		2,097
General and administrative (excluding equity-based compensation)		124,599		—		29,967		(29,967)		124,599
Equity-based compensation		44,988		—		23,175		(23,175)		44,988
Depletion, depreciation and amortization		515,247		—		101,174		(101,174)		515,247
Impairment of property and equipment		44,746		—				—		44,746
Accretion of asset retirement obligations		2,971		—		133		(133)		2,971
Loss (gain) on sale of assets		(447)		—		6,036		(6,036)		(447)
Contract termination, loss contingency and other operating expenses		24,223		23,763		2,553		(2,553)		47,986
Total operating expenses		2,948,702		240,841		325,420		(325,420)		3,189,543
Operating income (loss)	$	383,737		(85,451)		456,181		(456,181)		298,286
Equity in earnings of unconsolidated affiliates	$	58,986		—		77,825		(77,825)		58,986

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Exploration and Production Segment

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

	Nine Months Ended				Amount of
	September 30,				Increase		Percent
	2022		2023		(Decrease)		Change
Production data (1) (2):
Natural gas (Bcf)		602		606		4	1	%
C2 Ethane (MBbl)		13,040		19,251		6,211	48	%
C3+ NGLs (MBbl)		29,744		31,009		1,265	4	%
Oil (MBbl)		2,433		2,720		287	12	%
Combined (Bcfe)		873		924		51	6	%
Daily combined production (MMcfe/d)		3,198		3,383		185	6	%
Average prices before effects of derivative settlements (3):
Natural gas (per Mcf)	$	7.13		2.68		(4.45)	(62)	%
C2 Ethane (per Bbl) (4)	$	21.05		10.43		(10.62)	(50)	%
C3+ NGLs (per Bbl)	$	57.46		37.89		(19.57)	(34)	%
Oil (per Bbl)	$	90.23		63.38		(26.85)	(30)	%
Weighted Average Combined (per Mcfe)	$	7.44		3.43		(4.01)	(54)	%
Average realized prices after effects of derivative settlements (3):
Natural gas (per Mcf)	$	4.69		2.65		(2.04)	(43)	%
C2 Ethane (per Bbl) (4)	$	21.02		10.43		(10.59)	(50)	%
C3+ NGLs (per Bbl)	$	57.06		37.84		(19.22)	(34)	%
Oil (per Bbl)	$	89.52		63.04		(26.48)	(30)	%
Weighted Average Combined (per Mcfe)	$	5.74		3.41		(2.33)	(41)	%
Average costs (per Mcfe):
Lease operating	$	0.08		0.10		0.02	25	%
Gathering and compression	$	0.76		0.69		(0.07)	(9)	%
Processing	$	0.75		0.83		0.08	11	%
Transportation	$	0.74		0.62		(0.12)	(16)	%
Production and ad valorem taxes	$	0.26		0.13		(0.13)	(50)	%
Marketing expense, net	$	0.09		0.07		(0.02)	(22)	%
General and administrative (excluding equity-based compensation)	$	0.11		0.13		0.02	18	%
Depletion, depreciation, amortization and accretion	$	0.59		0.56		(0.03)	(5)	%

(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 nine months ended September 30, 2023 includes $13 million of proceeds related to a take-or-pay contract. Excluding the effect of these proceeds, the average realized price for ethane before and after the effects of derivatives would have been $9.77 per Bbl.

Natural gas sales. Revenues from sales of natural gas decreased from $4.3 billion for the nine months ended September 30, 2022 to $1.6 billion for the nine months ended September 30, 2023, a decrease of $2.7 million, or 62%. Lower commodity prices (excluding the effects of derivative settlements) during the nine months ended September 30, 2023 accounted for an approximate $2.7 billion decrease in year-over-year natural gas sales revenue (calculated as the change in the year-to-year average price times current year production volumes). Higher natural gas production volumes accounted for an approximate $29 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 $2.0 billion for the nine months ended September 30, 2022 to $1.4 billion for the nine months ended September 30, 2023, a decrease of $0.6 billion, or 31%. Lower commodity prices (excluding the effects of derivative settlements) during the nine months ended September 30, 2023 accounted for an approximate $811 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). Higher NGLs production volumes accounted for an approximate $203 million increase in year-over-year NGLs revenues (calculated as the change in year-to-year volumes times the prior year average price).

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Oil sales. Revenues from sales of oil decreased from $220 million for the nine months ended September 30, 2022 to $172 million for the nine months ended September 30, 2023, a decrease of $48 million, or 21%. Lower oil prices, excluding the effects of derivative settlements, accounted for an approximate $73 million decrease in year-over-year oil revenues (calculated as the change in the year-to-year average price times current year production volumes). Higher oil production volumes during the nine months ended September 30, 2023 accounted for an approximate $25 million increase in year-over-year oil revenues (calculated as the change in year-to-year volumes times the prior year average price).

Commodity derivative fair value gains (losses). Our commodity derivatives included variable price swap contracts, swaptions, basis swap contracts, call options and embedded put options. Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment. Consequently, all mark-to-market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our statements of operations. For the nine months ended September 30, 2022 and 2023, our commodity hedges resulted in derivative fair value losses of $1.8 billion and fair value gains of $138 million, respectively. For the nine months ended September 30, 2022, commodity derivative fair value losses included $1.5 billion of cash payments on settled commodity derivative losses. For the nine months ended September 30, 2023, commodity derivative fair value gains included $17 million of cash payments on settled commodity derivative losses and a $202 million cash payment for the early settlement of our swaption.

Commodity derivative fair value gains or losses vary based on future commodity prices and have no cash flow impact until the derivative contracts are settled or monetized prior to settlement. Derivative asset or liability positions at the end of any accounting period may reverse to the extent future commodity prices increase or decrease from their levels at the end of the accounting period, or as gains or losses are realized through settlement. Additionally, substantially all of our production is currently unhedged for 2023 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 $28 million for the nine months ended September 30, 2022 to $23 million for the nine months ended September 30, 2023, a decrease of $5 million or 19%, 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 $70 million, or $0.08 per Mcfe, for the nine months ended September 30, 2022 to $92 million, or $0.10 per Mcfe for the nine months ended September 30, 2023, an increase of $22 million or $0.02 per Mcfe, primarily due to higher oilfield service, workover and produced water handling costs.

Gathering, compression, processing and transportation expense. Gathering, compression, processing and transportation expense remained consistent at $2.0 billion for each of the nine months ended September 30, 2022 and 2023. This was primarily a result of the following:

● Gathering and compression costs on a per unit basis decreased from $0.76 per Mcfe for the nine months ended September 30, 2022 to $0.69 per Mcfe for the nine months ended September 30, 2023, primarily due to lower fuel costs as a result of decreased commodity prices, partially offset by annual CPI-based based adjustments between periods.

● Processing costs on a per unit basis increased from $0.75 per Mcfe for the nine months ended September 30, 2022 to $0.83 per Mcfe for the nine months ended September 30, 2023, primarily due to increased costs for NGLs processing and transportation, which include annual CPI-based and commodity based adjustments, as well as higher terminal fees and ethane transportation.

● Transportation costs on a per unit basis decreased from $0.74 per Mcfe for the nine months ended September 30, 2022 to $0.62 per Mcfe for the nine months ended September 30, 2023 primarily due to lower fuel costs as a result of lower commodity prices between periods.

Production and ad valorem tax expense.  Production and ad valorem taxes decreased from $228 million for the nine months ended September 30, 2022 to $118 million for the nine months ended September 30, 2023, a decrease of $110 million, or 48%, primarily due to lower commodity prices between periods, partially offset by higher production volumes between periods. Production and ad valorem taxes as a percentage of natural gas revenues increased from 5% for the nine months ended September 30, 2022 to 7% for the nine months ended September 30, 2023 primarily as a result of higher ad valorem taxes, which 2023 West Virginia ad valorem taxes are based on commodity prices during 2021.

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General and administrative expense. General and administrative expense (excluding equity-based compensation expense) increased from $100 million for the nine months ended September 30, 2022 to $125 million for the nine months ended September 30, 2023, an increase of $25 million, or 25%, primarily due to higher salary and wage expense, professional service fees, software license costs and office operating costs between periods. We had 554 and 605 employees as of September 30, 2022 and 2023, respectively. General and administrative expense on a per unit basis (excluding equity-based compensation) increased from $0.11 per Mcfe for the nine months ended September 30, 2022 to $0.13 per Mcfe for the nine months ended September 30, 2023 as a result of our higher overall general and administrative costs, partially offset by increased production volumes between periods.

Equity-based compensation expense. Noncash equity-based compensation expense increased from $23 million for the nine months ended September 30, 2022 to $45 million for the nine months ended September 30, 2023, an increase of $22 million, primarily due to an increase in the annual equity awards granted during the fourth quarter of 2022 and first three quarters of 2023 as compared to prior years, which were temporarily and significantly reduced during 2020 and supplemented by our cash awards program. Our equity awards vest over three or four year service periods, and our equity incentive program began returning to normal levels in 2021. See Note 9—Equity Based Compensation and Cash Awards to the unaudited condensed consolidated financial statements for more information on equity-based compensation awards.

Depletion, depreciation and amortization expense. DD&A expense remained relatively consistent at $511 million, or $0.59 per Mcfe, and $515 million, or $0.56 per Mcfe, for the nine months ended September 30, 2022 and 2023, respectively. This decrease in DD&A expense per Mcfe between periods was primarily due to higher reserve volumes during the nine months ended September 30, 2023.

Impairment of property and equipment. Impairment of oil and gas properties decreased from $80 million for the nine months ended September 30, 2022 to $45 million for the nine months ended September 30, 2023, a decrease of $35 million, or 44%, primarily related to lower impairments of expiring leases between periods. During both periods, we recognized impairments primarily related to expiring leases as well as design and initial costs related to pads we no longer plan to place into service.

Contract termination, loss contingency and other operating expenses. Contract termination, loss contingency and other operating expenses attributable to our exploration and production segment of $20 million for the nine months ended September 30, 2022 were primarily due to a payment for the cancellation of the Smithburg 2 gas processing plant. Contract termination, loss contingency and other operating expenses attributable to our exploration and production segment of $24 million for the nine months ended September 30, 2023 were primarily due to a loss contingency and the early termination of certain completion contracts.

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 (calculated as marketing revenues less marketing expense) decreased from $80 million, or $0.09 per Mcfe, for the nine months ended September 30, 2022 to $62 million, or $0.07 per Mcfe, for the nine months ended September 30, 2023, primarily due to lower firm transportation commitments, partially offset by lower marketing margins between periods.

Marketing revenue. Marketing revenue decreased from $335 million for the nine months ended September 30, 2022 to $155 million for the nine months ended September 30, 2023, a decrease of $180 million, or 54%. This fluctuation primarily resulted from the following:

● Natural gas marketing revenue decreased by $145 million between periods primarily due to lower natural gas prices, partially offset by higher natural gas marketing volumes. Lower natural gas prices accounted for an approximate $156 million decrease in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes), and higher natural gas marketing volumes accounted for a $11 million increase in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price).

● Ethane marketing revenues were $37 million for the nine months ended September 30, 2022. There were no third-party ethane marketing revenues for the nine months ended September 30, 2023.

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● Oil marketing revenue increased by $2 million between periods primarily due to higher marketing volumes, partially offset by lower oil prices. Higher oil marketing volumes accounted for a $19 million increase in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and lower oil prices accounted for an approximate $17 million decrease in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes).

Marketing expense. Marketing expense decreased from $415 million for the nine months ended September 30, 2022 to $217 million for the nine months ended September 30, 2023, a decrease of $198 million, or 48%. 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 ethane purchases decreased $150 million and $24 million, respectively, partially offset by oil purchase increases of $3 million. The total cost of third-party commodity purchases decreased primarily due to lower commodity prices between periods, partially offset by higher third-party natural gas and oil marketing volumes during the nine months ended September 30, 2023. Firm transportation costs were $109 million for the nine months ended September 30, 2022 and $82 million for the nine months ended September 30, 2023, a decrease of $27 million due to the reduction in firm transportation commitments and higher third-party marketing volumes between periods.

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

Antero Midstream Segment

Antero Midstream revenue. Revenue from the Antero Midstream segment increased from $678 million for the nine months ended September 30, 2022 to $782 million for the nine months ended September 30, 2023, an increase of $104 million, primarily due to increased throughput and water handling volumes between periods, as well as higher gathering, compression and fresh water delivery fees primarily as a result of an annual CPI-based adjustments and higher other fluid handling fees primarily due to increased costs partially due to inflationary pressures between periods that impact the cost plus 3% and cost of service rates.

Antero Midstream operating expense. Total operating expense related to the Antero Midstream segment increased from $283 million for the nine months ended September 30, 2022 to $325 million for the nine months ended September 30, 2023, an increase of $42 million, primarily due to increased direct operating and equity-based compensation expenses, partially offset by lower general and administrative expenses (excluding equity-based compensation) between periods. Direct operating expenses increased between periods primarily due to 12 compressors that were acquired during the fourth quarter of 2022 and increased heavy maintenance expense between periods. Equity-based compensation increased between periods primarily due to an increase in the annual equity awards granted during the first half of 2023 as compared to prior years, which were temporarily and significantly reduced during 2020 and supplemented by our cash awards program. Antero Midstream’s equity awards vest over three or four year service periods, and its equity incentive program began returning to normal levels in 2021. General and administrative expenses (excluding equity-based compensation expense) decreased between periods primarily due to lower legal costs.

Items Not Allocated to Segments

Interest expense. Interest expense decreased from $100 million for the nine months ended September 30, 2022 to $85 million for the nine months ended September 30, 2023, a decrease of $15 million or 15%, primarily due to the reduction in debt as a result of the repurchase of certain of our unsecured senior notes between periods, partially offset by higher benchmark interest rates during the nine months ended September 30, 2023 and higher Credit Facility borrowings between periods.

Loss on early extinguishment of debt. During the nine months ended September 30, 2022, we (i) redeemed the remaining $585 million aggregate principal amount of our 2025 Notes at a redemption price of 101.25% of par, plus accrued and unpaid interest and (ii) repurchased $221 million of our 2026 Notes at a weighted average of 109% of the principal amount thereof, plus accrued and unpaid interest, and $168 million of our 2029 notes at a weighted average of 107% of the principal amount thereof, plus accrued and unpaid interest, which resulted in a loss on early debt extinguishment of $45 million. There were no debt redemptions or repurchases during the nine months ended September 30, 2023. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information.

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Income tax expense. For the nine months ended September 30, 2022, we had an income tax expense of $308 million, with an effective tax rate of 20%, due to income before income taxes of $1.5 billion. For the nine months ended September 30, 2023, we had income tax expense of $46 million, with an effective tax rate of 17%, due to income before income taxes of $272 million. The decrease in the effective tax rate between periods was primarily due to lower income before income taxes and the effects of noncontrolling interests.

Capital Resources and Liquidity

Sources and Uses of Cash

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

Based on strip prices as of September 30, 2023, 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):

	Nine Months Ended September 30,
	2022		2023
Net cash provided by operating activities	$	2,576,057		682,546
Net cash used in investing activities		(718,363)		(914,137)
Net cash provided by (used in) financing activities		(1,857,694)		231,591
Net increase in cash and cash equivalents	$	—		—

Operating activities. Net cash provided by operating activities was $2.6 billion and $682 million for the nine months ended September 30, 2022 and 2023, respectively. Net cash provided by operating activities decreased primarily due to lower commodity prices, a $202 million payment for early settlement of our swaption agreement and higher contract termination expenses, general and administrative expenses (excluding equity-based compensation expense) and lease operating expenses. These operating cash flow decreases were partially offset by higher production and changes in working capital and lower payments for commodity derivative settlements, net marketing expense and interest expense between periods.

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

Investing activities. Net cash used in investing activities increased from $718 million for the nine months ended September 30, 2022 to $914 million for the nine months ended September 30, 2023, primarily due to an increase in capital expenditures of $191 million between periods. The increase in capital expenditures between periods was primarily due to increased drilling and completions activity and land purchases, as well as higher drilling and water costs between periods.

Financing activities. Net cash used in financing activities was $1.9 billion during the nine months ended September 30, 2022, as compared to net cash provided by financing activities of $232 million during the nine months ended September 30, 2023. During the nine months ended September 30, 2022, we redeemed $585 million aggregate principal amount of our 2025 Notes, repurchased $221 million aggregate principal amount of our 2026 Notes and $168 million aggregate principal amount of our 2029 Notes at a total cost of $1.0 billion. We also repurchased approximately 19 million shares of our common stock at a total cost of approximately $675 million, distributed $114 million to the noncontrolling interest in Martica and paid $65 million in employee withholding taxes for vested equity-based awards. Additionally, we borrowed $9 million, net, on our Credit Facility during the nine months ended September 30, 2022. During the nine months ended September 30, 2023, we

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borrowed $439 million, net, on our Credit Facility, partially offset by distributions to the noncontrolling interests in Martica of $104 million, repurchases of approximately 3 million shares of our common stock at a total cost of $75 million and payments for employee withholding taxes for vested equity-based awards of $27 million.

2023 Capital Budget and Capital Spending

On February 15, 2023, we announced a net capital budget for 2023 of $1.025 billion to $1.075 billion. Our budget includes: a range of $875 million to $925 million for drilling and completion and $150 million for leasehold expenditures. We do not budget for acquisitions. During 2023, we plan to complete 60 to 65 net horizontal wells in the Appalachian Basin. We periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, drilling results, leasehold acquisition opportunities and commodity prices.

For the three months ended September 30, 2023, our total consolidated capital expenditures were $262 million, including drilling and completion costs of $231 million, leasehold acquisitions of $27 million and other capital expenditures of $4 million. For the nine months ended September 30, 2023, our total consolidated capital expenditures were $890 million, including drilling and completion costs of $745 million, leasehold acquisitions of $134 million and other capital expenditures of $11 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 2022 Form 10-K for information on our senior notes.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our unaudited condensed consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our unaudited condensed consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our unaudited condensed consolidated financial statements. Our more significant accounting policies and estimates include the successful efforts method of accounting for our production activities, estimates of natural gas, NGLs and oil reserve quantities and standardized measure of future cash flows and impairment of proved properties. We provide an expanded discussion of our more significant accounting policies, estimates and judgments in the 2022 Form 10-K. We believe these accounting policies reflect our more significant estimates and assumptions used in the preparation of our unaudited condensed consolidated financial statements. Also, see Note 2—Summary of Significant Accounting Policies to the consolidated financial statements, included in the 2022 Form 10-K, for a discussion of additional accounting policies and estimates made by management.

We evaluate the carrying amount of our proved natural gas, NGLs and oil properties for impairment for the Utica and Marcellus Shale properties, by property, when events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. Under GAAP for successful efforts accounting, if the carrying amount exceeds the estimated undiscounted future net cash flows (measured using future prices), we estimate the fair value of our proved properties and record an impairment charge for any excess of the carrying amount of the properties over the estimated fair value of the properties.

Based on future prices as of September 30, 2023, the estimated undiscounted future net cash flows exceeded the carrying amount and no further evaluation was required. We have not recorded any impairment expenses associated with our proved properties during the three and nine months ended September 30, 2022 and 2023.

Estimated undiscounted future net cash flows are sensitive to commodity price swings and a decline in prices could result in the carrying amount exceeding the estimated undiscounted future net cash flows at the end of a future reporting period, which would require us to further evaluate if an impairment charge would be necessary. If future prices decline from September 30, 2023, the fair value of our properties may be below their carrying amounts and an impairment charge may be necessary. We are unable, however, to predict future commodity prices with any reasonable certainty.

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New Accounting Pronouncements

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

Off-Balance Sheet Arrangements

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Commodity Hedging Activities

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

To mitigate some of the potential negative impact on our cash flows caused by changes in commodity prices, we may enter into financial derivative instruments for a portion of our natural gas, NGLs and oil production when management believes that favorable future prices can be secured.

Our financial hedging activities are intended to support natural gas, NGLs and oil prices at targeted levels and to manage our exposure to natural gas, NGLs and oil price fluctuations. These contracts may include commodity price swaps whereby we will receive a fixed price and pay a variable market price to the contract counterparty, collars that set a floor and ceiling price for the hedged production, basis differential swaps or embedded options. These contracts are financial instruments and do not require or allow for physical delivery of the hedged commodity.

As of September 30, 2023, we had in place natural gas swaps and basis swaps, as well as a call option and embedded put option covering portions of our projected production. Substantially all of our derivative arrangements terminate by December 31, 2023. Our commodity hedge position as of September 30, 2023 is summarized in Note 11—Derivative Instruments to our unaudited condensed consolidated financial statements. Under the Credit Facility, we are permitted to hedge up to 75% of our projected production for the next 60 months. We may enter into hedge contracts with a term greater than 60 months, and for no longer than 72 months, for up to 65% of our estimated production. Based on our production and our fixed price swap contracts, call option and embedded put option that settled during the nine months ended September 30, 2023, our revenues would have decreased by $112 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 September 30, 2023.

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

Mark-to-market adjustments of derivative instruments cause earnings volatility but have no cash flow impact relative to changes in market prices until the derivative contracts are settled or monetized prior to settlement. We expect continued volatility in the fair value of our derivative instruments. Our cash flows are impacted when the associated derivative contracts are settled or monetized by making or receiving payments to or from the counterparty. As of December 31, 2022 and

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September 30, 2023, the estimated fair value of our commodity derivative instruments was a net liability $431 million and $75 million, respectively, comprised of current and noncurrent assets and liabilities.

Due to our improved liquidity and leverage position as compared to past levels, the percentage of our expected production that we hedge has decreased. For the three and nine months ended September 30, 2022, 31% and 34%, respectively, of our production was hedged through fixed price commodity swaps as compared to 1% for each of the three and nine months ended September 30, 2023. Assuming our 2023 production is the same as our production in 2022, 1% of our production for 2023 will be hedged through fixed price commodity swaps.

Counterparty and Customer Credit Risk

Our principal exposures to credit risk are through receivables resulting from the following: the sale of our natural gas, NGLs and oil production ($353 million as of September 30, 2023), which we market to energy companies, end users and refineries, and commodity derivative contracts ($9 million as of September 30, 2023).

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, by using derivative instruments that are not traded on an exchange to hedge exposures to changes in commodity prices, we expose ourselves to the credit risk of our counterparties. Credit risk is the potential failure of a counterparty to perform under the terms of a derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe us, which creates credit risk. To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions that management deems to be competent and competitive market makers. The creditworthiness of our counterparties is subject to periodic review. We have commodity hedges in place with three different counterparties, two of which are lenders under the Credit Facility. As of September 30, 2023, substantially all of our derivative assets were with one counterparty that is not affiliated with our Credit Facility. The estimated fair value of our commodity derivative assets has been risk-adjusted using a discount rate based upon the counterparties’ respective published credit default swap rates (if available, or if not available, a discount rate based on the applicable Reuters bond rating) as of September 30, 2023 for each of the European and American banks. We believe that all of our counterparties currently are acceptable credit risks. Other than as provided by the Credit Facility, we are not required to provide credit support or collateral to any of our counterparties under our derivative contracts, nor are they required to provide credit support to us. As of September 30, 2023, 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 nine months ended September 30, 2023 was 7.46%. We estimate that a 1.0% increase in the applicable average interest rates for the nine months ended September 30, 2023 would have resulted in an estimated $2.2 million increase in interest expense.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report on Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of September 30, 2023 at a level of reasonable assurance.

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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 September 30, 2023 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

We are subject to certain risks and hazards due to the nature of the business activities we conduct. For a discussion of these risks, see “Item 1A.  Risk Factors” in the 2022 Form 10-K. There have been no material changes to the risks described in such report. We may experience additional risks and uncertainties not currently known to us. Furthermore, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also materially and adversely affect us.

Item 2. Unregistered Sales of Equity Securities

Issuer Purchases of Equity Securities

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

				Total Number	Approximate
				of Shares	Dollar Value
				Repurchased	of Shares
				as Part of	that May
	Total Number			Publicly	Yet be Purchased
	of Shares	Average Price		Announced	Under the Plan
Period	Purchased (1)	Paid Per Share		Plans	($ in thousands)
July 1, 2023 - July 31, 2023	3,769	$	22.59	—	$	1,234,929
August 1, 2023 - August 31, 2023	—		—	—		1,234,929
September 1, 2023 - September 30, 2023	—		—	—		1,234,929
Total	3,769	$	22.59	—

(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 awards held by our employees.

Item 4. Mine Safety Disclosures

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

Item 5. Other Information

None.

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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).
95.1*	Federal Mine Safety and Health Act Information.
101*	The following financial information from this Quarterly Report on Form 10-Q of Antero Resources Corporation for the quarter ended September 30, 2023 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.

ANTERO RESOURCES CORPORATION
By:	/s/ MICHAEL N. KENNEDY
	Michael N. Kennedy
	Chief Financial Officer and Senior Vice President–Finance
Date:	October 25, 2023

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