Antero Resources (AR) 10-Q 2021 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, 2021

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

The registrant had 313,929,992 shares of common stock outstanding as of October 22, 2021.

TABLE OF CONTENTS

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS		2
PART I—FINANCIAL INFORMATION		4
Item 1.	Financial Statements (Unaudited)	4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	59
Item 4.	Controls and Procedures	61
PART II—OTHER INFORMATION		62
Item 1.	Legal Proceedings	62
Item 1A.	Risk Factors	62
Item 2.	Unregistered Sales of Equity Securities	62
Item 5.	Other Information	62
Item 6.	Exhibits	63
SIGNATURES		64

1

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Some of the information in this Quarterly Report on Form 10-Q may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements, although not all forward-looking statements contain such identifying words. When considering these forward-looking statements, investors should keep in mind the risk factors and other cautionary statements in this Quarterly Report on Form 10-Q. These forward-looking statements are based on management’s current beliefs, based on currently available information, as to the outcome and timing of future events. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

● our ability to execute our business strategy;

● our production and oil and gas reserves;

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

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

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

● impacts of world health events, including the coronavirus (“COVID-19”) pandemic;

● 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 and cost savings initiatives, including with respect to water handling services provided by Antero Midstream Corporation;

● competition and government regulations;

● 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;

● general economic conditions;

● credit markets;

● uncertainty regarding our future operating results; and

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

2

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, availability of drilling, completion, and production equipment and services, environmental risks, drilling and completion and other operating risks, marketing and transportation risks, regulatory changes, 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 world health events (including the COVID-19 pandemic), cybersecurity risks 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, 2020 (the “2020 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.

3

PART I—FINANCIAL INFORMATION

ANTERO RESOURCES CORPORATION

Condensed Consolidated Balance Sheets

(In thousands)

			(Unaudited)
	December 31,		September 30,
	2020		2021
Assets
Current assets:
Accounts receivable	$	28,457		34,768
Accrued revenue		425,314		652,521
Derivative instruments		105,130		627
Other current assets		15,238		20,937
Total current assets		574,139		708,853
Property and equipment:
Oil and gas properties, at cost (successful efforts method):
Unproved properties		1,175,178		1,052,543
Proved properties		12,260,713		12,559,146
Gathering systems and facilities		5,802		5,802
Other property and equipment		74,361		91,621
		13,516,054		13,709,112
Less accumulated depletion, depreciation, and amortization		(3,869,116)		(4,176,296)
Property and equipment, net		9,646,938		9,532,816
Operating leases right-of-use assets		2,613,603		2,969,642
Derivative instruments		47,293		14,834
Investment in unconsolidated affiliate		255,082		236,597
Other assets		13,790		8,796
Total assets	$	13,150,845		13,471,538
Liabilities and Equity
Current liabilities:
Accounts payable	$	26,728		60,409
Accounts payable, related parties		69,860		79,595
Accrued liabilities		343,524		501,132
Revenue distributions payable		198,117		315,936
Derivative instruments		31,242		1,436,292
Short-term lease liabilities		266,024		353,470
Deferred revenue, VPP		45,257		39,528
Other current liabilities		2,302		16,320
Total current liabilities		983,054		2,802,682
Long-term liabilities:
Long-term debt		3,001,593		2,341,033
Deferred income tax liability		412,252		55,636
Derivative instruments		99,172		331,570
Long-term lease liabilities		2,348,785		2,616,889
Deferred revenue, VPP		156,024		127,844
Other liabilities		59,694		60,642
Total liabilities		7,060,574		8,336,296
Commitments and contingencies (Notes 13 and 14)
Equity:
Stockholders' equity:
Preferred stock, $0.01 par value; authorized - 50,000 shares; NaN issued		—		—
Common stock, $0.01 par value; authorized - 1,000,000 shares; 268,672 shares and 313,866 shares issued and outstanding as of December 31, 2020 and September 30, 2021, respectively		2,686		3,138
Additional paid-in capital		6,195,497		6,365,929
Accumulated deficit		(430,478)		(1,518,762)
Total stockholders' equity		5,767,705		4,850,305
Noncontrolling interests		322,566		284,937
Total equity		6,090,271		5,135,242
Total liabilities and equity	$	13,150,845		13,471,538

See accompanying notes to unaudited condensed consolidated financial statements.

4

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Operations and Comprehensive Loss (Unaudited)

(In thousands, except per share amounts)

	Three Months Ended September 30,
	2020		2021
Revenue and other:
Natural gas sales	$	436,304		884,669
Natural gas liquids sales		327,426		598,327
Oil sales		34,265		56,734
Commodity derivative fair value losses		(514,751)		(1,250,466)
Marketing		91,497		232,685
Amortization of deferred revenue, VPP		5,175		11,404
Gain on sale of assets		—		539
Other income		675		530
Total revenue		380,591		534,422
Operating expenses:
Lease operating		21,450		25,363
Gathering, compression, processing, and transportation		656,615		628,225
Production and ad valorem taxes		25,790		52,219
Marketing		128,580		266,751
Exploration		454		235
Impairment of oil and gas properties		29,392		26,253
Depletion, depreciation, and amortization		238,418		182,810
Accretion of asset retirement obligations		1,115		828
General and administrative (including equity-based compensation expense of $5,699 and $5,298 in 2020 and 2021, respectively)		31,640		32,442
Contract termination and rig stacking		1,246		3,370
Total operating expenses		1,134,700		1,218,496
Operating loss		(754,109)		(684,074)
Other income (expense):
Interest expense, net		(48,043)		(45,414)
Equity in earnings of unconsolidated affiliate		24,419		21,450
Gain (loss) on early extinguishment of debt		55,633		(16,567)
Transaction expense		(524)		(626)
Total other income (expense)		31,485		(41,157)
Loss before income taxes		(722,624)		(725,231)
Provision for income tax benefit		168,778		158,656
Net loss and comprehensive loss including noncontrolling interests		(553,846)		(566,575)
Less: net loss and comprehensive loss attributable to noncontrolling interests		(18,233)		(17,257)
Net loss and comprehensive loss attributable to Antero Resources Corporation	$	(535,613)		(549,318)
Loss per share—basic	$	(1.99)		(1.75)
Loss per share—diluted	$	(1.99)		(1.75)
Weighted average number of shares outstanding:
Basic		268,511		313,790
Diluted		268,511		313,790

See accompanying notes to unaudited condensed consolidated financial statements.

5

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Operations and Comprehensive Loss (Unaudited)

(In thousands, except per share amounts)

	Nine Months Ended September 30,
	2020		2021
Revenue and other:
Natural gas sales	$	1,214,801		2,231,558
Natural gas liquids sales		797,296		1,503,027
Oil sales		78,233		153,326
Commodity derivative fair value losses		(116,933)		(2,260,062)
Marketing		201,855		562,928
Amortization of deferred revenue, VPP		5,175		33,833
Gain on sale of assets		—		2,827
Other income		2,180		551
Total revenue		2,182,607		2,227,988
Operating expenses:
Lease operating		71,836		71,555
Gathering, compression, processing, and transportation		1,877,084		1,874,664
Production and ad valorem taxes		71,481		130,610
Marketing		334,906		627,822
Exploration		895		6,092
Impairment of oil and gas properties		155,962		69,618
Depletion, depreciation, and amortization		652,130		564,166
Accretion of asset retirement obligations		3,330		2,947
General and administrative (including equity-based compensation expense of $17,001 and $15,189 in 2020 and 2021, respectively)		101,264		108,693
Contract termination and rig stacking		12,317		4,305
Total operating expenses		3,281,205		3,460,472
Operating loss		(1,098,598)		(1,232,484)
Other income (expense):
Interest expense, net		(152,956)		(138,120)
Equity in earnings (loss) of unconsolidated affiliate		(83,408)		57,621
Gain (loss) on early extinguishment of debt		175,365		(82,836)
Loss on convertible note equitizations		—		(50,777)
Impairment of equity method investment		(610,632)		—
Transaction expense		(6,662)		(3,102)
Total other expense		(678,293)		(217,214)
Loss before income taxes		(1,776,891)		(1,449,698)
Provision for income tax benefit		421,167		337,568
Net loss and comprehensive loss including noncontrolling interests		(1,355,724)		(1,112,130)
Less: net loss and comprehensive loss attributable to noncontrolling interests		(17,997)		(23,846)
Net loss and comprehensive loss attributable to Antero Resources Corporation	$	(1,337,727)		(1,088,284)
Loss per share—basic	$	(4.89)		(3.55)
Loss per share—diluted	$	(4.89)		(3.55)
Weighted average number of shares outstanding:
Basic		273,689		306,201
Diluted		273,689		306,201

See accompanying notes to unaudited condensed consolidated financial statements.

6

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)

(In thousands)

					Additional		Accumulated
	Common Stock				Paid-in		Earnings		Noncontrolling		Total
	Shares		Amount		Capital		(Deficit)		Interests		Equity
Balances, December 31, 2019		295,941	$	2,959		6,130,365		837,419		—		6,970,743
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		178		2		(34)		—		—		(32)
Repurchases and retirements of common stock		(27,193)		(272)		(42,418)		—		—		(42,690)
Equity-based compensation		—		—		3,329		—		—		3,329
Net loss and comprehensive loss		—		—		—		(338,810)		—		(338,810)
Balances, March 31, 2020		268,926		2,689		6,091,242		498,609		—		6,592,540
Issuance of common units in Martica Holdings, LLC		—		—		—		—		300,000		300,000
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		464		5		(305)		—		—		(300)
Distributions to noncontrolling interest		—		—		—		—		(3,413)		(3,413)
Repurchases and retirements of common stock		(1,000)		(10)		(743)		—		—		(753)
Equity-based compensation		—		—		7,973		—		—		7,973
Net income (loss) and comprehensive income (loss)		—		—		—		(463,304)		236		(463,068)
Balances, June 30, 2020		268,390		2,684		6,098,167		35,305		296,823		6,432,979
Issuance of common units in Martica Holdings, LLC		—		—		—		—		51,000		51,000
Equity component of 2026 Convertible Notes, net		—		—		61,926		—		—		61,926
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		159		1		(42)		—		—		(41)
Distributions to noncontrolling interest		—		—		—		—		(13,836)		(13,836)
Equity-based compensation		—		—		5,699		—		—		5,699
Net loss and comprehensive loss		—		—		—		(535,613)		(18,233)		(553,846)
Balances, September 30, 2020		268,549	$	2,685		6,165,750		(500,308)		315,754		5,983,881

See accompanying notes to unaudited condensed consolidated financial statements.

7

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Stockholders’ Equity (Unaudited) (Continued)

(In thousands)

					Additional
	Common Stock				Paid-in		Accumulated		Noncontrolling		Total
	Shares		Amount		Capital		Deficit		Interests		Equity
Balances, December 31, 2020		268,672	$	2,686		6,195,497		(430,478)		322,566		6,090,271
Issuance of common shares		31,388		314		238,551		—		—		238,865
Issuance of common units in Martica Holdings, LLC		—		—		—		—		51,000		51,000
Equity component of 2026 Convertible Notes, net		—		—		(116,381)		—		—		(116,381)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		1,130		11		(5,656)		—		—		(5,645)
Distributions to noncontrolling interest		—		—		—		—		(24,699)		(24,699)
Equity-based compensation		—		—		5,642		—		—		5,642
Net income (loss) and comprehensive income (loss)		—		—		—		(15,499)		4,395		(11,104)
Balances, March 31, 2021		301,190		3,011		6,317,653		(445,977)		353,262		6,227,949
Issuance of common shares		11,588		116		125,262		—		—		125,378
Equity component of 2026 Convertible Notes, net		—		—		(79,497)		—		—		(79,497)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		749		8		(3,893)		—		—		(3,885)
Distributions to noncontrolling interest		—		—		—		—		(21,329)		(21,329)
Equity-based compensation		—		—		4,249		—		—		4,249
Net loss and comprehensive loss		—		—		—		(523,467)		(10,984)		(534,451)
Balances, June 30, 2021		313,527		3,135		6,363,774		(969,444)		320,949		5,718,414
Equity component of 2026 Convertible Notes, net		—		—		36		—		—		36
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		339		3		(3,179)		—		—		(3,176)
Distributions to noncontrolling interest		—		—		—		—		(18,755)		(18,755)
Equity-based compensation		—		—		5,298		—		—		5,298
Net loss and comprehensive loss		—		—		—		(549,318)		(17,257)		(566,575)
Balances, September 30, 2021		313,866	$	3,138		6,365,929		(1,518,762)		284,937		5,135,242

See accompanying notes to unaudited condensed consolidated financial statements.

8

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Cash Flows (Unaudited)

(In thousands)

	Nine Months Ended September 30,
	2020		2021
Cash flows provided by (used in) operating activities:
Net loss including noncontrolling interests	$	(1,355,724)		(1,112,130)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation, amortization, and accretion		655,460		567,113
Impairments		766,594		69,618
Commodity derivative fair value losses		116,933		2,260,062
Gains (losses) on settled commodity derivatives		740,805		(481,083)
Proceeds from (payments for) derivative monetizations		18,073		(4,569)
Gain on sale of assets		—		(2,827)
Equity-based compensation expense		17,001		15,189
Deferred income tax benefit		(426,267)		(337,568)
Equity in (earnings) loss of unconsolidated affiliate		83,408		(57,621)
Dividends of earnings from unconsolidated affiliate		128,267		105,325
Amortization of deferred revenue		(5,175)		(33,833)
Amortization of debt issuance costs, debt discount, debt premium and other		7,391		10,122
(Gain) loss on early extinguishment of debt		(175,365)		82,836
Loss on convertible note equitizations		—		50,777
Changes in current assets and liabilities:
Accounts receivable		(15,454)		(11,336)
Accrued revenue		(20,843)		(227,207)
Other current assets		(1,455)		(5,695)
Accounts payable including related parties		(2,198)		39,108
Accrued liabilities		15,522		124,382
Revenue distributions payable		(54,403)		117,819
Other current liabilities		(60)		16,470
Net cash provided by operating activities		492,510		1,184,952
Cash flows provided by (used in) investing activities:
Additions to unproved properties		(31,136)		(48,960)
Drilling and completion costs		(693,920)		(447,899)
Additions to other property and equipment		(1,346)		(14,082)
Settlement of water earnout		125,000		—
Proceeds from asset sales		—		3,192
Proceeds from VPP sale, net		215,833		—
Change in other liabilities		—		(77)
Change in other assets		1,506		2,371
Net cash used in investing activities		(384,063)		(505,455)
Cash flows provided by (used in) financing activities:
Repurchases of common stock		(43,443)		—
Issuance of senior notes		—		1,800,000
Issuance of convertible notes		287,500		—
Repayment of senior notes		(899,971)		(1,424,354)
Borrowings (repayments) on bank credit facilities, net		275,000		(919,500)
Payment of debt issuance costs		(8,907)		(22,814)
Sale of noncontrolling interest		300,000		51,000
Distributions to noncontrolling interests in Martica Holdings LLC		(17,249)		(64,783)
Employee tax withholding for settlement of equity compensation awards		(373)		(12,706)
Convertible note equitizations		—		(85,648)
Other		(1,004)		(692)
Net cash used in financing activities		(108,447)		(679,497)
Net increase in cash and cash equivalents		0		0
Cash and cash equivalents, beginning of period		0		0
Cash and cash equivalents, end of period	$	0		0
Supplemental disclosure of cash flow information:
Cash paid during the period for interest	$	135,494		130,947
Increase (decrease) in accounts payable and accrued liabilities for additions to property and equipment	$	(44,302)		33,547

See accompanying notes to unaudited condensed consolidated financial statements.

9

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, 2020 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, 2020 consolidated financial statements were included in Antero Resources’ 2020 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, 2020 and September 30, 2021 and its results of operations for the three and nine months ended September 30, 2020 and 2021 and cash flows for the nine months ended September 30, 2020 and 2021. 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, 2021 are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received for natural gas, NGLs, and oil, natural production declines, the uncertainty of exploration and development drilling results, fluctuations in the fair value of derivative instruments, the impacts of COVID-19 and other factors.

(b) Principles of Consolidation

The accompanying unaudited condensed consolidated financial statements include the accounts of Antero Resources Corporation, its wholly owned subsidiaries, and its variable interest entity (“VIE”), Martica Holdings LLC, (“Martica”), for which the Company is the primary beneficiary. The noncontrolling interest reflected in the Company’s unaudited condensed consolidated financial statements for the three and nine months ended September 30, 2020 and 2021 represents the Company’s interest in Martica owned by third parties. See Note 3—Transactions to the unaudited condensed consolidated financial statements for more information on Martica.

(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, 2020, the book overdrafts included within accounts payable and revenue distributions payable were $11 million and $15 million, respectively. As of September 30, 2021, the book overdrafts included within accounts payable and revenue distributions payable were $37 million and $31 million, respectively.

(d) Earnings (Loss) Per Common Share

Earnings (loss) per common share—basic for each period is computed by dividing net income (loss) attributable to Antero by the basic weighted average number of shares outstanding during the period. Earnings (loss) per common share—diluted for each period is computed after giving consideration to the potential dilution from outstanding equity awards and shares of common stock

10

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

issuable upon conversion of the 2026 Convertible Notes (as defined below in Note 7—Long-Term Debt). The Company includes restricted stock unit (“RSU”) 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. The potential dilutive effect of the 2026 Convertible Notes is calculated using the (i) treasury stock method for the three and nine months ended September 30, 2020 as a result of the Company’s intent to settle the principal amount of such convertible notes in cash upon conversion during the nine months ended September 30, 2020, and (ii) if-converted method for the three and nine months ended September 30, 2021, as a result of the partial equitizations of the 2026 Convertible Notes during the nine months ended September 30, 2021. See Note 7—Long-Term Debt for further discussion on the equitization transactions. 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 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,
	2020	2021	2020	2021
Basic weighted average number of shares outstanding	268,511	313,790	273,689	306,201
Add: Dilutive effect of RSUs	—	—	—	—
Add: Dilutive effect of PSUs	—	—	—	—
Add: Dilutive effect of outstanding stock options	—	—	—	—
Add: Dilutive effect of 2026 Convertible Notes	—	—	—	—
Diluted weighted average number of shares outstanding	268,511	313,790	273,689	306,201
Weighted average number of outstanding securities excluded from calculation of diluted earnings per common share (1):
RSUs	10,129	6,158	7,397	6,562
PSUs	1,988	2,748	1,808	2,706
Outstanding stock options	432	357	432	388
2026 Convertible Notes (2)	—	18,778	—	18,778

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

(2) Under the treasury stock method, only the amount by which the conversion value exceeds the aggregate principal amount of the 2026 Convertible Notes is considered in the diluted earnings per share computation. As of September 30, 2020, the conversion value did not exceed the principal amount of the notes, and accordingly, there was no impact to diluted earnings per share for the three and nine months ended September 30, 2020. Under the if-converted method, the weighted average number of shares outstanding for the three and nine months ended September 30, 2020, would have been 28 million and 10 million, respectively, all of which would have been anti-dilutive.

(e) Income Taxes

The Company recognizes deferred tax assets and liabilities for temporary differences resulting from net operating loss carryforwards for income tax purposes and the differences between the financial statement and tax basis of assets and liabilities. The effect of changes in tax laws or tax rates is recognized in income during the period such changes are enacted.  Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion, or all, of the deferred tax assets will not be realized.

On April 9, 2021, West Virginia enacted new tax laws related to its apportionment and sourcing methodologies. The newly enacted laws are effective January 1, 2022 on a prospective basis and are expected to reduce the Company’s net income or loss that is apportioned to West Virginia.  As a result of this tax law change, the Company’s net deferred income tax liability was reduced by $34

11

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

million as of September 30, 2021, which includes a $48 million increase in deferred tax assets, partially offset by a $14 million increase in valuation allowance. 

(f) Recently Issued Accounting Standards

Convertible 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. The new standard becomes effective for the Company on January 1, 2022, and early adoption is permitted. The Company is evaluating the transition method it plans to use for adoption on January 1, 2022. However, the Company has utilized the modified retrospective approach to quantify the expected impact of this standard on its financial statements.

Upon adoption of this new standard, the Company expects to reclassify between $15 million and $30 million, net of deferred income taxes and equity issuance costs, to long-term debt and deferred income tax liability, as applicable, from stockholders’ equity, which amount is subject to adjustment for any conversions or other transactions until adoption of this new standard. Additionally, annual interest expense for the 2026 Convertible Notes will be based on an effective interest rate of 4.8% as compared to 15.1% for the three and nine months ended September 30, 2021. The Company does not believe that adoption of the standard will impact its operational strategies or development prospects.

Income Taxes

In December 2019, the FASB issued ASU No. 2019-12, Simplifying the Accounting for Income Taxes. This ASU removes certain exceptions to the general principles in ASC 740, Income Taxes (“ASC 740”) and also simplifies portions of ASC 740 by clarifying and amending existing guidance. It is effective for interim and annual reporting periods after December 15, 2020. The Company adopted this ASU on January 1, 2021, and it did not have a material impact on the Company's unaudited condensed consolidated financial statements.

(3) Transactions

(a) Conveyance of Overriding Royalty Interest

On June 15, 2020, the Company announced the consummation of a transaction with an affiliate of Sixth Street Partners, LLC (“Sixth Street”) relating to certain overriding royalty interests across the Company’s existing asset base (the “ORRIs”). In connection with the transaction, the Company contributed the ORRIs to Martica and Sixth Street contributed $300 million in cash (subject to customary adjustments) and agreed to contribute up to an additional $102 million in cash if certain production thresholds attributable to the ORRIs are achieved in the third quarter of 2020 and first quarter of 2021. All cash contributed by Sixth Street at the initial closing was distributed to the Company. The Company met the applicable production thresholds related to the third quarter of 2020 and first quarter of 2021 as of September 31, 2020 and March 31, 2021, respectively. The Company received a $51 million cash distribution during each of the fourth quarter of 2020 and the second quarter of 2021.

The ORRIs include an overriding royalty interest of 1.25% of the Company’s working interest in all of its proved operated developed properties in West Virginia and Ohio, subject to certain excluded wells (the “Initial PDP Override”), and an overriding royalty interest of 3.75% of the Company’s working interest in all of its undeveloped properties in West Virginia and Ohio (the “Development Override”). Wells turned to sales after April 1, 2020 and prior to the later of (a) the date on which the Company turns to sales 2.2 million lateral feet (net to the Company’s interest) of horizontal wells burdened by the Development Override 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 are subject to the Development Override.

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.

12

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

 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 the Company will receive all distributions in respect of the Incremental Override, unless certain production targets are not achieved, in which case Sixth Street will receive some or all of the 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.

The conveyance of the ORRIs from the Company to Martica was accounted for as a transaction between entities under common control.  As a result, the contributed ORRIs have been recorded by Martica at their historical cost.  

(b) Volumetric Production Payment Transaction

On August 10, 2020, the Company completed a volumetric production payment transaction and received net proceeds of approximately $216 million (the "VPP").  In connection with the VPP, the Company entered into a purchase and sale agreement, together with a conveyance agreement and production and marketing agreement, with J.P. Morgan Ventures Energy Corporation ("JPM-VEC") to convey, effective July 1, 2020, an overriding royalty interest in dry gas producing properties in West Virginia (the "VPP Properties") equal to 136,589,000 MMBtu over the expected seven-year term of the VPP.

The Company has accounted for the VPP as a conveyance under ASC 932, Extractive Activities—Oil and Gas (“ASC 932”), and the net proceeds were recorded as deferred revenue in the condensed consolidated balance sheet as of the transaction closing. Deferred revenue is recognized as volumes are delivered using the units-of-production method over the term of the VPP. Under the production and marketing agreement, Antero and its affiliates provide certain marketing services as JPM-VEC’s agent, and any income or expenses related to these services will be recorded as marketing revenue or marketing expenses as appropriate.

Contemporaneously with the VPP, the Company executed a call option related to the production volumes associated with its retained interest in the VPP properties, which is collateralized by a mortgage on the VPP properties. Additionally, the production and marketing agreement contains an embedded put option related to the production volumes for the Company’s retained interest in the VPP properties, which has been bifurcated from the production and marketing arrangement and accounted for as a derivative instrument recorded at fair value. See Note 11—Derivative Instruments to the unaudited condensed consolidated financial statements for more information on the Company’s derivative instruments.

(c) 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, Antero Resources and QL agreed to a capital budget for such annual tranche, and for each subsequent year through 2024, Antero Resources will propose a capital budget and estimated internal rate of return (“IRR”) for all wells to be spud during such year and, subject to the mutual agreement of the parties that the estimated IRR for the year exceeds a specified return, QL will be obligated to participate in such tranche. Antero Resources develops and manages the drilling program associated with each tranche, including the selection of wells. Additionally, for each annual tranche in which QL participates, Antero Resources and QL will enter into an assignment, bill of sale and conveyance pursuant to which QL will be conveyed a proportionate working interest percentage in each well spud in that year, which conveyance will not be subject to any reversion.

Under the terms of the arrangement, QL will fund 20% of development capital for wells spud in 2021 and is expected to fund between 15% and 20% of development capital for wells spud from 2022 through 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 December 31 following the end of each tranche year. Capital costs in excess of, and cost savings below, a specified percentage of budgeted amounts for each annual tranche will be for Antero Resources’ account. Subject to the preceding sentence, for any wells included in a tranche, QL is obligated and responsible for its working interest share of costs and liabilities, and is entitled to its working interest share of revenues, associated with such wells for the life of such wells. If Antero Resources presents a capital budget for an annual tranche with an estimated IRR equal to or exceeding a specified return that QL in good faith believes is less than such specified return and QL elects not to participate, Antero Resources will not be obligated to offer QL the opportunity to participate in subsequent annual tranches.

13

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

The Company has accounted for the drilling partnership as a conveyance under ASC 932 and such conveyances are recorded in the unaudited condensed consolidated financial statements as QL obtains its proportionate working interest in each well. NaN gain or loss was recognized for the interests conveyed during the three and nine months ended September 30, 2021.

(4) Revenue

(a) Disaggregation of Revenue

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2021		2020		2021		Reportable Segment
Revenues from contracts with customers:
Natural gas sales	$	436,304		884,669		1,214,801		2,231,558	Exploration and production
Natural gas liquids sales (ethane)		32,444		57,919		85,884		137,446	Exploration and production
Natural gas liquids sales (C3+ NGLs)		294,982		540,408		711,412		1,365,581	Exploration and production
Oil sales		34,265		56,734		78,233		153,326	Exploration and production
Marketing		91,497		232,685		201,855		562,928	Marketing
Total revenue from contracts with customers		889,492		1,772,415		2,292,185		4,450,839
Loss from derivatives, deferred revenue and other sources, net		(508,901)		(1,237,993)		(109,578)		(2,222,851)
Total revenue	$	380,591		534,422		2,182,607		2,227,988

(b) Transaction Price Allocated to Remaining Performance Obligations

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

(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, 2020 and September 30, 2021, the Company’s receivables from contracts with customers were $425 million and $653 million, respectively.

(5) Equity Method Investment

(a) Summary of Equity Method Investment

As of September 30, 2021, Antero owned approximately 29.1% of Antero Midstream Corporation’s common stock, which is reflected in Antero’s unaudited condensed consolidated financial statements using the equity method of accounting.

14

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

The following table sets forth a reconciliation of Antero’s investment in unconsolidated affiliate for the nine months ended September 30, 2021 (in thousands):

Balance as of December 31, 2020 (1)	$	255,082
Equity in earnings of unconsolidated affiliate		57,621
Dividends from unconsolidated affiliate		(105,325)
Elimination of intercompany profit		29,219
Balance as of September 30, 2021 (1)	$	236,597

(1) The Company’s investment in Antero Midstream Corporation as of December 31, 2020 and September 30, 2021 was $1.1 billion and $1.4 billion, respectively, based on the quoted market share price of Antero Midstream Corporation.

(b) Summarized Financial Information of Antero Midstream Corporation

The tables set forth below present summarized financial information of Antero Midstream Corporation (in thousands).

Balance Sheet

	December 31,		September 30,
	2020		2021
Current assets	$	93,931		87,490
Noncurrent assets		5,516,981		5,446,143
Total assets	$	5,610,912		5,533,633
Current liabilities	$	94,005		118,690
Noncurrent liabilities		3,098,621		3,102,350
Stockholders' equity		2,418,286		2,312,593
Total liabilities and stockholders' equity	$	5,610,912		5,533,633

Statement of Operations

	Nine Months Ended September 30,
	2020		2021
Revenues	$	696,859		681,712
Operating expenses		929,480		254,905
Income (loss) from operations		(232,621)		426,807
Net income (loss)	$	(198,985)		252,991

(6) Accrued Liabilities

Accrued liabilities as of December 31, 2020 and September 30, 2021 consisted of the following items (in thousands):

	December 31,		September 30,
	2020		2021
Capital expenditures	$	32,372		52,958
Gathering, compression, processing, and transportation expenses		152,724		158,443
Marketing expenses		68,193		115,317
Interest expense, net		25,645		34,693
Accrued production and ad valorem taxes		37,371		30,488
Derivative settlements payable		3,425		72,354
Other		23,794		36,879
Total accrued liabilities	$	343,524		501,132

15

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(7) Long-Term Debt

Long-term debt as of December 31, 2020 and September 30, 2021 consisted of the following items (in thousands):

	December 31,		September 30,
	2020		2021
Credit Facility (a)	$	1,017,000		97,500
5.125% senior notes due 2022 (b)		660,516		—
5.625% senior notes due 2023 (c)		574,182		—
5.00% senior notes due 2025 (d)		590,000		590,000
8.375% senior notes due 2026 (e)		—		325,000
7.625% senior notes due 2029 (f)		—		700,000
5.375% senior notes due 2030 (g)		—		600,000
4.25% convertible senior notes due 2026 (h)		287,500		81,570
Total principal		3,129,198		2,394,070
Unamortized premium (discount), net		(111,886)		(28,780)
Unamortized debt issuance costs		(15,719)		(24,257)
Long-term debt	$	3,001,593		2,341,033

(a) Senior Secured Revolving Credit Facility

Antero Resources has a senior secured revolving credit facility with a consortium of bank lenders. On October 26, 2021, Antero Resources entered into an amended and restated senior secured revolving credit facility. References in the notes to the condensed consolidated financial statements to the (i) “Prior Credit Facility” refers to the senior secured revolving credit facility in effect for periods before October 26, 2021, (ii) “New Credit Facility” refers to the senior secured revolving credit facility in effect on or after October 26, 2021 and (iii) “Credit Facility” refers to Prior Credit Facility and New Credit Facility, collectively. 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 September 30, 2021, the borrowing base under the Prior Credit Facility was $2.85 billion and lender commitments were $2.64 billion. As of October 26, 2021, the New Credit Facility had a borrowing base of $3.5 billion and lender commitments were $1.5 billion. The next redetermination of the borrowing base is scheduled to occur in April 2022. 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 senior notes.

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 Prior Credit Facility as of December 31, 2020 and September 30, 2021.

The Prior Credit Facility provides for borrowing under either an Alternate Base Rate or as a Eurodollar Loan (as each term is defined in the Prior Credit Facility), and the New Credit Facility provides for borrowing under either an Adjusted Term Secured Overnight Financing Rate (“SOFR”), an Adjusted Daily Simple SOFR or an Alternate Base Rate (each as defined in the New 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 (i) LIBOR or the prime rate, determined by Antero Resources’ election at the time of borrowing, plus an applicable margin rate under the Prior Credit Facility and (ii) SOFR or prime rate, determined by Antero Resources’ election at the time of borrowing, plus an applicable margin rate under the New 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 (i) 0.300% to 0.375% with respect to the Prior Credit Facility, determined with reference to borrowing base utilization and (ii) 0.375% to 0.500% with respect to the New Credit Facility, determined with reference to borrowing base utilization, both rates subject to certain exceptions based on the leverage ratio then in effect. The New 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 New Credit Facility).

As of September 30, 2021, Antero Resources had an outstanding balance under the Credit Facility of $98 million, with a weighted average interest rate of 3.40%, and had outstanding letters of credit of $742 million. As of December 31, 2020, Antero

16

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

Resources had an outstanding balance under the Credit Facility of $1.0 billion, with a weighted average interest rate of 3.26%, and outstanding letters of credit of $730 million.

(b) 5.125% Senior Notes Due 2022

On May 6, 2014, Antero Resources issued $600 million of 5.125% senior notes due December 1, 2022 (the “2022 Notes”) at par. On September 18, 2014, Antero Resources issued an additional $500 million of the 2022 Notes at 100.5% of par. The Company repurchased or otherwise redeemed all of the 2022 Notes between 2019 and the first quarter of 2021. The 2022 Notes were unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2022 Notes ranked pari passu to Antero Resources’ other outstanding senior notes. The 2022 Notes were 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 2022 Notes was payable on June 1 and December 1 of each year. See “—Debt Repurchase Program” below for further details on 2022 Notes repurchases.

(c) 5.625% Senior Notes Due 2023

On March 17, 2015, Antero Resources issued $750 million of 5.625% senior notes due June 1, 2023 (the “2023 Notes”) at par. The Company repurchased or otherwise fully redeemed all of the 2023 Notes between 2020 and the second quarter of 2021. The 2023 Notes were unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2023 Notes ranked pari passu to Antero Resources’ other outstanding senior notes. The 2023 Notes were 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 2023 Notes was payable on June 1 and December 1 of each year. See “—Debt Repurchase Program” below for further details on 2023 Notes repurchases and redemption.

(d) 5.00% Senior Notes Due 2025

On December 21, 2016, Antero Resources issued $600 million of 5.00% senior notes due March 1, 2025 (the “2025 Notes”) at par. The Company repurchased $10 million of the 2025 Notes from time to time during 2020, and as of September 30, 2021, $590 million principal amount of the 2025 Notes remained outstanding. The 2025 Notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2025 Notes rank pari passu to Antero Resources’ other outstanding senior notes. The 2025 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 2025 Notes is payable on March 1 and September 1 of each year. Antero Resources may redeem all or part of the 2025 Notes at any time at redemption prices ranging from 102.5% currently to 100.00% on or after March 1, 2023. If Antero Resources undergoes a change of control followed by a rating decline, the holders of the 2025 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 2025 Notes, plus accrued and unpaid interest.

(e) 8.375% Senior Notes Due 2026

On January 4, 2021, Antero Resources issued $500 million of 8.375% senior notes due July 15, 2026 (the “2026 Notes”) at par. The Company redeemed $175 million of the 2026 Notes on July 1, 2021, and as of September 30, 2021, $325 million principal amount of the 2026 Notes remained outstanding. See “—Debt Repurchase Program” below for further details on the 2026 Notes redemption. 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.

17

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(f) 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 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. See “—Subsequent Event” below for further details on the 2029 Notes redemption. 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.

(g) 5.375% Senior Notes Due 2030

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

(h) 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 2026 (the “ 2026 Convertible Notes”). On September 2, 2020, Antero Resources issued an additional $37.5 million of the 2026 Convertible Notes. During the nine months ended September 30, 2021, the Company completed the equitization transactions described below under “—Partial Equitizations of 2026 Convertible Notes,” that extinguished $206 million principal amount of the 2026 Convertible Notes, and as of September 30, 2021, $82 million principal amount of the 2026 Convertible Notes remained outstanding. The 2026 Convertible Notes were issued pursuant to an indenture and are senior, unsecured obligations of Antero Resources. The 2026 Convertible Notes bear interest at a fixed rate of 4.25% per annum, payable semi-annually in arrears on March 1 and September 1 of each year, commencing on March 1, 2021. Proceeds from the issuance of the 2026 Convertible Notes totaled $278.5 million, net of initial purchasers’ fees and issuance cost of $9 million. Each capitalized term used in this subsection but not otherwise defined in this Quarterly Report on Form 10-Q has the meaning as set forth in the indenture governing the 2026 Convertible Notes.

The initial conversion rate is 230.2026 shares of Antero Resources’ common stock per $1,000 principal amount of 2026 Convertible Notes, subject to adjustment upon the occurrence of specified events. As of September 30, 2021, the if-converted value of the 2026 Convertible Notes was $353 million, which exceeded the principal amount of the 2026 Convertible Notes by $272 million. The 2026 Convertible Notes will mature on September 1, 2026, unless earlier repurchased, redeemed or converted. Before May 1, 2026, note holders will have the right to convert their 2026 Convertible Notes only upon the occurrence of the following events:

18

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

● 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 5 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 sale 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, 2021.

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

If certain corporate events that constitute a Fundamental Change occur, then noteholders may require Antero Resources to repurchase their 2026 Convertible Notes at a cash repurchase price equal to the principal amount of the 2026 Convertible Notes to be repurchased, plus accrued and unpaid interest, if any, to, but excluding, the fundamental change repurchase date. 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 will be 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 and will not be remeasured as long as it continues to meet the conditions for equity classification. 

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 are 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.

19

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

Partial Equitizations of 2026 Convertible Notes

On January 12, 2021, the Company completed a registered direct offering (the “January Share Offering”) of an aggregate of 31.4 million shares of its common stock at a price of $6.35 per share to certain holders of the 2026 Convertible Notes. The Company used the proceeds from the January Share Offering and approximately $63 million of borrowings under the Credit Facility to repurchase from such holders $150 million aggregate principal amount of the 2026 Convertible Notes in privately negotiated transactions (the “January Convertible Note Repurchase,” and, collectively with the January Share Offering, the “January Equitization Transactions”).  The 2026 Convertible Notes have an initial conversion rate of 230.2026 shares of the Company’s common stock per $1,000 principal amount, and the January Equitization Transactions had the effect of increasing this conversion rate to 275.3525 shares of common stock per $1,000 principal amount. The Company accounted for this transaction as an inducement of the 2026 Convertible Notes, and as a result, the Company recorded a $39 million loss on convertible note equitization in the unaudited condensed consolidated statements of operations and comprehensive loss for the nine months ended September 30, 2021 for the consideration paid in excess of the original terms of the 2026 Convertible Notes. Additionally, the January Equitization Transactions resulted in a loss on early extinguishment of debt of $41 million in the unaudited condensed consolidated statement of operations and comprehensive loss for the nine months ended September 30, 2021.

On May 13, 2021, the Company completed a registered direct offering (the “May Share Offering”) of an aggregate of 11.6 million shares of its common stock at a price of $11.01 per share to certain holders of the 2026 Convertible Notes. The Company used the proceeds from the May Share Offering and approximately $26 million of borrowings under the Credit Facility to repurchase from such holders $56 million aggregate principal amount of the 2026 Convertible Notes in privately negotiated transactions (the “May Convertible Note Repurchase,” and, collectively with the May Share Offering, the “May Equitization Transactions”).  The 2026 Convertible Notes have an initial conversion rate of 230.2026 shares of the Company’s common stock per $1,000 principal amount, and the May Equitization Transactions had the effect of increasing this conversion rate to 245.2802 shares of common stock per $1,000 principal amount. The Company accounted for this transaction as an inducement of the 2026 Convertible Notes, and as a result, the Company recorded a $12 million loss on convertible note equitization in the unaudited condensed consolidated statements of operations and comprehensive loss for the nine months ended September 30, 2021 for the consideration paid in excess of the original terms of the 2026 Convertible Notes. Additionally, the May Equitization Transactions resulted in a loss on early extinguishment of debt of $21 million in the unaudited condensed consolidated statement of operations and comprehensive loss for the nine months ended September 30, 2021.

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

	December 31,		September 30,
	2020		2021
Liability component:
Principal	$	287,500		81,570
Less: unamortized note discount		(112,265)		(28,780)
Less: unamortized debt issuance costs		(5,852)		(1,665)
Net carrying value	$	169,383		51,125
Equity component (1)	$	115,601		32,799

(1) As of December 31, 2020, the equity component attributable to the outstanding 2026 Convertible Notes was recorded in additional paid-in capital, net of $3 million of issuance costs and $28 million of deferred taxes. As of September 30, 2021, the equity component attributable to the outstanding 2026 Convertible Notes was recorded in additional paid-in capital net of $1 million of issuance costs and $8 million of deferred taxes.

Interest expense recognized on the 2026 Convertible Notes related to the stated interest rate, amortization of the debt discount and debt issuance costs totaled $2.3 million and $1.5 million for the three months ended September 30, 2020 and 2021, respectively, and $2.3 million and $8.7 million for the nine months ended September 30, 2020 and 2021, respectively.

(i) Debt Repurchase Program

During the three and nine months ended September 30, 2020, Antero Resources repurchased $461 million and $1.1 billion, respectively, principal amount of debt at a weighted average discount of 13% and 17%, respectively. The Company recognized a gain of $56 million and $175 million for the three and nine months ended September 30, 2020 on the early extinguishment of the debt repurchased.

20

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

During the first quarter of 2021, the Company redeemed the remaining $661 million of the 2022 Notes at par, plus accrued and unpaid interest, and as a result, the 2022 Notes were fully retired as of February 10, 2021. The Company redeemed the remaining $574 million of the 2023 Notes at par, plus accrued and unpaid interest, during the second quarter of 2021. The 2023 Notes were fully retired as of June 1, 2021. During the third quarter of 2021, the Company redeemed $175 million of the principal amount of its 2026 Notes at a redemption price of 108.375% of the principal amount thereof, plus accrued and unpaid interest, and recognized a loss on early debt extinguishment of $17 million during the three months ended September 30, 2021.

(j) Subsequent Event

On October 18, 2021, Antero Resources issued a notice of partial redemption with respect to the 2029 Notes. On November 2, 2021, the Company will redeemd $116 million of the aggregate principal amount of its 2029 Notes at a redemption price of 107.625% of the principal amount thereof, plus accrued and unpaid interest. Immediately following the redemption, there will be $584 million aggregate principal amount of 2029 Notes outstanding. The $9 million premium to the principal amount redeemed along with the write-off of a proportional amount of unamortized debt issuance costs will be included in the Company’s loss on early debt extinguishment during the fourth quarter of 2021.

(8) Asset Retirement Obligations

The following table sets forth a reconciliation of the Company’s asset retirement obligations for the nine months ended September 30, 2021 (in thousands):

Asset retirement obligations—December 31, 2020	$	54,452
Obligations incurred		2,359
Accretion expense		2,947
Settlement of obligations		(50)
Revisions to prior estimates		(549)
Asset retirement obligations—September 30, 2021	$	59,159

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 7,888,490 shares were available for future grant under the 2020 Plan as of September 30, 2021.

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 include 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

21

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

assumed by Antero Midstream Corporation and converted into 1.8926 RSUs (all such RSUs, the “Converted AM RSU Awards”) under the Antero Midstream Corporation Long Term Incentive Plan (the “AMC Plan”). Each RSU award under the AMC Plan represents a right to receive 1 share of Antero Midstream Corporation common stock.

The Company’s equity-based compensation expense, by type of award, was as follows for the three and nine months ended September 30, 2020 and 2021 (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2021		2020		2021
RSU awards	$	3,063		3,327	$	9,021		9,957
PSU awards		1,827		1,452		5,380		3,211
Converted AM RSU Awards (1)		459		186		1,881		988
Equity awards issued to directors		350		333		719		1,033
Total expense	$	5,699		5,298	$	17,001		15,189

(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 the deconsolidation of Antero Midstream Partners on March 12, 2019 to Antero Midstream Partners based on its proportionate share of Antero Resources’ labor costs.

(a) Restricted Stock Unit Awards

A summary of RSU award activity for the nine months ended September 30, 2021 is as follows:

		Weighted
		Average
	Number of	Grant Date
	Shares	Fair Value
Total awarded and unvested—December 31, 2020	8,432,397	$	4.06
Granted	1,431,993		9.52
Vested	(3,546,654)		4.36
Forfeited	(293,338)		5.18
Total awarded and unvested—September 30, 2021	6,024,398	$	5.12

As of September 30, 2021, there was approximately $24 million of unamortized equity-based compensation expense related to unvested RSUs. That expense is expected to be recognized over a weighted average period of approximately 2.6 years.

(b) Performance Share Unit Awards

PSU Awards Based on Absolute Total Shareholder Return (“TSR”)

In April 2021, the Company granted PSU awards to certain of its executive officers that vest based on Antero Resources’ absolute TSR determined as of the last day of each of 3 one-year performance periods ending on April 15, 2022, April 15, 2023, and April 15, 2024, and 1 cumulative three-year performance period ending on April 15, 2024, in each case, subject to the executive officer’s continued employment through April 15, 2024. 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 TSR PSUs ranges from 0 to 200% of the target number of 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.

PSU Awards Based on Leverage Ratio

In April 2021, the Company granted PSUs to certain of its 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 and described in Item 2 below under “Non-GAAP Financial Measures”) determined as of the last day of each of 3 one-year performance periods ending on December 31,

22

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

2021, December 31, 2022, and December 31, 2023, in each case, subject to the executive officer’s continued employment through December 31, 2023 (“Leverage Ratio PSUs”). The number of shares of common stock that may ultimately be earned with respect to the Leverage Ratio PSUs ranges from 0 to 200% of the target number of Leverage Ratio PSUs originally granted. Expense related to the Leverage Ratio PSUs is recognized based on 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, 2021, the likelihood of achieving the performance conditions related to the Leverage Ratio PSUs was probable.

A summary of PSU award activity for the nine months ended September 30, 2021 is as follows:

		Weighted
	Number of	Average Grant
	Units	Date Fair Value
Total awarded and unvested—December 31, 2020	2,547,798	$	12.66
Granted	479,120		9.71
Forfeited	(67,000)		2.97
Cancelled (unearned)	(1,112,639)		19.19
Total awarded and unvested—September 30, 2021	1,847,279	$	8.31

The following table presents information regarding the weighted average fair values for market-based PSUs granted during the nine months ended September 30, 2021, and the assumptions used to determine the fair values:

Dividend yield		—	%
Volatility		85	%
Risk-free interest rate		0.32	%
Weighted average fair value of awards granted—Absolute TSR	$	11.99

As of September 30, 2021, there was approximately $8 million of unamortized equity-based compensation expense related to unvested PSUs. That expense is expected to be recognized over a weighted average period of approximately 2.0 years.

(c) Stock Options

A summary of stock option activity for the nine months ended September 30, 2021 is as follows:

				Weighted
		Weighted		Average
		Average		Remaining	Intrinsic
	Stock	Exercise		Contractual	Value
	Options	Price		Life	(in thousands)
Outstanding—December 31, 2020	432,461	$	50.64	4.1	$	—
Granted	—		—
Exercised	—		—
Forfeited	—		—
Expired	(76,167)		50.00
Outstanding—September 30, 2021	356,294	$	50.78	3.2	$	—
Vested—September 30, 2021	356,294	$	50.78	3.2	$	—
Exercisable—September 30, 2021	356,294	$	50.78	3.2	$	—

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

As of September 30, 2021, all stock options were fully vested resulting in 0 unamortized equity-based compensation expense.

23

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(d) Converted AM RSU Awards

A summary of the Converted AM RSU Awards for the nine months ended September 30, 2021 is as follows:

		Weighted
		Average
	Number of	Grant Date
	Units	Fair Value
Total awarded and unvested—December 31, 2020	296,390	$	15.06
Granted	—		—
Vested	(209,964)		15.73
Forfeited	(3,444)		13.25
Total awarded and unvested—September 30, 2021	82,982	$	13.46

As of September 30, 2021, there was less than $1.0 million of unamortized equity-based compensation expense related to unvested Converted AM RSU Awards. Such expense is expected to be recognized over a weighted average period of 0.6 years, and the Company’s proportionate share will be allocated to it as it is recognized.

(e) Cash Awards

In January 2020, the Company granted cash awards of approximately $3.3 million to certain executives under the 2013 Plan, and compensation expense for these awards is recognized ratably over the vesting period for each of 3 tranches through January 20, 2023. In July 2020, the Company granted additional cash awards in the aggregate of $2.6 million to certain non-executive employees under the 2020 Plan that vest ratably over four years. As of December 31, 2020 and September 30, 2021, the Company has recorded approximately $3.2 million and $2.0 million, respectively, in Other 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, 2020 and September 30, 2021 approximated market values because of their short-term nature. The carrying values of the amounts outstanding under the Prior Credit Facility as of December 31, 2020 and September 30, 2021 approximated fair value because the variable interest rates are reflective of current market conditions.

The fair value and carrying value of the senior notes and 2026 Convertible Notes as of December 31, 2020 and September 30, 2021 as follows (in thousands):

	December 31, 2020				September 30, 2021
	Fair		Carrying		Fair		Carrying
	Value (1)		Value (2)		Value (1)		Value (2)
2022 Notes	$	658,468		658,400		—		—
2023 Notes		562,698		571,370		—		—
2025 Notes		560,500		585,440		601,800		586,191
2026 Notes		—		—		368,128		321,570
2029 Notes		—		—		782,600		691,575
2030 Notes		—		—		631,860		593,072
2026 Convertible Notes		430,963		169,383		356,689		51,125
Total	$	2,212,629		1,984,593		2,741,077		2,243,533

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

(2) Carrying values are presented net of unamortized debt issuance costs and debt discounts or premiums.

See Note 11—Derivative Instruments to the unaudited condensed consolidated financial statements for information regarding the fair value of derivative financial instruments.

24

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 uses 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, 2020 and 2021. 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.

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, 2021, the Company’s fixed price natural gas, oil and NGL 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 2021	Henry Hub	2,160,000	MMBtu/day	$	2.78	/MMBtu
January-December 2022	Henry Hub	1,155,486	MMBtu/day		2.50	/MMBtu
January-December 2023	Henry Hub	43,000	MMBtu/day		2.37	/MMBtu
Butane
October-December 2021	Mont Belvieu Butane-OPIS Non-TET	2,600	Bbl/day	$	33.77	/Bbl
October-December 2021	Mont Belvieu Butane-OPIS TET	1,500	Bbl/day	$	32.24	/Bbl
Natural Gasoline
October-December 2021	Mont Belvieu Natural Gasoline-OPIS Non-TET	8,300	Bbl/day	$	49.70	/Bbl
Isobutane
October-December 2021	Mont Belvieu Isobutane-OPIS Non-TET	2,800	Bbl/day	$	35.75	/Bbl
Oil
October-December 2021	West Texas Intermediate	3,000	Bbl/day	$	55.16	/Bbl

In addition, the Company has a call option agreement, which entitles the holder the right, but not the obligation, to enter into a fixed price swap agreement on December 21, 2023 to purchase 427,500 MMBtu per day at a price of $2.77 per MMBtu for the year ending December 31, 2024.

25

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

As of September 30, 2021, 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 2021	NYMEX to TCO	40,000	MMBtu/day	$	0.414	/MMBtu
January-December 2022	NYMEX to TCO	60,000	MMBtu/day		0.515	/MMBtu
January-December 2023	NYMEX to TCO	50,000	MMBtu/day		0.525	/MMBtu
January-December 2024	NYMEX to TCO	50,000	MMBtu/day		0.530	/MMBtu

The Company also entered into NGL derivative contracts, which establish a contractual price for the settlement month as a fixed percentage of the West Texas Intermediate Crude Oil index (“WTI”) price for the settlement month. When the percentage of the contractual price is above the contracted percentage, the Company pays the difference to the counterparty. When it is below the contracted percentage, the Company receives the difference from the counterparty. As of September 30, 2021, the Company had natural gas and NGL contracts that fix the Mont Belvieu index price for natural gasoline to percentages of WTI as follows:

				Weighted Average
Commodity / Settlement Period	Index to Basis Differential	Contracted Volume		Payout Ratio
Gas Liquids
October-December 2021	Mont Belvieu Natural Gasoline to WTI	9,325	Bbl/day	77	%

As of September 30, 2021, the Company’s fixed price natural gas, oil and NGL 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 2021	Henry Hub	46,384	MMBtu/day	$	2.77	/MMBtu
January-December 2022	Henry Hub	38,356	MMBtu/day		2.39	/MMBtu
January-December 2023	Henry Hub	35,616	MMBtu/day		2.35	/MMBtu
January-December 2024	Henry Hub	23,885	MMBtu/day		2.33	/MMBtu
January-March 2025	Henry Hub	18,021	MMBtu/day		2.53	/MMBtu
Ethane
October-December 2021	Mont Belvieu Purity Ethane-OPIS	990	Bbl/day	$	7.01	/Bbl
January-March 2022	Mont Belvieu Purity Ethane-OPIS	521	Bbl/day		6.68	/Bbl
Propane
October-December 2021	Mont Belvieu Propane-OPIS Non-TET	1,069	Bbl/day	$	19.88	/Bbl
January-December 2022	Mont Belvieu Propane-OPIS Non-TET	934	Bbl/day		19.20	/Bbl
Natural Gasoline
October-December 2021	Mont Belvieu Natural Gasoline-OPIS Non-TET	339	Bbl/day	$	35.24	/Bbl
January-December 2022	Mont Belvieu Natural Gasoline-OPIS Non-TET	282	Bbl/day		34.37	/Bbl
January-December 2023	Mont Belvieu Natural Gasoline-OPIS Non-TET	247	Bbl/day		40.74	/Bbl
Oil
October-December 2021	West Texas Intermediate	111	Bbl/day	$	43.48	/Bbl
January-December 2022	West Texas Intermediate	112	Bbl/day		44.25	/Bbl
January-December 2023	West Texas Intermediate	99	Bbl/day		45.03	/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

26

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(b) Embedded Derivatives

The VPP includes an embedded put option tied to NYMEX pricing for the production volumes associated with the Company’s retained interest in the VPP properties of 94,544,000 MMBtu remaining through December 31, 2026 at a weighted average strike price of $2.57 per MMBtu. The embedded put option is not clearly and closely related to the host contract, and therefore, the Company bifurcated this derivative instrument and reflected it at fair value in the unaudited condensed consolidated financial statements.

(c) 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 as of December 31, 2020 and September 30, 2021 (in thousands). None of the Company’s derivative instruments are designated as hedges for accounting purposes.

	Balance Sheet	December 31,		September 30,
	Location	2020		2021
Asset derivatives not designated as hedges for accounting purposes:
Commodity derivatives—current	Derivative instruments	$	97,144		—
Embedded derivatives—current	Derivative instruments		7,986		627
Commodity derivatives—noncurrent	Derivative instruments		14,689		—
Embedded derivatives—noncurrent	Derivative instruments		32,604		14,834
Total asset derivatives			152,423		15,461
Liability derivatives not designated as hedges for accounting purposes:
Commodity derivatives—current (1)	Derivative instruments		31,242		1,436,292
Commodity derivatives—noncurrent (1)	Derivative instruments		99,172		331,570
Total liability derivatives			130,414		1,767,862
Net derivatives assets (liabilities)		$	22,009		(1,752,401)

(1) As of September 30, 2021, approximately $87 million of commodity derivative liabilities, including $53 million of current commodity derivatives and $34 million of noncurrent commodity derivatives, are attributable to the Company’s consolidated VIE, Martica. As of December 31, 2020, approximately $14 million of commodity derivative liabilities, including $7 million of current commodity derivatives and $7 million of noncurrent commodity derivatives, are attributable to the Company’s consolidated VIE, Martica.

The following table presents 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):

	December 31, 2020						September 30, 2021
					Net Amounts of						Net Amounts of
	Gross		Gross Amounts		Assets		Gross		Gross Amounts		Assets
	Amounts on		Offset on		(Liabilities) on		Amounts on		Offset on		(Liabilities) on
	Balance Sheet		Balance Sheet		Balance Sheet		Balance Sheet		Balance Sheet		Balance Sheet
Commodity derivative assets	$	181,375		(69,542)		111,833	$	18,246		(18,246)		—
Embedded derivative assets	$	40,590		—		40,590	$	15,461		—		15,461
Commodity derivative liabilities	$	(199,956)		69,542		(130,414)	$	(1,786,108)		18,246		(1,767,862)

27

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

The following is a summary of derivative fair value gains and losses and where such values are recorded in the unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2020 and 2021 (in thousands):

	Statement of
	Operations	Three Months Ended September 30,				Nine Months Ended September 30,
	Location	2020		2021		2020		2021
Commodity derivative fair value losses (1)	Revenue	$	(558,979)		(1,238,384)	$	(161,161)		(2,228,076)
Embedded derivative fair value gains (losses) (1)	Revenue	$	44,228		(12,082)	$	44,228		(31,986)

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

(12) Leases

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

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

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

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

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

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

28

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(a) Supplemental Balance Sheet Information Related to Leases

The Company’s lease assets and liabilities as of December 31, 2020 and September 30, 2021 consisted of the following items (in thousands):

		December 31,		September 30,
Leases	Balance Sheet Classification	2020		2021
Operating Leases
Operating lease right-of-use assets:
Processing plants	Operating lease right-of-use assets	$	1,302,290		1,786,321
Drilling rigs and completion services	Operating lease right-of-use assets		29,894		10,812
Gas gathering lines and compressor stations (1)	Operating lease right-of-use assets		1,241,090		1,136,859
Office space	Operating lease right-of-use assets		36,879		34,032
Vehicles	Operating lease right-of-use assets		2,704		1,023
Other office and field equipment	Operating lease right-of-use assets		746		595
Total operating lease right-of-use assets		$	2,613,603		2,969,642
Short-term operating lease obligation	Short-term lease liabilities	$	265,178		352,939
Long-term operating lease obligation	Long-term lease liabilities		2,348,425		2,616,703
Total operating lease obligation		$	2,613,603		2,969,642
Finance Leases
Finance lease right-of-use assets:
Vehicles	Other property and equipment	$	1,206		717
Total finance lease right-of-use assets (2)		$	1,206		717
Short-term finance lease obligation	Short-term lease liabilities	$	845		531
Long-term finance lease obligation	Long-term lease liabilities		361		186
Total finance lease obligation		$	1,206		717

(1) Gas gathering lines and compressor stations leases includes $1.1 billion and $1.0 billion related to Antero Midstream Corporation as of December 31, 2020 and September 30, 2021. See “—Related party lease disclosure” for additional discussion.

(2) Financing lease assets are recorded net of accumulated amortization of $3 million and $2 million as of December 31, 2020 and September 30, 2021, respectively. The processing plants, gathering lines and compressor stations that are classified as lease liabilities are classified as such under ASC 842, Leases, because Antero is the sole customer of the assets and because Antero makes the decisions that most impact the economic performance of the assets.

29

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(b) Supplemental Information Related to Leases

Costs associated with operating leases and finance leases were included in the unaudited condensed consolidated statement of operations and comprehensive loss for the three and nine months ended September 30, 2020 and 2021 (in thousands):

			Three Months Ended				Nine Months Ended
			September 30,				September 30,
Cost	Classification	Location	2020		2021		2020		2021
Operating lease cost	Statement of operations	Gathering, compression, processing, and transportation	$	350,853		386,033	$	1,112,502		1,147,985
Operating lease cost	Statement of operations	General and administrative		2,789		2,833		8,639		8,057
Operating lease cost	Statement of operations	Contract termination and rig stacking		5,841		3,369		6,387		4,213
Operating lease cost	Statement of operations	Lease operating		—		43		—		109
Operating lease cost	Balance sheet	Proved properties (1)		31,822		25,558		91,081		82,749
Total operating lease cost			$	391,305		417,836	$	1,218,609		1,243,113
Finance lease cost:
Amortization of right-of-use assets	Statement of operations	Depletion, depreciation, and amortization	$	168		132	$	727		391
Total finance lease cost			$	168		132	$	727		391
Short-term lease payments			$	15,871		21,030	$	108,029		62,328

(1) Capitalized costs related to drilling and completion activities.

(c) Supplemental Cash Flow Information Related to Leases

The following is the Company’s supplemental cash flow information related to leases for the nine months ended September 30, 2020 and 2021 (in thousands):

	Nine Months Ended September 30,
	2020		2021
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	1,147,489		1,042,684
Investing cash flows from operating leases		88,229		66,042
Financing cash flows from finance leases		1,004		692
Noncash activities:
Right-of-use assets obtained in exchange for new operating lease obligations	$	178,348		232,771
Increase (decrease) to existing right-of-use assets and lease obligations from operating lease modifications, net (1)	$	(174,880)		345,066

(1) During the nine months ended September 30, 2020, the weighted average discount rate for remeasured operating leases increased from 10.0% as of December 31, 2019 to 14.4% as of September 30, 2020. During the nine months ended September 30, 2021, the weighted average discount rate for remeasured operating leases decreased from 14.4% as of December 31, 2020 to 5.5% as of September 30, 2021.

30

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, 2021 (in thousands):

	Operating Leases		Financing Leases		Total
Remainder of 2021	$	158,056		174		158,230
2022		601,512		424		601,936
2023		595,852		76		595,928
2024		587,016		67		587,083
2025		514,963		22		514,985
2026		464,262		—		464,262
Thereafter		1,260,244		—		1,260,244
Total lease payments		4,181,905		763		4,182,668
Less: imputed interest		(1,212,263)		(46)		(1,212,309)
Total	$	2,969,642		717		2,970,359

(e) Lease Term and Discount Rate

The following table sets forth the Company’s weighted average remaining lease term and discount rate as of December 31, 2020 and September 30, 2021:

	December 31, 2020				September 30, 2021
	Operating Leases		Finance Leases		Operating Leases		Finance Leases
Weighted average remaining lease term	8.0 years		1.5 years		7.8 years		1.9 years
Weighted average discount rate	13.7	%	6.2	%	9.1	%	5.7	%

(f) Related Party Lease Disclosure

The Company has a gathering and compression agreement with Antero Midstream Corporation, whereby Antero Midstream Corporation receives a low-pressure gathering fee per Mcf, a high-pressure gathering fee per Mcf and a compression fee per Mcf, in each case subject to annual adjustments based on the consumer price index. If and to the extent the Company requests that Antero Midstream Corporation construct new high pressure lines and compressor stations, the gathering and compression agreement contains 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. In December 2019, the Company and Antero Midstream Corporation agreed to extend the initial term of the gathering and compression agreement to 2038 and established a growth incentive fee program whereby low pressure gathering fees will be reduced from 2020 through 2023 to the extent the Company achieves certain volumetric targets at certain points during such time. Upon completion of the initial contract term, the gathering and compression agreement will continue in effect from year to year until such time as the agreement is terminated, effective upon an anniversary of the effective date of the agreement, by either the Company or Antero Midstream Corporation on or before the 180^th day prior to the anniversary of such effective date. The Company achieved the volumetric targets during each of the first, second and third quarters of 2020, and Antero Midstream Corporation provided a rebate of $12 million and $36 million for the three and nine months ended September 30, 2020, respectively. The Company did 0t achieve the volumetric target during either the first, second or third quarters of 2021.

For the three and nine months ended September 30, 2020, gathering and compression fees paid by Antero related to this agreement were $181 million and $503 million, respectively. For the three and nine months ended September 30, 2021, gathering and compression fees paid by Antero related to this agreement were $178 million and $539 million, respectively. As of December 31, 2020 and September 30, 2021, $55 million and $62 million were included within Accounts payable, related parties, respectively, on the condensed consolidated balance sheets as due to Antero Midstream Corporation related to this agreement.

31

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(13) Commitments

The following table sets forth a schedule of future minimum payments for firm transportation, drilling rig and completion services, processing, gathering and compression, and office and equipment agreements, which include leases that have remaining lease terms in excess of one year as of September 30, 2021 (in thousands).

			Processing,
	Firm		Gathering and		Land Payment		Operating and		Imputed Interest
	Transportation		Compression		Obligations		Financing Leases		for Leases
	(a)		(b)		(c)		(d)		(d)		Total
Remainder of 2021	$	264,307		13,597		1,905		91,149		67,081		438,039
2022		1,042,280		52,265		400		352,249		249,687		1,696,881
2023		1,072,523		59,140		—		377,308		218,620		1,727,591
2024		1,045,442		59,262		—		402,702		184,381		1,691,787
2025		1,024,783		47,960		—		366,353		148,632		1,587,728
2026		1,018,812		14,783		—		350,438		113,824		1,497,857
Thereafter		6,033,138		98,596		—		1,030,160		230,084		7,391,978
Total	$	11,501,285		345,603		2,305		2,970,359		1,212,309		16,031,861

(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, and Compression Service Commitments

The Company has entered into various long-term gas processing, gathering and compression service agreements. Certain of these agreements were determined to be leases. The minimum payment obligations under the agreements that are not leases are presented in this column.

The values in the table represent the gross amounts that the Company is committed to pay; however, the Company will record in the unaudited condensed consolidated financial statements its proportionate share of costs based on its working interest.

(c) Land Payment Obligations

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

(d) 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. Refer to Note 12—Leases to the unaudited condensed consolidated financial statements for more information on the Company’s operating and finance leases.

32

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

(14) Contingencies

Environmental

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

WGL

The Company and Washington Gas Light Company and WGL Midstream, Inc. (collectively, “WGL”) were involved in multiple contractual disputes involving firm gas sales contracts executed June 20, 2014 (the “Contracts”) that the Company began delivering gas under in January 2016. In late 2015, WGL asserted that the natural gas index price specified in the Contracts was no longer appropriate and sought to invoke an alternative index clause in the Contracts. This dispute was referred to arbitration. In January 2017, the arbitration panel ruled in the Company’s favor and found that the natural gas index price specified in the Contracts should remain.

In March of 2017, WGL filed a lawsuit against the Company in Colorado district court claiming that the Company breached contractual obligations by failing to deliver “TCO pool” gas, ultimately seeking damages of more than $40 million. Subsequently, after WGL failed to take certain volumes of gas required under the Contracts, the Company filed a separate lawsuit against WGL to recover damages that WGL refused to pay. These 2 lawsuits were consolidated and tried in June 2019. On June 20, 2019, the Company was awarded a jury verdict of approximately $96 million in damages against WGL. In addition, the jury rejected WGL’s claim against the Company, finding that the Company did not breach the Contracts. On December 10, 2020, the Colorado Court of Appeals affirmed the judgment of the trial court in favor of the Company. In February 2021, the Company and its royalty owners received a gross payment of approximately $107 million from WGL, which was in full satisfaction and discharge of the June 2019 judgment entered in favor of the Company.

Other

The Company is party to various other legal proceedings and claims in the ordinary course of its business, including, but not limited to, royalty claims. 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.

(15) Related Parties

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

(16) Reportable Segments

Management evaluated how the Company is organized and managed and identified the following 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 Corporation. All of the Company’s assets are located in the United States and substantially all of its production revenues are attributable to customers located

33

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

in the United States; however, some of the Company’s production revenues are attributable to customers who then transport the Company’s production to foreign countries for resale or consumption.

Operating segments are evaluated based on their contribution to consolidated results, which is primarily determined by the respective operating income (loss) of each segment. General and administrative expenses were allocated to the midstream segment based on the nature of the expenses and on a combination of the segments’ proportionate share of the Company’s consolidated property and equipment, capital expenditures, and labor costs, as applicable. General and administrative expenses related to the marketing segment are not allocated because they are immaterial. Other income, income taxes, and interest expense are primarily managed and evaluated on a consolidated basis. Intersegment sales were transacted at prices which approximate market. Accounting policies for each segment are the same as the Company’s accounting policies described in Note 2—Summary of Significant Accounting Policies to the unaudited condensed consolidated financial statements.

The operating results and assets of the Company’s reportable segments were as follows for the three months ended September 30, 2020 and 2021 (in thousands):

	Three Months Ended September 30, 2020
					Equity Method		Elimination of
					Investment in		Intersegment
	Exploration				Antero		Transactions and
	and				Midstream		Unconsolidated		Consolidated
	Production		Marketing		Corporation		Affiliates		Total
Sales and revenues:
Third-party	$	288,419		91,497		—		—		379,916
Intersegment		675		—		233,415		(233,415)		675
Total revenue	$	289,094		91,497		233,415		(233,415)		380,591
Operating expenses:
Lease operating	$	21,450		—		—		—		21,450
Gathering, compression, processing, and transportation		656,615		—		38,052		(38,052)		656,615
Impairment of oil and gas properties		29,392		—		—		—		29,392
Depletion, depreciation, and amortization		238,418		—		26,801		(26,801)		238,418
General and administrative		31,640		—		13,232		(13,232)		31,640
Other		28,605		128,580		3,513		(3,513)		157,185
Total operating expenses		1,006,120		128,580		81,598		(81,598)		1,134,700
Operating income (loss)	$	(717,026)		(37,083)		151,817		(151,817)		(754,109)
Equity in earnings of unconsolidated affiliates	$	24,419		—		23,173		(23,173)		24,419
Investments in unconsolidated affiliates	$	272,926		—		—		—		272,926
Segment assets	$	13,349,739		—		5,673,504		(5,673,504)		13,349,739
Capital expenditures for segment assets	$	151,269		—		41,851		(41,851)		151,269

34

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

	Three Months Ended September 30, 2021
					Equity Method		Elimination of
					Investment in		Intersegment
	Exploration				Antero		Transactions and
	and				Midstream		Unconsolidated		Consolidated
	Production		Marketing		Corporation		Affiliates		Total
Sales and revenues:
Third-party	$	301,207		232,685		242,472		(242,472)		533,892
Intersegment		530		—		(17,668)		17,668		530
Total revenue	$	301,737		232,685		224,804		(224,804)		534,422
Operating expenses:
Lease operating	$	25,363		—		—		—		25,363
Gathering, compression, processing, and transportation		628,225		—		39,499		(39,499)		628,225
Impairment of oil and gas properties		26,253		—		—		—		26,253
Depletion, depreciation, and amortization		182,810		—		27,487		(27,487)		182,810
General and administrative		32,442		—		14,810		(14,810)		32,442
Other		56,652		266,751		1,187		(1,187)		323,403
Total operating expenses		951,745		266,751		82,983		(82,983)		1,218,496
Operating income (loss)	$	(650,008)		(34,066)		141,821		(141,821)		(684,074)
Equity in earnings of unconsolidated affiliates	$	21,450		—		24,088		(24,088)		21,450
Investments in unconsolidated affiliates	$	236,597		—		703,780		(703,780)		236,597
Segment assets	$	13,375,515		96,023		5,533,633		(5,533,633)		13,471,538
Capital expenditures for segment assets	$	387,783		—		82,583		(82,583)		387,783

The operating results and assets of the Company’s reportable segments were as follows for the nine months ended September 30, 2020 and 2021 (in thousands):

	Nine Months Ended September 30, 2020
					Equity Method		Elimination of
					Investment in		Intersegment
	Exploration				Antero		Transactions and
	and				Midstream		Unconsolidated		Consolidated
	Production		Marketing		Corporation		Affiliates		Total
Sales and revenues:
Third-party	$	1,978,572		201,855		—		—		2,180,427
Intersegment		2,180		—		696,859		(696,859)		2,180
Total revenue	$	1,980,752		201,855		696,859		(696,859)		2,182,607
Operating expenses:
Lease operating	$	71,836		—		—		—		71,836
Gathering, compression, processing, and transportation		1,877,084		—		128,847		(128,847)		1,877,084
Impairment of oil and gas properties		155,962		—		—		—		155,962
Impairment of midstream assets		—		—		665,491		(665,491)		—
Depletion, depreciation, and amortization		652,130		—		81,889		(81,889)		652,130
General and administrative		101,264		—		39,191		(39,191)		101,264
Other		88,023		334,906		14,062		(14,062)		422,929
Total operating expenses		2,946,299		334,906		929,480		(929,480)		3,281,205
Operating loss	$	(965,547)		(133,051)		(232,621)		232,621		(1,098,598)
Equity in earnings (loss) of unconsolidated affiliates	$	(83,408)		—		63,197		(63,197)		(83,408)
Investments in unconsolidated affiliates	$	272,926		—		—		—		272,926
Segment assets	$	13,349,739		—		5,673,504		(5,673,504)		13,349,739
Capital expenditures for segment assets	$	726,402		—		165,265		(165,265)		726,402

35

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

	Nine Months Ended September 30, 2021
					Equity Method		Elimination of
					Investment in		Intersegment
	Exploration				Antero		Transactions and
	and				Midstream		Unconsolidated		Consolidated
	Production		Marketing		Corporation		Affiliates		Total
Sales and revenues:
Third-party	$	1,664,509		562,928		—		—		2,227,437
Intersegment		551		—		681,712		(681,712)		551
Total revenue	$	1,665,060		562,928		681,712		(681,712)		2,227,988
Operating expenses:
Lease operating	$	71,555		—		—		—		71,555
Gathering, compression, processing, and transportation		1,874,664		—		118,368		(118,368)		1,874,664
Impairment of oil and gas properties		69,618		—		—		—		69,618
Depletion, depreciation, and amortization		564,166		—		80,956		(80,956)		564,166
General and administrative		108,693		—		46,991		(46,991)		108,693
Other		143,954		627,822		8,590		(8,590)		771,776
Total operating expenses		2,832,650		627,822		254,905		(254,905)		3,460,472
Operating income (loss)	$	(1,167,590)		(64,894)		426,807		(426,807)		(1,232,484)
Equity in earnings of unconsolidated affiliates	$	57,621		—		66,347		(66,347)		57,621
Investments in unconsolidated affiliates	$	236,597		—		703,780		(703,780)		236,597
Segment assets	$	13,375,515		96,023		5,533,633		(5,533,633)		13,471,538
Capital expenditures for segment assets	$	510,941		—		156,948		(156,948)		510,941

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

36

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

Balance Sheet
	December 31, 2020		September 30, 2021
	Parent (Antero)		Parent (Antero)
	and Guarantor Subsidiaries		and Guarantor Subsidiaries
Accounts receivable, non-guarantor subsidiaries	$	—		—
Accounts receivable, related parties		—		—
Other current assets		543,841		665,111
Total current assets		543,841		665,111
Noncurrent assets		11,783,502		12,016,722
Total assets	$	12,327,343		12,681,833
Accounts payable, non-guarantor subsidiaries	$	—		—
Accounts payable, related parties		69,860		79,595
Other current liabilities		906,348		2,674,603
Total current liabilities		976,208		2,754,198
Noncurrent liabilities		6,070,388		5,499,255
Total liabilities	$	7,046,596		8,253,453
Statement of Operations
			Nine Months Ended
			September 30, 2021
			Parent (Antero)
			and Guarantor Subsidiaries
Revenues			$	2,220,306
Operating expenses				3,428,943
Loss from operations				(1,208,637)
Net loss and comprehensive loss including noncontrolling interests				(1,088,283)
Net loss and comprehensive loss attributable to Antero Resources Corporation			$	(1,088,283)

37

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our unaudited condensed consolidated financial statements and related notes included elsewhere in this Quarterly Report on Form 10-Q. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results, and the differences can be material. Some of the key factors that could cause actual results to vary from our expectations include changes in natural gas, NGLs, and oil prices, the timing of planned capital expenditures, our ability to fund our development programs, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, impacts of world health events, including the COVID-19 pandemic, potential shut-ins of production due to lack of downstream demand or storage capacity, 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 profitably grow 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 Marcellus Shale and Utica Shale of the Appalachian Basin. As of September 30, 2021, we held approximately 508,000 net acres of rich gas and dry gas properties located in the Appalachian Basin in West Virginia and Ohio. Our corporate headquarters are in Denver, Colorado.

2021 Developments and Highlights

COVID-19 Pandemic

In March 2020, the World Health Organization declared the COVID-19 outbreak a pandemic. Governments tried to slow the spread of the virus by imposing social distancing guidelines, travel restrictions and stay-at-home orders, among other actions, which caused a significant decrease in activity in the global economy and the demand for oil and, to a lesser extent, natural gas and NGLs. The imbalance between the supply of and demand for oil, as well as the uncertainty around the extent and timing of an economic recovery, caused extreme market volatility and a substantial adverse effect on commodity prices in 2020. As vaccines have become widely available, social distancing guidelines, travel restrictions and stay-at-home orders have eased, activity in the global economy has increased and demand for oil, natural gas and NGLs, and related commodity pricing, has improved. However, new variants of the virus could cause further commodity market volatility and resulting financial market instability, and these are variables beyond our control that may adversely impact our generation of funds from operating cash flows, distributions from unconsolidated affiliate, available borrowings under our Credit Facility (defined below in “—Capital Resources and Liquidity—Debt Agreements—Senior Secured Revolving Credit Facility”) and our ability to access the capital markets.

As a producer of natural gas, NGLs and oil, we are recognized as an essential business under various federal, state and local regulations related to the COVID-19 pandemic. As such, we have continued to operate throughout the pandemic as permitted under these regulations while taking steps to protect the health and safety of our employees and contract workers. We have implemented protocols to reduce the risk of an outbreak within our field operations, and these protocols have not reduced production or efficiency in a significant manner. A substantial portion of our non-field level employees operated in remote work from home arrangements through September 30, 2021, and due to the rise of COVID-19 cases as a result of new variants of the virus, our plans to return to in-

38

office arrangements during the third quarter of 2021 have been deferred in order to protect the health and safety of our employees and contract workers. We have been able to maintain a consistent level of effectiveness through these arrangements, including maintaining our day-to-day operations, our financial reporting systems and our internal control over financial reporting.

Our natural gas, NGLs and oil producing properties are located in the liquids-rich Appalachian Basin. We have hedged through fixed price contracts the sale of 2.2 Bcf per day of natural gas at a weighted average price of $2.78 per MMBtu for the remainder of 2021. Our hedges cover a substantial majority of our expected natural gas production for the remainder of 2021. We also have fixed priced contracts for the sale of 3,000 barrels per day of oil at a weighted average price of $55.16 per barrel for the remainder of 2021. All of our hedges are financial hedges and do not have physical delivery requirements. As such, any decreases in anticipated production, such as a result of decreased development activity, will not impact our ability to realize the benefits of our hedges.

Our supply chain has not experienced any significant interruptions. The lack of a market or available storage for any one NGL product or oil could result in our having to delay or discontinue well completions and commercial production or shut in production for other products because we cannot curtail the production of individual products in a meaningful way without reducing production of other products. Potential impacts of these constraints may include partial shut-in of production, although we are not able to determine the extent of shut-ins or for how long they may last. However, because some of our wells produce rich gas, which is processed, and some produce dry gas, which does not require processing, we can change the mix of products that we produce and wells that we complete to adjust our production to address takeaway capacity constraints for certain products. For example, we can shut-in rich gas wells and still produce from our dry gas wells if processing or storage capacity of NGL products becomes further limited or constrained. Prior to the COVID-19 pandemic, we had developed a diverse set of buyers and destinations, as well as in-field and off-site storage capacity for our condensate volumes. As a result of the pandemic, we have expanded our customer base and our condensate storage capacity within the Appalachian Basin.

As of September 30, 2021, we had $98 million of borrowings under our Prior Credit Facility (defined below in “—Capital Resources and Liquidity—Debt Agreements—Senior Secured Revolving Credit Facility”) and had outstanding letters of credit of $742 million. On October 26, 2021, we amended our Prior Credit Facility with a borrowing base of $3.5 billion and lender commitments of $1.5 billion. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements and “—Capital Resources and Liquidity—Debt Agreements—Senior Secured Revolving Credit Facility.”

In addition, our borrowing capacity is directly impacted by the amount of financial assurance we are required to provide in the form of letters of credit to third parties, primarily pipeline capacity providers. The amount of financial assurance we provided has not increased during the COVID-19 pandemic and, thus far, we have not experienced any losses due to counterparty risk. However, our ability to limit any additional financial assurance we are required to provide, as well as to protect ourselves from the counterparty risk of our financial hedges, may be limited in the future. Since the onset of the COVID-19 pandemic, we have timely serviced our debt and other obligations, and we have not materially modified the terms of any agreements.

Financing and Asset Sales Program Highlights

Credit Facility

On October 26, 2021, we entered into an amended and restated senior secured revolving credit facility with a borrowing base of $3.5 billion and lender commitments of $1.5 billion. and matures on the earlier of (i) October 26, 2026 and (ii) the day that is 180 days prior to the earliest stated redemption date of any series of our senior notes. Lender commitments were reduced by $1.1 billion from the previous commitments of $2.64 billion to better align with our expected future liquidity needs. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements and “—Capital Resources and Liquidity—Debt Agreements—Senior Secured Revolving Credit Facility” for more information.

Issuance of Senior Notes

On January 4, 2021, we issued $500 million of our 8.375% senior notes due July 15, 2026 (the “2026 Notes”) at par. On January 26, 2021, we issued $700 million of 7.625% senior notes due February 1, 2029 (the “2029 Notes”) at par. On June 1, 2021, we issued $600 million of 5.375% senior notes due March 1, 2030 (the “2030 Notes”). The 2026 Notes, 2029 Notes and 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 2026 Notes, 2029 Notes and 2030 Notes rank pari passu to our other outstanding senior notes. The 2026 Notes, 2029 Notes and 2030 Notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by our existing subsidiaries that guarantee the Credit Facility and certain of our future restricted subsidiaries. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information.

39

Redemption of Senior Notes

We fully redeemed all of our outstanding 5.125% senior notes due December 1, 2022 (the “2022 Notes”) at par, plus accrued and unpaid interest in the first quarter of 2021. During the second quarter of 2021, we fully redeemed all of our outstanding 5.625% senior notes due June 1, 2023 (the “2023 Notes”) at par, plus accrued and unpaid interest.

On July 1, 2021, we redeemed $175 million of the principal amount of our 2026 Notes at a redemption price of 108.375% of the principal amount thereof, plus accrued and unpaid interest. Immediately following the redemption, there were $325 million aggregate principal amount of 2026 Notes outstanding. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information.

On October 18, 2021, we issued a notice of partial redemption with respect to the 2029 Notes. On November 2, 2021, we

will redeem $116 million aggregate principal amount of outstanding 2029 Notes at a redemption price of 107.625% of the principal

amount thereof, plus accrued and unpaid interest. Immediately following the redemption, there will be $584 million aggregate

principal amount of 2029 Notes outstanding. The $9 million premium to the principal amount to be redeemed along with the

write off of a proportional amount of unamortized debt issuance costs will be included in our loss on early debt extinguishment during

the fourth quarter of 2021.

Convertible Notes Equitizations

On January 12, 2021, we completed a registered direct offering (the “January Share Offering”) of an aggregate of 31.4 million shares of our common stock at a price of $6.35 per share to certain holders of our 4.25% convertible senior notes due 2026 (the “2026 Convertible Notes”). We used the proceeds from the January Share Offering and approximately $63 million of borrowings under the Prior Credit Facility to repurchase from such holders $150 million aggregate principal amount of the 2026 Convertible Notes in privately negotiated transactions (the “January Convertible Note Repurchase,” and, collectively with the January Share Offering, the “January Equitization Transactions”).

On May 13, 2021, we completed a registered direct offering (the “May Share Offering”) of an aggregate of 11.6 million shares of our common stock at a price of $11.01 per share to certain holders of our 2026 Convertible Notes. We used the proceeds from the May Share Offering and approximately $26 million of borrowings under the Prior Credit Facility to repurchase from such holders $56 million aggregate principal amount of the 2026 Convertible Notes in privately negotiated transactions (the “May Convertible Note Repurchase,” and, collectively with the May Share Offering, the “May Equitization Transactions”).  See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information.

Drilling Partnership

On February 17, 2021, we announced the formation of a drilling partnership with QL Capital Partners (“QL”), an affiliate of Quantum Energy Partners, for our 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 us during such tranche year. For 2021, together with QL, we agreed to a capital budget for such annual tranche, and for each subsequent year through 2024, we will propose a capital budget and estimated internal rate of return (“IRR”) for all wells to be spud during such year and, subject to the mutual agreement of the parties that the estimated IRR for the year exceeds a specified return, QL will be obligated to participate in such tranche. We develop and manage the drilling program associated with each tranche, including the selection of wells. Additionally, for each annual tranche in which QL participates, together with QL, we will enter into an assignment, bill of sale and conveyance pursuant to which QL will be conveyed a proportionate working interest percentage in each well spud in that year, which conveyance will not be subject to any reversion.

Under the terms of the arrangement, QL will fund 20% of development capital for wells spud in 2021 and is expected to fund between 15% and 20% of development capital for wells spud from 2022 through 2024, which funding amounts represent QL’s proportionate working interest in such wells. Additionally, we 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 December 31 following the end of each tranche year. Capital costs in excess of, and cost savings below, a specified percentage of budgeted amounts for each annual tranche will be for our account. Subject to the preceding sentence, for any wells included in a tranche, QL is obligated and responsible for its working interest share of costs and liabilities, and is entitled to its working interest share of revenues, associated with such wells for the life of such wells. If we present a capital budget for an annual tranche with an estimated IRR equal to or exceeding a specified return that QL in good faith believes is less than such specified return and QL elects not to participate, we will not be obligated to offer QL the opportunity to participate in subsequent annual tranches. See Note 3—Transactions to the unaudited condensed consolidated financial statements for more information.

40

Overriding Royalty Interest Additional Contributions

On June 15, 2020, we announced the consummation of a transaction with an affiliate of Sixth Street Partners, LLC (“Sixth Street”) relating to certain overriding royalty interests across our existing asset base (the “ORRIs”). In connection with the transaction, we contributed the ORRIs to a newly formed subsidiary, Martica Holdings LLC (“Martica”). At the initial closing, Sixth Street contributed $300 million in cash (subject to customary adjustments) and agreed to contribute up to an additional $102 million in cash if certain production thresholds attributable to the ORRIs were achieved in the third quarter of 2020 and first quarter of 2021. All cash contributed by Sixth Street was distributed to us. We met the applicable production thresholds related to the third quarter of 2020 and first quarter of 2021 as of September 31, 2020 and March 31, 2021, respectively. We received a $51 million cash distribution during each of the fourth quarter of 2020 and the second quarter of 2021. See Note 3—Transactions to the unaudited condensed consolidated financial statements for more information.

Hedge Position (Excluding Martica)

We are exposed to certain risks relating to our ongoing business operations, and we use derivative instruments to manage our commodity price risk.  In addition, we periodically enter into contracts that contain embedded features that are required to be bifurcated and accounted for separately as derivatives. The table below excludes derivative instruments attributable to Martica, our consolidated variable interest entity (“VIE”), since all gains or losses from such contracts are fully attributable to the noncontrolling interests in Martica. As of September 30, 2021, our fixed price natural gas, oil and NGL swap positions excluding Martica, our consolidated VIE, were as follows:

				Weighted
				Average
Commodity / Settlement Period	Index	Contracted Volume		Price
Natural Gas
October-December 2021	Henry Hub	199	Bcf	$	2.78	/MMBtu
January-December 2022	Henry Hub	422	Bcf		2.50	/MMBtu
January-December 2023	Henry Hub	16	Bcf		2.37	/MMBtu
		637	Bcf		2.58	/MMBtu
Butane
October-December 2021	Mont Belvieu Butane-OPIS Non-TET	239	MBbl	$	33.77	/Bbl
October-December 2021	Mont Belvieu Butane-OPIS TET	138	MBbl	$	32.24	/Bbl
Natural Gasoline
October-December 2021	Mont Belvieu Natural Gasoline-OPIS Non-TET	764	MBbl	$	49.70	/Bbl
Isobutane
October-December 2021	Mont Belvieu Isobutane-OPIS Non-TET	258	MBbl	$	35.75	/Bbl
Oil
October-December 2021	West Texas Intermediate	276	MBbl	$	55.16	/Bbl

In addition, we have a call option agreement, which entitles the holder, if exercised, to enter into a fixed price swap agreement for approximately 156 Bcf at a price of $2.77 per MMBtu in 2024.

As of September 30, 2021, our natural gas basis swap positions, which settle on the pricing index to basis differential of the Columbia Gas Transmission pipeline (“TCO”) to the NYMEX Henry Hub natural gas price were as follows:

				Weighted Average
Commodity / Settlement Period	Index to Basis Differential	Contracted Volume		Hedged Differential
Natural Gas
October-December 2021	NYMEX to TCO	4	Bcf	$	0.414	/MMBtu
January-December 2022	NYMEX to TCO	22	Bcf		0.515	/MMBtu
January-December 2023	NYMEX to TCO	18	Bcf		0.525	/MMBtu
January-December 2024	NYMEX to TCO	18	Bcf		0.530	/MMBtu
		62	Bcf		0.516	/MMBtu

41

As of September 30, 2021, we had natural gas and NGL contracts that fix the Mont Belvieu index price for natural gasoline to percentages of WTI as follows:

				Weighted Average
Commodity / Settlement Period	Index to Basis Differential	Contracted Volume		Payout Ratio
Gas Liquids
October-December 2021	Mont Belvieu Natural Gasoline to WTI	858	MBbl	77	%

As of September 30, 2021, we also had an embedded put option tied to NYMEX pricing for the production volumes associated with our retained interest in the VPP (as defined below) properties of 95 Bcf remaining through December 31, 2026 at a weighted average strike price of $2.57 per MMBtu.

We believe our hedge position provides some certainty to cash flows supporting our future operations and capital spending plans. As of September 30, 2021, the estimated fair value of our commodity derivative contracts was a net liability of approximately $1.7 billion. See Note 11—Derivative Instruments to the unaudited condensed consolidated financial statements for more information.

42

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 Corporation. Revenues from Antero Midstream Corporation’s operations were primarily derived from intersegment transactions for services provided to our exploration and production operations by Antero Midstream Partners. All intersegment transactions were eliminated upon consolidation, including revenues from water handling and treatment services provided by Antero Midstream Partners LP (“Antero Midstream Partners”), which we capitalized as proved property development costs. Marketing revenues are primarily derived from activities to purchase and sell third-party natural gas and NGLs and to market and utilize excess firm transportation capacity. See Note 16—Reportable Segments to the unaudited condensed consolidated financial statements.

Three Months Ended September 30, 2020 Compared to Three Months Ended September 30, 2021

The operating results of our reportable segments were as follows for the three months ended September 30, 2020 and 2021 (in thousands):

	Three Months Ended September 30, 2020
					Equity Method		Elimination of
					Investment in		Intersegment
	Exploration				Antero		Transactions and
	and				Midstream		Unconsolidated		Consolidated
	Production		Marketing		Corporation		Affiliates		Total
Revenue and other:
Natural gas sales	$	436,304		—		—		—		436,304
Natural gas liquids sales		327,426		—		—		—		327,426
Oil sales		34,265		—		—		—		34,265
Commodity derivative fair value losses		(514,751)		—		—		—		(514,751)
Gathering, compression, water handling and treatment		—		—		251,215		(251,215)		—
Marketing		—		91,497		—		—		91,497
Amortization of deferred revenue, VPP		5,175		—		—		—		5,175
Other income (loss)		675		—		(17,800)		17,800		675
Total revenue	$	289,094		91,497		233,415		(233,415)		380,591
Operating expenses:
Lease operating	$	21,450		—		—		—		21,450
Gathering and compression		221,004		—		38,052		(38,052)		221,004
Processing		244,888		—		—		—		244,888
Transportation		190,723		—		—		—		190,723
Production and ad valorem taxes		25,790		—		—		—		25,790
Marketing		—		128,580		—		—		128,580
Exploration		454		—		—		—		454
Impairment of oil and gas properties		29,392		—		—		—		29,392
Depletion, depreciation, and amortization		238,418		—		26,801		(26,801)		238,418
Accretion of asset retirement obligations		1,115		—		39		(39)		1,115
General and administrative (excluding equity-based compensation)		25,941		—		9,554		(9,554)		25,941
Equity-based compensation		5,699		—		3,678		(3,678)		5,699
Contract termination and rig stacking and other expenses		1,246		—		3,474		(3,474)		1,246
Total operating expenses		1,006,120		128,580		81,598		(81,598)		1,134,700
Operating income (loss)	$	(717,026)		(37,083)		151,817		(151,817)		(754,109)
Equity in earnings of unconsolidated affiliates	$	24,419		—		23,173		(23,173)		24,419

43

	Three Months Ended September 30, 2021
					Equity Method		Elimination of
					Investment in		Intersegment
	Exploration				Antero		Transactions and
	and				Midstream		Unconsolidated		Consolidated
	Production		Marketing		Corporation		Affiliates		Total
Revenue and other:
Natural gas sales	$	884,669		—		—		—		884,669
Natural gas liquids sales		598,327		—		—		—		598,327
Oil sales		56,734		—		—		—		56,734
Commodity derivative fair value losses		(1,250,466)		—		—		—		(1,250,466)
Gathering, compression, water handling and treatment		—		—		242,472		(242,472)		—
Marketing		—		232,685		—		—		232,685
Amortization of deferred revenue, VPP		11,404		—		—		—		11,404
Gain on sale of assets		539		—		—		—		539
Other income (loss)		530		—		(17,668)		17,668		530
Total revenue	$	301,737		232,685		224,804		(224,804)		534,422
Operating expenses:
Lease operating	$	25,363		—		—		—		25,363
Gathering and compression		218,815		—		39,499		(39,499)		218,815
Processing		207,093		—		—		—		207,093
Transportation		202,317		—		—		—		202,317
Production and ad valorem taxes		52,219		—		—		—		52,219
Marketing		—		266,751		—		—		266,751
Exploration		235		—		—		—		235
Impairment of oil and gas properties		26,253		—		—		—		26,253
Depletion, depreciation, and amortization		182,810		—		27,487		(27,487)		182,810
Accretion of asset retirement obligations		828		—		114		(114)		828
General and administrative (excluding equity-based compensation)		27,144		—		11,555		(11,555)		27,144
Equity-based compensation		5,298		—		3,255		(3,255)		5,298
Contract termination and rig stacking and other expenses		3,370		—		1,073		(1,073)		3,370
Total operating expenses		951,745		266,751		82,983		(82,983)		1,218,496
Operating income (loss)	$	(650,008)		(34,066)		141,821		(141,821)		(684,074)
Equity in earnings of unconsolidated affiliates	$	21,450		—		24,088		(24,088)		21,450

44

Exploration and Production Segment

The following table sets forth selected operating data of the exploration and production segment for the three months ended September 30, 2020 compared to the three months ended September 30, 2021:

	Three Months Ended				Amount of
	September 30,				Increase		Percent
	2020		2021		(Decrease)		Change
Production data (1):
Natural gas (Bcf)		226		205		(21)	(9)	%
C2 Ethane (MBbl)		5,459		4,372		(1,087)	(20)	%
C3+ NGLs (MBbl)		13,400		10,258		(3,142)	(23)	%
Oil (MBbl)		1,367		932		(435)	(32)	%
Combined (Bcfe)		347		299		(48)	(14)	%
Daily combined production (MMcfe/d)		3,772		3,247		(525)	(14)	%
Average prices before effects of derivative settlements (2):
Natural gas (per Mcf)	$	1.93		4.31		2.38	123	%
C2 Ethane (per Bbl)	$	5.94		13.25		7.31	123	%
C3+ NGLs (per Bbl)	$	22.01		52.68		30.67	139	%
Oil (per Bbl)	$	25.07		60.87		35.80	143	%
Weighted Average Combined (per Mcfe)	$	2.30		5.15		2.85	124	%
Average realized prices after effects of derivative settlements (2):
Natural gas (per Mcf)	$	2.73		3.00		0.27	10	%
C2 Ethane (per Bbl)	$	5.67		13.25		7.58	134	%
C3+ NGLs (per Bbl)	$	23.81		38.67		14.86	62	%
Oil (per Bbl)	$	34.96		56.31		21.35	61	%
Weighted Average Combined (per Mcfe)	$	2.92		3.79		0.87	30	%
Average costs (per Mcfe):
Lease operating	$	0.06		0.08		0.02	33	%
Gathering and compression	$	0.64		0.73		0.09	14	%
Processing	$	0.71		0.69		(0.02)	(3)	%
Transportation	$	0.55		0.68		0.13	24	%
Production taxes	$	0.07		0.17		0.10	143	%
Marketing, net	$	0.11		0.11		—	—	%
Depletion, depreciation, amortization and accretion	$	0.69		0.61		(0.08)	(12)	%
General and administrative (excluding equity-based compensation)	$	0.07		0.09		0.02	29	%

(1) Production data excludes volumes related to the volumetric production payment transaction (the “VPP”). See Note 3— Transactions to the unaudited condensed consolidated financial statements for more information.

(2) Average sales prices shown in the table reflect both the before and after effects of our settled commodity derivatives. Our calculation of such after effects includes gains 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. 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 does not necessarily reflect their relative economic value.

Natural gas sales. Revenues from sales of natural gas increased from $436 million for the three months ended September 30, 2020 to $885 million for the three months ended September 30, 2021, an increase of $449 million, or 103%. Lower natural gas production volumes during the three months ended September 30, 2021 accounted for an approximate $39 million decrease in year-over-year natural gas sales revenue (calculated as the change in year-to-year volumes times the prior year average price), and increases in commodity prices (excluding the effects of derivative settlements) accounted for an approximate $488 million increase in year-over-year gas sales revenue (calculated as the change in the year-to-year average price excluding the net proceeds from the litigation times current year production volumes).

NGLs sales. Revenues from sales of NGLs increased from $327 million for the three months ended September 30, 2020 to $598 million for the three months ended September 30, 2021, an increase of $271 million, or 83% (calculated as the change in year-over-year volumes times the change in year-to-year average price). Lower NGLs production volumes accounted for an approximate $76 million decrease in year-over-year NGL revenues (calculated as the change in year-to-year volumes times the prior year average price), and increases in commodity prices, excluding the effects of derivative settlements, accounted for an approximate $347 million

45

increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

Oil sales. Revenues from sales of oil increased from $34 million for the three months ended September 30, 2020 to $57 million for the three months ended September 30, 2021, an increase of $23 million, or 66% (calculated as the change in year-over-year volumes times the change in year-to-year average price). Lower oil production volumes accounted for an approximate $11 million decrease in year-over-year oil revenues (calculated as the change in year-to-year volumes times the prior year average price), and increases in commodity prices, excluding the effects of derivative settlements, accounted for an approximate $34 million increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

Commodity derivative fair value gains (losses). To achieve more predictable cash flows, and to reduce our exposure to price fluctuations, we enter into fixed for variable price swap contracts, basis swap contracts and collar contracts when management believes that favorable future sales prices for our production can be secured. 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, 2020 and 2021, our commodity hedges resulted in derivative fair value losses of $515 million and $1.3 billion, respectively. For the three months ended September 30, 2020, commodity derivative fair value losses included $234 million of cash proceeds for gains on settled derivatives. For the three months ended September 30, 2021, commodity derivative fair value losses included $416 million of cash payments on commodity settled 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 increased from $5 million for the three months ended September 30, 2020 to $11 million for the three months ended September 30, 2021 as a result of the VPP closing in August 2020. Under the terms of the agreement, the production volumes are delivered at approximately $1.61 per MMBtu over the contractual term. See Note 3—Transactions to the unaudited condensed consolidated financial statements for more information on this transaction.

Lease operating expense. Lease operating expense increased from $21 million for the three months ended September 30, 2020 to $25 million for the three months ended September 30, 2021, an increase of $4 million or 18%. On a per unit basis, lease operating expenses increased from $0.06 per Mcfe for the three months ended September 30, 2020 to $0.08 per Mcfe for the three months ended September 30, 2021 primarily due to decreased production and higher fixed costs partially offset by lower water disposal costs.

Gathering, compression, processing, and transportation expense. Gathering, compression, processing, and transportation expense decreased from $657 million for the three months ended September 30, 2020 to $628 million for the three months ended September 30, 2021, a decrease of $29 million or 4%. This decrease is primarily a result of lower production and decreased processing costs, partially offset by higher gathering and compression and transportation costs between periods. Gathering and compression costs increased from $0.64 per Mcfe for the three months ended September 30, 2020 to $0.73 per Mcfe for the three months ended September 30, 2021, primarily due to higher fuel costs as a result of increased natural gas prices and $12 million in incentive fee rebates from Antero Midstream Corporation received during the three months ended September 30, 2020 that were not received during the three months ended September 30, 2021. Processing costs decreased from $0.71 per Mcfe for the three months ended September 30, 2020 to $0.69 per Mcfe for the three months ended September 30, 2021, due to a decrease in C3+ NGL volumes as compared to total production volumes between periods, partially offset by increased NGL pipeline and terminaling fees from higher NGL volumes taken in-kind between periods. Transportation costs increased from $0.55 per Mcfe for the three months ended September 30, 2020 to $0.68 per Mcfe for the three months ended September 30, 2021 primarily due to increased utilization on higher tariff pipelines to the Midwest and Gulf Coast between periods.

Production and ad valorem tax expense.  Production and ad valorem taxes increased from $26 million for the three months ended September 30, 2020 to $52 million for the three months ended September 30, 2021, an increase of $26 million, or 100% primarily due to higher commodity prices between periods. Production and ad valorem taxes as a percentage of natural gas revenues remained consistent at 6% in each of the three months ended September 30, 2020 and 2021.

46

Impairment of oil and gas properties. Impairment of oil and gas properties decreased from $29 million for the three months ended September 30, 2020 to $26 million for the three months ended September 30, 2021, a decrease of $3 million, or 11%, primarily related to lower impairments of expiring leases between periods. During both periods, we recognized impairments primarily related to expiring leases and initial costs related to pads we no longer plan to place into service.

Depletion, depreciation, and amortization expense. Depletion, depreciation and amortization (“DD&A”) expense decreased from $238 million for the three months ended September 30, 2020 to $183 million for the three months ended September 30, 2021, a decrease of $55 million, or 23%, primarily as a result of increased proved reserve volumes due to higher commodity prices as well as lower production volumes between periods. DD&A expense decreased from $0.69 per Mcfe for the three months ended September 30, 2020 to $0.61 per Mcfe for the three months ended September 30, 2021, primarily as a result of increased proved reserve volumes between periods.

General and administrative expense. General and administrative expense (excluding equity-based compensation expense) increased from $26 million for the three months ended September 30, 2020 to $27 million for the three months ended September 30, 2021, an increase of $1 million, or 5%. The increase was primarily due to higher salary and wage expense between periods, which includes our annual incentive program that was significantly reduced during 2020, partially offset by lower employee headcount during 2021. We had 520 and 506 employees as of September 30, 2020 and 2021, respectively. On a per-unit basis, general and administrative expense excluding equity-based compensation increased from $0.07 per Mcfe for the three months ended September 30, 2020 to $0.09 per Mcfe for the three months ended September 30, 2021 primarily due to lower production between periods.

Equity-based compensation expense. Noncash equity-based compensation expense decreased from $6 million for the three months ended September 30, 2020 to $5 million for the three months ended September 30, 2021, primarily due to equity award forfeitures, partially offset by new awards granted to employees. When an equity award is forfeited, expense previously recognized for the award is reversed. See Note 9—Equity Based Compensation and Cash Awards to the unaudited condensed consolidated financial statements for more information on equity-based compensation awards.

Marketing Segment

Marketing. 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, to optimize the revenues and mitigate costs from these transportation agreements. We have entered into long-term firm transportation agreements for a significant portion of our current and expected future production to secure guaranteed capacity to favorable markets.

Net marketing expenses decreased from $37 million, or $0.11 per Mcfe, for the three months ended September 30, 2020 to $34 million, or $0.11 per Mcfe, for the three months ended September 30, 2021. The decrease in net marketing expense was driven by higher marketing volumes and margins that mitigated some of our excess firm transportation expense.

Marketing revenues increased from $91 million for the three months ended September 30, 2020 to $233 million for the three months ended September 30, 2021, an increase of $142 million due to increased marketing volumes.

Marketing expenses increased from $129 million for the three months ended September 30, 2020 to $267 million for the three months ended September 30, 2021, an increase of $138 million, or 107%. Marketing expenses include firm transportation costs related to current excess firm capacity as well as the cost of third-party purchased gas and NGLs. Firm transportation costs included in the expenses above were $32 million and $28 million for the three months ended September 30, 2020 and 2021, respectively.

Equity Method Investment in Antero Midstream Corporation

Antero Midstream Corporation. Revenue from the Antero Midstream Corporation segment decreased from $233 million for the three months ended September 30, 2020 to $225 million for the three months ended September 30, 2021, a decrease of $8 million, or 4%, primarily due to lower water handling revenue due to decreased well completions period-over-period and lower gathering and compression revenues as a result of reduced throughput between periods. Total operating expenses related to the segment remained relatively consistent between periods at $82 million and $83 million for the three months ended September 30, 2020 and 2021, respectively.

47

Items Not Allocated to Segments

Interest expense. Our interest expense decreased from $48 million for the three months ended September 30, 2020 to $45 million for the three months ended September 30, 2021, a decrease of $3 million or 5%, primarily due to the reduction in debt as a result of the repurchase of certain our unsecured senior notes, paydown of our Prior Credit Facility and increased interest income between periods, partially offset by interest that accrued on the 2026 Notes, 2029 Notes and 2030 Notes, each of which was issued after September 30, 2020.

Gain (loss) on early extinguishment of debt. During the three months ended September 30, 2020, we recognized a gain on early extinguishment of debt of $56 million related to $1.1 billion principal amount of debt that we repurchased at a weighted average discount of 13%. During the three months ended September 30, 2021, we redeemed $175 million of our 2026 Notes at a redemption price of 108.375% of par, plus accrued and unpaid interest, which resulted in a loss on early debt extinguishment of $17 million. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information.

Transaction expense. Transaction expense remained consistent between periods at less than $1 million for both the three months ended September 31, 2020 and 2021.

Income tax benefit. Income tax benefit decreased from $169 million, with an effective tax rate of 23%, for the three months ended September 30, 2020 to $159 million, with an effective tax rate of 22%, for the three months ended September 30, 2021, a decrease of $10 million. The decrease was primarily due to unfavorable adjustments related to the West Virginia law change effecting apportionment and sourcing methodologies resulting in lower income tax benefit for the period ending September 30, 2021.

48

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2021

The operating results of our reportable segments were as follows for the nine months ended September 30, 2020 and 2021 (in thousands):

	Nine Months Ended September 30, 2020
					Equity Method		Elimination of
					Investment in		Intersegment
	Exploration				Antero		Transactions and
	and				Midstream		Unconsolidated		Consolidated
	Production		Marketing		Corporation		Affiliates		Total
Revenue and other:
Natural gas sales	$	1,214,801		—		—		—		1,214,801
Natural gas liquids sales		797,296		—		—		—		797,296
Oil sales		78,233		—		—		—		78,233
Commodity derivative fair value losses		(116,933)		—		—		—		(116,933)
Gathering, compression, water handling and treatment		—		—		749,870		(749,870)		—
Marketing		—		201,855		—		—		201,855
Amortization of deferred revenue, VPP		5,175		—		—		—		5,175
Other income (loss)		2,180		—		(53,011)		53,011		2,180
Total revenue	$	1,980,752		201,855		696,859		(696,859)		2,182,607
Operating expenses:
Lease operating		71,836		—		—		—		71,836
Gathering and compression		616,785		—		128,847		(128,847)		616,785
Processing		697,716		—		—		—		697,716
Transportation		562,583		—		—		—		562,583
Production and ad valorem taxes		71,481		—		—		—		71,481
Marketing		—		334,906		—		—		334,906
Exploration		895		—		—		—		895
Impairment of oil and gas properties		155,962		—		—		—		155,962
Impairment of midstream assets		—		—		665,491		(665,491)		—
Depletion, depreciation, and amortization		652,130		—		81,889		(81,889)		652,130
Accretion of asset retirement obligations		3,330		—		142		(142)		3,330
General and administrative (excluding equity-based compensation)		84,263		—		29,478		(29,478)		84,263
Equity-based compensation		17,001		—		9,713		(9,713)		17,001
Contract termination and rig stacking and other expenses		12,317		—		13,920		(13,920)		12,317
Total operating expenses		2,946,299		334,906		929,480		(929,480)		3,281,205
Operating loss	$	(965,547)		(133,051)		(232,621)		232,621		(1,098,598)
Equity in earnings (loss) of unconsolidated affiliates	$	(83,408)		—		63,197		(63,197)		(83,408)

49

	Nine Months Ended September 30, 2021
					Equity Method		Elimination of
					Investment in		Intersegment
	Exploration				Antero		Transactions and
	and				Midstream		Unconsolidated		Consolidated
	Production		Marketing		Corporation		Affiliates		Total
Revenue and other:
Natural gas sales	$	2,231,558		—		—		—		2,231,558
Natural gas liquids sales		1,503,027		—		—		—		1,503,027
Oil sales		153,326		—		—		—		153,326
Commodity derivative fair value losses		(2,260,062)		—		—		—		(2,260,062)
Gathering, compression, water handling and treatment		—		—		734,716		(734,716)		—
Marketing		—		562,928		—		—		562,928
Amortization of deferred revenue, VPP		33,833		—		—		—		33,833
Gain on sale of assets		2,827				—		—		2,827
Other income (loss)		551		—		(53,004)		53,004		551
Total revenue	$	1,665,060		562,928		681,712		(681,712)		2,227,988
Operating expenses:
Lease operating	$	71,555		—		—		—		71,555
Gathering and compression		663,176		—		118,368		(118,368)		663,176
Processing		601,040		—		—		—		601,040
Transportation		610,448		—		—		—		610,448
Production and ad valorem taxes		130,610		—		—		—		130,610
Marketing		—		627,822		—		—		627,822
Exploration		6,092		—		—		—		6,092
Impairment of oil and gas properties		69,618		—		—		—		69,618
Depletion, depreciation, and amortization		564,166		—		80,956		(80,956)		564,166
Accretion of asset retirement obligations		2,947		—		347		(347)		2,947
General and administrative (excluding equity-based compensation)		93,504		—		36,665		(36,665)		93,504
Equity-based compensation		15,189		—		10,326		(10,326)		15,189
Contract termination and rig stacking and other expenses		4,305		—		8,243		(8,243)		4,305
Total operating expenses		2,832,650		627,822		254,905		(254,905)		3,460,472
Operating income (loss)	$	(1,167,590)		(64,894)		426,807		(426,807)		(1,232,484)
Equity in earnings of unconsolidated affiliates	$	57,621		—		66,347		(66,347)		57,621

50

Exploration and Production Segment

The following table sets forth selected operating data of the exploration and production segment for the nine months ended September 30, 2020 compared to the nine months ended September 30, 2021:

					Amount of
	Nine Months Ended September 30,				Increase		Percent
	2020		2021		(Decrease)		Change
Production data (1) (2):
Natural gas (Bcf)		649		621		(28)	(4)	%
C2 Ethane (MBbl)		14,686		13,132		(1,554)	(11)	%
C3+ NGLs (MBbl)		36,167		30,624		(5,543)	(15)	%
Oil (MBbl)		3,308		2,832		(476)	(14)	%
Combined (Bcfe)		974		900		(74)	(8)	%
Daily combined production (MMcfe/d)		3,554		3,297		(257)	(7)	%
Average prices before effects of derivative settlements (3):
Natural gas (per Mcf)	$	1.87		3.60		1.73	93	%
C2 Ethane (per Bbl)	$	5.85		10.47		4.62	79	%
C3+ NGLs (per Bbl)	$	19.67		44.59		24.92	127	%
Oil (per Bbl)	$	23.65		54.14		30.49	129	%
Weighted Average Combined (per Mcfe)	$	2.15		4.32		2.17	101	%
Average realized prices after effects of derivative settlements (3):
Natural gas (per Mcf)	$	2.80		3.16		0.36	13	%
C2 Ethane (per Bbl)	$	5.72		10.24		4.52	79	%
C3+ NGLs (per Bbl)	$	22.25		38.11		15.86	71	%
Oil (per Bbl)	$	38.00		51.34		13.34	35	%
Weighted Average Combined (per Mcfe)	$	2.91		3.79		0.88	30	%
Average costs (per Mcfe):
Lease operating	$	0.07		0.08		0.01	14	%
Gathering and compression	$	0.63		0.74		0.11	17	%
Processing	$	0.72		0.67		(0.05)	(7)	%
Transportation	$	0.58		0.68		0.10	17	%
Production and ad valorem taxes	$	0.07		0.15		0.08	114	%
Marketing expense, net	$	0.14		0.07		(0.07)	(50)	%
Depletion, depreciation, amortization, and accretion	$	0.67		0.63		(0.04)	(6)	%
General and administrative (excluding equity-based compensation)	$	0.09		0.10		0.01	11	%

(1) Production data excludes volumes related to the VPP. See Note 3— Transactions to the unaudited condensed consolidated financial statements for more information.

(2) Average sales prices shown in the table reflect both the before and after effects of our settled commodity derivatives. Our calculation of such after effects includes gains 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. 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 does not necessarily reflect their relative economic value.

(3) The average realized price for the nine months ended September 30, 2021 includes $85 million of net litigation proceeds related to a favorable litigation judgment. See Note 14—Contingencies to the unaudited condensed consolidated financial statements for further discussion on the litigation proceeds. Excluding the effect of the litigation proceeds received, the average realized price would have been $3.46 per Mcf.

Natural gas sales. Revenues from sales of natural gas increased from $1.2 billion for the nine months ended September 30, 2020 to $2.2 billion, which included litigation proceeds of $85 million, for the nine months ended September 30, 2021, an increase of $1.0 billion, or 84%. See Note 14— Contingencies to the unaudited condensed consolidated financial statements for more information on the litigation proceeds.

Excluding net litigation proceeds, lower natural gas production volumes during the nine months ended September 30, 2021 accounted for an approximate $53 million decrease in year-over-year natural gas sales revenue (calculated as the change in year-to-year volumes times the prior year average price excluding the net proceeds from the litigation), and increases in commodity prices (excluding the effects of derivative settlements) accounted for an approximate $984 million increase in year-over-year gas sales revenue (calculated as the change in the year-to-year average price excluding the net proceeds from the litigation times current year production volumes).

51

NGLs sales. Revenues from sales of NGLs increased from $797 million for the nine months ended September 30, 2020 to $1.5 billion for the nine months ended September 30, 2021, an increase of $706 million, or 89% (calculated as the change in year-over-year volumes times the change in year-to-year average price). Lower NGLs production volumes accounted for an approximate $118 million decrease in year-over-year NGL revenues (calculated as the change in year-to-year volumes times the prior year average price), and increases in commodity prices, excluding the effects of derivative settlements, accounted for an approximate $824 million increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

Oil sales. Revenues from sales of oil increased from $78 million for the nine months ended September 30, 2020 to $153 million for the nine months ended September 30, 2021, an increase of $75 million, or 96% (calculated as the change in year-over-year volumes times the change in year-to-year average price). Lower oil production volumes accounted for a $11 million decrease in year-over-year oil revenues (calculated as the change in year-to-year volumes times the prior year average price), and increases in commodity prices, excluding the effects of derivative settlements, accounted for an approximate $86 million increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

Commodity derivative fair value gains (losses). To achieve more predictable cash flows, and to reduce our exposure to price fluctuations, we enter into fixed for variable price swap contracts, basis swap contracts and collar contracts when management believes that favorable future sales prices for our production can be secured. 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, 2020, our commodity hedges resulted in derivative fair value losses of $117 million. For the nine months ended September 30, 2021, our commodity hedges resulted in derivative fair value loss of $2.3 billion. Commodity derivative fair value losses included $759 million of cash proceeds for gains on settled derivatives for the nine months ended September 30, 2020. For the nine months ended September 30, 2021, commodity derivative fair value losses included $481 million of cash payments on commodity derivative losses as well as $5 million for payments on derivative monetizations.

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 increased from $5 million for the nine months ended September 30, 2020 to $34 million for the nine months ended September 30, 2021 as a result of the VPP closing in August 2020. Under the terms of the agreement, the production volumes are delivered at approximately $1.61 per MMBtu over the contractual term. See Note 3—Transactions to the unaudited condensed consolidated financial statements for more information on this transaction.

Lease operating expense. Lease operating expense was $72 million for each of the nine months ended September 30, 2020 and 2021. On a per unit basis, lease operating expenses increased from $0.07 per Mcfe for the nine months ended September 30, 2020 to $0.08 per Mcfe for the three months ended September 30, 2021 primarily due to lower production volumes.

Gathering, compression, processing, and transportation expense. Gathering, compression, processing, and transportation expense remained relatively flat at $1.9 billion for both the nine months ended September 30, 2020 and 2021. Gathering and compression costs increased from $0.63 per Mcfe for the nine months ended September 30, 2020 to $0.74 per Mcfe for the nine months ended September 30, 2021, primarily due to higher fuel costs as a result of increased natural gas prices and $36 million in incentive fee rebates from Antero Midstream Corporation received during the nine months ended September 30, 2020 that were not received during the nine months ended September 30, 2021. Processing costs decreased from $0.72 per Mcfe for the nine months ended September 30, 2020 to $0.67 per Mcfe for the nine months ended September 30, 2021, due to a decrease in C3+ NGL volumes as compared to total production volumes between periods, partially offset by increased NGL pipeline and terminaling fees from higher NGL volumes taken in-kind between periods. Transportation costs increased from $0.58 per Mcfe for the nine months ended September 30, 2020 to $0.68 per Mcfe for the nine months ended September 30, 2021 primarily due to increased utilization on higher tariff pipelines to the Midwest and Gulf Coast between periods.

Production and ad valorem tax expense.  Production and ad valorem taxes increased from $71 million for the nine months ended September 30, 2020 to $131 million for the nine months ended September 30, 2021, an increase of $60 million, or 83% primarily due to higher commodity prices between periods and $5 million for the litigation judgment. Production and ad valorem

52

taxes as a percentage of natural gas revenues remained consistent at 6% in each of the nine months ended September 30, 2020 and 2021.

Impairment of oil and gas properties. Impairment of oil and gas properties decreased from $156 million for the nine months ended September 30, 2020 to $70 million for the nine months ended September 30, 2021, a decrease of $86 million, or 55%, 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.

Depletion, depreciation, and amortization expense. DD&A expense decreased from $652 million for the nine months ended September 30, 2020 to $564 million for the nine months ended September 30, 2021, a decrease of $88 million, or 13%, primarily as a result of increased proved reserve volumes between periods due to higher commodity prices as well as lower production volumes between periods. DD&A per Mcfe remained relatively consistent at $0.67 per Mcfe and $0.63 per Mcfe during the nine months ended September 30, 2020 and 2021, respectively.

General and administrative expense. General and administrative expense (excluding equity-based compensation expense) increased from $84 million for the nine months ended September 30, 2020 to $94 million for the nine months ended September 30, 2021, an increase of $10 million, or 11%. The increase was primarily due to higher salary and wage expense between periods, which includes our annual incentive program that was significantly reduced during 2020. We had 520 and 506 employees as of September 30, 2020 and 2021, respectively. On a per-unit basis, general and administrative expense excluding equity-based compensation increased from $0.09 per Mcfe during the nine months ended September 30, 2020 to $0.10 per Mcfe during the nine months ended September 30, 2021 as a result of lower production volumes and higher overall costs between periods.

Equity-based compensation expense. Noncash equity-based compensation expense decreased from $17 million for the nine months ended September 30, 2020 to $15 million for the nine months ended September 30, 2021, primarily due to equity award forfeitures, partially offset by new awards granted to employees. When an equity award is forfeited, expense previously recognized for the award is reversed. See Note 9—Equity Based Compensation and Cash Awards to the unaudited condensed consolidated financial statements for more information on equity-based compensation awards.

Marketing Segment

Marketing. 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, to optimize the revenues and mitigate costs from these transportation agreements. We have entered into long-term firm transportation agreements for a significant portion of our current and expected future production to secure guaranteed capacity to favorable markets.

Net marketing expenses decreased from $133 million, or $0.14 per Mcfe, for the nine months ended September 30, 2020 to $65 million, or $0.07 per Mcfe, for the nine months ended September 30, 2021. The decrease was driven by higher marketing volumes and margins that mitigated some of our excess firm transportation expense.

Marketing revenues increased from $202 million for the nine months ended September 30, 2020 to $563 million for the nine months ended September 30, 2021, an increase of $361 million due to increased marketing volumes.

Marketing expenses increased from $335 million for the nine months ended September 30, 2020 to $628 million for the nine months ended September 30, 2021, an increase of $293 million, or 87%. Marketing expenses include firm transportation costs related to current excess firm capacity as well as the cost of third-party purchased gas and NGLs. Firm transportation costs included in the expenses above were $122 million and $81 million for the nine months ended September 30, 2020 and 2021, respectively.

Equity Method Investment in Antero Midstream Corporation

Antero Midstream Corporation. Revenue from the Antero Midstream Corporation segment decreased from $697 million for the nine months ended September 30, 2020 to $682 million for the nine months ended September 30, 2021, a decrease of $15 million, or 2%, primarily due to lower fresh water delivery revenue as a result of decreased well completions period-over-period and lower gathering volumes, partially offset by higher compression revenues as a result of increased throughput between periods. Total operating expenses related to the segment decreased from $929 million for the nine months ended September 30, 2020 to $255 million for the nine months ended September 30, 2021, primarily due to impairments by Antero Midstream Corporation during the nine months ended September 30, 2020 of $89 million on its freshwater pipelines and equipment and impairment of goodwill of $575 million. Antero Midstream Corporation’s impairment expense was $2 million for the nine months ended September 30, 2021 due to a lower of cost or market adjustment for pipe inventory.

53

Items Not Allocated to Segments

Interest expense. Our interest expense decreased from $153 million for the nine months ended September 30, 2020 to $138 million for the nine months ended September 30, 2021 primarily due to the reduction in debt as a result of our debt repurchases of our unsecured senior notes, paydown of our Prior Credit Facility and increased interest income between periods, partially offset by interest that accrued on the (i) 2026 Convertible Notes, which were issued in August 2020 and (ii) 2026 Notes, 2029 Notes and 2030 Notes, each of which was issued after September 30, 2020.

Impairment of equity investment. As of March 31, 2020, we determined that events and circumstances indicated that the carrying value of our equity method investment in Antero Midstream Corporation had experienced an other-than-temporary decline and we recorded an impairment of $611 million. The fair value of the equity method investment in Antero Midstream Corporation was based on the quoted market share price of Antero Midstream Corporation as of March 31, 2020. There was no such impairment for the nine months ended September 30, 2021.

Gain (loss) on early extinguishment of debt. During the nine months ended September 30, 2020, we recognized a gain on early extinguishment of debt of $175 million related to $1.1 billion principal amount of debt that we repurchased at a weighted average discount of 17%. During the nine months ended September 30, 2021, we equitized $206 million aggregate principal amount of our 2026 Convertible Notes in privately negotiated exchange transactions and as a result, we recognized a loss of $61 million which represents the difference between the fair value of the liability component of the 2026 Convertible Notes and the carrying value of such notes. Additionally, during the nine months ended September 30, 2021, we redeemed (i) the remaining balance of $661 million of our 2022 Notes at par, plus accrued and unpaid interest, (ii) the remaining balance of $574 million of our 2023 Notes at par, plus accrued and unpaid interest and (iii) $175 million of our 2026 Notes at a redemption price of 108.375% of par, plus accrued and unpaid interest and recognized a $22 million loss on early extinguishment of debt for such redemptions. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information.

Loss on convertible note equitization. During the nine months ended September 30, 2021, we recognized a loss of $51 million for the January Equitization Transactions and the May Equitization Transactions, which represents the consideration paid in excess of the original terms of the 2026 Convertible Notes. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information.

Transaction expense. Transaction expense decreased from $7 million for the nine months ended September 30, 2020 to $3 million for the nine months ended September 30, 2021, a decreased of $4 million or 53%. Transaction expense for the nine months ended September 30, 2020 included legal and transaction fees associated with the sale of our overriding royalty interest and the creation of Martica, as well as the VPP transaction. For the nine months ended September 30, 2021, transaction expense included legal and transaction fees associated with the drilling partnership. See Note 3—Transactions to the unaudited condensed consolidated financial statements for more information on these transactions.

Income tax benefit. Income tax benefit decreased from $421 million, with an effective tax rate of 24%, for the nine months ended September 30, 2020 to $338 million, with an effective tax rate of 23%, for the nine months ended September 30, 2021, a decrease of $83 million. The decrease was primarily due to lower loss before income taxes between periods.

Capital Resources and Liquidity

Sources and Uses of Cash

Our primary sources of liquidity have been through net cash provided by operating activities including borrowings under the Prior 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. For information about the impacts of COVID-19 on our capital resources and liquidity, see “—COVID-19 Pandemic.”

Based on strip prices as of September 30, 2021, we believe that net cash provided by operating activities, distributions from unconsolidated affiliate, available borrowings under the Credit Facility, capital market transactions and the effects of the drilling partnership 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.

54

2021 Capital Budget and Capital Spending

On February 17, 2021, we announced our net capital budget for 2021 is $635 million, which includes: $590 million for drilling and completion and $45 million for leasehold expenditures. We do not include acquisitions in our capital budget. We periodically review our capital expenditures and adjust our budget and its allocation based on commodity prices, takeaway constraints, operating cash flow and liquidity, and on July 28, 2021, we announced a $22.5 million increase for our leasehold expenditures for 2021 to reflect accelerated leasing activity focused on organically expanding our core liquids rich inventory. As a result, our total net capital budget for 2021 was revised to $657.5 million.

For the nine months ended September 30, 2021, our total consolidated capital expenditures, which excludes QL’s working interest share of such costs, were approximately $542 million, including drilling and completion costs of $475 million, leasehold acquisitions of $48 million, and other capital expenditures of $19 million.

Cash Flows

The following table summarizes our cash flows for the nine months ended September 30, 2020 and 2021:

	Nine Months Ended September 30,
	2020		2021
Net cash provided by operating activities	$	492,510		1,184,952
Net cash used in investing activities		(384,063)		(505,455)
Net cash used in financing activities		(108,447)		(679,497)
Net increase in cash and cash equivalents	$	—		—

Operating Activities. Net cash provided by operating activities was $493 million and $1.2 billion for the nine months ended September 30, 2020 and 2021, respectively. Net cash provided by operating activities increased primarily due to increases in commodity prices both before and after the effects of settled commodity derivatives, decreased net marketing expense as well as decreased cash utilized for working capital, partially offset by increases in gathering, compression and transportation costs and production and ad valorem taxes between periods.

Our net operating cash flows are sensitive to many variables, the most significant of which is the volatility of natural gas, NGLs, and oil prices, as well as volatility in the cash flows attributable to settlement of our commodity derivatives. Prices for natural gas, NGLs, and oil are primarily determined by prevailing market conditions. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets, storage capacity and other variables influence the market conditions for these products. For example, the impact of the COVID-19 outbreak has reduced domestic and international demand for natural gas, NGLs, and oil. These factors are beyond our control and are difficult to predict.

Investing Activities. Cash flows used in investing activities increased from $384 million for the nine months ended September 30, 2020 to $505 million for the nine months ended September 30, 2021, primarily due to $216 million in proceeds from the VPP and $125 million in settlement of the water earnout impacting the nine months ended September 30, 2020, partially offset by a decrease in capital expenditures of $215 million during the nine months ended September 30, 2021 as compared to the same period in 2020.

Financing Activities. Net cash flows used in financing activities increased from $108 million for the nine months ended September 30, 2020 to $679 million for the nine months ended September 30, 2021. During the nine months ended September 30, 2021, we issued $500 million aggregate principal amount of 2026 Notes, $700 million aggregate principal amount of 2029 Notes and $600 million aggregate principal amount of 2030 Notes (net of $23 million of aggregate debt issuance costs), of which proceeds were used to (i) redeem $661 million of our 2022 Notes, which were fully retired, (ii) redeem $574 million of our 2023 Notes, which were fully retired (ii) redeem $175 million of our 2026 Notes and (iv) partially repay borrowings on our Prior Credit Facility. Also, during the nine months ended September 30, 2021, we completed the January Share Offering and the May Share Offering and used the proceeds and approximately $89 million of borrowings under the Prior Credit Facility to repurchase $206 million aggregate principal amount of the 2026 Convertible Notes in privately negotiated transactions. Additionally, during the nine months ended September 30, 2021, we received a $51 million payment from Martica and distributed $65 million to the noncontrolling interest in Martica. During the nine months ended September 30, 2020, we repurchased (i) $1.1 billion principal amount of debt at a weighted average discount of 17% for $900 million of cash and (ii) $43 million of our common stock at weighted average price of $1.54 per share.

55

Debt Agreements

Senior Secured Revolving Credit Facility

Antero Resources has a senior secured revolving credit facility with a consortium of bank lenders. On October 26, 2021, Antero Resources entered into an amended and restated senior secured revolving credit facility. References to the (i) “Prior Credit Facility” refers to the senior secured revolving credit facility in effect for periods before October 26, 2021, (ii) “New Credit Facility” refers to the senior secured revolving credit facility in effect on or after October 26, 2021 and (ii) “Credit Facility” refers to Prior Credit Facility and New Credit Facility collectively. Borrowings under the New Credit Facility are subject to borrowing base limitations based on the collateral value of our assets and are subject to regular semi-annual redeterminations. As of October 26, 2021, the borrowing base was $3.5 billion and lender commitments were $1.5 billion. The next redetermination of the borrowing base is scheduled to occur in April 2022. The maturity date of the New 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 Antero’s senior notes.

As of September 30, 2021, we had $98 million borrowings and had $742 million of letters of credit outstanding under the Prior Credit Facility.

The New Credit Facility provides for borrowing under either an Adjusted Term Secured Overnight Financing Rate (“SOFR”), an Adjusted Daily Simple SOFR or an Alternate Base Rate (each as defined in the New Credit Facility).

The New Credit Facility contains restrictive covenants that may limit our ability to, among other things:

● incur additional indebtedness;

● sell assets;

● make loans to others;

● make investments;

● enter into mergers;

● pay dividends;

● hedge future production;

● incur liens; and

● engage in certain other transactions without the prior consent of the lenders.

The New Credit Facility also requires us to maintain the following financial ratios (subject to certain exceptions): The current ratio and the leverage ratio shall be tested quarterly commencing with the quarter ending December 31, 2021.

● a minimum consolidated current ratio of 1.0 to 1.0 at the end of each fiscal quarter; and

● a maximum leverage ratio of total debt to EBITDAX for the trailing four quarter period of 4.00 to 1.00 at the end of each fiscal quarter.

We were in compliance with the applicable covenants and ratios as of December 31, 2020 and September 30, 2021 under the Prior Credit Facility. As of September 30, 2021, our current ratio was 2.7 to 1.0 and our interest coverage ratio was 15.0 to 1.0.

See Note 7—Long Term Debt to the unaudited condensed consolidated financial statements included in this Quarterly Report on Form 10-Q for more information on our Credit Facility.

Senior Notes and Convertible Senior Notes

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 2020 Form 10-K for information on our senior notes.

56

Non-GAAP Financial Measures

Adjusted EBITDAX is a non-GAAP financial measure that we define as net income (loss), including noncontrolling interests, before interest expense, interest income, gains or losses from commodity derivatives, amortization of deferred revenue, gain on sale of assets but including net cash receipts or payments on derivative instruments included in derivative gains or losses other than proceeds from and payments for derivative monetizations, income taxes, impairments, depletion, depreciation, amortization, and accretion, exploration expense, equity-based compensation, gain (loss) on early extinguishment of debt, contract termination and rig stacking costs, equity in earnings (loss) of unconsolidated affiliate, transaction fees and loss on convertible note equitization.

Adjusted EBITDAX as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. Adjusted EBITDAX should not be considered in isolation or as a substitute for operating income or loss, net income or loss, cash flows provided by operating, investing, and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. Adjusted EBITDAX provides no information regarding our capital structure, borrowings, interest costs, capital expenditures, working capital movement, or tax position. Adjusted EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, exploration expenses, and other commitments and obligations. However, our management team believes Adjusted EBITDAX is useful to an investor in evaluating our financial performance because this measure:

● is widely used by investors in the oil and natural gas industry to measure operating performance without regard to items excluded from the calculation of such term, which may vary substantially from company to company depending upon accounting methods and the book value of assets, capital structure and the method by which assets were acquired, among other factors;

● helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital and legal structure from our operating structure;

● is used by our management team for various purposes, including as a measure of our operating performance, in presentations to our Board of Directors, and as a basis for strategic planning and forecasting; and

● is used by our Board of Directors as a performance measure in determining executive compensation.

There are significant limitations to using Adjusted EBITDAX as a measure of performance, including the inability to analyze the effects of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations of different companies, and the different methods of calculating Adjusted EBITDAX reported by different companies.

The following table represents a reconciliation of our net income (loss), including noncontrolling interest, to Adjusted EBITDAX and a reconciliation of our Adjusted EBITDAX to net cash provided by operating activities per our unaudited condensed consolidated statements of cash flows, in each case, for the three and nine months ended September 30, 2020 and 2021 (in thousands). Adjusted EBITDAX also excludes the noncontrolling interests in Martica and these adjustments are disclosed in the table below as Martica related adjustments.

57

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2021		2020		2021
Reconciliation of net loss to Adjusted EBITDAX:
Net loss and comprehensive loss attributable to Antero Resources Corporation	$	(535,613)		(549,318)		(1,337,727)		(1,088,284)
Net loss and comprehensive loss attributable to noncontrolling interests		(18,233)		(17,257)		(17,997)		(23,846)
Unrealized commodity derivative losses		748,791		834,334		875,811		1,774,410
Payments for (proceeds from) derivative monetizations		(18,073)		—		(18,073)		4,569
Amortization of deferred revenue, VPP		(5,175)		(11,404)		(5,175)		(33,833)
Loss on sale of assets		—		(539)		—		(2,827)
Interest expense, net		48,043		45,414		152,956		138,120
Loss (gain) on early extinguishment of debt		(55,633)		16,567		(175,365)		82,836
Loss on convertible note equitizations		—		—		—		50,777
Provision for income tax benefit		(168,778)		(158,656)		(421,167)		(337,568)
Depletion, depreciation, amortization, and accretion		239,533		183,638		655,460		567,113
Impairment of oil and gas properties		29,392		26,253		155,962		69,618
Impairment of equity method investment		—		—		610,632		—
Exploration expense		454		235		895		6,092
Equity-based compensation expense		5,699		5,298		17,001		15,189
Equity in (earnings) loss of unconsolidated affiliate		(24,419)		(21,450)		83,408		(57,621)
Dividends from unconsolidated affiliate		42,755		31,285		128,267		105,325
Contract termination and rig stacking		1,246		3,370		12,317		4,305
Transaction expense		524		626		6,662		3,102
		290,513		388,396		723,867		1,277,477
Martica related adjustments (1)		(18,072)		(30,197)		(21,172)		(80,436)
Adjusted EBITDAX	$	272,441		358,199		702,695		1,197,041
Reconciliation of our Adjusted EBITDAX to net cash provided by operating activities:
Adjusted EBITDAX	$	272,441		358,199		702,695		1,197,041
Martica related adjustments (1)		18,072		30,197		21,172		80,436
Interest expense, net		(48,043)		(45,414)		(152,956)		(138,120)
Exploration expense		(454)		(235)		(895)		(6,092)
Changes in current assets and liabilities		(80,308)		(28,316)		(78,891)		53,541
Transaction expense		(524)		(626)		(6,662)		(3,102)
Proceeds from (payments for) derivative monetizations		18,073		—		18,073		(4,569)
Other items		(3,387)		(1,125)		(10,026)		5,817
Net cash provided by operating activities	$	175,870		312,680		492,510		1,184,952

(1) Adjustments reflect noncontrolling interests in Martica not otherwise adjusted in amounts above.

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 measures of future cash flows, and impairment of proved properties. We provide an expanded discussion of our more significant accounting policies,

58

estimates and judgments in the 2020 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 2020 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, 2021, 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, 2020 and 2021.

Estimated undiscounted future net cash flows are very sensitive to commodity price swings at current commodity price levels and a relatively small 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, 2021, the fair value of our properties may be below their carrying amounts and an impairment charge may be necessary. We are unable, however, to predict future commodity prices with any reasonable certainty.

New Accounting Pronouncements

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

Off-Balance Sheet Arrangements

As of September 30, 2021, we did not have any off balance sheet arrangements other than contractual commitments for firm transportation, gas processing and fractionation, gathering, and compression services and land payment obligations. See Note 13—Commitments to the unaudited condensed consolidated financial statements for further information on off balance sheet arrangements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Commodity Hedging Activities

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

To mitigate some of the potential negative impact on our cash flows caused by changes in commodity prices, we 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, 2021, our commodity derivatives included fixed price swaps and basis differential swaps at index-based pricing.

59

As of September 30, 2021, we had in place natural gas swaps covering portions of our projected production through 2023. Our commodity hedge position as of September 30, 2021 is summarized in Note 11—Derivative Instruments to our unaudited condensed consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q. 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 and embedded put option that settled during the nine months ended September 30, 2021, our revenues would have decreased by approximately $22 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, 2021.

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 only impacted when the associated derivative contracts are settled or monetized by making or receiving payments to or from the counterparty. As of September 30, 2021, the estimated fair value of our commodity derivative instruments was a net liability of $1.7 billion comprised of current and noncurrent assets and liabilities. As of December 31, 2020, the estimated fair value of our commodity derivative instruments was a net asset of $22 million comprised of current and noncurrent assets and liabilities.

By removing price volatility from a portion of our expected production through December 2023, we have mitigated, but not eliminated, the potential negative effects of changing prices on our operating cash flows for those periods. While mitigating the negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices above the fixed hedge prices.

Counterparty and Customer Credit Risk

Our principal exposures to credit risk are through receivables resulting from the following: commodity derivative contracts ($15 million as of September 30, 2021); and the sale of our natural gas, NGLs and oil production ($556 million as of September 30, 2021), which we market to energy companies, end users, and refineries.

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 17 different counterparties, 13 of which are lenders under our Prior Credit Facility. As of September 30, 2021, we did not have any derivative assets by bank counterparties under our Prior 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, 2021 for each of the European and American banks. We believe that all of these institutions, currently, are acceptable credit risks. Other than as provided by the Prior Credit Facility, we are not required to provide credit support or collateral to any of our counterparties under our derivative contracts, nor are they required to provide credit support to us. As of September 30, 2021, we did not have any past-due receivables from, or payables to, any of the counterparties to our derivative contracts.

We are also subject to credit risk due to the concentration of our receivables from several significant customers for sales of natural gas, NGLs, and oil. We generally do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us, or their insolvency or liquidation, may adversely affect our financial results.

60

Interest Rate Risks

Our primary exposure to interest rate risk results from outstanding borrowings under the Prior Credit Facility, which has a floating interest rate. The average annualized interest rate incurred on the Prior Credit Facility during the nine months ended September 30, 2021 was approximately 4.18%. We estimate that a 1.0% increase in the applicable average interest rates for the nine months ended September 30, 2021 would have resulted in an estimated $1.5 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, 2021 at a level of reasonable assurance.

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the three months ended September 30, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

61

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 2020 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
				of Shares	Approximate
				Repurchased	Dollar Value
				as Part of	of Shares
	Total Number			Publicly	that May
	of Shares	Average Price		Announced	Yet be Purchased
Period	Purchased	Paid Per Share		Plans	Under the Plan
July 1, 2021 - July 31, 2021 (1)	241,703	$	13.12	—	$	—
August 1, 2021 - August 31, 2021	—		—	—		—
September 1, 2021 - September 30, 2021	—		—	—		—
Total	241,703	$	13.12	—	$	—

(1) The total number of shares purchased represent shares of our common stock transferred to us in order to satisfy tax withholding obligations incurred upon the vesting of restricted stock and RSUs held by our employees.

ITEM 5. OTHER INFORMATION

Amended and Restated Credit Facility

On October 26, 2021, we entered into an amendment and restatement of the Prior Credit Facility. Refer to “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Debt Agreements—Senior Secured Revolving Credit Facility” for a description of the New Credit Facility. The description of the New Credit Facility is a summary and is qualified in its entirety by the terms of the New Credit Facility. A copy of the New Credit Facility is filed as Exhibit 10.1 hereto, and is incorporated herein by reference.

62

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	Amended and Restated Bylaws of Antero Resources Corporation (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K (Commission File No. 001-36120) filed on October 17, 2013).
10.1*	Sixth Amended and Restated Credit Facility, dated as of October 26, 2021, by and among Antero Resources Corporation, as Borrower, the lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent
22.1	List of Guarantor Subsidiaries (incorporated by reference to Exhibit 22.1 to the Company’s Annual Report on Form 10-K (Commission File No. 001-36120) filed on February 17, 2021).
31.1*	Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 7241).
31.2*	Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 7241).
32.1*	Certification of the Company’s Chief Executive Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 1350).
32.2*	Certification of the Company’s Chief Financial Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 1350).
101*	The following financial information from this Quarterly Report on Form 10-Q of Antero Resources Corporation for the quarter ended September 30, 2021 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations and Comprehensive 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.

63

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 27, 2021

64