ensura

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, 2017~~March 31, 2020


☐	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)~~ (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 ~~and posted on its corporate Web site, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ 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 ~~and post~~ 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 ⌧		Accelerated ~~filer ☐~~Filer ◻
Non-accelerated ~~filer ☐~~Filer ◻		Smaller ~~reporting company~~ Reporting Company ☐
~~(Do not check if a smaller reporting company)~~ Emerging ~~growth company~~ 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 ~~315,632,497~~268,390,401 shares of common stock outstanding as of ~~October 26, 2017.~~April 24, 2020.

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TABLE OF CONTENTS

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

~~The~~Some of the information in this ~~report includes~~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. ~~When used, the words “could,~~Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” ~~“anticipate,~~“project,” ~~“intend,~~“budget,” ~~“estimate,~~“potential,” ~~“expect,~~or “continue,” ~~“project”~~ and similar expressions are ~~intended~~used to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering these forward-looking statements, ~~you~~investors should keep in mind the risk factors and other cautionary statements ~~described under the heading “Item 1A. Risk Factors”~~ in ~~our Annual~~this Quarterly Report on Form ~~10-K for~~10-Q. These forward-looking statements are based on management’s current belief, based on currently available information, as to the ~~year ended December 31, 2016 (our “2016 Form 10-K”) on file with~~outcome and timing of future events. Factors that could cause our actual results to differ materially from the ~~Securities and Exchange Commission (the “SEC”) and in “Item 1A. Risk Factors” of our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2017 and June 30, 2017.~~

~~Forward-looking~~results contemplated by such forward-looking statements ~~may include statements about our:~~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;

●

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

●

our hedging strategy and results;

●

our ability to execute our debt repurchase program and/or our asset sale program;

●

our ability to meet ~~our~~ 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 and treatment 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 ~~including the operations of its unconsolidated affiliates;~~

Corporation;

●

general economic conditions;

●

credit markets;

●

expectations regarding the amount and timing of jury awards;

●

uncertainty regarding our future operating results; and

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●

our other plans, objectives, expectations and ~~intentions.~~

intentions contained in this Quarterly Report on Form 10-Q.

We caution ~~you~~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, incident to the exploration for and development, production, gathering, processing, transportation, and sale of natural gas, NGLs, and oil.~~control. These risks include, but are not limited to, commodity price

~~Table of Contents~~

volatility, ~~and low commodity prices,~~ 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 ~~flow~~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, potential shut-ins of production due to lack of downstream demand or storage capacity, and the other risks described under the heading “Item 1A. Risk Factors” in this Quarterly Report on Form 10-Q and in our ~~2016~~Annual Report on Form 10-K for the year ended December 31, 2019 (the “2019 Form 10-K”) on file with the ~~SEC~~Securities and ~~in “Item 1A. Risk Factors” of our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2017 and June 30, 2017.~~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 in this ~~report~~Quarterly Report on Form 10-Q or the 2019 Form 10-K 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 ~~report~~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 ~~all of which are expressly qualified by the statements in this section,~~ to reflect events or circumstances after the date of this Quarterly Report on Form 10-Q.

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PART I—FINANCIAL INFORMATION

ANTERO RESOURCES CORPORATION

Condensed Consolidated Balance Sheets

December 31, ~~2016~~2019 and ~~September 30, 2017~~March 31, 2020

~~(Unaudited)~~

(In ~~thousands, except per share amounts)~~thousands)

December 31, 2016

September 30, 2017

Assets

Current assets:



Cash and cash equivalents

$
31,610

23,694

Accounts receivable, net of allowance for doubtful accounts of $1,195 and $1,320 at December 31, 2016 and September 30, 2017, respectively

29,682

43,854

Accrued revenue

261,960

233,585

Derivative instruments

73,022

299,796

Other current assets

6,313

10,024

Total current assets

402,587

610,953

Property and equipment:

Natural gas properties, at cost (successful efforts method):

Unproved properties

2,331,173

2,305,749

Proved properties

9,549,671

10,779,043

Water handling and treatment systems

744,682

891,869

Gathering systems and facilities

1,723,768

1,977,510

Other property and equipment

41,231

54,571

14,390,525

16,008,742

Less accumulated depletion, depreciation, and amortization

(2,363,778)

(2,973,544)

Property and equipment, net

12,026,747

13,035,198

Derivative instruments

1,731,063

876,293

Investments in unconsolidated affiliates

68,299

287,842

Other assets

26,854

38,928

Total assets

$
14,255,550

14,849,214

Liabilities and Equity

Current liabilities:



Accounts payable

$
38,627

47,457

Accrued liabilities

393,803

429,696

Revenue distributions payable

163,989

220,971

Derivative instruments

203,635

4,285

Other current liabilities

17,334

15,267

Total current liabilities

817,388

717,676

Long-term liabilities:

Long-term debt

4,703,973

4,510,521

Deferred income tax liability

950,217

1,180,564

Derivative instruments

234

427

Other liabilities

55,160

52,764

Total liabilities

6,526,972

6,461,952

Commitments and contingencies (notes 10 and 13)

Equity:

Stockholders' equity:

Preferred stock, $0.01 par value; authorized - 50,000 shares; none issued

—

—

Common stock, $0.01 par value; authorized - 1,000,000 shares; 314,877 shares and 315,470 shares issued and outstanding at December 31, 2016 and September 30, 2017, respectively

3,149

3,155

Additional paid-in capital

5,299,481

6,564,320

Accumulated earnings

959,995

1,088,196

Total stockholders' equity

6,262,625

7,655,671

Noncontrolling interests in consolidated subsidiary

1,465,953

731,591

Total equity

7,728,578

8,387,262

Total liabilities and equity

$
14,255,550

14,849,214


			(Unaudited)
	December 31,		March 31,
	2019		2020
Assets
Current assets:
Accounts receivable	$	46,419		91,944
Accounts receivable, related parties		125,000		—
Accrued revenue		317,886		201,320
Derivative instruments		422,849		816,444
Other current assets		10,731		10,313
Total current assets		922,885		1,120,021
Property and equipment:
Oil and gas properties, at cost (successful efforts method):
Unproved properties		1,368,854		1,289,770
Proved properties		11,859,817		12,154,162
Gathering systems and facilities		5,802		5,802
Other property and equipment		71,895		72,312
		13,306,368		13,522,046
Less accumulated depletion, depreciation, and amortization		(3,327,629)		(3,527,306)
Property and equipment, net		9,978,739		9,994,740
Operating leases right-of-use assets		2,886,500		2,814,539
Derivative instruments		333,174		284,461
Investment in unconsolidated affiliate		1,055,177		291,989
Other assets		21,094		20,039
Total assets	$	15,197,569		14,525,789

Liabilities and Equity
Current liabilities:
Accounts payable	$	14,498		37,909
Accounts payable, related parties		97,883		88,894
Accrued liabilities		400,850		367,444
Revenue distributions payable		207,988		174,654
Derivative instruments		6,721		—
Short-term lease liabilities		305,320		295,658
Other current liabilities		6,879		7,315
Total current liabilities		1,040,139		971,874
Long-term liabilities:
Long-term debt		3,758,868		3,707,787
Deferred income tax liability		781,987		672,002
Derivative instruments		3,519		215
Long-term lease liabilities		2,583,678		2,520,939
Other liabilities		58,635		60,432
Total liabilities		8,226,826		7,933,249
Commitments and contingencies (Notes 13 and 14)
Equity:
Stockholders' equity:
Preferred stock, $0.01 par value; authorized - 50,000 shares; none issued		—		—
Common stock, $0.01 par value; authorized - 1,000,000 shares; 295,941 shares and 268,926 shares issued and outstanding at December 31, 2019 and March 31, 2020, respectively		2,959		2,689
Additional paid-in capital		6,130,365		6,091,242
Accumulated earnings		837,419		498,609
Total equity		6,970,743		6,592,540
Total liabilities and equity	$	15,197,569		14,525,789

See accompanying notes to unaudited condensed consolidated financial statements.

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ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)

Three Months Ended ~~September 30, 2016~~March 31, 2019 and ~~2017~~2020

(Unaudited)

(In thousands, except per share amounts)

Three Months Ended September 30,

2016

2017

Revenue:

Natural gas sales

$
364,373

409,141

Natural gas liquids sales

106,958

224,533

Oil sales

14,793

26,527

Gathering, compression, water handling and treatment

2,969

2,869

Marketing

97,076

50,767

Commodity derivative fair value gains (losses)

530,334

(65,957)

Total revenue

1,116,503

647,880

Operating expenses:

Lease operating

13,854

23,491

Gathering, compression, processing, and transportation

234,915

282,134

Production and ad valorem taxes

15,554

22,995

Marketing

114,611

78,884

Exploration

1,166

1,599

Impairment of unproved properties

11,753

41,000

Depletion, depreciation, and amortization

199,113

206,968

Accretion of asset retirement obligations

628

658

General and administrative (including equity-based compensation expense of $26,381 and $26,447 in 2016 and 2017, respectively)

57,577

62,203

Total operating expenses

649,171

719,932

Operating income (loss)

467,332

(72,052)

Other income (expenses):

Equity in earnings of unconsolidated affiliates

1,543

7,033

Interest

(59,755)

(70,059)

Total other expenses

(58,212)

(63,026)

Income (loss) before income taxes

409,120

(135,078)

Provision for income tax (expense) benefit

(140,924)

45,078

Net income (loss) and comprehensive income (loss) including noncontrolling interests

268,196

(90,000)

Net income and comprehensive income attributable to noncontrolling interests

29,941

45,063

Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation

$
238,255

(135,063)

Earnings (loss) per common share—basic

$
0.78

(0.43)

Earnings (loss) per common share—assuming dilution

$
0.77

(0.43)

Weighted average number of shares outstanding:

Basic

306,785

315,463

Diluted

308,657

315,463


	Three Months Ended March 31,
	2019		2020
Revenue and other:
Natural gas sales	$	657,266		411,082
Natural gas liquids sales		313,685		257,673
Oil sales		48,052		35,646
Commodity derivative fair value gains (losses)		(77,368)		565,833
Gathering, compression, water handling and treatment		4,479		—
Marketing		91,186		46,073
Other income		107		798
Total revenue and other		1,037,407		1,317,105
Operating expenses:
Lease operating		41,732		25,644
Gathering, compression, processing, and transportation		424,529		588,624
Production and ad valorem taxes		35,678		25,699
Marketing		163,084		93,273
Exploration		126		210
Impairment of oil and gas properties		81,244		89,220
Impairment of midstream assets		6,982		—
Depletion, depreciation, and amortization		240,201		199,677
Accretion of asset retirement obligations		976		1,104
General and administrative (including equity-based compensation expense of $8,903 and $3,329 in 2019 and 2020, respectively)		68,202		31,221
Contract termination and rig stacking		8,360		—
Total operating expenses		1,071,114		1,054,672
Operating income (loss)		(33,707)		262,433
Other income (expenses):
Equity in earnings (loss) of unconsolidated affiliates		14,081		(128,055)
Impairment of equity investment		—		(610,632)
Gain on deconsolidation of Antero Midstream Partners LP		1,406,042		—
Interest expense, net		(71,950)		(53,102)
Gain on early extinguishment of debt		—		80,561
Total other income (expenses)		1,348,173		(711,228)
Income (loss) before income taxes		1,314,466		(448,795)
Provision for income tax (expense) benefit		(288,710)		109,985
Net income (loss) and comprehensive income (loss) including noncontrolling interests		1,025,756		(338,810)
Net income and comprehensive income attributable to noncontrolling interests		46,993		—
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$	978,763		(338,810)

Income (loss) per share—basic	$	3.17		(1.19)
Income (loss) per share—diluted	$	3.17		(1.19)

Weighted average number of shares outstanding:
Basic		308,694		284,227
Diluted		308,788		284,227

See accompanying notes to unaudited condensed consolidated financial statements.

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ANTERO RESOURCES CORPORATION

Condensed Consolidated ~~Statements~~Statement of ~~Operations and Comprehensive Income (Loss)~~Equity

~~Nine~~Three Months Ended ~~September 30, 2016 and 2017~~March 31, 2019

(Unaudited)

(In ~~thousands, except per share amounts)~~thousands)

Nine Months Ended September 30,


2016

2017

Revenue and other:



Natural gas sales

$
848,936

1,330,062

Natural gas liquids sales

274,736

590,004

Oil sales

41,712

79,999

Gathering, compression, water handling and treatment

10,107

8,665

Marketing

287,194

166,659

Commodity derivative fair value gains

125,624

458,459

Total revenue and other

1,588,309

2,633,848

Operating expenses:

Lease operating

37,190

56,034

Gathering, compression, processing, and transportation

649,713

815,710

Production and ad valorem taxes

52,296

70,341

Marketing

378,521

246,298

Exploration

3,289

5,510

Impairment of unproved properties

47,223

83,098

Depletion, depreciation, and amortization

588,057

610,879

Accretion of asset retirement obligations

1,846

1,944

General and administrative (including equity-based compensation expense of $75,667 and $78,925 in 2016 and 2017, respectively)

173,966

191,000

Total operating expenses

1,932,101

2,080,814

Operating income (loss)

(343,792)

553,034

Other income (expenses):

Equity in earnings of unconsolidated affiliates

2,027

12,887

Interest

(185,634)

(205,311)

Total other expenses

(183,607)

(192,424)

Income (loss) before income taxes

(527,399)

360,610

Provision for income tax (expense) benefit

230,755

(105,087)

Net income (loss) and comprehensive income (loss) including noncontrolling interests

(296,644)

255,523

Net income and comprehensive income attributable to noncontrolling interests

66,400

127,322

Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation

$
(363,044)

128,201

Earnings (loss) per common share—basic

$
(1.26)

0.41

Earnings (loss) per common share—assuming dilution

$
(1.26)

0.41

Weighted average number of shares outstanding:

Basic

288,607

315,275

Diluted

288,607

316,140


					Additional
	Common Stock				paid-in		Accumulated		Noncontrolling		Total
	Shares		Amount		capital		earnings		interests		equity
Balances, December 31, 2018		308,594	$	3,086		6,485,174		1,177,548		821,669		8,487,477
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		147		1		(451)		—		—		(450)
Issuance of common units in Antero Midstream Partners LP upon vesting of equity-based compensation awards, net of units withheld for income taxes		—		—		(85)		—		56		(29)
Equity-based compensation		—		—		7,801		—		1,102		8,903
Net income and comprehensive income		—		—		—		978,763		46,993		1,025,756
Distributions to noncontrolling interests		—		—		—		—		(85,076)		(85,076)
Effect of deconsolidation of Antero Midstream Partners LP		—		—		(359,039)		—		(784,744)		(1,143,783)
Balances, March 31, 2019		308,741	$	3,087		6,133,400		2,156,311		—		8,292,798

See accompanying notes to unaudited condensed consolidated financial statements.

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ANTERO RESOURCES CORPORATION

Condensed Consolidated ~~Statements~~Statement of Equity

~~Nine~~Three Months Ended ~~September 30, 2017~~March 31, 2020

(Unaudited)

(In thousands)

Common Stock

Additional paid-

Accumulated

Noncontrolling

Total


Shares

Amount

in capital

earnings

interests

equity

Balances, December 31, 2016

314,877

$
3,149

5,299,481

959,995

1,465,953

7,728,578

Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes

593

6

(7,574)

—

—

(7,568)

Issuance of common units by Antero Midstream Partners LP, net of underwriter discounts and offering costs

—

—

—

—

248,949

248,949

Issuance of common units in Antero Midstream Partners LP upon vesting of equity-based compensation awards, net of units withheld for income taxes

—

—

(1,559)

—

627

(932)

Sale of common units of Antero Midstream Partners LP held by Antero Resources Corporation, net of tax

—

—

205,780

—

(19,940)

185,840

Equity-based compensation

—

—

71,786

—

7,139

78,925

Net income and comprehensive income

—

—

—

128,201

127,322

255,523

Effects of changes in ownership interests in consolidated subsidiaries

—

—

996,406

—

(996,406)

—

Distributions to noncontrolling interests

—

—

—

—

(102,053)

(102,053)

Balances, September 30, 2017

315,470

$
3,155

6,564,320

1,088,196

731,591

8,387,262


					Additional
	Common Stock				paid-in		Accumulated		Total
	Shares		Amount		capital		earnings		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

See accompanying notes to unaudited condensed consolidated financial statements.

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ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Cash Flows

~~Nine~~Three Months Ended ~~September 30, 2016~~March 31, 2019 and ~~2017~~2020

(Unaudited)

(In thousands)

Nine Months Ended September 30,


2016

2017

Cash flows from operating activities:



Net income (loss) including noncontrolling interests

$
(296,644)

255,523

Adjustment to reconcile net income (loss) to net cash provided by operating activities:

Depletion, depreciation, amortization, and accretion

589,903

612,823

Impairment of unproved properties

47,223

83,098

Derivative fair value gains

(125,624)

(458,459)

Gains on settled derivatives

813,559

137,392

Proceeds from derivative monetizations

—

749,906

Deferred income tax expense (benefit)

(230,755)

105,087

Equity-based compensation expense

75,667

78,925

Equity in earnings of unconsolidated affiliates

(2,027)

(12,887)

Distributions of earnings from unconsolidated affiliates

—

10,120

Other

(1,544)

1,191

Changes in current assets and liabilities:

Accounts receivable

10,077

1,771

Accrued revenue

(68,248)

28,375

Other current assets

4,685

(3,836)

Accounts payable

5,683

4,731

Accrued liabilities

41,386

43,043

Revenue distributions payable

42,253

56,982

Other current liabilities

103

(977)

Net cash provided by operating activities

905,697

1,692,808

Cash flows used in investing activities:

Additions to proved properties

(64,789)

(179,318)

Additions to unproved properties

(559,572)

(182,207)

Drilling and completion costs

(1,009,851)

(946,508)

Additions to water handling and treatment systems

(137,355)

(143,470)

Additions to gathering systems and facilities

(154,136)

(254,619)

Additions to other property and equipment

(1,747)

(11,417)

Investments in unconsolidated affiliates

(45,044)

(216,776)

Change in other assets

(2,173)

(16,148)

Other

—

2,156

Net cash used in investing activities

(1,974,667)

(1,948,307)

Cash flows from financing activities:

Issuance of common stock

837,414

—

Issuance of common units by Antero Midstream Partners LP

19,605

248,949

Proceeds from sale of common units of Antero Midstream Partners LP held by Antero Resources Corporation

178,000

311,100

Issuance of senior notes

650,000

—

Repayments on bank credit facilities, net

(552,000)

(198,000)

Payments of deferred financing costs

(9,029)

—

Distributions to noncontrolling interests in consolidated subsidiary

(51,238)

(102,053)

Employee tax withholding for settlement of equity compensation awards

(4,876)

(8,500)

Other

(3,867)

(3,913)

Net cash provided by financing activities

1,064,009

247,583

Net decrease in cash and cash equivalents

(4,961)

(7,916)

Cash and cash equivalents, beginning of period

23,473

31,610

Cash and cash equivalents, end of period

$
18,512

23,694

Supplemental disclosure of cash flow information:

Cash paid during the period for interest

$
132,928

174,324

Supplemental disclosure of noncash investing activities:

Decrease in accounts payable and accrued liabilities for additions to property and equipment

$
(189,234)

(3,084)


	Three Months Ended March 31,
	2019		2020
Cash flows provided by (used in) operating activities:
Net income (loss) including noncontrolling interests	$	1,025,756		(338,810)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, amortization, and accretion		241,177		200,781
Impairment of oil and gas properties		81,244		89,220
Impairment of midstream assets		6,982		—
Commodity derivative fair value (gains) losses		77,368		(565,833)
Gains on settled commodity derivatives		97,092		210,926
Equity-based compensation expense		8,903		3,329
Deferred income tax expense (benefit)		287,854		(109,985)
Gain on early extinguishment of debt		—		(80,561)
Equity in (earnings) loss of unconsolidated affiliates		(14,081)		128,055
Impairment of equity investment		—		610,632
Gain on deconsolidation of Antero Midstream Partners LP		(1,406,042)		—
Distributions/dividends of earnings from unconsolidated affiliates		12,605		42,756
Other		11,081		2,440
Changes in current assets and liabilities:
Accounts receivable		42,168		(54,514)
Accrued revenue		109,677		116,566
Other current assets		1,364		(583)
Accounts payable including related parties		(21,370)		(1,251)
Accrued liabilities		(14,965)		(19,593)
Revenue distributions payable		(9,761)		(33,333)
Other current liabilities		1,952		435
Net cash provided by operating activities		539,004		200,677
Cash flows provided by (used in) investing activities:
Additions to unproved properties		(27,463)		(10,357)
Drilling and completion costs		(368,687)		(300,483)
Additions to water handling and treatment systems		(24,416)		—
Additions to gathering systems and facilities		(48,239)		—
Additions to other property and equipment		(3,128)		(771)
Settlement of water earnout		—		125,000
Investments in unconsolidated affiliates		(25,020)		—
Proceeds from the Antero Midstream Partners LP Transactions		296,611		—
Change in other assets		(4,475)		(70)
Net cash used in investing activities		(204,817)		(186,681)
Cash flows provided by (used in) financing activities:
Repurchases of common stock		—		(42,690)
Issuance of senior notes		650,000		—
Repayment of senior notes		—		(300,835)
Borrowings (repayments) on bank credit facilities, net		(270,000)		330,000
Payments of deferred financing costs		(8,259)		—
Distributions to noncontrolling interests in Antero Midstream Partners LP		(85,076)		—
Employee tax withholding for settlement of equity compensation awards		(479)		(32)
Other		(841)		(439)
Net cash provided by (used in) financing activities		285,345		(13,996)
Effect of deconsolidation of Antero Midstream Partners LP		(619,532)		—
Net decrease in cash and cash equivalents		—		—
Cash and cash equivalents, beginning of period		—		—
Cash and cash equivalents, end of period	$	—		—

Supplemental disclosure of cash flow information:
Cash paid during the period for interest	$	37,081		30,089
Increase (decrease) in accounts payable and accrued liabilities for additions to property and equipment	$	(22,825)		10,767

See accompanying notes to unaudited condensed consolidated financial statements.

Table of Contents

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, ~~2016~~2019 and ~~September 30, 2017~~March 31, 2020

(1) Organization

~~(1)Organization~~

Antero Resources Corporation (individually referred to as “Antero” ~~or the “Parent”~~) and its consolidated subsidiaries (collectively referred to as “Antero Resources,” the ~~“Company”~~“Company,” “we,” “us” or “our”) are engaged in the exploration, development, 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. Through its consolidated subsidiary, Antero Midstream Partners LP, a publicly-traded limited partnership (“Antero Midstream”), the Company has gathering and compression, as well as water handling and treatment, operations in the Appalachian Basin. The Company’s corporate headquarters are located in Denver, Colorado.

(2)Summary of Significant Accounting Policies

~~(a)Basis of Presentation~~

(a)
Basis of Presentation

These unaudited condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the ~~SEC~~Securities and Exchange Commission (the “SEC”) applicable to interim financial information and should be read in the context of the Company’s December 31, ~~2016~~2019 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, ~~2016~~2019 consolidated financial statements ~~have been~~were included in Antero Resources’ 2019 Annual Report on Form 10-K, which was filed with the ~~Securities and Exchange Commission (“SEC”) in the Company’s 2016 Form 10-K.~~SEC.

~~The accompanying~~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, ~~the accompanying~~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, ~~2016~~2019 and ~~September 30, 2017,~~March 31, 2020, and the results of its operations ~~for the three and nine months ended September 30, 2016 and 2017,~~ and its cash flows for the ~~nine~~three months ended ~~September 30, 2016~~March 31, 2019 and ~~2017.~~2020. The Company has no items of other comprehensive income or loss; therefore, its net income or loss is ~~identical~~equal to its comprehensive income or loss. Operating results for the period ended ~~September 30, 2017~~March 31, 2020 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. The Company’s statement of cash flows for the nine months ended September 30, 2016 includes reclassifications within current liabilities that were made to conform to the nine months ended September 30, 2017 presentation.

(b)

Principles of Consolidation

~~The Company’s exploration and production activities are accounted for under the successful efforts method.~~

As of the date these financial statements were filed with the SEC, the Company completed its evaluation of potential subsequent events for disclosure and no items requiring disclosure were identified except for the amended and restated credit facilities entered into by Antero and Antero Midstream in October 2017. See note 5 for descriptions of the amended and restated facilies.

~~(b)Principles of Consolidation~~

The accompanying unaudited condensed consolidated financial statements include the accounts of Antero Resources Corporation, its ~~wholly-owned~~wholly owned subsidiaries, any entities in which the Company owns a controlling interest, and variable interest entities (“VIEs”) for which the Company is the primary beneficiary.

~~We have determined that~~Through March 12, 2019, Antero Midstream isPartners LP (“Antero Midstream Partners”), a ~~VIE for which Antero is the primary beneficiary. Therefore, Antero Midstream’s accounts are~~publicly traded limited partnership, was included in the ~~Company’s~~consolidated financial statements of Antero. Prior to the Closing (defined in Note 3 to the unaudited condensed consolidated financial ~~statements. Antero is the primary beneficiary~~statements), our ownership of Antero Midstream based on its power to direct the activities that most significantly impact Antero Midstream’s economic performance, and its obligation to absorb losses or right to receive benefits of Antero Midstream that could be significant to Antero Midstream.

~~Antero Midstream was formed to own, operate, and develop midstream energy assets to service Antero’s production under long-term service contracts. Antero owned 53.0% of the outstanding~~Partners common units represented approximately a 53% limited partner ~~interests in Antero Midstream at September 30, 2017. Antero Midstream GP LP (“AMGP”) indirectly controls the general partnership~~ interest in Antero Midstream ~~as well as~~Partners, and we consolidated Antero ~~IDR~~

~~Table~~Midstream Partners’ financial position and results of ~~Contents~~

~~ANTERO RESOURCES CORPORATION~~

~~Notes~~operations into our consolidated financial statements. The Transactions (defined in Note 3 to ~~Condensed Consolidated Financial Statements~~

~~December 31, 2016 and September 30, 2017~~

~~Holdings LLC (“IDR LLC”), which owns~~ the ~~incentive distribution rights~~unaudited condensed consolidated financial statements) resulted in the exchange of the limited partner interest we owned in Antero ~~Midstream. AMGP has not provided, and is not expected to provide, financial support to Antero Midstream. Antero’s officers and management group also act as management~~Midstream Partners for common stock of Antero Midstream ~~and AMGP.~~

~~Antero and~~Corporation, par value $0.01 per share (the “Antero Midstream Corporation common stock”), representing an approximate 31% interest in Antero Midstream have contracts with 20-year initial terms and automatic renewal provisions, whereby Antero has dedicated the rights for gathering and compression, and water delivery and handling, services to Antero Midstream on a fixed-fee basis. Such dedications cover a substantial portion of Antero’s current acreage and future acquired acreage, in each case, except for acreage that was already dedicated to other parties prior to entering into the service contracts or that was acquired subject to a pre-existing dedication. The contracts call for Antero to present, in advance, its drilling and completion plans in order for Antero Midstream to develop gathering and compression and water delivery and handling assets to service Antero’s operations. Consequently, the drilling and completion capital investment decisions made by Antero control the development and operation of all of Antero Midstream’s assets. Because of these contractual obligations and the capital requirements related to these obligations, Antero Midstream has and, for the foreseeable future, will devote substantially all of its resources to servicing Antero’s operations. Additionally, revenues from Antero provide substantially all of Antero Midstream’s financial support and, therefore, its ability to finance its operations.Corporation. As a result, ~~of the long-term contractual commitment to support Antero’s substantial growth plans,~~our controlling interest in Antero Midstream ~~will be practically and physically constrained from providing any substantive amount of services~~Partners was converted to ~~third-parties. Therefore,~~an interest in Antero ~~controls the activities~~Midstream Corporation that ~~most significantly impact Antero Midstream’s economic performance. Antero does~~provides significant influence, but not control, ~~AMGP~~over Antero Midstream Corporation. Thus, effective March 13, 2019, Antero no longer consolidates Antero Midstream Partners in its consolidated financial statements and ~~does not have any investment~~accounts for its interest in ~~AMGP.~~Antero Midstream Corporation using the equity method of accounting. See Note 3 to the unaudited condensed consolidated financial statements for further discussion on the Transactions.

All significant intercompany accounts and transactions have been eliminated in the Company’s unaudited condensed consolidated financial statements. ~~Noncontrolling~~The noncontrolling interest in the Company’s unaudited condensed consolidated financial statements for the three months ended March 31, 2019 represents the interests in Antero Midstream ~~which are~~Partners that were owned by the public prior to the Transactions, and the ~~holder of Antero Midstream’s~~ incentive distribution ~~rights. Noncontrolling interests~~rights in ~~consolidated subsidiaries is included as a component~~Antero Midstream Partners.

Table of ~~equity in the Company’s condensed consolidated balance sheets.~~Contents

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and March 31, 2020

Investments in entities for which the Company exercises significant influence, but not control, are accounted for under the equity method. The Company’s judgment regarding the level of influence over its equity investments includes considering key factors such as Antero’s ownership interest, representation on the board of directors and participation in the policy-making decisions of equity method investees. Such investments are included in ~~Investments~~Investment in unconsolidated ~~affiliates~~affiliate on the Company’s unaudited condensed consolidated balance sheets. Income (loss) from investees that are accounted for under the equity method is included in Equity in earnings (loss) of unconsolidated affiliates on the Company’s unaudited condensed consolidated statements of operations and cash flows. When Antero records its proportionate share of net income or net loss, it is recorded in equity in earnings (loss) of unconsolidated affiliates in the statements of operations and the carrying value of that investment on the Company’s balance sheet. When a distribution is received, it is recorded as a reduction to the carrying value of that investment on the Company’s balance sheet. The Company’s equity in earnings of unconsolidated affiliates is adjusted for intercompany transactions and the basis differences recognized due to the difference between the cost of the equity investment in Antero Midstream Corporation and the amount of underlying equity in the net assets of Antero Midstream Partners as of the date of deconsolidation.

~~(c)Use~~The Company accounts for distributions received from equity method investees under the “nature of ~~Estimates~~the distribution” approach. Under this approach, distributions received from equity method investees are classified on the basis of the nature of the activity or activities of the investee that generated the distribution as either a return on investment, which is classified as cash inflows from operating activities, or a return of investment, which is classified as cash inflows from investing activities.

(c)

Use of Estimates

The preparation of the unaudited condensed consolidated financial statements in conformity with GAAP requires ~~that~~ management ~~formulate~~to make estimates and assumptions ~~which~~that affect revenues, expenses, assets, ~~and~~ liabilities ~~as well as~~and the disclosure of contingent assets and liabilities. Changes in facts and circumstances or discovery of new information may result in revised estimates, and actual results could differ from those estimates.

The Company’s unaudited condensed consolidated financial statements are based on a number of significant estimates, including estimates of natural gas, NGLs, and oil reserve quantities, which are the basis for the calculation of depletion and impairment of oil and gas properties. Reserve estimates, by their nature, are inherently imprecise. Other items in the Company’s unaudited condensed consolidated financial statements ~~which~~that involve the use of significant estimates include derivative assets and liabilities, accrued revenue, deferred and current income taxes, equity-based compensation, asset retirement obligations, depreciation, amortization, and commitments and contingencies.

(d)

Risks and Uncertainties

~~(d)Risks and Uncertainties~~

~~Historically, the~~The markets for natural gas, NGLs, and oil have, ~~experienced~~and continue to, experience significant price fluctuations. Price fluctuations can result from variations in weather, levels of production, availability of storage capacity and transportation ~~capacity~~ to other regions of the country, the level of imports to and exports from the United States, and various other factors. Increases or decreases in the prices the Company receives for its production could have a significant impact on the Company’s future results of operations and reserve quantities.

(e)

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 unaudited condensed consolidated balance sheets, and classifies the change in accounts payable and revenue distributions payable associated with book overdrafts as an operating activity within its unaudited condensed consolidated statements of cash flows. As of December 31, 2019, the book overdraft included within accounts payable and revenue distributions payable were $7 million and $18 million, respectively. As of March 31, 2020, the book overdraft included within accounts payable and revenue distributions payable were $5 million and $21 million, respectively.

Table of Contents

ANTERO RESOURCES CORPORATION

~~(e)Derivative~~Notes to Unaudited Condensed Consolidated Financial ~~Instruments~~Statements

December 31, 2019 and March 31, 2020

(f)

Oil and Gas Properties

The Company accounts for its natural gas, NGLs, and oil exploration and development activities under the successful efforts method of accounting. Under the successful efforts method, the costs incurred to acquire, drill, and complete productive wells, development wells, and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel and other internal costs, geological and geophysical expenses, delay rentals for gas and oil leases, and costs associated with unsuccessful lease acquisitions are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if the Company determines that the well does not contain reserves in commercially viable quantities. The Company reviews exploration costs related to wells-in-progress at the end of each quarter and makes a determination, based on known results of drilling at that time, whether the costs should continue to be capitalized pending further well testing and results, or charged to expense. The Company incurred 0 such charges to expense during the three months ended March 31, 2019 and 2020. The sale of a partial interest in a proved property is accounted for as a cost recovery, and no gain or loss is recognized as long as this treatment does not significantly affect the units-of-production amortization rate. A gain or loss is recognized for all other sales of producing properties.

Unproved properties are assessed for impairment on a property-by-property basis, and any impairment in value is charged to expense. Impairment is assessed based on remaining lease terms, commodity price outlooks, and future plans to develop acreage, as well as drilling results, and reservoir performance of wells in the area. Unproved properties and the related costs are transferred to proved properties when reserves are discovered on, or otherwise attributed to, the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of cost without recognition of any gain or loss until the cost has been recovered. Impairment of oil and gas properties was $81 million and $89 million for the three months ended March 31, 2019 and 2020, respectively.

The Company evaluates the carrying amount of its proved natural gas, NGLs, and oil properties for impairment on a geological reservoir basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company would estimate the fair value of its properties and record an impairment charge for any excess of the carrying amount of the properties over the estimated fair value of the properties. Factors used to estimate fair value may include estimates of proved reserves, estimated future commodity prices, future production estimates, and anticipated capital expenditures, using a commensurate discount rate.

(g)

Derivative Financial Instruments

In order to manage its exposure to natural gas, NGLs, and oil price volatility, the Company enters into derivative transactions from time to time, which may include commodity swap agreements, basis swap agreements, collar agreements, and other similar

~~Table of Contents~~

~~ANTERO RESOURCES CORPORATION~~

~~Notes to Condensed Consolidated Financial Statements~~

~~December 31, 2016 and September 30, 2017~~

agreements related to the price risk associated with the Company’s production. To the extent legal right of offset exists with a counterparty, the Company reports derivative assets and liabilities on a net basis. The Company has exposure to credit risk to the extent that the counterparty is unable to satisfy its settlement obligations. The Company actively monitors the creditworthiness of counterparties and assesses the impact, if any, on its derivative ~~position.~~positions.

The Company records derivative instruments on the unaudited condensed consolidated balance sheets as either assets or liabilities measured at fair value and records changes in the fair value of derivatives in current earnings as they occur. Changes in the fair value of commodity derivatives, including gains or losses on settled derivatives, are classified as revenues on the Company’s unaudited condensed consolidated statements of operations. The Company’s derivatives have not been designated as hedges for accounting purposes.

(h)

Asset Retirement Obligations

The Company is obligated to dispose of certain long-lived assets upon their abandonment. The Company’s asset retirement obligations (“AROs”) relate primarily to its obligation to plug and abandon oil and gas wells at the end of their lives. AROs are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations, which is then discounted at the Company’s credit-adjusted, risk-free interest rate. Revisions to estimated AROs often result from changes in retirement cost estimates or changes in the estimated timing of abandonment. The fair value of the liability is added to the carrying amount of the associated asset, and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense.

Table of Contents

ANTERO RESOURCES CORPORATION

~~(f)Industry Segments~~Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and ~~Geographic Information~~March 31, 2020

(i)

Natural Gas, NGLs, and Oil Revenues

Our revenues are primarily derived from the sale of natural gas and oil production, as well as the sale of NGLs that are extracted from our natural gas. Sales of natural gas, NGLs, and oil are recognized when we satisfy a performance obligation by transferring control of a product to a customer. Payment is generally received in the month following the sale.

Under our natural gas sales contracts, we deliver natural gas to the purchaser at an agreed upon delivery point. Natural gas is transported from our wellheads to delivery points specified under sales contracts. To deliver natural gas to these points, Antero Midstream Corporation or other third parties gather, compress, process and transport our natural gas. We maintain control of the natural gas during gathering, compression, processing, and transportation. Our sales contracts provide that we receive a specific index price adjusted for pricing differentials. We transfer control of the product at the delivery point and recognize revenue based on the contract price. The costs incurred to gather, compress, process and transport natural gas are recorded as Gathering, compression, processing and transportation expense.

NGLs, which are extracted from natural gas through processing, are either sold by us directly or by the processor under processing contracts. For NGLs sold by us directly, our sales contracts provide that we deliver the product to the purchaser at an agreed upon delivery point and that we receive a specific index price adjusted for pricing differentials. We transfer control of the product to the purchaser at the delivery point and recognize revenue based on the contract price. The costs incurred to process and transport NGLs are recorded as Gathering, compression, processing, and transportation expense. For NGLs sold by the processor, our processing contracts provide that we transfer control to the processor at the tailgate of the processing plant and we recognize revenue based on the price received from the processor.

Under our oil sales contracts, we generally sell oil to purchasers and collect a contractually agreed upon index price, net of pricing differentials. We recognize revenue based on the contract price when we transfer control of the product to a purchaser. When applicable, the costs incurred to transport oil to a purchaser are recorded as Gathering, compression, processing and transportation expense.

(j)

Marketing Revenues and Expenses

Marketing revenues are derived from activities to purchase and sell third-party natural gas and NGLs and to market excess firm transportation capacity to third parties. We retain control of the purchased natural gas and NGLs prior to delivery to the purchaser. We have concluded that we are the principal in these arrangements and therefore we recognize revenue on a gross basis, with costs to purchase and transport natural gas and NGLs presented as marketing expenses. Contracts to sell third party gas and NGLs are generally subject to similar terms as contracts to sell our produced natural gas and NGLs. We satisfy performance obligations to the purchaser by transferring control of the product at the delivery point and recognize revenue based on the contract price received from the purchaser. Fees generated from the sale of excess firm transportation marketed to third parties are included in Marketing revenue.

Marketing expenses include the cost of purchased third-party natural gas and NGLs. The Company classifies firm transportation costs related to capacity contracted for in advance of having sufficient production and infrastructure to fully utilize the capacity (excess capacity) as marketing expenses since it is marketing this excess capacity to third parties. Firm transportation for which the Company has sufficient production capacity (even though it may not use the transportation capacity because of alternative delivery points with more favorable pricing) is considered unutilized capacity and is charged to transportation expense.

(k)

Gathering, compression, water handling and treatment revenue

Substantially all revenues from the gathering, compression, water handling and treatment operations were derived from transactions for services Antero Midstream Partners provided to our exploration and production operations through March 12, 2019 and were eliminated in consolidation. Effective March 13, 2019, Antero Midstream Partners is no longer consolidated in Antero’s results. See Note 3 to the consolidated financial statements for further discussion on the Transactions and Note 17 to the consolidated financial statements for disclosures on the Company’s reportable segments. The portion of such fees shown in our consolidated financial statements prior to March 13, 2019 represent amounts charged to interest owners in Antero-operated wells, as well as fees charged to other third parties for water handling and treatment services provided by Antero Midstream Partners or usage of Antero Midstream Partners’ gathering and compression systems. For gathering and compression revenue, Antero Midstream Partners

Table of Contents

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and March 31, 2020

satisfied its performance obligations and recognized revenue when low pressure volumes were delivered to a compressor station, high pressure volumes were delivered to a processing plant or transmission pipeline, and compression volumes were delivered to a high pressure line. Revenue was recognized based on the per Mcf gathering or compression fee charged by Antero Midstream Partners in accordance with the gathering and compression agreement. For water handling and treatment revenue, Antero Midstream Partners satisfied its performance obligations and recognized revenue when the fresh water volumes were delivered to the hydration unit of a specified well pad and the wastewater volumes were delivered to its wastewater treatment facility. For services contracted through third-party providers, Antero Midstream Partners’ performance obligation was satisfied when the services performed by the third-party providers were completed. Revenue was recognized based on the per barrel fresh water delivery or wastewater treatment fee charged by Antero Midstream Partners in accordance with the water services agreement.

(l)

Industry Segments and Geographic Information

Management has evaluated how the Company is organized and managed and has identified the following segments: (1) the exploration, development, and production of natural gas, NGLs, and oil; (2) ~~gathering~~marketing and ~~processing; (3) water handling and treatment; and (4) marketing~~utilization of excess firm transportation ~~capacity.~~capacity; and (3) our equity method investment in Antero Midstream Corporation. Through March 12, 2019, the results of Antero Midstream Partners were included in the consolidated financial statements of Antero. Effective March 13, 2019, the results of Antero Midstream Partners are no longer consolidated in Antero’s results; however, the Company’s segment disclosures include our equity method investment in Antero Midstream Corporation due to its significance to the Company’s operations. See Note 3 to the unaudited condensed consolidated financial statements for further discussion on the Transactions and Note 17 to the unaudited condensed consolidated financial statements for disclosures on the Company’s reportable segments.

All of the Company’s assets are located in the United States and substantially all of its production revenues are attributable to customers located in the United ~~States.~~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.

~~(g)~~(m) Earnings ~~(Loss) per~~(loss) Per Common Share

Earnings (loss) per common ~~share~~—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—assuming dilution for each period is computed after giving consideration to the potential dilution from outstanding equity awards, calculated using the treasury stock method. The Company includes performance share unit awards 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 ~~such~~the awards. During periods in which the Company incurs a net loss, diluted weighted average shares outstanding are equal to basic weighted average shares outstanding because the effect of all equity awards is ~~antidilutive.~~ anti-dilutive.

Table of Contents

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and March 31, 2020

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 March 31,
	2019	2020
Basic weighted average number of shares outstanding	308,694	284,227
Add: Dilutive effect of restricted stock units	80	—
Add: Dilutive effect of outstanding stock options	—	—
Add: Dilutive effect of performance stock units	14	—
Diluted weighted average number of shares outstanding	308,788	284,227

Weighted average number of outstanding equity awards excluded from calculation of diluted earnings per common share ⁽¹⁾:
Restricted stock units	1,445	5,952
Outstanding stock options	570	459
Performance stock units	1,721	1,621

Three Months Ended September 30,

Nine Months Ended September 30,

2016

2017

2016

2017

Basic weighted average number of shares outstanding

306,785

315,463

288,607

315,275

Add: Dilutive effect of non-vested restricted stock units

1,835

—

—

828

Add: Dilutive effect of outstanding stock options

—

—

—

—

Add: Dilutive effect of performance stock units

37

—

—

37

Diluted weighted average number of shares outstanding

308,657

315,463

288,607

316,140

Weighted average number of outstanding equity awards excluded from calculation of diluted earnings per common share(1):

Non-vested restricted stock and restricted stock units

1,251

5,054

6,899

2,293

Outstanding stock options

693

674

706

679

Performance stock units

660

1,293

577

1,002

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

(n)

Treasury Share Retirement

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

~~(h)Cash and Cash Equivalents~~

The Company ~~considers all liquid investments purchased with an initial maturity~~retires treasury shares acquired through share repurchases and returns those shares to the status of ~~three months or less~~authorized but unissued. When treasury shares are retired, the Company’s policy is to allocate the excess of the repurchase price over the par value of shares acquired first, to additional paid-in capital, and then to accumulated earnings. The portion allocable to additional paid-in capital is determined by applying a percentage, determined by dividing the number of shares to be ~~cash equivalents. The carrying value~~retired by the number of ~~cash and cash equivalents approximates fair value due~~shares outstanding, to the ~~short term nature~~balance of ~~these instruments. From time to time, the Company may be in the position~~additional paid-in capital as of ~~a “book overdraft” in which outstanding checks exceed cash and cash equivalents.~~ retirement.

~~Table~~(3) Deconsolidation of ~~Contents~~

~~ANTERO RESOURCES CORPORATION~~

~~Notes to Condensed Consolidated Financial Statements~~

~~December 31, 2016 and September 30, 2017~~

The Company classifies book overdrafts within accounts payable within its condensed consolidated balance sheets, and classifies the change in accounts payable associated with book overdrafts as an operating activity within its condensed consolidated statements of cash flows.

~~(i)Income Taxes~~

For the three and nine months ended September 30, 2016 and 2017, respectively, the Company’s overall effective tax rate was different than the statutory rate of 35% primarily due to the effects of noncontrolling interest income, state tax rates, and permanent differences on vested equity compensation awards.

~~(3)~~Antero Midstream Partners LP

~~In 2014, the Company formed~~On March 12, 2019, Antero Midstream ~~to own, operate,~~GP LP and develop midstream energy assets that service Antero’s production. Antero Midstream’s assets consist of gathering systems and facilities, water handling and treatment facilities, and interests in processing and fractionation plants, through which it provides services to Antero under long-term, fixed-fee contracts. AMGP indirectly owns the general partnership interest in Antero Midstream Partners completed (the “Closing”) the transactions contemplated by the Simplification Agreement (the “Simplification Agreement”), dated as of October 9, 2018, by and ~~directly owns capital interests in IDR LLC, which owns the incentive distribution rights in Antero Midstream.~~among Antero Midstream ~~is an unrestricted subsidiary as defined by Antero’s senior secured revolving bank credit facility (the “Credit Facility”). As an unrestricted subsidiary,~~GP LP, Antero Midstream Partners and certain of their affiliates, pursuant to which (i) Antero Midstream GP LP was converted from a limited partnership to a corporation under the laws of the State of Delaware and changed its ~~subsidiaries are not guarantors of Antero’s obligations, and Antero is not a guarantor of Antero Midstream’s obligations (see Note 12).~~

~~In connection with Antero’s contribution of its water handling and treatment assets~~name to Antero Midstream ~~in September 2015, Antero Midstream agreed to pay Antero (a) $125 million in cash if Antero Midstream delivers 176,295,000 barrels or more of fresh water during the period between January 1, 2017~~Corporation, and ~~December 31, 2019 and (b)~~(ii) an ~~additional $125 million in cash if Antero Midstream delivers 219,200,000 barrels or more of fresh water during the period between January 1, 2018 and December 31, 2020.~~

Antero Midstream has an Equity Distribution Agreement (the “Distribution Agreement”) pursuant to which Antero Midstream may sell, from time to time through brokers acting as its sales agents, common units representing limited partner interests having an aggregate offering price of up to $250 million. Sales of the common units are made by means of ordinary brokers’ transactions on the New York Stock Exchange, at market prices, in block transactions, or as otherwise agreed to between Antero Midstream and the sales agents. Proceeds are used for general partnership purposes, which may include repayment of indebtedness and funding working capital or capital expenditures. Antero Midstream is under no obligation to offer and sell common units under the Distribution Agreement.

During the nine months ended September 30, 2017, Antero Midstream issued and sold 777,262 common units under the Distribution Agreement, resulting in net proceeds of $25.5 million after deducting commissions and other offering costs. As of September 30, 2017, Antero Midstream had the capacity to issue additional common units under the Distribution Agreement up to an aggregate sales price of $157.3 million.

On May 26, 2016, Antero Midstream purchased a 15% equity interest in a regional gathering pipeline. This investment is accounted for under the equity method, and had a carrying amount of $67.5 million at September 30, 2017. Antero Midstream’s equity share of the pipeline’s earnings was $7.7 million during the nine months ended September 30, 2017.

~~On February 6, 2017, Antero Midstream formed a joint venture (the “Joint Venture”) to develop processing assets in Appalachia with MarkWest Energy Partners, L.P. (“MarkWest”), a~~indirect, wholly owned subsidiary of ~~MPLX, L.P.~~ Antero Midstream Corporation was merged with and ~~MarkWest each own a 50% equity interest in~~into Antero Midstream Partners, with Antero Midstream Partners surviving the ~~Joint Venture and MarkWest operates the Joint Venture assets. The Joint Venture assets consist~~merger as an indirect, wholly owned subsidiary of processing plants in West Virginia and a one-third interest in a recently commissioned MarkWest fractionator in Ohio. The Joint Venture is accounted for under the equity method, and had a carrying amount of $220.3 million at September 30, 2017. Antero ~~Midstream’s equity share of the Joint Venture’s earnings was $5.2 million during the nine months ended September 30, 2017.~~

~~In conjunction~~Midstream Corporation (together, along with the ~~formation~~other transactions contemplated by the Simplification Agreement, the “Transactions”). In connection with the Closing, Antero received $297 million in cash and 158.4 million shares of ~~the Joint Venture, on February 10, 2017,~~ Antero Midstream ~~issued 6,900,000~~Corporation common units, including common units issued pursuant to the underwriters’ option to purchase additional common units, generating net proceeds of approximately $223 million. Antero Midstream used the net proceeds to fund the initial contribution to the Joint Venture, repay outstanding borrowings under its credit facility, dated as of November 10, 2014 (the “Prior Midstream Facility”), andstock in consideration for ~~general partnership purposes.~~

~~Table of Contents~~

~~ANTERO RESOURCES CORPORATION~~

~~Notes to Condensed Consolidated Financial Statements~~

~~December 31, 2016 and September 30, 2017~~

~~On September 11, 2017, Antero sold 10,000,000~~98,870,335 common units representing limited partnership interests in Antero Midstream ~~for approximately $311 million.~~ Partners.

The ~~sale~~Company recorded a gain on deconsolidation of $1.4 billion calculated as the sum of (i) the cash proceeds received, (ii) the fair value of the ~~units~~Antero Midstream Corporation common stock received at the Closing, and (iii) the elimination of the noncontrolling interest less the carrying amount of the investment in Antero Midstream Partners. The fair value of Antero’s retained equity method investment on March 13, 2019 in Antero Midstream Corporation was $2.0 billion based on the market price of the shares received on March 12, 2019. See Note 5 to the unaudited condensed consolidated financial statements for further discussion on equity method investments.

Antero Midstream Partners’ results of operations are no longer consolidated in the Company’s unaudited consolidated statement of operations and comprehensive income (loss) beginning March 13, 2019. Because Antero Midstream Partners does not meet the requirements of a discontinued operation, Antero Midstream Partners’ results of operations continue to be included in the Company’s consolidated unaudited statement of operations and comprehensive income (loss) through March 12, 2019.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and March 31, 2020

(4) Revenue

(a)Disaggregation of Revenue

Revenue is disaggregated by type in the following table. The table also identifies which reportable segment that the disaggregated revenues relate. For more information on reportable segments, see Note 17— Segment Information.


	Three months ended March 31,				Segment to which
(in thousands)	2019		2020		revenues relate
Revenues from contracts with customers:
Natural gas sales	$	657,266		411,082	Exploration and production
Natural gas liquids sales (ethane)		35,516		26,796	Exploration and production
Natural gas liquids sales (C3+ NGLs)		278,169		230,877	Exploration and production
Oil sales		48,052		35,646	Exploration and production
Gathering and compression ⁽¹⁾		3,972		—	Equity method investment in AMC
Water handling and treatment ⁽¹⁾		507		—	Equity method investment in AMC
Marketing		91,186		46,073	Marketing
Total revenue from contracts with customers		1,114,668		750,474
Income (loss) from derivatives and other sources:		(77,261)		566,631
Total revenue and other	$	1,037,407		1,317,105

(1)	Gathering and compression and water handling and treatment revenues were included through March 12, 2019. See Note 3 to the unaudited condensed consolidated financial statements for further discussion on the Transactions.

(b)Transaction Price Allocated to Remaining Performance Obligations

For our product sales that have a contract term greater than one year, we have utilized the practical expedient, 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 our 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 our product sales that have a contract term of one year or less, we have utilized the practical expedient, 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 our sales contracts, we invoice customers after our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our contracts do not give rise to contract assets or liabilities. At December 31, 2019 and March 31, 2020, our receivables from contracts with customers were $318 million and $201 million, respectively.

(5) Equity Method Investments

At March 31, 2020, the Company owned approximately 29% of Antero Midstream Corporation’s common stock, which is reflected in ~~stockholders’~~Antero’s consolidated financial statements using the equity ~~as additional paid-in capital, net~~method of ~~taxes. Proceeds from~~accounting. See Note 3 to the ~~sale were used~~unaudited condensed consolidated financial statements for further discussion on the Transactions.

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ANTERO RESOURCES CORPORATION

Notes to ~~pay down amounts outstanding under Antero’ credit facility, dated as~~Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and March 31, 2020

The following table is a reconciliation of ~~November 4, 2010 (the “Prior Credit Facility”).~~

~~Antero owned approximately 60.9% and 53.0% of~~investments in unconsolidated affiliates for the ~~limited partner interests~~three months ended March 31, 2020 (in thousands):


	Antero Midstream
	Corporation
Balance at December 31, 2019	$	1,055,177
Equity in loss of unconsolidated affiliates		(128,055)
Distributions/dividends from unconsolidated affiliates		(42,756)
Impairment⁽¹⁾		(610,632)
Elimination of intercompany profit		18,255
Balance at March 31, 2020	$	291,989

(1)

Other-than-temporary impairment in Antero Midstream Corporation recorded as of March 31, 2020 to reduce the carrying value to fair value.

Summarized Financial Information of Antero Midstream at Corporation

The following tables present summarized financial information of Antero Midstream Corporation.

Balance Sheet


	December 31,		March 31,
(in thousands)	2019		2020
Current assets	$	108,558		151,372
Noncurrent assets		6,174,320		5,629,987
Total assets	$	6,282,878		5,781,359

Current liabilities	$	242,084		83,560
Noncurrent liabilities		2,897,380		3,108,844
Stockholders' equity		3,143,414		2,588,955
Total liabilities and equity	$	6,282,878		5,781,359

Statement of Operations


	For the period
	March 13, 2019		Three months
	through		ended
(in thousands)	March 31, 2019		March 31, 2020
Revenues	$	54,108		243,708
Operating expenses		30,029		762,872
Income (loss) from operations	$	24,079		(519,164)
Net income (loss) attributable to the equity method investment	$	23,197		(392,933)

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, ~~2016~~2019 and ~~September 30, 2017, respectively.~~March 31, 2020

~~(4)~~(6) Accrued Liabilities

Accrued liabilities as of December 31, ~~2016~~2019 and ~~September 30, 2017~~March 31, 2020 consisted of the following items (in thousands):


	December 31, 2016		September 30, 2017

					December 31,		March 31,
					2019		2020
Capital expenditures	$	159,811		162,116	$	105,706		85,363
Gathering, compression, processing, and transportation expenses		75,223		84,388		134,153		154,039
Marketing expenses		52,822		32,455		52,612		28,014
Interest expense		35,533		66,398
Interest expense, net						30,834		51,281
Other		70,414		84,339		77,545		48,747
	$	393,803		429,696
Total accrued liabilities					$	400,850		367,444

~~(5)~~

(7) Long-Term Debt

Long-term debt ~~was~~ as ~~follows at~~of December 31, ~~2016~~2019 and ~~September 30, 2017~~March 31, 2020 consisted of the following items (in thousands):


	December 31,		March 31,
	2019		2020
Credit Facility^(a)	$	552,000		882,000
5.375% senior notes due 2021 ^(b)		952,500		730,283
5.125% senior notes due 2022 ^(c)		923,041		761,337
5.625% senior notes due 2023^(d)		750,000		750,000
5.00% senior notes due 2025 ^(e)		600,000		600,000
Net unamortized premium		791		600
Net unamortized debt issuance costs		(19,464)		(16,433)
Long-term debt	$	3,758,868		3,707,787

(a)

Senior Secured Revolving Credit Facility

December 31, 2016

September 30, 2017

Antero:

Prior Credit Facility(a)

$
440,000

25,000

5.375% senior notes due 2021(b)

1,000,000

1,000,000

5.125% senior notes due 2022(c)

1,100,000

1,100,000

5.625% senior notes due 2023(d)

750,000

750,000

5.00% senior notes due 2025(e)

600,000

600,000

Net unamortized premium

1,749

1,588

Net unamortized debt issuance costs

(37,690)

(33,789)

Antero Midstream:

Prior Midstream Facility(g)

210,000

427,000

5.375% senior notes due 2024(h)

650,000

650,000

Net unamortized debt issuance costs

(10,086)

(9,278)

$
4,703,973

4,510,521

Antero Resources ~~Corporation~~

~~(a)Senior Secured Revolving Credit Facility~~

~~Antero’s Credit Facility (as defined below) is~~has a senior secured revolving credit facility (the “Credit Facility”) with a consortium of bank lenders. On ~~November 4, 2010,~~April 29, 2020, Antero Resources entered into a ~~credit facility with a consortium of bank lenders (the “Prior~~Third Amendment to the Credit ~~Facility”). On October 26, 2017, Antero entered into an amendment and restatement~~Facility, pursuant to which certain terms of the ~~Prior~~ Credit Facility ~~(the “Credit Facility”).~~were amended, as further described herein. Borrowings under the Credit Facility are subject to borrowing base limitations based on the collateral value of ~~Antero’s~~Antero Resources’ assets and are subject to regular ~~annual~~semi-annual redeterminations. ~~At September 30, 2017, the~~The borrowing base ~~under the Prior Credit Facility~~ was ~~$4.75~~adjusted to $2.85 billion and lender commitments were ~~$4.0 billion. As of October 26, 2017,~~reaffirmed at $2.64 billion in the ~~Credit Facility had a maximum facility amount of $4.75 billion, aggregate commitments were $2.5 billion, and the facility was subject to a $4.5 billion borrowing base.~~redetermination in April 2020. The next redetermination of the borrowing base ~~under the Credit Facility~~ is scheduled to occur in ~~March 2018.~~October 2020. The maturity date of the Credit Facility is the earlier of (i) October 26, 2022 and (ii) the date that is 91 days prior to the ~~maturity~~earliest stated redemption date of any series of ~~Antero’s~~Antero Resources’ senior notes ~~unless such series of notes is refinanced.~~then outstanding.

~~Table of Contents~~

~~ANTERO RESOURCES CORPORATION~~

~~Notes to Condensed Consolidated Financial Statements~~

~~December 31, 2016 and September 30, 2017~~

Under the Credit Facility, “Investment Grade Period” is a period that, as long as no event of default has occurred, commences when Antero Resources elects to give notice to the Administrative Agent that Antero Resources has received at least one of (i) a BBB- or better rating from ~~Standard and Poor’s~~S&P Global Ratings (“S&P”) and (ii) a Baa3 or better rating from Moody’s (an “Investment Grade Rating”). An Investment Grade Period can end at ~~Antero’s~~Antero Resources’ election.

During any period that is not an Investment Grade Period, the Credit Facility is ratably secured by mortgages on substantially all of ~~Antero’s~~Antero Resources’ properties, Antero Resources’ and Antero Subsidiary Holdings LLC’s ownership interests in Antero Midstream Corporation, Antero Resources’ ownership interest in Antero Subsidiary Holdings LLC and Monroe Pipeline LLC, and guarantees from ~~Antero’s~~Antero Resources’ restricted subsidiaries, as applicable. During an Investment Grade Period, the liens securing the obligations under the Credit Facility shall be automatically released (subject to the provisions of the Credit Facility). The Credit Facility contains certain covenants, including restrictions on indebtedness and dividends, and requirements with respect to working capital and interest coverage ratios. ~~Interest~~During any period that is not an Investment Grade Period, interest is payable at a variable rate based on (i) LIBOR or (ii) the Alternate Base Rate, in each case, determined by Antero Resources�� election at the time of borrowing, plus an applicable margin based on Antero Resources’ borrowing base utilization which ranges from 75 basis points to 275 basis points. Alternate Base Rate is defined as the greatest of (a) the prime rate, (b) the NYFRB rate plus ½ of 1%, and (c) LIBOR plus 1%.

Table of Contents

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and March 31, 2020

During an Investment Grade Period, interest is payable at a variable rate based on LIBOR or the ~~prime rate,~~Alternate Base Rate determined by ~~Antero’s~~Antero Resources’ election at the time of ~~borrowing. During~~borrowing, plus an ~~Investment Grade Period, the~~applicable margin ~~applicable to the Credit Facility borrowings is determined with reference to Antero’s~~based on Antero Resources’ credit rating ~~and~~which ranges from ~~0.125%~~62.5 basis points to ~~0.50% lower than rates during~~225 basis points. In each case, the credit facility further provides a ~~period that is not an Investment Grade Period, depending on Antero’s credit rating~~1% floor for LIBOR and ~~utilization under~~a 2% floor for the Credit Facility. During any period that is not an Investment Grade Period, the margin applicable to the Credit Facility borrowings is determined with reference to utilization under the Credit Facility.

Alternate Base Rate. Antero Resources was in compliance with all of the financial covenants under the ~~Prior~~ Credit Facility as of December 31, ~~2016~~2019 and ~~September 30, 2017.~~March 31, 2020.

As of ~~September 30, 2017,~~March 31, 2020, Antero Resources had ~~a total~~an outstanding balance under the ~~Prior~~ Credit Facility of ~~$25~~$882 million, with a weighted average interest rate of ~~4.75%~~2.57%, and outstanding letters of credit of ~~$700~~$730 million. As of December 31, ~~2016,~~2019, Antero Resources had an outstanding balance under the ~~Prior~~ Credit Facility of ~~$440~~$552 million, with a weighted average interest rate of ~~2.44%~~3.28%, and outstanding letters of credit of ~~$710~~$623 million. Commitment fees on the unused portion of the Credit Facility are due quarterly at rates ranging from (i) 0.300% to 0.375% (during any period that is not an Investment Grade Period) of the unused portion based on utilization and (ii) 0.150% to 0.300% (during an Investment Grade Period) of the unused portion based on ~~Antero’s~~Antero Resources’ credit rating.

~~(b)5.375% Senior Notes Due 2021~~

(b)

5.375% Senior Notes Due 2021

On November 5, 2013, Antero Resources issued $1 billion of 5.375% senior notes due November 1, 2021 (the “2021 notes”) at ~~par.~~par. The 2021 notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2021 notes rank pari passu to ~~Antero’s~~Antero Resources’ other outstanding senior notes. The 2021 notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by ~~Antero’s wholly-owned~~Antero Resources’ wholly owned subsidiaries and certain of its future restricted subsidiaries. Interest on the 2021 notes is payable on May 1 and November 1 of each year. Antero may redeem all or part of the 2021 notes at any time at a redemption ~~prices ranging from 104.031% currently to~~price of 100.00% ~~on or after November 1, 2019.~~. If Antero Resources undergoes a change of control followed by a rating decline, the holders of the 2021 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 2021 notes, plus accrued and unpaid interest.

~~(c)5.125% Senior Notes Due 2022~~

(c)

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.~~par. On September 18, 2014, Antero Resources issued an additional $500 million of the 2022 notes at 100.5% of par. The 2022 notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2022 notes rank pari passu to ~~Antero’s~~Antero Resources’ other outstanding senior notes. The 2022 notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by ~~Antero’s wholly-owned~~Antero Resources’ wholly owned subsidiaries and certain of its future restricted subsidiaries. Interest on the 2022 notes is payable on June 1 and December 1 of each year. Antero Resources may redeem all or part of the 2022 notes at any time at redemption prices ranging from ~~103.844%~~101.281% currently to 100.00% on or after June 1, 2020. If Antero Resources undergoes a change of control followed by a rating decline, the holders of the 2022 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 2022 notes, plus accrued and unpaid interest.

~~(d)5.625% Senior Notes Due 2023~~

(d)

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.~~par. The 2023 notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit

~~Table of Contents~~

~~ANTERO RESOURCES CORPORATION~~

~~Notes to Condensed Consolidated Financial Statements~~

~~December 31, 2016 and September 30, 2017~~

Facility. The 2023 notes rank pari passu to ~~Antero’s~~Antero Resources’ other outstanding senior notes. The 2023 notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by ~~Antero’s wholly-owned~~Antero Resources’ wholly owned subsidiaries and certain of its future restricted subsidiaries. Interest on the 2023 notes is payable on June 1 and December 1 of each year. Antero Resources may redeem all or part of the 2023 notes at any time ~~on or after June 1, 2018~~ at redemption prices ranging from ~~104.219% on or after June 1, 2018~~102.813% currently to 100.00% on or after June 1, 2021. ~~In addition, on or before June 1, 2018,~~If Antero may redeem up to 35% of the aggregate principal amount of the 2023 notes with the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 105.625% of the principal amount of the 2023 notes, plus accrued and unpaid interest. At any time prior to June 1, 2018, Antero may also redeem the 2023 notes, in whole or in part, at a price equal to 100% of the principal amount of the 2023 notes plus a “make-whole” premium and accrued and unpaid interest. If AnteroResources undergoes a change of control followed by a rating decline, the holders of the 2023 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 2023 notes, plus accrued and unpaid interest.

~~(e) 5.00% Senior Notes Due 2025~~

(e)

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.~~par. The 2025 notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral

Table of Contents

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and March 31, 2020

securing the Credit Facility. The 2025 notes rank pari passu to ~~Antero’s~~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’s wholly-owned~~Antero Resources’ wholly owned subsidiaries 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 ~~on or after March 1, 2020~~ at redemption prices ranging from 103.750% ~~on or after March 1, 2020~~currently to 100.00% on or after March 1, 2023. ~~In addition, on or before March 1, 2020,~~If Antero may redeem up to 35% of the aggregate principal amount of the 2025 notes with the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 105.00% of the principal amount of the 2025 notes, plus accrued and unpaid interest. At any time prior to March 1, 2020, Antero may also redeem the 2025 notes, in whole or in part, at a price equal to 100% of the principal amount of the 2025 notes plus a “make-whole” premium and accrued and unpaid interest. If AnteroResources 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.

~~(f)Treasury Management Facility~~

(f)

Treasury Management Facility

Antero Resources has a ~~stand-alone~~ revolving note with a lender ~~which~~that is also part of the Credit Facility lending consortium that provides for up to $25 million of cash management obligations in order to facilitate ~~Antero’s~~Antero Resources’ daily treasury management. Borrowings under the revolving note are secured by the collateral for the Credit Facility. Borrowings under the revolving note bear interest at the lender’s prime rate plus 1.0%. The note matures on ~~May~~June 1, ~~2018. At December 31, 2016 and September 30, 2017, there~~2020. There were no outstanding borrowings under ~~this note.~~the revolving note at December 31, 2019 and March 31, 2020, respectively.

~~Antero Midstream Partners LP~~

(g)~~Senior Secured Revolving Credit Facility – Antero Midstream~~

Antero Midstream has a secured revolving credit facility (the “Midstream Facility”) with a syndicate of bank lenders. The Midstream Facility is an amendment and restatement of the Prior Midstream Facility, and provides for lender commitments of $1.5 billion. The maturity date of the Midstream Facility is October 26, 2022.Debt Repurchase Program

During ~~any period that is not an Investment Grade Period (as such term is defined in~~ the ~~Midstream Facility), the Midstream Facility is ratably secured by mortgages on substantially all~~first quarter of ~~the properties of~~2020, Antero Midstream and guarantees from its restricted subsidiaries, as applicable. During an Investment Grade Period under the Midstream Facility, the liens securing the Midstream Facility are automatically released (subject to the provisions of the Midstream Facility). The Midstream Facility contains certain covenants, including restrictions on indebtedness and certain distributions to owners, and requirements with respect to leverage and interest coverage ratios. Interest is payable at a variable rate based on LIBOR or the prime rate, determined by election at the time of borrowing. Interest at the time of borrowing is determined with reference to (i) during any period that is not an Investment Grade Period, the Antero Midstream’s then-current leverage ratio and (ii) during an Investment Grade Period, with reference to the rating given to the Partnership by Moody’s or Standard and Poor’s. During an Investment Grade Period, the applicable margin rates are reduced by 25 basis points. Antero Midstream was in compliance with all of the financial covenants under the Prior Midstream Facility as of December 31, 2016 and September 30, 2017.

~~Table of Contents~~

~~ANTERO RESOURCES CORPORATION~~

~~Notes to Condensed Consolidated Financial Statements~~

~~December 31, 2016 and September 30, 2017~~

~~As of September 30, 2017, Antero Midstream had an outstanding balance under the Prior Midstream Facility of $427~~Resources repurchased $383 million with a weighted average interest rate of 2.82%. As of December 31, 2016, Antero Midstream had a total outstanding balance under the Prior Midstream Facility of $210 million with a weighted average interest rate of 2.23%. Commitment fees on the unused portion of the Midstream Facility are due quarterly at rates ranging from (i) 0.25% to 0.375% of the unused portion (during an period that is not an Investment Grade Period) based on the leverage ratio and (ii) 0.175% to 0.375% of the unused portion (during an Investment Grade Period) based on Antero Midstream’s credit rating.

~~(h)5.375% Senior Notes Due 2024 – Antero Midstream~~

~~On September 13, 2016, Antero Midstream and its wholly-owned subsidiary, Antero Midstream Finance Corporation (“Midstream Finance Corp.”) as co-issuers, issued $650 million in aggregate~~ principal amount of 5.375% senior notes due September 15, 2024 (the “2024 Midstream notes”) at par. The 2024 Midstream notes are unsecured and effectively subordinated to the Midstream Facility to the extent of the value of the collateral securing the Midstream Facility. The 2024 Midstream notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by Antero Midstream’s wholly-owned subsidiaries, excluding Midstream Finance Corp., and certain of Antero Midstream’s future restricted subsidiaries. Interest on the 2024 Midstream notes is payable on March 15 and September 15 of each year. Antero Midstream may redeem all or part of the 2024 Midstream notes at any time on or after September 15, 2019 at redemption prices ranging from 104.031% on or after September 15, 2019 to 100.00% on or after September 15, 2022. In addition, prior to September 15, 2019, Antero Midstream may redeem up to 35% of the aggregate principal amount of the 2024 Midstream notes with an amount of cash not greater than the net cash proceeds of certain equity offerings, if certain conditions are met,debt at a redemption price of 105.375% of the principal amount of the 2024 Midstream notes, plus accrued and unpaid interest. At any time prior to September 15, 2019, Antero Midstream may also redeem the 2024 Midstream notes, in whole or in part, at a price equal to 100% of the principal amount of the 2024 Midstream notes plus a “make-whole” premium and accrued and unpaid interest. If Antero Midstream undergoes a change of control, the holders of the 2024 Midstream notes will have the right to require Antero Midstream to repurchase all or21% weighted average discount, including a portion of the 2021 notes atand the 2022 notes. The Company recognized a ~~price equal to 101%~~gain of approximately $81 million on the early extinguishment of the ~~principal amount of the 2024 Midstream notes, plus accrued and unpaid interest.~~debt repurchased.

~~(6)~~(8) Asset Retirement Obligations

The following is a reconciliation of the Company’s asset retirement obligations for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2020 (in thousands):

Asset retirement obligations—December 31, 2016

$
32,736

Obligations settled

(21)

Obligations incurred for wells drilled and producing properties acquired

3,399

Accretion expense

1,944

Asset retirement obligations—September 30, 2017

$
38,058


Asset retirement obligations—December 31, 2019	$	54,845
Obligations incurred		773
Accretion expense		1,104
Asset retirement obligations—March 31, 2020	$	56,722

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

~~(7)~~(9) Equity-Based Compensation

Antero Resources is authorized to grant up to 16,906,500 shares of common stock to employees and directors of the Company under the Antero Resources Corporation Long-Term Incentive Plan (the “Plan”). The Plan allows equity-based compensation awards to be granted in a variety of forms, including stock options, stock appreciation rights, restricted stock awards, restricted stock unit awards, dividend equivalent awards, and other types of awards. The terms and conditions of the awards granted are established by the Compensation Committee of ~~Antero’s~~Antero Resources’ Board of Directors. A total of ~~7,724,613~~1,742,720 shares were available for future grant under the Plan as of ~~September 30, 2017.~~

March 31, 2020.

Antero Midstream isPartners’ 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 ~~“Midstream~~“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)~~includes Antero Resources). ~~A total~~As part of ~~7,656,134 common units were available for future grant~~the Transactions, each outstanding phantom unit award under the AMP Plan, was assumed by Antero Midstream Corporation and converted into 1.8926 restricted stock units under the Antero Midstream Corporation Long Term Incentive Plan as(the “AMC Plan”). Each restricted stock unit award under the AMC Plan represents a right to receive 1 share of ~~September 30, 2017.~~

Antero Midstream Corporation common stock.

Table of Contents

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, ~~2016~~2019 and ~~September 30, 2017~~March 31, 2020

The Company’s equity-based compensation expense, by type of award, was as follows for the three ~~and nine~~ months ended ~~September 30, 2016~~March 31, 2019 and ~~2017~~2020 (in thousands):


	Three months ended March 31,
	2019		2020
Restricted stock unit awards	$	3,972		1,878
Stock options		344		—
Performance share unit awards		2,959		922
Antero Midstream Partners phantom unit awards ⁽¹⁾		1,125		160
Equity awards issued to directors		503		369
Total expense	$	8,903		3,329

Three Months Ended September 30,

Nine Months Ended September 30,


2016

2017

2016

2017

Restricted stock unit awards

$
18,618

17,910

54,231

54,816

Stock options

638

614

1,939

1,850

Performance share unit awards

2,668

3,014

6,017

7,897

Antero Midstream phantom unit awards

3,977

4,420

11,978

12,906

Equity awards issued to directors

480

489

1,502

1,456

Total expense

$
26,381

26,447

75,667

78,925

~~Restricted Stock Unit Awards~~

~~Restricted stock unit~~

(1)Antero Resources recognized compensation expense for equity awards ~~vest subject to~~granted under both the ~~satisfaction of service requirements. Expense related to each restricted stock unit award is recognized on a straight-line basis over~~Plan and the ~~requisite service period of~~AMP Plan because the ~~entire award. Forfeitures~~awards under the AMP Plan are accounted for as if they ~~occur~~are distributed by ~~reversing~~Antero Midstream Partners to Antero Resources. Antero Resources allocates a portion of equity-based compensation expense related to grants prior to the ~~expense previously recognized for awards that were forfeited during the period. The grant date fair values of these awards are determined~~Transactions to Antero Midstream Partners based on its proportionate share of Antero Resources’ labor costs. Through March 12, 2019, the ~~closing price~~total amount of equity-based compensation is included in the ~~Company’s common stock~~consolidated financial statements of Antero Resources; and effective March 13, 2019 (date of deconsolidation), the amount allocated to Antero Midstream Partners is no longer reflected in Antero Resources consolidated financial statements. See Note 3 to the unaudited condensed consolidated financial statements for further discussion on the ~~date of the grant.~~Transactions.

Restricted Stock Unit Awards

A summary of restricted stock unit ~~awards~~award activity for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2020 is as follows:

Weighted
average

Aggregate


Number of
shares

grant date
fair value

intrinsic value
(in thousands)

Total awarded and unvested—December 31, 2016

5,353,447

$
31.77

$
126,609

Granted

828,753

$
22.21

Vested

(834,796)

$
43.46

Forfeited

(353,152)

$
27.10

Total awarded and unvested—September 30, 2017

4,994,252

$
28.56

$
99,386


		Weighted
		average		Aggregate
	Number of	grant date		intrinsic value
	shares	fair value		(in thousands)
Total awarded and unvested—December 31, 2019	2,370,575	$	12.81	$	6,756
Granted	4,644,934	$	2.39
Vested	(191,216)	$	5.04
Forfeited	(69,293)	$	13.07
Total awarded and unvested—March 31, 2020	6,755,000	$	5.86	$	4,816

Intrinsic values are based on the closing price of ~~the Company’s~~Antero Resources’ common stock on the referenced dates. As of ~~September 30, 2017,~~March 31, 2020, there was ~~$85.3~~$27 million of unamortized equity-based compensation expense related to unvested restricted stock units. That expense is expected to be recognized over a weighted average period of approximately ~~1.8~~2.3 years.

~~Stock Options~~

Stock options granted under the Plan vest over periods from one to four years and have a maximum contractual life of 10 years. Expense related to stock options is recognized on a straight-line basis over the requisite service period of the entire award. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period. Stock options are granted with an exercise price equal to or greater than the market price of the Company’s common stock on the date of grant.

Table of Contents

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, ~~2016~~2019 and ~~September 30, 2017~~March 31, 2020

Stock Options

A summary of stock option activity for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2020 is as follows:

Weighted

Weighted
average

average
remaining

Intrinsic


Stock
options

exercise
price

contractual
life

value
(in thousands)

Outstanding at December 31, 2016

687,929

$
50.46

8.12

$
—

Granted

—

$
—

Exercised

—

$
—

Forfeited

(16,542)

$
50.00

Expired

—

$
—

Outstanding at September 30, 2017

671,387

$
50.47

7.32

$
—

Vested or expected to vest as of  September 30, 2017

671,387

$
50.47

7.32

$
—

Exercisable at September 30, 2017

363,605

$
50.70

7.20

$
—


				Weighted
		Weighted		average
		average		remaining	Intrinsic
	Stock	exercise		contractual	value
	options	price		life	(in thousands)
Outstanding at December 31, 2019	467,633	$	50.64	5.05	$	—
Granted	—	$	—
Exercised	—	$	—
Forfeited	(8,339)	$	52.36
Expired	—	$	—
Outstanding at March 31, 2020	459,294	$	50.61	4.77	$	—
Vested or expected to vest as of March 31, 2020	459,294	$	50.61	4.77	$	—
Exercisable at March 31, 2020	459,294	$	50.61	4.77	$	—

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

As of ~~September 30, 2017, there was $3.3 million of~~March 31, 2020, all stock options were fully vested resulting in 0 unamortized equity-based compensation ~~expense related~~expense.

Performance Share Unit Awards

The Company did not have any activities with regards to ~~unvested stock options. That expense is expected to be recognized over~~its performance share units (“PSUs”) during the three months ended March 31, 2020, and the number of PSUs outstanding at March 31, 2020 remained 2,537,283 at a weighted average ~~period of approximately 1.5 years.~~

~~Performance Share Unit Awards~~

~~Performance Share Unit Awards Based on Price Targets~~

In 2016, the Company granted performance share unit awards (“PSUs”) to certain of its executive officers that are based on price targets. The vesting of these PSUs is conditioned on the closing price of the Company’s common stock achieving specific price thresholds over 10-day periods, subject to the following vesting restrictions: no PSUs may vest before the first anniversary of the grant date; no more than one-third of the PSUs may vest before the second anniversary of the grant date; and no more than two-thirds of the PSUs may vest before the third anniversary of the grant date. Any PSUs which have not vested by the fifth anniversary of the grant date ~~will expire. Expense related to these PSUs is recognized on a graded basis over three years.~~

~~Performance Share Unit Awards Based on Total Shareholder Return~~

In 2016 and 2017, the Company also granted PSUs to certain of its employees and executive officers which vest based on the total shareholder return (“TSR”) of the Company’s common stock relative to the TSR of a peer group of companies over a three-year performance period. The number of performance shares which may ultimately be earned ranges from zero to 200% of the PSUs granted. Expense related to these PSUs is recognized on a straight-line basis over three years.

~~Summary Information for Performance Share Unit Awards~~

~~A summary of PSU activity for the nine months ended September 30, 2017 is as follows:~~

Number of
units

Weighted
average
grant date
fair value

Total awarded and unvested—December 31, 2016

785,301

$
29.75

Granted

558,021

$
26.21

Vested

(41,666)

$
27.38

Forfeited

(8,623)

$
29.86

Total awarded and unvested—September 30, 2017

1,293,033

$
28.30

~~Table of Contents~~

~~ANTERO RESOURCES CORPORATION~~

~~Notes to Condensed Consolidated Financial Statements~~

~~December 31, 2016 and September 30, 2017~~

~~The following table presents information regarding the weighted average~~ fair value ~~for PSUs granted during the nine months ended September 30, 2017 and the assumptions used to determine the fair values.~~of $16.74.

Nine Months Ended September 30, 2017

Dividend yield

—
%

Volatility

42
%

Risk-free interest rate

1.40
%

Weighted average fair value of awards granted

$
26.21

As of ~~September 30, 2017,~~March 31, 2020, there was ~~$21.1~~$14 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 ~~2.1~~1.6 years.

Cash Awards

During the three months ended March 31, 2020, the Company granted cash awards of approximately $3.3 million to certain executives under the Plan. Compensation expense for these awards is recognized ratably over the vesting period for each of 3 tranches through January 20, 2023. As of March 31, 2020, the Company has accrued approximately $0.6 million in Other liabilities in the unaudited condensed consolidated balance sheet related to such cash awards.

Antero Midstream Partners Phantom Unit Awards

~~Phantom units granted by~~ and Antero Midstream vest subject to the satisfaction of service requirements, upon the completion of which common units in Antero Midstream are delivered to the holder of the phantom units. These phantom units are treated, for accounting purposes, as if Antero Midstream distributed the units to Antero. Antero recognizes compensation expense as the units are granted to its employees, and a portion of the expense is allocated to Antero Midstream. Expense related to each phantom unit award is recognized on a straight-line basis over the requisite service period of the entire award. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period. The grant date fair values of these awards are determined based on the closing price of Antero Midstream’s common units on the date of grant.

Corporation Restricted Stock Unit Awards

A summary of ~~phantom~~Antero Midstream Corporation restricted stock unit awards ~~activity~~ for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2020 is as follows:


		Weighted
		average		Aggregate
	Number of	grant date		intrinsic value
	units	fair value		(in thousands)
Total awarded and unvested—December 31, 2019	657,757	$	14.71	$	4,992
Granted	—	$	—
Vested	(10,120)	$	15.81
Forfeited	(9,496)	$	13.75
Total awarded and unvested—March 31, 2020	638,141	$	14.70	$	1,340

Number of
units

Weighted
average
grant date
fair value

Aggregate
intrinsic value
(in thousands)

Total awarded and unvested—December 31, 2016

1,331,961

$
27.31

$
41,131

Granted

377,660

$
32.52

Vested

(73,080)

$
21.34

Forfeited

(78,584)

$
28.76

Total awarded and unvested—September 30, 2017

1,557,957

$
28.78

$
49,122

Table of Contents

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and March 31, 2020

Intrinsic values are based on the closing price of shares of Antero ~~Midstream’s~~Midstream Corporation common ~~units on the referenced dates.~~stock. As of ~~September 30, 2017,~~March 31, 2020, there was ~~$30.4~~$5 million of unamortized equity-based compensation expense related to unvested phantom unit awards. That expense is expected to be recognized over a weighted average period of approximately ~~2.2~~1.5 years.

~~(8)~~(10) Financial Instruments

The carrying values of accounts receivable and accounts payable at December 31, ~~2016~~2019 and ~~September 30, 2017~~March 31, 2020 approximated market values because of their short-term nature. The carrying values of the amounts outstanding under the ~~Prior~~ Credit ~~Facility and Prior Midstream~~ Facility at December 31, ~~2016~~2019 and ~~September 30, 2017~~March 31, 2020 approximated fair value because the variable interest rates are reflective of current market conditions.

Based on Level 2 market data inputs, the fair value of ~~Antero’s~~ senior notes was approximately ~~$3.5~~$2.8 billion and $1.5 billion at December 31, ~~2016~~2019 and ~~September 30, 2017. Based on Level 2 market data inputs, the fair value of Antero Midstream’s senior notes was approximately $657 million at December~~ March 31, ~~2016 and $676 million at September 30, 2017.~~

2020, respectively.

See Note 911 to the unaudited condensed consolidated financial statements for information regarding the fair value of derivative financial instruments.

~~Table of Contents~~

~~ANTERO RESOURCES CORPORATION~~

~~Notes to Condensed Consolidated Financial Statements~~

~~December 31, 2016 and September 30, 2017~~

~~(9)~~(11) Derivative Instruments

(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 ~~nine~~three months ended ~~September 30, 2016~~March 31, 2019 and ~~2017.~~2020. 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, ~~to fixed price swap contracts,~~ 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 also entered into NGL derivative contracts, which establish a contractual price ~~at which~~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 ~~sells~~pays the difference to the counterparty. When it is below the contracted percentage, the Company receives the difference from the counterparty.

In addition, the Company has also entered into a ~~portion~~call option agreement that gives the counterparty the right, but not the obligation, to enter into a fixed price swap agreement on a specified future date for a specific amount of ~~its natural gas production.~~

production for a specified future period.

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

Table of Contents

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and March 31, 2020

As of ~~September 30, 2017,~~March 31, 2020, the Company’s fixed price natural gas, ~~NGLs,~~oil and ~~oil~~NGL swap positions from ~~October~~April 1, ~~2017~~2020 through December 31, 2023 were as follows (abbreviations in the table refer to the index to which the swap position is tied, as follows: NYMEX=Henry Hub; ~~CGTLA=Columbia Gas Louisiana Onshore; CCG=Chicago City Gate; Mont Belvieu-Ethane=Mont Belvieu Purity Ethane; Mont Belvieu-Propane=Mont Belvieu Propane;~~ NYMEX-WTI=West Texas ~~Intermediate)~~Intermediate; ARA Propane =European Propane CIF ARA):

Natural gas
MMbtu/day

Oil
Bbls/day

Natural Gas
Liquids
Bbls/day

Weighted
average index
price

Three months ending December 31, 2017:

NYMEX ($/MMBtu)

1,370,000

—

—

$
3.46

CGTLA ($/MMBtu)

420,000

—

—

$
4.37

CCG ($/MMBtu)

70,000

—

—

$
4.68

NYMEX-WTI ($/Bbl)

—

3,000

—

$
54.75

Mont Belvieu-Ethane ($/Gallon)

—

—

20,000

$
0.25

Mont Belvieu-Propane ($/Gallon)

—

—

27,500

$
0.40

Total

1,860,000

3,000

47,500

Year ending December 31, 2018:

NYMEX ($/MMBtu)

2,002,500

—

—

$
3.50

NYMEX-WTI ($/Bbl)

—

1,000

—

$
49.96

Mont Belvieu-Propane ($/Gallon)

—

—

3,000

$
0.67

Total

2,002,500

1,000

3,000

Year ending December 31, 2019:

NYMEX ($/MMBtu)

2,330,000

$
3.50

Year ending December 31, 2020:

NYMEX ($/MMBtu)

1,417,500

$
3.25

Year ending December 31, 2021:

NYMEX ($/MMBtu)

710,000

$
3.00

Year ending December 31, 2022:

NYMEX ($/MMBtu)

850,000

$
3.00

Year ending December 31, 2023:

NYMEX ($/MMBtu)

90,000

$
2.91


		Natural Gas		Weighted
	Natural gas	Liquids	Oil	average index
	MMBtu/day	Bbls/day	Bbls/day	price
Nine months ending December 31, 2020:
NYMEX ($/MMBtu)	2,227,500		—	$	2.87
ARA Propane ($/Gal)	—	10,352	—		0.65
NYMEX-WTI ($/Bbl)	—	—	26,000		55.63
Total	2,227,500	10,352	26,000
Year ending December 31, 2021:
NYMEX ($/MMBtu)	2,400,000		—	$	2.80
NYMEX-WTI ($/Bbl)	—		3,000		55.16
Total	2,400,000		3,000
Year ending December 31, 2022:
NYMEX ($/MMBtu)	687,500			$	2.48
Year ending December 31, 2023:
NYMEX ($/MMBtu)	50,000			$	2.39

~~Table~~A portion of ~~Contents~~the NYMEX-WTI ($/Bbl) in 2020 combined with the Mont Belvieu Natural Gasoline to NYMEX-WTI are intended to fix the price of Natural Gasoline.

~~ANTERO RESOURCES CORPORATION~~

~~Notes~~In addition, we have a call option agreement, which entitles the holder the right, but not the obligation, to ~~Condensed Consolidated Financial Statements~~

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, ~~2016 and September 30, 2017~~2024.

As of ~~September 30, 2017,~~March 31, 2020, the Company’s natural gas basis swap positions, which settle on the pricing index to basis differential of ~~TCO~~the Columbia Gas Transmission pipeline (“TCO”) to the NYMEX Henry Hub natural gas price, ~~were as follows:~~

Natural gas
MMbtu/day

Hedged Differential
($/MMBtu)

Three months ending December 31, 2017:

125,000

$
(0.51)

~~As of September 30, 2017, the Company’s natural gas~~and NGL basis swap positions, which settle on the pricing index to basis differential of ~~NYMEX Henry Hub~~Mont Belvieu Butane to the ~~TCO~~European Butane CIF ARA natural gas liquids price, were as follows:


		Natural Gas	Weighted
	Natural gas	Liquids	average hedged
	MMBtu/day	Bbls/day	differential
Three months ending June 30, 2020:
ARA to Mont Belvieu Non-TET ($/Gal)	—	1,602	$	0.22
Nine months ending December 31, 2020:
NYMEX to TCO ($/MMBtu)	60,000		$	0.353
Year ending December 31, 2021:
NYMEX to TCO ($/MMBtu)	40,000		$	0.414
Year ending December 31, 2022:
NYMEX to TCO ($/MMBtu)	60,000		$	0.515
Year ending December 31, 2023:
NYMEX to TCO ($/MMBtu)	50,000		$	0.525
Year ending December 31, 2024:
NYMEX to TCO ($/MMBtu)	50,000		$	0.530

Natural gas
MMbtu/day

Hedged Differential
($/MMBtu)

Three months ending December 31, 2017:

125,000

$
0.39

Table of Contents

~~(b)Commodity Derivative Fair Values~~ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and March 31, 2020

As of March 31, 2020, the Company had NGL contracts for April 1, 2020 through December 31, 2021 that fix the Mont Belvieu index price for natural gasoline to percentages of WTI as follows:


		Weighted
	Gas	average
	Liquids	Payout
	Bbls/day	Ratio
Nine months ending December 31, 2020:
Mont Belvieu Natural Gasoline to NYMEX-WTI	18,800	80	%
Year ending December 31, 2021:
Mont Belvieu Natural Gasoline to NYMEX-WTI	18,650	78	%

A portion of the Mont Belvieu Natural Gasoline to NYMEX-WTI combined with the NYMEX-WTI ($/Bbl) in 2020 are intended to fix the price of Natural Gasoline.

(b)

Summary

The following table presents a summary of the fair values of the Company’s derivative instruments and where such values are recorded in the consolidated balance sheets as of December 31, ~~2016~~2019 and ~~September 30, 2017. None~~March 31, 2020. NaN of the Company’s derivative instruments are designated as hedges for accounting ~~purposes.~~purposes and the fair value of derivative instruments was determined using Level 2 inputs.

December 31, 2016

September 30, 2017

Balance sheet
location

Fair value

Balance sheet
location

Fair value

(In thousands)

(In thousands)

Asset derivatives not designated as hedges for accounting purposes:

Commodity contracts

Current assets

$
73,022

Current assets

299,796

Commodity contracts

Long-term assets

1,731,063

Long-term assets

876,293

Total asset derivatives

1,804,085

1,176,089

Liability derivatives not designated as hedges for accounting purposes:

Commodity contracts

Current liabilities

203,635

Current liabilities

4,285

Commodity contracts

Long-term liabilities

234

Long-term liabilities

427

Total liability derivatives

203,869

4,712

Net derivatives

$
1,600,216

1,171,377


	December 31, 2019			March 31, 2020
	Balance sheet	Fair value		Balance sheet	Fair value
	location	(In thousands)		location	(In thousands)
Asset derivatives not designated as hedges for accounting purposes:
Commodity derivatives—current	Derivative instruments	$	422,849	Derivative instruments	$	816,444
Commodity derivatives—noncurrent	Derivative instruments		333,174	Derivative instruments		284,461

Total asset derivatives			756,023			1,100,905

Liability derivatives not designated as hedges for accounting purposes:
Commodity derivatives—current	Derivative instruments		6,721	Derivative instruments		—
Commodity derivatives—noncurrent	Derivative instruments		3,519	Derivative instruments		215

Total liability derivatives			10,240			215

Net derivatives		$	745,783		$	1,100,690

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 consolidated balance sheets as of the dates presented, all at fair value (in thousands):


	December 31, 2016						September 30, 2017
	Gross amounts on balance sheet		Gross amounts offset on balance sheet		Net amounts of assets on balance sheet		Gross amounts on balance sheet		Gross amounts offset on balance sheet		Net amounts of assets (liabilities) on balance sheet

													December 31, 2019						March 31, 2020
													Gross		Gross amounts		Net amounts of		Gross		Gross amounts		Net amounts of
													amounts on		offset on		assets (liabilities)		amounts on		offset on		assets (liabilities)
													balance sheet		balance sheet		on balance sheet		balance sheet		balance sheet		on balance sheet
Commodity derivative assets	$	1,914,245		(110,160)		1,804,085	$	1,326,727		(150,638)		1,176,089	$	882,817		(126,794)		756,023	$	1,193,046		(92,141)		1,100,905
Commodity derivative liabilities	$	(324,667)		120,798		(203,869)	$	(4,823)		111		(4,712)	$	(137,034)		126,794		(10,240)	$	(92,356)		92,141		(215)

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, ~~2016~~2019 and ~~September 30, 2017~~March 31, 2020

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, 2016~~March 31, 2019 and ~~2017~~2020 (in thousands):

Statement of
operations

Three months ended September 30,

Nine months ended September 30,

location

2016

2017

2016

2017

Commodity derivative fair value gains (losses)

Revenue

$
530,334

(65,957)

$
125,624

458,459


	Statement of
	operations	Three months ended March 31,
	location	2019		2020
Commodity derivative fair value gains (losses)	Revenue	$	(77,368)		565,833

~~Commodity derivative fair~~

(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 are 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 ~~gains (losses)~~of the known future minimum payments of the contract using a discount rate on the date of commencement. The leased asset classification is determined at the date of recording as either operating or financing, depending upon certain criteria of the contract.

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

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

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and March 31, 2020

Supplemental Balance Sheet Information Related to Leases

The Company’s lease assets as of December 31, 2019 and March 31, 2020 consisted of the following items (in thousands):


	December 31, 2019				March 31, 2020
	Operating Leases		Finance Leases		Operating Leases		Finance Leases
Right-of-use Assets:
Processing plants	$	1,460,770		—	$	1,440,110		—
Drilling rigs and completion services		71,662		—		56,353		—
Gas gathering lines and compressor stations ⁽¹⁾		1,308,428		—		1,273,200		—
Office space		40,491		—		39,631		—
Vehicles		4,983		2,328		4,232		2,058
Other office and field equipment		166		170		1,013		—
Total right-of-use assets	$	2,886,500		2,498	$	2,814,539		2,058	⁽²⁾

(1)	Gas gathering lines and compressor stations leases includes $1.1 billion related to Antero Midstream Corporation as of December 31, 2019 and March 31, 2020. See “—Related party lease disclosure” for additional discussion.

(2)	Financing lease assets are recorded net of accumulated amortization of $9 million and $3 million as of December 31, 2019 and March 31, 2020, respectively.

The Company’s lease liabilities as of December 31, 2019 and March 31, 2020 consisted of the following items (in thousands):


	December 31, 2019				March 31, 2020
	Operating Leases		Finance Leases		Operating Leases		Finance Leases
Location on the balance sheet:
Short-term lease liabilities	$	304,397		923	$	294,535		1,123
Long-term lease liabilities		2,582,103		1,575		2,520,004		935
Total lease liabilities	$	2,886,500		2,498	$	2,814,539		2,058

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

Supplemental Information Related to Leases

Costs associated with operating leases were included in the statement of operations and comprehensive income (loss) for the three ~~and nine~~ months ended ~~September 30, 2017 include gains~~March 31, 2019 and 2020 (in thousands):


	Three months ended
Statement of Operations Location	March 31, 2019		March 31, 2020
Gathering, compression, processing, and transportation	$	187,847		352,643
General and administrative		2,726		2,881
Contract termination and rig stacking		8,019		—
Total lease expense	$	198,592		355,524

Costs associated with finance leases of ~~$750~~less than $1 million for each of the three months ended March 31, 2019 and 2020 were included in interest expense.

We capitalized $55 million and $33 million, respectively, of costs related to operating leases and less than $1 million of costs related to finance leases during each of the three months ended March 31, 2019 and 2020.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and March 31, 2020

Short-term lease costs that are more than one month but less than 12 months are excluded from the above amounts and total $35 million and $63 million, respectively, for the three months ended March 31, 2019 and 2020.

Supplemental Cash Flow Information Related to Leases

The following is the Company’s supplemental cash flow information related to leases for the three months ended March 31, 2019 and March 31, 2020 (in thousands):


	Three months ended March 31, 2019				Three months ended March 31, 2020
	Operating Leases		Finance Leases		Operating Leases		Finance Leases
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash out flows related to operating leases	$	150,320		—	$	358,039		—
Investing cash out flows related to operating leases		52,366		—		27,534		—
Financing cash out flows related to financing leases		—		791		—		439
	$	202,686		791	$	385,573		439

Noncash activities:
Right of use assets obtained in exchange for operating lease liabilities	$	3,345,549		—	$	9,382		—
Right of use assets obtained in exchange for financing lease liabilities	$	—		—	$	—		—

Maturities of Lease Liabilities

The table below is a schedule of future minimum payments for operating and financing lease liabilities as of March 31, 2020 (in thousands):


(in thousands)	Operating Leases		Financing Leases		Total
Remainder of 2020	$	464,093		978		465,071
2021		558,241		844		559,085
2022		543,326		321		543,647
2023		538,771		7		538,778
2024		530,003		—		530,003
2025		457,326		—		457,326
Thereafter		1,394,412		—		1,394,412
Total lease payments		4,486,172		2,150		4,488,322
Less: imputed interest		(1,671,633)		(92)		(1,671,725)
Total	$	2,814,539		2,058		2,816,597

Lease Term and Discount Rate

The table below is the Company’s weighted-average remaining lease term and discount rate as of March 31, 2020:



	Operating Leases			Finance Leases
Weighted-average remaining lease term:		8.5 years			2.0 years
Weighted-average discount rate:		11.6	%		6.1	%

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and March 31, 2020

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 adjustments based on the consumer price index. If and to the extent we request 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% and 70%, respectively, 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^thday prior to the anniversary of such effective date. The Company achieved the volumetric targets for the three months ended March 31, 2020, and Antero Midstream Corporation provided a rebate of $12 million.

For the three months ended March 31, 2019 and 2020, gathering and compression fees paid by Antero related to this agreement were $152 million and $156 million, respectively. As of March 31, 2020, $60 million was included within Accounts payable, related parties on the Condensed Consolidated Balance Sheet as due to Antero Midstream Corporation related to this agreement.

(13) Commitments

The table below is 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 March 31, 2020 (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 2020	$	832,753		42,144		2,411		228,796		236,275		1,342,379
2021		1,076,995		55,780		2,859		269,661		289,424		1,694,719
2022		1,034,275		53,606		328		284,665		258,982		1,631,856
2023		1,057,150		58,565		—		313,475		225,303		1,654,493
2024		1,017,104		58,687		—		342,348		187,655		1,605,794
2025		977,891		47,385		—		308,465		148,861		1,482,602
Thereafter		6,930,640		105,138		—		1,069,187		325,225		8,430,190
Total	$	12,926,808		421,305		5,598		2,816,597		1,671,725		17,842,033

(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 ~~derivatives that were monetized prior to their settlement dates. Proceeds received from the monetizations~~or NGLs volumes at negotiated rates or pay for any deficiencies at specified reservation fee rates. The amounts in this table are ~~classified as operating cash flows~~based on the Company’s ~~condensed~~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 consolidated ~~statement~~financial statements its proportionate share of ~~cash flows for the nine months ended September 30, 2017. The monetizations were effected by reducing the average fixed index prices~~costs based on certain natural gas swap contracts maturing from 2018 through 2022 while maintaining the total volumes hedged. The Company’s commodity derivative position presented in note 9(a) reflects the adjusted fixed price indices after the monetization. Proceeds from the monetization were usedits working interest.

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ANTERO RESOURCES CORPORATION

Notes to ~~pay down amounts outstanding under the Prior Credit Facility.~~Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and March 31, 2020

~~The fair value of commodity derivative instruments was determined using Level 2 inputs.~~

~~(10)Contingencies~~

~~SJGC~~

(b)

Processing, Gathering, and Compression Service Commitments

The Company ishas 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 ~~plaintiff~~agreements that are not leases are presented in ~~a lawsuit against South Jersey Gas Company and South Jersey Resources Group, LLC (collectively, “SJGC”) pending~~this column.

The values in ~~United States District Court in Colorado. In March 2015,~~the table represent the gross amounts that the Company ~~filed suit against SJGC seeking relief for breach of contract and damages~~is committed to pay; however, the Company will record in the 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 ~~SJGC had short paid,~~we are committed to pay; however, we will record in our financial statements our proportionate share of costs based on our working interests. Refer to Note 12 to the unaudited condensed consolidated financial statements for more information on the Company’s operating and ~~continued to short pay,~~finance leases.

(14) Contingencies

Environmental

In June 2018, following site inspections conducted in September 2017 at certain of our facilities located in Doddridge County, Tyler County, and Ritchie County, West Virginia, we received a Notice of Violation (“NOV”) from the ~~Company in connection with two nearly identical long term gas contracts. Under those contracts, SJGC are long term purchasers of 80,000 MMBtu/day~~U.S. Environmental Protection Agency (“EPA”) Region III for alleged violations of the ~~Company’s~~federal Clean Air Act and the West Virginia State Implementation Plan relating to permitting and control requirements for emissions of regulated pollutants at several of our natural gas ~~production. Deliveries under~~production facilities. The NOV alleges that combustion devices at these facilities did not meet applicable air permitting requirements. Separately, in June 2018, we received an information request from EPA Region III pursuant to Section 114(a) of the ~~contracts began~~Clean Air Act relating to the facilities that were inspected in ~~October 2011~~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. We have separately received an NOV from West Virginia Department of Environmental Protection (“WVDEP”) alleging violations relating to the same issues being investigated by the EPA. We continue to negotiate with EPA and WVDEP to resolve the issues alleged in the NOVs and the ~~term~~information request; however, we believe that there is a reasonable possibility that these actions may result in monetary sanctions exceeding $100,000. Our operations at these facilities are not suspended, and management does not expect these matters to have a material adverse effect on our financial condition, results of the contracts continues through October 2019. The price for gas was based on specified indices in the contracts. Beginning in October 2014, SJGC began short paying the Company based on price indices unilaterally selected by SJGC and not the applicable index specified in the contracts. SJGC claimed that the index price specified in the contracts, and the index at which SJGC paid for deliveries from 2011 through September 2014, was no longer appropriate under the contracts because a market disruption event (as defined by the contract) had occurred and, as a result, a new index price was required to be determined by the parties. The Company rejected SJGC’s contention that a market disruption event occurred. SJGC’s actions constituted a breach of the contracts by failing to pay the Company based on the express price terms of the contracts and paying the Company based on unilaterally selected price indices in violation of the contracts’ remedial provisions. On May 8, 2017, a jury in the United States District Court in Colorado returned a unanimous verdict finding in favor of Antero’s positions in the lawsuit against SJGC. On July 21, 2017, final judgment on the jury’s unanimous verdict was entered by the court. On August 18, 2017, SJGC filed post-judgment motions with the court, which are currently pending. If the court denies those motions, SJGC will have 30 days from the court’s decision on these post-judgment motions to file an appeal. SJGC continues to short pay the Company based on indexes unilaterally selected by SJGC and not the index specified in the contract. Through September 30, 2017, the Company estimates that it is owed approximately $70 million (gross damages, including interest) more than SJGC has paid using the indices unilaterally selected by them. Substantially all of this amount has not been accrued in the Company’s financial statements. The Company will vigorously seek recovery from SJGC of all underpayments and damages, including interest, based on the contracted price.operations, or cash flows.

WGL

~~WGL~~

The Company and Washington Gas Light Company and WGL Midstream, Inc. (collectively, “WGL”) were involved in a pricing dispute involving firm gas sales contracts executed June 20, 2014 (the “Contracts”) that the Company began delivering gas under in January 2016. From January 2016 through July 2017 and from December 2017 through January 2018, the aggregate daily gas volumes contracted for under the Contracts was 500,000 MMBtu/day, with the aggregate daily contracted volumes having increased to 600,000 MMBtu/day ~~during the months of~~from August ~~and September~~through November 2017. The Company invoiced WGL based on the natural gas index price specified in the Contracts and WGL paid the Company based on that invoice price. However, WGL asserted that the index price was no longer appropriate under the Contracts and claimed that an undefined alternative index was more appropriate for the delivery point of the gas. In July 2016, the matter was referred to arbitration by the Colorado district court. In January 2017, ~~after hearing a week of testimony and evidence,~~ the arbitration panel ruled in the Company’s favor. As a result, the index price has remained as specified in the Contracts and there will be no

~~Table of Contents~~

~~ANTERO RESOURCES CORPORATION~~

~~Notes to Condensed Consolidated Financial Statements~~

~~December 31, 2016 and September 30, 2017~~

adjustments to the invoices that have been paid by WGL, nor will future invoices to WGL be adjusted based on the same claim rejected by the arbitration panel. The arbitration panel’s award was confirmed by the Colorado district court on April 14, 2017.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and March 31, 2020

In March of 2017, WGL filed a second ~~lawsuit~~legal proceeding against the Company in Colorado district court alleging breach of contract and seeking damages of more than $30 million. In this lawsuit, WGL claimed that the Company breached its contractual obligations under the Contracts by failing to deliver “TCO pool” gas. In subsequent filings, WGL explained that its claims were based on an alleged obligation that the Company must deliver gas to the Columbia IPP Pool (“IPP Pool”). WGL asserted this exact same ~~claim~~issue in the arbitration and it was rejected by the arbitration panel. The arbitration panel specifically found that the Delivery Point under the Contracts was at a specific geographic point in Braxton County, West Virginia, not the IPP Pool. On August 24, 2017, the Colorado district court dismissed with prejudice WGL’s claims against the Company in its ~~second~~new lawsuit and found that the Company had not breached its Contracts with WGL by allegedly failing to deliver to the IPP Pool. The Court ~~also reaffirmed~~dismissed WGL’s lawsuit because WGL had not adequately pled a claim against Antero Resources for the ~~arbitration panel’s finding that the delivery point~~alleged failure to deliver “TCO pool” gas under the ~~Contracts was not the IPP Pool.~~Contracts. WGL has appealed this decision to the Colorado Court of Appeals and on October 11, 2018 the Colorado Court of Appeals reversed the Colorado district court’s decision finding that WGL had adequately pled a claim for relief and ~~that appeal remains pending.~~remanded the case back to the district court for further proceedings.

The Company is also actively engaged in pursuing cover damages against WGL based on WGL’s failure to take receipt of all of the agreed quantities of gas required under the Contracts. WGL’s failure to take the gas volumes specified in the Contracts is directly related to WGL’s lack of primary firm transportation rights at the Delivery Point. The failures by WGL to take the full contracted volumes of gas began in April 2017 and ~~have~~ continued each month ~~since~~through December 2017 in varying quantities. In defense of its conduct, WGL ~~has~~ asserted to the Company that their failure to receive gas is excused by (1) the Company’s failure to deliver gas to the IPP Pool or (2) alleged instances of Force Majeure under the Contracts. However, as stated above, the alleged obligation that the Company must deliver gas to the IPP Pool was already rejected by the arbitration ~~panel and the Colorado district court.~~panel. Further, the Contracts expressly prohibit a Force Majeure claim in circumstances in which the gas purchaser does not have primary firm transportation agreements in place to transport the purchased gas. In each instance that WGL ~~has~~ failed to receive the quantity of gas required under the Contracts, the Company ~~has~~ resold the quantities not taken and invoiced WGL for cover damages pursuant to the terms of the Contracts. WGL ~~has~~ refused to pay for the invoiced cover damages as required by the Contracts and ~~has~~ also short paid the Company for, among other things, certain amounts of gas received by WGL. ~~Through September 30, 2017, these damages amounted to approximately $65 million (gross damages, including interest). This amount has not been accrued in the Company’s financial statements.~~ The Company ~~is currently pursuing its cover damages in~~filed a lawsuit ~~filed~~against WGL in Colorado district court on October 24, ~~2017. WGL’s failure~~2017 to ~~take receipt of all quantities of gas and resulting cover damages remains ongoing. The Company will continue to vigorously seek recovery of~~recover its cover damages, ~~and~~ other unpaid amounts, ~~including interest,~~and interest. WGL’s claims have been consolidated with Antero Resources’ claims in the same district court and trial began on June 10, 2019. WGL quantified its damages claim for the alleged failure to deliver TCO Pool gas and sought approximately $40 million from Antero Resources.

On June 20, 2019, the Company was awarded a jury verdict of approximately $96 million in damages after the jury found that WGL breached the Contracts with the Company. In addition, the jury rejected WGL’s claim against the Company, finding that the Company did not breach the Contracts by allegedly failing to deliver TCO Pool gas and awarding no damages in favor of WGL. On August 16, 2019, WGL appealed the judgment and the appeal is currently pending before the Colorado Court of Appeals.

Effective February 1, 2018, as ~~part~~a result of a recent amendment to its ~~claims against WGL.~~firm gas sales contract with WGL Midstream, Inc. that was executed on December 28, 2017, the total aggregate volumes to be delivered to WGL at the Braxton delivery point were reduced from 500,000 MMBtu/day to 200,000 MMBtu/day and in November 2018, the total aggregate contract volumes to be delivered to WGL at a delivery point in Loudoun County, Virginia increased by 330,000 MMBtu/day. This increase of 330,000 MMBtu/day is in effect for the remaining term of our gas sale contract with WGL Midstream, which expires in 2038, and these increased volumes are subject to NYMEX-based pricing. Following this increase, the aggregate contract volumes delivered to WGL total 530,000 MMBtu/day.

Other

~~Other~~

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

~~(11)Segment Information~~(15) Contract Termination and Rig Stacking

The Company incurred costs associated with the delay or cancellation of drilling and completion contracts with third-party contractors of approximately $8 million for the three months ended March 31, 2019. No such costs were incurred during the three months ended March 31, 2020.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and March 31, 2020

(16) Related Parties

Antero Midstream Partners’ operations comprised substantially all of the operations reflected in the gathering and processing, and water handling and treatment, results through March 12, 2019. Effective March 13, 2019, Antero Resources accounts for Antero Midstream Corporation as an equity method investment. See Note ~~2(f)~~3 to the unaudited condensed consolidated financial statements for more discussion on the Transactions.

Substantially all of the revenues for gathering and processing and water handling and treatment were derived from transactions with Antero Resources. See Note 17 to the unaudited condensed consolidated financial statements for the operating results of the Company’s reportable segments.

(17) Segment Information

See Note 2(l) to the unaudited condensed consolidated financial statements for a description of the Company’s determination of its reportable segments. Revenues from gathering and processing and water handling and treatment operations ~~are~~were primarily derived from intersegment transactions for services provided to the Company’s exploration and production operations prior to the closing of the Transactions. Through March 12, 2019, the results of Antero Midstream Partners were included in the consolidated financial statements of Antero Resources. Effective March 13, 2019, the results of Antero Midstream Partners are no longer consolidated in Antero Resources’ results; however, the Company’s segment disclosures include the results of our unconsolidated affiliates due to their significance to the Company’s operations. See Note 3 to the unaudited condensed consolidated financial statements for further discussion on the Transactions. Marketing revenues are primarily derived from activities to purchase and sell third-party natural gas and NGLs and to market excess firm transportation capacity to third parties.

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 ~~are~~were allocated to the ~~gathering and processing and water handling and treatment segments~~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 ~~are~~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 to the unaudited condensed consolidated financial statements.

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ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, ~~2016~~2019 and ~~September 30, 2017~~March 31, 2020

The operating results and assets of the Company’s reportable segments were as follows for the three months ended ~~September 30, 2016~~March 31, 2019 and ~~2017~~2020 (in thousands):


	Exploration and production		Gathering and processing	Water handling and treatment	Marketing	Elimination of intersegment transactions	Consolidated total
Three months ended September 30, 2016:

												Equity Method		Elimination of
												Investment in		intersegment
								Exploration				Antero		transactions and
								and				Midstream		unconsolidated		Consolidated
								production		Marketing		Corporation		affiliates		total
Three months ended March 31, 2019:
Sales and revenues:
Third-party	$	1,016,458	2,745	224	97,076	—	1,116,503	$	941,635		91,186		4		—		1,032,825
Intersegment		3,990	75,319	72,187	—	(151,496)	—		1,758		—		54,104		(51,280)		4,582
Total	$	1,020,448	78,064	72,411	97,076	(151,496)	1,116,503	$	943,393		91,186		54,108		(51,280)		1,037,407


Operating expenses:
Lease operating	$	13,710	—	28,978	—	(28,834)	13,854	$	42,969		—		11,815		(13,052)		41,732
Gathering, compression, processing, and transportation		303,753	6,400	—	—	(75,238)	234,915		535,015		—		2,935		(113,421)		424,529
Impairment of oil and gas properties									81,244		—		—		—		81,244
Impairment of midstream assets									—		—		6,982		—		6,982
Depletion, depreciation, and amortization		172,735	18,540	7,838	—	—	199,113		218,494		—		7,650		14,057		240,201
General and administrative		44,637	10,282	3,033	—	(375)	57,577		49,908		—		2,184		16,110		68,202
Other		31,266	(1,708)	3,070	114,611	(3,527)	143,712		44,137		163,084		1,291		(288)		208,224
Total		566,101	33,514	42,919	114,611	(107,974)	649,171		971,767		163,084		32,857		(96,594)		1,071,114
Operating income (loss)	$	454,347	44,550	29,492	(17,535)	(43,522)	467,332	$	(28,374)		(71,898)		21,251		45,314		(33,707)
Equity in earnings of unconsolidated affiliates	$	—	1,543	—	—	—	1,543	$	1,817		—		2,880		9,384		14,081
Investments in unconsolidated affiliates								$	1,989,612		—		1,153,943		(1,153,943)		1,989,612
Segment assets	$	12,966,493	1,669,667	562,995	33,114	(603,016)	14,629,253	$	17,263,369		25,361		6,660,325		(6,660,325)		17,288,730
Capital expenditures for segment assets	$	909,837	56,836	58,730	—	(43,343)	982,060	$	399,278		—		16,005		56,650		471,933

Exploration
and
production

Gathering and
processing

Water handling and treatment

Marketing

Elimination of
intersegment
transactions

Consolidated
total

Three months ended September 30, 2017:

Sales and revenues:

Third-party

$
594,244

2,609

260

50,767

—

647,880

Intersegment

3,070

97,909

92,851

—

(193,830)

—

Total

$
597,314

100,518

93,111

50,767

(193,830)

647,880

Operating expenses:

Lease operating

$
24,060

—

51,569

—

(52,138)

23,491

Gathering, compression, processing, and transportation

369,538

10,468

—

—

(97,872)

282,134

Depletion, depreciation, and amortization

176,188

22,027

8,753

—

—

206,968

General and administrative

48,289

9,336

4,980

—

(402)

62,203

Other

65,259

92

3,457

78,884

(2,556)

145,136

Total

683,334

41,923

68,759

78,884

(152,968)

719,932

Operating income (loss)

$
(86,020)

58,595

24,352

(28,117)

(40,862)

(72,052)

Equity in earnings of unconsolidated affiliates

$
—

7,033

—

—

—

7,033

Segment assets

$
12,751,606

2,158,107

752,982

15,807

(829,288)

14,849,214

Capital expenditures for segment assets

$
415,088

99,254

48,019

—

(40,704)

521,657

Table of Contents

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, ~~2016~~2019 and ~~September 30, 2017~~March 31, 2020


					Equity Method		Elimination of
					Investment in		intersegment
	Exploration				Antero		transactions and
	and				Midstream		unconsolidated		Consolidated
	production		Marketing		Corporation		affiliates		total
Three months ended March 31, 2020:
Sales and revenues:
Third-party	$	1,270,234		46,073		—		—		1,316,307
Intersegment		798		—		243,708		(243,708)		798
Total	$	1,271,032		46,073		243,708		(243,708)		1,317,105

Operating expenses:
Lease operating	$	25,644		—		—		—		25,644
Gathering, compression, processing, and transportation		588,624		—		55,908		(55,908)		588,624
Impairment of oil and gas properties		89,220		—		—		—		89,220
Impairment of midstream assets		—		—		664,544		(664,544)		—
Depletion, depreciation, and amortization		199,677		—		27,343		(27,343)		199,677
General and administrative		31,221		—		10,199		(10,199)		31,221
Other		27,013		93,273		4,878		(4,878)		120,286
Total		961,399		93,273		762,872		(762,872)		1,054,672
Operating income (loss)	$	309,633		(47,200)		(519,164)		519,164		262,433
Equity in earnings (loss) of unconsolidated affiliates	$	(128,055)		—		19,077		(19,077)		(128,055)
Investments in unconsolidated affiliates	$	291,989		—		716,778		(716,778)		291,989
Segment assets	$	14,516,150		9,639		5,781,359		(5,781,359)		14,525,789
Capital expenditures for segment assets	$	311,611		—		67,983		(67,983)		311,611

~~The operating results and assets~~

(18) Subsidiary Guarantors

Each of the Company’s ~~reportable segments were as follows for the nine months ended September 30, 2016 and 2017 (in thousands):~~

Exploration
and
production

Gathering and
processing

Water handling and treatment

Marketing

Elimination of
intersegment
transactions

Consolidated
total

Nine months ended September 30, 2016:

Sales and revenues:

Third-party

$
1,291,008

9,463

644

287,194

—

1,588,309

Intersegment

11,714

210,144

203,106

—

(424,964)

—

Total

$
1,302,722

219,607

203,750

287,194

(424,964)

1,588,309

Operating expenses:

Lease operating

$
37,299

—

104,009

—

(104,118)

37,190

Gathering, compression, processing, and transportation

838,936

20,567

—

—

(209,790)

649,713

Depletion, depreciation, and amortization

513,302

52,780

21,975

—

—

588,057

General and administrative

135,356

29,755

9,957

—

(1,102)

173,966

Other

104,279

(809)

11,568

378,521

(10,384)

483,175

Total

1,629,172

102,293

147,509

378,521

(325,394)

1,932,101

Operating income (loss)

$
(326,450)

117,314

56,241

(91,327)

(99,570)

(343,792)

Equity in earnings of unconsolidated affiliates

$
—

2,027

—

—

—

2,027

Segment assets

$
12,966,493

1,669,667

562,995

33,114

(603,016)

14,629,253

Capital expenditures for segment assets

$
1,734,914

154,136

137,355

—

(98,955)

1,927,450

Exploration
and
production

Gathering and
processing

Water handling and treatment

Marketing

Elimination of
intersegment
transactions

Consolidated
total

Nine months ended September 30, 2017:

Sales and revenues:

Third-party

$
2,458,524

7,472

1,193

166,659

—

2,633,848

Intersegment

11,421

283,467

270,033

—

(564,921)

—

Total

$
2,469,945

290,939

271,226

166,659

(564,921)

2,633,848

Operating expenses:

Lease operating

$
56,991

—

131,635

—

(132,592)

56,034

Gathering, compression, processing, and transportation

1,070,522

28,492

—

—

(283,304)

815,710

Depletion, depreciation, and amortization

521,603

64,445

24,831

—

—

610,879

General and administrative

148,876

30,179

13,383

—

(1,438)

191,000

Other

158,128

104

12,333

246,298

(9,672)

407,191

Total

1,956,120

123,220

182,182

246,298

(427,006)

2,080,814

Operating income (loss)

$
513,825

167,719

89,044

(79,639)

(137,915)

553,034

Equity in earnings of unconsolidated affiliates

$
—

12,887

—

—

—

12,887

Segment assets

$
12,751,606

2,158,107

752,982

15,807

(829,288)

14,849,214

Capital expenditures for segment assets

$
1,456,870

254,619

143,470

—

(137,420)

1,717,539

~~(12)Subsidiary Guarantors~~

~~Each of Antero’s wholly-owned~~wholly owned subsidiaries has fully and unconditionally guaranteed ~~Antero’s~~Antero Resources’ senior notes. Antero Midstream and its subsidiaries have been designated as unrestricted subsidiaries under the Credit Facility and the indentures governing Antero’s senior notes, and do not guarantee any of Antero’s obligations (see Note 5). 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 ~~the Company~~Antero (as defined in the indentures governing the notes) or the sale of all or substantially all of its assets (other than by lease))

~~Table of Contents~~

~~ANTERO RESOURCES CORPORATION~~

~~Notes to Condensed Consolidated Financial Statements~~

~~December 31, 2016 and September 30, 2017~~

and whether or not the subsidiary guarantor is the surviving entity in such transaction to a person ~~which~~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 Condensed Consolidating Balance Sheets at December 31, ~~2016~~2019 and ~~September 30, 2017,~~March 31, 2020, and the related Condensed Consolidating Statements of Operations and Comprehensive Income (Loss) for the three ~~and nine~~ months ended ~~September 30, 2016~~March 31, 2019 and ~~2017~~2020, and Condensed Consolidating Statements of Cash Flows for the ~~nine~~three months ended ~~September 30, 2016~~March 31, 2019 and ~~2017~~2020 present financial information for Antero Resources on a stand-alone basis (carrying its investment in subsidiaries using the equity method), financial information for the subsidiary guarantors, financial information for the non-guarantor subsidiaries, and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis. ~~Antero’s wholly-owned~~The Company’s wholly owned subsidiaries are not restricted from making distributions to the ~~Parent.~~

Company.

Table of Contents

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, ~~2016~~2019 and ~~September 30, 2017~~March 31, 2020

Condensed Consolidating Balance Sheet

December 31, ~~2016~~2019

(In thousands)


	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations		Consolidated

											Parent		Guarantor		Non-Guarantor
											(Antero)		Subsidiaries		Subsidiaries		Eliminations		Consolidated
Assets
Current assets:
Cash and cash equivalents	$	17,568		—		14,042		—		31,610
Accounts receivable, net		28,442		—		1,240		—		29,682	$	46,419		—		—		—		46,419
Intercompany receivables		3,193		—		64,139		(67,332)		—
Accounts receivable, related parties												125,000		299,450		—		(299,450)		125,000
Accrued revenue		261,960		—		—		—		261,960		317,886		—		—		—		317,886
Derivative instruments		73,022		—		—		—		73,022		422,849		—		—		—		422,849
Other current assets		5,784		—		529		—		6,313		10,731		—		—		—		10,731
Total current assets		389,969		—		79,950		(67,332)		402,587		922,885		299,450		—		(299,450)		922,885
Property and equipment:
Natural gas properties, at cost (successful efforts method):
Oil and gas properties, at cost (successful efforts method):
Unproved properties		2,331,173		—		—		—		2,331,173		1,368,854		—		—		—		1,368,854
Proved properties		9,726,957		—		—		(177,286)		9,549,671		11,859,817		—		—		—		11,859,817
Water handling and treatment systems		—		—		744,682		—		744,682
Gathering systems and facilities		17,929		—		1,705,839		—		1,723,768		5,802		—		—		—		5,802
Other property and equipment		41,231		—		—		—		41,231		71,895		—		—		—		71,895
		12,117,290		—		2,450,521		(177,286)		14,390,525
												13,306,368		—		—		—		13,306,368
Less accumulated depletion, depreciation, and amortization		(2,109,136)		—		(254,642)		—		(2,363,778)		(3,327,629)		—		—		—		(3,327,629)
Property and equipment, net		10,008,154		—		2,195,879		(177,286)		12,026,747		9,978,739		—		—		—		9,978,739
Operating leases right-of-use assets												2,886,500		—		—		—		2,886,500
Derivative instruments		1,731,063		—		—		—		1,731,063		333,174		—		—		—		333,174
Investments in subsidiaries		(420,429)		—		—		420,429		—
Contingent acquisition consideration		194,538		—		—		(194,538)		—
Investments in unconsolidated affiliates		—		—		68,299		—		68,299		243,048		812,129		—		—		1,055,177
Other assets, net		21,087		—		5,767		—		26,854
Investments in consolidated affiliates												812,129		—		—		(812,129)		—
Other assets												21,094		—		—		—		21,094
Total assets	$	11,924,382		—		2,349,895		(18,727)		14,255,550	$	15,197,569		1,111,579		—		(1,111,579)		15,197,569


Liabilities and Equity
Current liabilities:
Accounts payable	$	21,648		—		16,979		—		38,627	$	14,498		—		—		—		14,498
Intercompany payable		64,139		—		3,193		(67,332)		—
Accounts payable, related parties												397,333		—		—		(299,450)		97,883
Accrued liabilities		332,162		—		61,641		—		393,803		400,850		—		—		—		400,850
Revenue distributions payable		163,989		—		—		—		163,989		207,988		—		—		—		207,988
Derivative instruments		203,635		—		—		—		203,635		6,721		—		—		—		6,721
Short-term lease liabilities												305,320		—		—		—		305,320
Other current liabilities		17,134		—		200		—		17,334		6,879		—		—		—		6,879
Total current liabilities		802,707		—		82,013		(67,332)		817,388		1,339,589		—		—		(299,450)		1,040,139
Long-term liabilities:
Long-term debt		3,854,059		—		849,914		—		4,703,973		3,758,868		—		—		—		3,758,868
Deferred income tax liability		950,217		—		—		—		950,217		781,987		—		—		—		781,987
Contingent acquisition consideration		—		—		194,538		(194,538)		—
Derivative instruments		234		—		—		—		234		3,519		—		—		—		3,519
Long-term lease liabilities												2,583,678		—		—		—		2,583,678
Other liabilities		54,540		—		620		—		55,160		58,635		—		—		—		58,635
Total liabilities		5,661,757		—		1,127,085		(261,870)		6,526,972		8,526,276		—		—		(299,450)		8,226,826
Equity:
Stockholders' equity:
Partners' capital		—		—		1,222,810		(1,222,810)		—
Common stock		3,149		—		—		—		3,149		2,959		—		—		—		2,959
Additional paid-in capital		5,299,481		—		—		—		5,299,481		5,600,714		1,341,780		—		(812,129)		6,130,365
Accumulated earnings		959,995		—		—		—		959,995		1,067,620		(230,201)		—		—		837,419
Total stockholders' equity		6,262,625		—		1,222,810		(1,222,810)		6,262,625		6,671,293		1,111,579		—		(812,129)		6,970,743
Noncontrolling interest in consolidated subsidiary		—		—		—		1,465,953		1,465,953
Total equity		6,262,625		—		1,222,810		243,143		7,728,578
Total liabilities and equity	$	11,924,382		—		2,349,895		(18,727)		14,255,550	$	15,197,569		1,111,579		—		(1,111,579)		15,197,569

Table of Contents

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, ~~2016~~2019 and ~~September 30, 2017~~March 31, 2020

Condensed Consolidating Balance Sheet

~~September 30, 2017~~

March 31, 2020
(In thousands)


	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations		Consolidated

											Parent		Guarantor		Non-Guarantor
											(Antero)		Subsidiaries		Subsidiaries		Eliminations		Consolidated
Assets
Current assets:
Cash and cash equivalents	$	21,199		—		2,495		—		23,694
Accounts receivable, net		42,689		—		1,165		—		43,854
Intercompany receivables		4,050		—		84,124		(88,174)		—
Accounts receivable											$	91,944		—		—		—		91,944
Accounts receivable, related parties												—		332,353		—		(332,353)		—
Accrued revenue		233,585		—		—		—		233,585		201,320		—		—		—		201,320
Derivative instruments		299,796		—		—		—		299,796		816,444		—		—		—		816,444
Other current assets		9,011		—		1,013		—		10,024		10,313		—		—		—		10,313
Total current assets		610,330		—		88,797		(88,174)		610,953		1,120,021		332,353		—		(332,353)		1,120,021
Property and equipment:
Natural gas properties, at cost (successful efforts method):
Oil and gas properties, at cost (successful efforts method):
Unproved properties		2,305,749		—		—		—		2,305,749		1,289,770		—		—		—		1,289,770
Proved properties		11,093,749		—		—		(314,706)		10,779,043		12,154,162		—		—		—		12,154,162
Water handling and treatment systems		—		—		891,869		—		891,869
Gathering systems and facilities		17,929		—		1,959,581		—		1,977,510		5,802		—		—		—		5,802
Other property and equipment		54,571		—	��	—		—		54,571		72,312		—		—		—		72,312
		13,471,998		—		2,851,450		(314,706)		16,008,742
												13,522,046		—		—		—		13,522,046
Less accumulated depletion, depreciation, and amortization		(2,630,298)		—		(343,246)		—		(2,973,544)		(3,527,306)		—		—		—		(3,527,306)
Property and equipment, net		10,841,700		—		2,508,204		(314,706)		13,035,198		9,994,740		—		—		—		9,994,740
Operating leases right-of-use assets												2,814,539		—		—		—		2,814,539
Derivative instruments		876,293		—		—		—		876,293		284,461		—		—		—		284,461
Investments in subsidiaries		488,089		—		—		(488,089)		—
Contingent acquisition consideration		204,210		—		—		(204,210)		—
Investments in unconsolidated affiliates		—		—		287,842		—		287,842		67,289		224,700		—		—		291,989
Other assets, net		28,380		—		10,548		—		38,928
Investments in consolidated affiliates												224,700		—		—		(224,700)		—
Other assets												20,039		—		—		—		20,039
Total assets	$	13,049,002		—		2,895,391		(1,095,179)		14,849,214	$	14,525,789		557,053		—		(557,053)		14,525,789

Liabilities and Equity
Current liabilities:
Accounts payable	$	33,637		—		13,820		—		47,457	$	37,909		—		—		—		37,909
Intercompany payable		84,124		—		4,050		(88,174)		—
Accounts payable, related parties												421,247		—		—		(332,353)		88,894
Accrued liabilities		359,164		—		70,532		—		429,696		367,444		—		—		—		367,444
Revenue distributions payable		220,971		—		—		—		220,971		174,654		—		—		—		174,654
Derivative instruments		4,285		—		—		—		4,285
Short-term lease liabilities												295,658		—		—		—		295,658
Other current liabilities		15,061		—		206		—		15,267		7,315		—		—		—		7,315
Total current liabilities		717,242		—		88,608		(88,174)		717,676		1,304,227		—		—		(332,353)		971,874
Long-term liabilities:																		—
Long-term debt		3,442,799		—		1,067,722		—		4,510,521		3,707,787		—		—		—		3,707,787
Deferred income tax liability		1,180,564		—		—		—		1,180,564		672,002		—		—		—		672,002
Contingent acquisition consideration		—		—		204,210		(204,210)		—
Derivative instruments		427		—		—		—		427		215		—		—		—		215
Long-term lease liabilities												2,520,939				—		—		2,520,939
Other liabilities		52,299		—		465		—		52,764		60,432		—		—		—		60,432
Total liabilities		5,393,331		—		1,361,005		(292,384)		6,461,952		8,265,602		—		—		(332,353)		7,933,249
Equity:
Stockholders' equity:																		—
Partners' capital		—		—		1,534,386		(1,534,386)		—
Common stock		3,155		—		—		—		3,155		2,689		—		—		—		2,689
Additional paid-in capital		6,564,320		—		—		—		6,564,320		4,974,162		1,341,780		—		(224,700)		6,091,242
Accumulated earnings		1,088,196		—		—		—		1,088,196		1,283,336		(784,727)		—		—		498,609
Total stockholders' equity		7,655,671		—		1,534,386		(1,534,386)		7,655,671		6,260,187		557,053		—		(224,700)		6,592,540
Noncontrolling interests in consolidated subsidiary		—		—		—		731,591		731,591
Total equity		7,655,671		—		1,534,386		(802,795)		8,387,262
Total liabilities and equity	$	13,049,002		—		2,895,391		(1,095,179)		14,849,214	$	14,525,789		557,053		—		(557,053)		14,525,789

Table of Contents

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, ~~2016~~2019 and ~~September 30, 2017~~March 31, 2020

Condensed Consolidating Statement of Operations and Comprehensive Income

Three Months Ended March 31, 2019
(In thousands)


	Parent		Guarantor		Non-Guarantor
	(Antero)		Subsidiaries		Subsidiaries		Eliminations		Consolidated
Revenue and other:
Natural gas sales	$	657,266		—		—		—		657,266
Natural gas liquids sales		313,685		—		—		—		313,685
Oil sales		48,052		—		—		—		48,052
Commodity derivative fair value losses		(77,368)		—		—		—		(77,368)
Gathering, compression, water handling and treatment		—		—		218,360		(213,881)		4,479
Marketing		91,186		—		—		—		91,186
Other income		1,758		—		—		(1,651)		107
Total revenue and other		1,034,579		—		218,360		(215,532)		1,037,407
Operating expenses:
Lease operating		42,969		—		64,818		(66,055)		41,732
Gathering, compression, processing, and transportation		535,015		—		—		(110,486)		424,529
Production and ad valorem taxes		34,738		—		—		940		35,678
Marketing		163,084		—		—		—		163,084
Exploration		126		—		—		—		126
Impairment of oil and gas properties		81,244		—		—		—		81,244
Impairment of midstream assets		—		—		6,982		—		6,982
Depletion, depreciation, and amortization		218,494		—		21,707		—		240,201
Accretion of asset retirement obligations		913		—		63		—		976
General and administrative		49,908		—		18,793		(499)		68,202
Contract termination and rig stacking		8,360		—		—		—		8,360
Accretion of contingent acquisition consideration		—		—		1,928		(1,928)		—
Total operating expenses		1,134,851		—		114,291		(178,028)		1,071,114
Operating income (loss)		(100,272)		—		104,069		(37,504)		(33,707)
Other income (expenses):
Equity in earnings of unconsolidated affiliates		589		1,228		12,264		—		14,081
Equity in earnings of affiliates		15,021		—		—		(15,021)		—
Interest expense, net		(55,135)		—		(16,815)		—		(71,950)
Gain on deconsolidation of Antero Midstream Partners LP		1,205,705		200,337		—		—		1,406,042
Total other expenses		1,166,180		201,565		(4,551)		(15,021)		1,348,173
Income before income taxes		1,065,908		201,565		99,518		(52,525)		1,314,466
Provision for income tax expense		(288,710)		—		—		—		(288,710)
Net income and comprehensive income including noncontrolling interests		777,198		201,565		99,518		(52,525)		1,025,756
Net income and comprehensive income attributable to noncontrolling interests		—		—		—		46,993		46,993
Net income and comprehensive income attributable to Antero Resources Corporation	$	777,198		201,565		99,518		(99,518)		978,763

Table of Contents

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2019 and March 31, 2020

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss)

Three Months Ended ~~September 30, 2016~~

March 31, 2020
(In thousands)


	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations		Consolidated
Revenue:

											Parent		Guarantor		Non-Guarantor
											(Antero)		Subsidiaries		Subsidiaries		Eliminations		Consolidated
Revenue and other:
Natural gas sales	$	364,373		—		—		—		364,373	$	411,082		—		—		—		411,082
Natural gas liquids sales		106,958		—		—		—		106,958		257,673		—		—		—		257,673
Oil sales		14,793		—		—		—		14,793		35,646		—		—		—		35,646
Gathering, compression, water handling and treatment		—		—		150,475		(147,506)		2,969
Commodity derivative fair value gains												565,833		—		—		—		565,833
Marketing		97,076		—		—		—		97,076		46,073		—		—		—		46,073
Commodity derivative fair value gains		530,334		—		—		—		530,334
Other income		3,990		—		—		(3,990)		—		798		—		—		—		798
Total revenue		1,117,524		—		150,475		(151,496)		1,116,503
Total revenue and other												1,317,105		—		—		—		1,317,105
Operating expenses:
Lease operating		13,710		—		28,978		(28,834)		13,854		25,644		—		—		—		25,644
Gathering, compression, processing, and transportation		303,753		—		6,400		(75,238)		234,915		588,624		—		—		—		588,624
Production and ad valorem taxes		17,719		—		(2,165)		—		15,554		25,699		—		—		—		25,699
Marketing		114,611		—		—		—		114,611		93,273		—		—		—		93,273
Exploration		1,166		—		—		—		1,166		210		—		—		—		210
Impairment of unproved properties		11,753		—		—		—		11,753
Impairment of oil and gas properties												89,220		—		—		—		89,220
Depletion, depreciation, and amortization		172,976		—		26,137		—		199,113		199,677		—		—		—		199,677
Accretion of asset retirement obligations		628		—		—		—		628		1,104		—		—		—		1,104
General and administrative		44,637		—		13,315		(375)		57,577		31,221		—		—		—		31,221
Accretion of contingent acquisition consideration		—		—		3,527		(3,527)		—
Total operating expenses		680,953		—		76,192		(107,974)		649,171		1,054,672		—		—		—		1,054,672
Operating income		436,571		—		74,283		(43,522)		467,332		262,433		—		—		—		262,433
Other income (expenses):			��
Equity in earnings of unconsolidated affiliates		—		—		1,543		—		1,543
Interest		(54,631)		—		(5,303)		179		(59,755)
Equity in net income of subsidiaries		(2,761)		—		—		2,761		—
Equity in earnings of unconsolidated affiliate												(40,312)		(87,743)		—		—		(128,055)
Impairment of equity investment												(143,849)		(466,783)		—		—		(610,632)
Interest expense, net												(53,102)		—		—		—		(53,102)
Gain on early extinguishment of debt												80,561		—		—		—		80,561
Total other expenses		(57,392)		—		(3,760)		2,940		(58,212)		(156,702)		(554,526)		—		—		(711,228)
Income before income taxes		379,179		—		70,523		(40,582)		409,120
Provision for income tax expense		(140,924)		—		—		—		(140,924)
Net income and comprehensive income including noncontrolling interests		238,255		—		70,523		(40,582)		268,196
Net income and comprehensive income attributable to noncontrolling interests		—		—		—		29,941		29,941
Net income and comprehensive income attributable to Antero Resources Corporation	$	238,255		—		70,523		(70,523)		238,255
Income (loss) before income taxes												105,731		(554,526)		—		—		(448,795)
Provision for income tax benefit												109,985		—		—		—		109,985
Net income (loss) and comprehensive income (loss)											$	215,716		(554,526)		—		—		(338,810)

Table of Contents

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, ~~2016~~2019 and ~~September 30, 2017~~March 31, 2020

Condensed Consolidating Statement of ~~Operations and Comprehensive Income (Loss)~~

Cash Flows
Three Months Ended ~~September 30, 2017~~

March 31, 2019
(In thousands)

Parent

Guarantor
Subsidiaries

Non-Guarantor
Subsidiaries

Eliminations

Consolidated

Revenue:

Natural gas sales

$
409,141

—

—

—

409,141

Natural gas liquids sales

224,533

—

—

—

224,533

Oil sales

26,527

—

—

—

26,527

Gathering, compression, water handling and treatment

—

—

193,629

(190,760)

2,869

Marketing

50,767

—

—

—

50,767

Commodity derivative fair value losses

(65,957)

—

—

—

(65,957)

Other income

3,070

—

—

(3,070)

—

Total revenue

648,081

—

193,629

(193,830)

647,880

Operating expenses:

Lease operating

24,060

—

51,569

(52,138)

23,491

Gathering, compression, processing, and transportation

369,538

—

10,468

(97,872)

282,134

Production and ad valorem taxes

22,002

—

993

—

22,995

Marketing

78,884

—

—

—

78,884

Exploration

1,599

—

—

—

1,599

Impairment of unproved properties

41,000

—

—

—

41,000

Depletion, depreciation, and amortization

176,412

—

30,556

—

206,968

Accretion of asset retirement obligations

658

—

—

—

658

General and administrative

48,289

—

14,316

(402)

62,203

Accretion of contingent acquisition consideration

—

—

2,556

(2,556)

—

Total operating expenses

762,442

—

110,458

(152,968)

719,932

Operating income (loss)

(114,361)

—

83,171

(40,862)

(72,052)

Other income (expenses):

Equity in earnings of unconsolidated affiliates

—

—

7,033

—

7,033

Interest

(60,906)

—

(9,311)

158

(70,059)

Equity in net income (loss) of subsidiaries

(4,874)

—

—

4,874

—

Total other expenses

(65,780)

—

(2,278)

5,032

(63,026)

Income (loss) before income taxes

(180,141)

—

80,893

(35,830)

(135,078)

Provision for income tax benefit

45,078

—

—

—

45,078

Net income (loss) and comprehensive income (loss) including noncontrolling interests

(135,063)

—

80,893

(35,830)

(90,000)

Net income and comprehensive income attributable to noncontrolling interests

—

—

—

45,063

45,063

Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation

$
(135,063)

—

80,893

(80,893)

(135,063)


	Parent		Guarantor		Non-Guarantor
	(Antero)		Subsidiaries		Subsidiaries		Eliminations		Consolidated
Cash flows provided by (used in) operating activities:
Net income including noncontrolling interests	$	777,198		201,565		99,518		(52,525)		1,025,756
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, amortization, and accretion		219,407		—		21,770		—		241,177
Impairments		81,244		—		6,982		—		88,226
Commodity derivative fair value losses		77,368		—		—		—		77,368
Gains on settled commodity derivatives		97,092		—		—		—		97,092
Deferred income tax expense		287,854		—		—		—		287,854
Equity-based compensation expense		6,426		—		2,477		—		8,903
Equity in earnings of consolidated subsidiaries		(15,021)		—		—		15,021		—
Equity in earnings of unconsolidated affiliates		(589)		(1,228)		(12,264)		—		(14,081)
Distributions of earnings from unconsolidated affiliates		—		—		12,605		—		12,605
Gain on deconsolidation of Antero Midstream Partners LP		(1,205,705)		(200,337)		—		—		(1,406,042)
Distributions from Antero Midstream Partners LP		46,469		—		—		(46,469)		—
Other		10,331		—		750		—		11,081
Changes in current assets and liabilities		102,830		—		(10,573)		16,808		109,065
Net cash provided by operating activities		484,904		—		121,265		(67,165)		539,004
Cash flows provided by (used in) investing activities:
Additions to unproved properties		(27,463)		—		—		—		(27,463)
Drilling and completion costs		(389,252)		—		—		20,565		(368,687)
Additions to water handling and treatment systems		—		—		(24,547)		131		(24,416)
Additions to gathering systems and facilities		—		—		(48,239)		—		(48,239)
Additions to other property and equipment		(2,066)		—		(1,062)		—		(3,128)
Investments in unconsolidated affiliates		—		—		(25,020)		—		(25,020)
Proceeds from the Antero Midstream Partners LP Transactions		296,611		—		—		—		296,611
Change in other assets		(1,118)		—		(3,357)		—		(4,475)
Net cash used in investing activities		(123,288)		—		(102,225)		20,696		(204,817)
Cash flows provided by (used in) financing activities:
Issuance of senior notes		—		—		650,000		—		650,000
Borrowings (repayments) on bank credit facility, net		(360,379)		—		90,379		—		(270,000)
Payments of deferred financing costs		(791)		—		(7,468)		—		(8,259)
Distributions to noncontrolling interests in Antero Midstream Partners LP		—		—		(131,545)		46,469		(85,076)
Employee tax withholding for settlement of equity compensation awards		(450)		—		(29)		—		(479)
Other		4		—		(845)		—		(841)
Net cash provided by (used in) financing activities		(361,616)		—		600,492		46,469		285,345
Effect of deconsolidation of Antero Midstream Partners LP		—		—		(619,532)		—		(619,532)
Net increase (decrease) in cash and cash equivalents		—		—		—		—		—
Cash and cash equivalents, beginning of period		—		—		—		—		—
Cash and cash equivalents, end of period	$	—		—		—		—		—

Table of Contents

ANTERO RESOURCES CORPORATION

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, ~~2016~~2019 and ~~September 30, 2017~~

March 31, 2020

~~Condensed Consolidating Statement of Operations and Comprehensive Income (Loss)~~

~~Nine Months Ended September 30, 2016~~

~~(In thousands)~~

Parent

Guarantor
Subsidiaries

Non-Guarantor
Subsidiaries

Eliminations

Consolidated

Revenue and other:

Natural gas sales

$
848,936

—

—

—

848,936

Natural gas liquids sales

274,736

—

—

—

274,736

Oil sales

41,712

—

—

—

41,712

Gathering, compression, water handling and treatment

—

—

423,357

(413,250)

10,107

Marketing

287,194

—

—

—

287,194

Commodity derivative fair value gains

125,624

—

—

—

125,624

Other income

11,714

—

—

(11,714)

—

Total revenue and other

1,589,916

—

423,357

(424,964)

1,588,309

Operating expenses:

Lease operating

37,299

—

104,009

(104,118)

37,190

Gathering, compression, processing, and transportation

838,936

—

20,567

(209,790)

649,713

Production and ad valorem taxes

51,921

—

375

—

52,296

Marketing

378,521

—

—

—

378,521

Exploration

3,289

—

—

—

3,289

Impairment of unproved properties

47,223

—

—

—

47,223

Depletion, depreciation, and amortization

513,957

—

74,100

—

588,057

Accretion of asset retirement obligations

1,846

—

—

—

1,846

General and administrative

135,356

—

39,712

(1,102)

173,966

Accretion of contingent acquisition consideration

—

—

10,384

(10,384)

—

Total operating expenses

2,008,348

—

249,147

(325,394)

1,932,101

Operating income (loss)

(418,432)

—

174,210

(99,570)

(343,792)

Other income (expenses):

Equity in earnings of unconsolidated affiliates

—

—

2,027

—

2,027

Interest

(173,364)

—

(12,885)

615

(185,634)

Equity in net income of subsidiaries

(2,003)

—

—

2,003

—

Total other expenses

(175,367)

—

(10,858)

2,618

(183,607)

Income (loss) before income taxes

(593,799)

—

163,352

(96,952)

(527,399)

Provision for income tax benefit

230,755

—

—

—

230,755

Net income (loss) and comprehensive income (loss) including noncontrolling interests

(363,044)

—

163,352

(96,952)

(296,644)

Net income and comprehensive income attributable to noncontrolling interests

—

—

—

66,400

66,400

Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation

$
(363,044)

—

163,352

(163,352)

(363,044)

~~Table of Contents~~

~~ANTERO RESOURCES CORPORATION~~

~~Notes to Condensed Consolidated Financial Statements~~

~~December 31, 2016 and September 30, 2017~~

~~Condensed Consolidating Statement of Operations and Comprehensive Income~~

~~Nine Months Ended September 30, 2017~~

~~(In thousands)~~

Parent

Guarantor
Subsidiaries

Non-Guarantor
Subsidiaries

Eliminations

Consolidated

Revenue and other:

Natural gas sales

$
1,330,062

—

—

—

1,330,062

Natural gas liquids sales

590,004

—

—

—

590,004

Oil sales

79,999

—

—

—

79,999

Gathering, compression, water handling and treatment

—

—

562,165

(553,500)

8,665

Marketing

166,659

—

—

—

166,659

Commodity derivative fair value gains

458,459

—

—

—

458,459

Other income

11,421

—

—

(11,421)

—

Total revenue and other

2,636,604

—

562,165

(564,921)

2,633,848

Operating expenses:

Lease operating

56,991

—

131,635

(132,592)

56,034

Gathering, compression, processing, and transportation

1,070,522

—

28,492

(283,304)

815,710

Production and ad valorem taxes

67,576

—

2,765

—

70,341

Marketing

246,298

—

—

—

246,298

Exploration

5,510

—

—

—

5,510

Impairment of unproved properties

83,098

—

—

—

83,098

Depletion, depreciation, and amortization

522,275

—

88,604

—

610,879

Accretion of asset retirement obligations

1,944

—

—

—

1,944

General and administrative

148,876

—

43,562

(1,438)

191,000

Accretion of contingent acquisition consideration

—

—

9,672

(9,672)

—

Total operating expenses

2,203,090

—

304,730

(427,006)

2,080,814

Operating income

433,514

—

257,435

(137,915)

553,034

Other income (expenses):

Equity in earnings of unconsolidated affiliates

—

—

12,887

—

12,887

Interest

(178,644)

—

(27,162)

495

(205,311)

Equity in net income of subsidiaries

(21,582)

—

—

21,582

—

Total other expenses

(200,226)

—

(14,275)

22,077

(192,424)

Income before income taxes

233,288

—

243,160

(115,838)

360,610

Provision for income tax expense

(105,087)

—

—

—

(105,087)

Net income and comprehensive income including noncontrolling interests

128,201

—

243,160

(115,838)

255,523

Net income and comprehensive income attributable to noncontrolling interests

—

—

—

127,322

127,322

Net income and comprehensive income attributable to Antero Resources Corporation

$
128,201

—

243,160

(243,160)

128,201

~~Table of Contents~~

~~ANTERO RESOURCES CORPORATION~~

~~Notes to Condensed Consolidated Financial Statements~~

~~December 31, 2016 and September 30, 2017~~

Condensed Consolidating Statement of Cash Flows

~~Nine~~
Three Months Ended ~~September 30, 2016~~March 31, 2020

(In thousands)

Parent

Guarantor
Subsidiaries

Non-Guarantor
Subsidiaries

Eliminations

Consolidated

Net cash provided by operating activities

$
745,517

—

259,135

(98,955)

905,697

Cash flows used in investing activities:

Additions to proved properties

(64,789)

—

—

—

(64,789)

Additions to unproved properties

(559,572)

—

—

—

(559,572)

Drilling and completion costs

(1,108,806)

—

—

98,955

(1,009,851)

Additions to water handling and treatment systems

—

—

(137,355)

—

(137,355)

Additions to gathering systems and facilities

(1,367)

—

(152,769)

—

(154,136)

Additions to other property and equipment

(1,747)

—

—

—

(1,747)

Investments in unconsolidated affiliates

—

—

(45,044)

—

(45,044)

Change in other assets

236

—

(2,409)

—

(2,173)

Distributions from non-guarantor subsidiary

78,514

—

—

(78,514)

—

Net cash used in investing activities

(1,657,531)

—

(337,577)

20,441

(1,974,667)

Cash flows provided by financing activities:

Issuance of common stock

837,414

—

—

—

837,414

Issuance of common units by Antero Midstream Partners LP

—

—

19,605

—

19,605

Sale of common units in Antero Midstream Partners LP by Antero Resources Corporation

178,000

—

—

—

178,000

Issuance of senior notes

—

—

650,000

—

650,000

Repayments on bank credit facility, net

(102,000)

—

(450,000)

—

(552,000)

Payments of deferred financing costs

(89)

—

(8,940)

—

(9,029)

Distributions

—

—

(129,752)

78,514

(51,238)

Employee tax withholding for settlement of equity compensation awards

(4,859)

—

(17)

—

(4,876)

Other

(3,751)

—

(116)

—

(3,867)

Net cash provided by financing activities

904,715

—

80,780

78,514

1,064,009

Net increase (decrease) in cash and cash equivalents

(7,299)

—

2,338

—

(4,961)

Cash and cash equivalents, beginning of period

16,590

—

6,883

—

23,473

Cash and cash equivalents, end of period

$
9,291

—

9,221

—

18,512


	Parent		Guarantor		Non-Guarantor
	(Antero)		Subsidiaries		Subsidiaries		Eliminations		Consolidated
Cash flows provided by (used in) operating activities:
Net income (loss) including noncontrolling interests	$	215,716		(554,526)		—		—		(338,810)
Adjustment to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, amortization, and accretion		200,781		—		—		—		200,781
Impairment of oil and gas properties		89,220		—		—		—		89,220
Commodity derivative fair value gains		(565,833)		—		—		—		(565,833)
Gains on settled commodity derivatives		210,926		—		—		—		210,926
Equity-based compensation expense		3,329		—		—		—		3,329
Deferred income tax benefit		(109,985)		—		—		—		(109,985)
Gain on early extinguishment of debt		(80,561)		—		—		—		(80,561)
Equity in loss of unconsolidated affiliates		40,312		87,743		—		—		128,055
Impairment of equity investment		143,849		466,783		—		—		610,632
Distributions/dividends of earnings from unconsolidated affiliates		42,756		—		—		—		42,756
Other		2,440		—		—		—		2,440
Changes in current assets and liabilities		7,727		—		—		—		7,727
Net cash provided by operating activities		200,677		—		—		—		200,677
Cash flows provided by (used in) investing activities:
Additions to unproved properties		(10,357)		—		—		—		(10,357)
Drilling and completion costs		(300,483)		—		—		—		(300,483)
Additions to other property and equipment		(771)		—		—		—		(771)
Settlement of water earnout		125,000		—		—		—		125,000
Change in other assets		(70)		—		—		—		(70)
Net cash used in investing activities		(186,681)		—		—		—		(186,681)
Cash flows provided by (used in) financing activities:
Repurchases of common stock		(42,690)		—		—		—		(42,690)
Repayment of senior notes		(300,835)		—		—		—		(300,835)
Borrowings on bank credit facility, net		330,000		—		—		—		330,000
Employee tax withholding for settlement of equity compensation awards		(32)		—		��		—		(32)
Other		(439)		—		—		—		(439)
Net cash used in financing activities		(13,996)		—		—		—		(13,996)
Net increase in cash and cash equivalents		—		—		—		—		—
Cash and cash equivalents, beginning of period		—		—		—		—		—
Cash and cash equivalents, end of period	$	—		—		—		—		—

3339

Table of Contents

~~ANTERO RESOURCES CORPORATION~~

~~Notes to Condensed Consolidated Financial Statements~~

~~December 31, 2016 and September 30, 2017~~

~~Condensed Consolidating Statement of Cash Flows~~

~~Nine Months Ended September 30, 2017~~

~~(In thousands)~~

Parent

Guarantor
Subsidiaries

Non-Guarantor
Subsidiaries

Eliminations

Consolidated

Net cash provided by operating activities

$
1,485,961

—

344,267

(137,420)

1,692,808

Cash flows used in investing activities:

Additions to proved properties

(179,318)

—

—

—

(179,318)

Additions to unproved properties

(182,207)

—

—

—

(182,207)

Drilling and completion costs

(1,083,928)

—

—

137,420

(946,508)

Additions to water handling and treatment systems

—

—

(143,470)

—

(143,470)

Additions to gathering systems and facilities

—

—

(254,619)

—

(254,619)

Additions to other property and equipment

(11,417)

—

—

—

(11,417)

Investments in unconsolidated affiliates

—

—

(216,776)

—

(216,776)

Change in other assets

(10,271)

—

(5,877)

—

(16,148)

Net distributions from subsidiaries

97,984

—

—

(97,984)

—

Other

2,156

—

—

—

2,156

Net cash used in investing activities

(1,367,001)

—

(620,742)

39,436

(1,948,307)

Cash flows provided by (used in) financing activities:

Issuance of common units by Antero Midstream Partners LP

—

—

248,949

—

248,949

Sale of common units in Antero Midstream Partners LP by Antero Resources Corporation

311,100

—

—

—

311,100

Borrowings (repayments) on bank credit facility, net

(415,000)

—

217,000

—

(198,000)

Distributions

—

—

(200,037)

97,984

(102,053)

Employee tax withholding for settlement of equity compensation awards

(7,568)

—

(932)

—

(8,500)

Other

(3,861)

—

(52)

—

(3,913)

Net cash provided by (used in) financing activities

(115,329)

—

264,928

97,984

247,583

Net increase (decrease) in cash and cash equivalents

3,631

—

(11,547)

—

(7,916)

Cash and cash equivalents, beginning of period

17,568

—

14,042

—

31,610

Cash and cash equivalents, end of period

$
21,199

—

2,495

—

23,694

~~(13)Commitments~~

The table below is a schedule of future minimum payments for firm transportation, drilling rig and completion services, processing, gathering and compression, and office and equipment agreements, as well as leases that have remaining lease terms in excess of one year as of September 30, 2017 (in millions).

Firm
transportation

Processing,
gathering and
compression

Drilling rigs and completion
services

Office and equipment


(a)

(b)

(c)

(d)

Total

Remainder of 2017

$
135

109

28

4

276

2018

886

401

80

13

1,380

2019

1,107

340

41

11

1,499

2020

1,127

337

—

9

1,473

2021

1,106

321

—

8

1,435

2022

1,053

317

—

8

1,378

Thereafter

9,635

1,502

—

17

11,154

Total

$
15,049

3,327

149

70

18,595

~~(a) Firm Transportation~~

~~Table of Contents~~

~~ANTERO RESOURCES CORPORATION~~

~~Notes to Condensed Consolidated Financial Statements~~

~~December 31, 2016 and September 30, 2017~~

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 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 agreements for certain of its production that will allow it to realize the value of its NGLs. The minimum payment obligations under the agreements are presented in the table.

The Company has various gathering and compression service agreements with third parties that provide for payments based on volumes gathered or compressed. The minimum payment obligations under these agreements are presented in the table.

The values in the table represent the gross amounts that the Company is committed to pay; however, the Company will record in the consolidated financial statements its proportionate share of costs based on its working interest. The values in the table also include minimum processing fees to be paid to the Joint Venture owned by Antero Midstream and MarkWest, and Antero Midstream’s commitments for the construction of its advanced wastewater treatment complex. The table does not include intracompany commitments. Future capital contributions to unconsolidated affiliates are excluded from the table as neither the amounts nor the timing of the obligations can be determined in advance.

~~(c) Drilling Rig Service Commitments~~

The Company has obligations under agreements with service providers to procure drilling rigs and completion services. The values in the table represent the gross amounts that the Company is committed to pay; however, the Company will record in the consolidated financial statements its proportionate share of costs based on its working interest.

~~(d) Office and Equipment Leases~~

~~The Company leases various office space and equipment under capital and operating lease arrangements.~~

~~(14) Related Parties~~

Certain of the Company’s shareholders, including members of its executive management group, own a significant interest in the Company and, either through their representatives or directly, serve as members of the Board of Directors of Antero and the Boards of Directors of the general partners of Antero Midstream and AMGP. These same groups or individuals own limited partner interests in Antero Midstream and common shares and other interests in AMGP, which indirectly owns the incentive distribution rights in Antero Midstream. Antero’s executive management group also manages the operations and business affairs of Antero Midstream and AMGP.

Antero Midstream’s operations comprise substantially all of the operations of our gathering and processing segment and our water handling and treatment segment. Substantially all of the revenues for those segments in the three and nine months ended September 30, 2016 and 2017 were derived from transactions with Antero. Please see Note 11 for the operating results of the Company’s reportable segments.

~~Table of Contents~~

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 ~~report.~~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, ~~availability of acquisitions,~~ 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. For more information, please refer to the Annual Report on Form 10-K for the year ended December 31, 2016, filed with the SEC on February 28, 2017, the Quarterly Report on Form 10-Q for the quarter ended March 31, 2017, filed with the SEC on May 8, 2017, and the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017, filed with the SEC on August 2, 2017.

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

Our Company

~~Antero Resources Corporation is~~We are an independent oil and natural gas company engaged in the exploration, development and production 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, 2017,~~March 31, 2020, we held approximately ~~630,000~~536,000 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.

We operate in the following industry segments: (i) the exploration, development, and production of natural gas, NGLs, and oil; (ii) ~~gathering and processing; (iii) water handling and treatment; and (iv)~~ marketing of excess firm transportation ~~capacity.~~capacity; and (iii) our equity method investment in Antero Midstream Corporation. All of our operations are conducted in the United States. As described below and elsewhere in this Quarterly Report on Form 10-Q, effective March 13, 2019, the results of Antero Midstream Partners are no longer consolidated in Antero’s results.

Address, Internet Website and Availability of Public Filings

Our principal executive offices are located at 1615 Wynkoop Street, Denver, Colorado 80202, and our telephone number is (303) 357-7310. Our website is located at www.anteroresources.com.

We furnish or file with the SEC our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, and our Current Reports on Form 8-K. We make these documents available free of charge ~~on our website~~at www.anteroresources.com under the ~~“Investors Relations” link~~“Investors–SEC Filings” section as soon as reasonably practicable after they are ~~filed~~furnished or ~~furnished~~filed with the SEC.

Information on our website is not incorporated into this Quarterly Report on Form 10-Q or any of our other filings with the ~~SEC and is not a part of them.~~

SEC.

Table of Contents

~~2017~~2020 Developments and Highlights

COVID-19 Pandemic

~~Energy Industry Environment~~

In ~~late 2014,~~March 2020, the World Health Organization declared the COVID-19 outbreak a pandemic. Governments have tried to slow the spread of the virus by imposing social distancing guidelines, travel restrictions and stay-at-home orders, which have caused a significant decrease in activity in the global ~~energy~~economy and the demand for oil and to a lesser extent natural gas and NGLs. Also in March 2020, Saudi Arabia and Russia failed to agree to cut production of oil along with the Organization of the Petroleum Exporting Countries (“OPEC”), and Saudi Arabia significantly reduced the price at which it sells oil and announced plans to increase production, which contributed to a sharp drop in the price of oil. While OPEC, Russia and other allied producers reached an agreement in April 2020 to reduce production, oil prices have remained low. The imbalance between the supply of and demand for oil, as well as the uncertainty around the extent and timing of an economic recovery, have caused extreme market volatility and a substantial adverse effect on commodity prices ~~declined precipitously~~in March and April.

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. We have continued to operate as permitted under these regulations while taking steps to protect the health and safety of our 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 ~~result~~significant manner. A substantial portion of ~~several factors,~~our non-field level employees have transitioned temporarily to remote work from home arrangements, and we have been able to maintain a consistent level of effectiveness through these arrangements, including ~~an increase in worldwide commodity supplies, a stronger U.S. dollar, relatively mild weather in large portions~~maintaining our day-to-day operations, our financial reporting systems and our internal control over financial reporting. To date, we have had no confirmed cases of ~~the U.S.,~~COVID-19 within our employee group at any of our locations.

Our natural gas, NGLs and ~~strong competition among~~ oil producing ~~countries~~properties are located in the liquids-rich Appalachian Basin. Although the decline in oil prices has negatively impacted our oil revenue, oil sales represented approximately 3% and 4% of our total revenue for ~~market share. Depressed commodity~~the three months ended March 31, 2020 and the year ended December 31, 2019, respectively. While natural gas prices ~~continued into 2015 and 2016, although a modest recovery occurred in late 2016 and has continued through 2017. The following chart depicts quarterly percentage changes~~also declined during the first quarter of 2020, the decline in natural gas ~~(Henry Hub), propane (Mont Belvieu), and~~prices has been far less significant than the decline in oil ~~(West Texas Intermediate) spot prices since June 30, 2014.~~

prices. In response to these market conditions and concerns about access to capital markets, many U.S. exploration and production companies significantly reduced their capital spending plans in recent years. Our 2017 capital budget includes $1.5 billion for drilling, completions, and land. Excluding acquisitions, this is consistent with our 2016 capital expenditures. Our 2017 capital budget includes plans to operate an average of seven drilling rigs over the course of 2017, which is consistent with 2016; completion of 170 horizontal wells in the Marcellus and Utica Shales in 2017 as compared to 140 in 2016; and deferring the completion of 30 wells until 2018. Although commodity prices have decreased in recent years,addition, we have hedged through fixed price contracts the sale of 2.2 Bcf per day of natural gas at a weighted average price of $2.87 per MMBtu for the remainder of 2020. Our hedges cover a substantial majority of our expected natural gas production in 2020. We also ~~realized reductions~~have fixed priced contracts for the sale of 10,352 barrels per day of propane at a weighted average price of $0.65 per gallon and 26,000 barrels per day of oil at a weighted average price of $55.63 per barrel for the remainder of 2020. These fixed price contracts resulted in ~~drilling~~total commodity derivative fair value gains of $566 million, including settled commodity derivative gains of $211 million, during the three months ended March 31, 2020. All of our hedges are financial hedges and ~~development costs~~do not have physical delivery requirements. As such, any decreases in anticipated production, whether as a result of decreased development activity or shut-ins, will not impact our ability to realize the benefits of the hedges. Our natural gas and NGLs are primarily used in manufacturing, power generation and heating rather than transportation. While we have seen a decrease in the overall demand for ~~oilfield services~~these products, demand for natural gas and ~~increased efficiencies~~NGLs has not declined as much as demand for oil, and there has not been as substantial an oversupply of natural gas and NGLs as there has been of oil. Furthermore, the decrease in demand for oil has significantly reduced the number of rigs drilling for oil in the continental U.S. and, as a result, estimates of future gas supply associated with oil production have declined. Additionally, the restart of economic activity in Asia, coupled with lower refinery liquefied petroleum gas (“LPG”) production in the U.S., Europe, and other markets such as India, has led to strengthening prices for international LPG.

Our supply chain also has not thus far experienced any significant interruptions. The industry overall is experiencing storage capacity constraints with respect to oil and certain NGL products, and we may become subject to those constraints if we are not able to sell our production, or certain components of our production, or enter into additional storage arrangements. The lack of a market or available storage for any one NGL product or oil could result in us having to delay or discontinue well completions and commercial production or shut in production for other products as we cannot curtail the production of individual products in a meaningful way without reducing the 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 or for how long any shut-ins may occur. However, because some of our wells produce rich gas, which is processed, and some produce dry gas, which does not require processing, we have the ability to 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 better than if we had only rich gas or dry gas wells. We have the ability to shut-in rich gas wells and still produce from ~~improved~~our dry gas wells if processing or storage capacity of NGL products becomes further limited or constrained. Also, 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. Since the outbreak of the pandemic, we have expanded our customer base and doubled our condensate storage capacity within the basin.

Table of Contents

In addition, as discussed below in “—2020 Capital Budget and Capital Spending,” we have reduced our drilling and completion ~~technologies and procedures.~~

~~We believe that our 2017~~ capital budget for 2020 by approximately 34% since the beginning of the year. We will continue to monitor our five-year drilling plan throughout the year and will make further revisions if deemed necessary. Reductions in the 2020 capital budget may impact production levels in 2021 and forward to the extent fewer wells will be ~~fully funded through~~brought online.

During the three months ended March 31, 2020 and during the two previous quarters, we have recognized various impairment charges related to the decline in commodity prices and the value of our investment in Antero Midstream Corporation. At this time, we do not anticipate any further impairment charges in our equity method investment in Antero Midstream Corporation, as the value of our equity method investment has increased since March 31, 2020. Additional impairment charges related to our assets may occur if we experience disruptions in production, additional or sustained declines in the forward commodity price strip from March 31, 2020, unresolved storage capacity restraints or other consequences of the COVID-19 pandemic.

In April 2020, the borrowing base supporting our Credit Facility was subject to its annual redetermination. The bank prices used in our redetermination were materially lower than the bank prices used in our April 2019 redetermination and were lower than strip prices as of April 27, 2020. As a result, the lenders under our Credit Facility reduced our borrowing base from the previous level. Lender commitments remained unchanged at $2.64 billion, providing us with a consistent amount of available borrowings. Our borrowing base is now subject to a semi-annual redetermination and, therefore, our available borrowings and liquidity could be impacted by an additional redetermination in 2020. 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. Our ability to limit the financial assurance we are required to provide, while also protecting ourselves from the counterparty risk of our financial hedges, may be impacted by the ongoing effects of the COVID-19 pandemic.

The COVID-19 pandemic, commodity market volatility and resulting financial market instability are variables beyond our control, which can adversely impact our generation of funds from operating cash flows, distributions from unconsolidated affiliates, available ~~borrowing capacity~~borrowings under ~~Antero’s senior secured revolving bank credit facility (the “Credit Facility”),~~our Credit Facility and ~~potential capital market transactions. We continually monitor commodity prices and may revise~~our ability to access the capital ~~budget if conditions warrant. Additionally, given~~markets. In addition, our plan to strengthen our balance sheet through significant absolute debt reduction depends upon our ability to identify and successfully execute our previously announced asset monetization program. Instability in the ~~current commodity price~~financial markets and uncertainty in the general business environment resulting from the COVID-19 pandemic may impact our ability to execute our asset monetization program on the terms and the timeframe previously anticipated. To the extent we are not able to execute our asset monetization plan or access the capital markets, we may have ~~evaluated the carrying value of~~to delay or reduce our ~~proved properties. See “—Critical Accounting Policies and Estimates” for a discussion of such evaluation.~~planned capital expenditures in order to address our upcoming debt obligations.

Production and Financial Results

For the three months ended September 30, 2017, we generated consolidated cash flows from operations of $1.0 billion, a consolidated net loss of $135 million, and consolidated Adjusted EBITDAX of $336 million. This compares to consolidated cash flows from operations of $327 million, consolidated net income of $238 million, and consolidated Adjusted EBITDAX of $373 million for the three months ended September 30, 2016. The consolidated net loss of $135 million for the three months ended September 30, 2017 included (i) commodity derivative fair value losses of $66 million, comprising gains on settled derivatives of $61 million, cash proceeds from hedge monetizations of $750 million (see “—Deleveraging Activities” below), and a non-cash loss of $877 million on changes in the fair value of unsettled commodity derivatives, (ii) a non-cash charge of $26 million for equity-based compensation, (iii) a non-cash charge of $41 million for impairments of unproved properties, and (iv) a non-cash deferred tax benefit

~~Table of Contents~~

of $45 million. See “—Non-GAAP Financial Measures” for a definition of Adjusted EBITDAX (a non-GAAP measure) and a reconciliation of Adjusted EBITDAX to net income. The impact of hedge monetizations is excluded from our Adjusted EBITDAX and per-unit calculations presented herein. See “—Deleveraging Activities” for further discussion.

~~For the three months ended September 30, 2017,~~March 31, 2020, our net production totaled ~~213~~306 Bcfe, or ~~2,317~~3,366 MMcfe per day, a ~~24%~~9% increase in daily combined production compared to ~~172~~279 Bcfe, or ~~1,875~~3,099 MMcfe per day, for the three months ended ~~September 30, 2016.~~March 31, 2019. Production increases resulted from an increase in the number of producing wells as a result of our drilling and completion activity. Our average price received for production, before the effects of gains on settled commodity derivatives for the three months ended ~~September 30, 2017~~March 31, 2020 was ~~$3.10~~$2.30 per Mcfe compared to ~~$2.82~~$3.65 per Mcfe for the three months ended ~~September 30, 2016.~~March 31, 2019. Our average realized price after the effects of gains on settled commodity derivatives was ~~$3.39~~$2.99 per Mcfe for the three months ended ~~September 30, 2017~~March 31, 2020 compared to ~~$3.96~~$4.00 per Mcfe for the three months ended ~~September 30, 2016.~~

March 31, 2019.

For the ~~nine~~three months ended ~~September 30, 2017,~~March 31, 2020, we generated consolidated cash flows from operations of ~~$1.7 billion, consolidated~~$201 million, net ~~income~~loss attributable to Antero of ~~$128~~$339 million, and Adjusted EBITDAX of ~~$1.0 billion.~~$244 million. This compares to consolidated cash flows from operations of ~~$906~~$539 million, a consolidated net ~~loss~~income attributable to Antero Resources of ~~$363~~$979 million, and ~~consolidated~~ Adjusted EBITDAX of ~~$1.1 billion for the nine months ended September 30, 2016. Consolidated net income of $128~~$443 million for the ~~nine~~three months ended September 30, 2017 included (i) commodity derivative fair value gains of $458 million, comprising gains on settled derivatives of $137 million, cash proceeds from hedge monetizations of $750 million, and a non-cash loss of $429 million on changes in the fair value of unsettled commodity derivatives, (ii) a non-cash charge of $79 million for equity-based compensation, (iii) a non-cash charge of $83 million for impairments of unproved properties, and (iv) a non-cash deferred tax expense of $105 million.March 31, 2019. See “—Non-GAAP Financial Measures” for a definition of Adjusted EBITDAX ~~(a non-GAAP measure)~~ and a reconciliation of Adjusted EBITDAX to net ~~income. The impact of hedge monetizations is excluded~~cash provided by operating activities and net income (loss).

Cash flows from ~~our Adjusted EBITDAX and per-unit calculations presented herein. See “—Deleveraging Activities”~~operations decreased by $338 million for ~~further discussion.~~

~~For~~ the ~~nine~~three months ended ~~September 30, 2017, our net production totaled 606 Bcfe, or 2,221 MMcfe per day, a 23% increase~~March 31, 2020 compared to ~~493 Bcfe, or 1,799 MMcfe per day, for~~ the ~~nine months ended September 30, 2016. Our average price received for production,~~prior year period primarily due to decreases in commodity prices both before the effects of gains on settled derivatives, for the nine months ended September 30, 2017 was $3.30 per Mcfe compared to $2.36 per Mcfe for the nine months ended September 30, 2016. Our average realized priceand after the effects of ~~gains on~~ settled commodity derivatives ~~was $3.53 per Mcfe~~and increases in gathering, compression and transportation costs. Consolidated net loss attributable to Antero Resources of $339 million for ~~the nine months ended September 30, 2017 compared to $4.02 per Mcfe for the nine months ended September 30, 2016.~~

~~Deleveraging Activities~~

~~During~~ the three months ended ~~September 30, 2017, we monetized over $1 billion~~March 31, 2020 decreased from consolidated net income attributable to Antero Resources of ~~our non-exploration and production assets and used~~$979 million for the ~~proceeds to repay outstanding borrowings under our revolving credit facility. Proceeds from these activities are not expected to result in cash taxes payable~~three months ended March 31, 2019 primarily due to the ~~utilization~~gain on deconsolidation of Antero Midstream Partners in 2019 partially offset by commodity derivative realized and fair value gains in 2020. The three months ended March 31, 2020 was also impacted by an Impairment of equity investment due to the decline in Antero Midstream Corporation’s fair value and Antero Midstream Corporation’s earnings changing from earnings to a loss.

Adjusted EBITDAX decreased from $443 million for the three months ended March 31, 2019 to $244 million for the three months ended March 31, 2020, a decrease of 45%, primarily due to the decrease in commodity prices of 37% per Mcfe before and

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26% per Mcfe after the effects of settled commodity derivatives, and increased gathering, compression and transportation costs discussed above. A portion of ~~our net operating loss (“NOL”) carryforwards. These deleveraging activities consisted~~the cost increases are the result of the ~~following transactions:~~deconsolidation of Antero Midstream Partners as costs that were previously eliminated in consolidation are now expensed.

On September 11, 2017, we completed a public sale of 10,000,000 common units representing limited partner interests in Antero Midstream which were held by Antero. We received total net proceeds from the transaction of $311 million.

In September 2017, we monetized portions of our hedge portfolio by reducing the average fixed index prices on certain of our natural gas hedges that settle from 2018 through 2022 while maintaining the total volumes hedged. We received total proceeds of approximately $750 million from the monetization of the natural gas hedges.

~~2017~~2020 Capital Budget and Capital Spending

Our ~~consolidated~~drilling and completion capital budget for ~~2017 is $2.3 billion~~2020 has been reduced to $750 million from $1.15 billion. Reductions in the 2020 capital budget may impact production in 2021 and includes: $1.3 billion for drilling and completion, $200 million for core leasehold acreage additions and extensions, and $800 million for capital expenditures by Antero Midstream, which includes investments in unconsolidated gathering and processing entities.forward to the extent fewer wells will be brought online. We do not budget for acquisitions. Approximately 70% of the drilling and completion budget is allocated to the Marcellus Shale, and the remaining 30% is allocated to the Ohio Utica Shale. Over the course of 2017, we plan to operate an average of four drilling rigsinclude acquisitions in ~~the Marcellus Shale and three drilling rigs in the Ohio Utica Shale.~~our capital budget. We periodically review our capital expenditures and adjust our budget and its allocation based on ~~liquidity, drilling results, leasehold acquisition opportunities,~~commodity prices, takeaway constraints, operating cash flow and ~~commodity prices.~~

liquidity.

For the ~~nine~~three months ended ~~September 30, 2017,~~ March 31, 2020, our ~~consolidated~~ capital expenditures were approximately ~~$1.7 billion,~~$312 million, including drilling and completion costs of ~~$947~~$300 million, leasehold ~~additions of $182 million,~~ acquisitions of ~~$179~~$10 million, and other capital expenditures of $2 million. Our capital expenditures for the three months ended March 31, 2019 of approximately $472 million included drilling and completion costs of $369 million, leasehold acquisitions of $27 million, and other capital expenditures of $3 million. In addition, consolidated capital expenditures for the three months ended March 31, 2019, included gathering and compression expenditures of ~~$255~~$48 million and water handling and treatment expenditures of ~~$143 million, and other capital expenditures~~

~~Table of Contents~~

~~of $11~~$24 million. Antero Midstream Partners also invested ~~$217~~$25 million in a joint ~~venture with MarkWest Energy~~venture. These expenditures relate to the period prior to deconsolidation of Antero Midstream Partners ~~L.P. (the “Joint Venture”).~~on March 12. 2019.

For the three months ended March 31, 2020, our exploration and production capital expenditures decreased by $87 million from the three month period ended March 31, 2019. This 22% reduction in capital costs was a result of our well cost savings initiatives, which include savings resulting from service cost deflation, sand and water logistics optimization, as well as operational efficiency gains.

Hedge Position ~~(after effects of hedge monetization)~~

~~As of September 30, 2017,~~At March 31, 2020, we had ~~entered into hedging~~fixed price natural gas swap contracts on NYMEX Henry Hub for ~~approximately 2.9~~the period from April 2020 through December 2023 covering 1.8 Tcf of our projected natural gas production at a weighted average index price of ~~$3.36~~$2.77 per MMbtu for the period from October 1, 2017 through December 31, 2023, 152 million gallons of propane at a weighted average price of $0.48 per gallon for the period from October 1, 2017 through December 31, 2018, 77 million gallons of ethane at a weighted average price of $0.25 per gallon for the period from October 1, 2017 through December 31, 2017, and 641 MBbls of oil at a weighted average price of $52.02 per Bbl for the period from October 1, 2017 through December 31, 2018. These hedging contracts includeMMBtu, including contracts for the remainder of ~~2017~~2020 of approximately ~~171~~613 Bcf of natural gas at a weighted average index price of ~~$3.71~~$2.87 per ~~Mcf, 106 million gallons~~MMBtu. At March 31, 2020, we also had basis swaps for the period from April 2020 through December 2024 for approximately 89.5 Bcf of ~~propane~~our projected natural gas production with pricing differentials ranging from $0.35 to $0.53 per MMBtu that hedge the difference between TCO and the NYMEX Henry Hub. In addition, we have a call option agreement, which entitles the holder, if exercised, to enter into a fixed price swap agreement for approximately 428 MMBtu per day at a ~~weighted average~~ price of ~~$0.40~~$2.77 per ~~gallon, 77 million gallons of ethane at a weighted average price of $0.25 per gallon,~~MMBtu in 2024.

We believe our hedge position provides some certainty to cash flows supporting our future operations and ~~276 MBbls of oil at a weighted average price of $54.75 per Bbl.~~

~~Credit Facilities~~

On November 4, 2010, Antero entered into a credit facility with a consortium of bank lenders (the “Prior Credit Facility”). On October 26, 2017, Antero entered into an amendment and restatement of the Prior Credit Facility (the “Credit Facility”).capital spending plans. As of ~~September 30, 2017,~~March 31, 2020, the estimated fair value of our commodity derivative contracts was approximately $1.1 billion.

Credit Facility

Our borrowing base ~~under the Prior Credit Facility~~ was ~~$4.75~~reduced to $2.85 billion and lender commitments ~~were $4.0 billion. Under~~remained at $2.64 billion at the ~~Credit Facility, the maximum facility amount is $4.75 billion, the borrowing base is $4.5 billion, and lender commitments are $2.5 billion. Our~~redetermination in April 2020. The borrowing base under ~~the~~our Credit Facility is redetermined ~~annually~~semi-annually and is based on the estimated future cash flows from our proved oil and gas reserves, the value of our ownership interest in Antero Midstream Corporation and our commodity ~~hedge~~derivative positions. The next redetermination is scheduled to occur in ~~March 2018. At September 30, 2017, we had $25 million of borrowings and $700 million of letters of credit outstanding under the Prior Credit Facility.~~October 2020. The maturity date of the Credit Facility is the earlier of (i) October 26, 2022 and (ii) the date that is 91 days prior to the ~~maturity~~earliest stated redemption date of any series of ~~Antero’s~~our senior notes ~~unless such series~~then outstanding. At March 31, 2020, we had an outstanding balance under the Credit Facility of ~~senior notes is refinanced.~~$882 million, with a weighted average interest rate of 2.57%, and letters of credit of $730 million. See “—Debt Agreements and Contractual Obligations—Senior Secured Revolving Credit Facility” for a description of the Credit Facility.

On November 10, 2014, Antero Midstream entered into a credit facility with a consortium of bank lenders that provides for lender commitments of $1.5 billion (the “Prior Midstream Facility”). On October 26, 2017, Antero Midstream entered into an amendment and restatement of the Prior Midstream Facility (the “Midstream Facility”) that also provides for lender commitments of $1.5 billion. At September 30, 2017, Antero Midstream had $427 million of borrowings outstanding under the Prior Midstream Facility. The Midstream Facility will mature on October 26, 2022. See “—Debt Agreements and Contractual Obligations—Midstream Credit Facility” for a description of the Midstream Facility.

~~Antero Midstream Equity Distribution Agreement~~

Share Repurchase Program

During the ~~nine~~three months ended ~~September 30, 2017, Antero Midstream issued and sold 777,262~~March 31, 2020, pursuant to our share repurchase program, we repurchased 27,193,237 shares of our common ~~units under~~stock (approximately 9% of total shares outstanding at commencement of the ~~Distribution Agreement, resulting in net proceeds~~program) at an average cost of ~~$25.5 million after deducting commissions and other offering costs. As~~$1.57 for a total cost of ~~September 30, 2017, Antero Midstream had~~approximately $43 million. During the ~~capacity to issue additional common units under the Distribution Agreement up to~~term of this program, we repurchased an aggregate ~~sales price~~ of ~~$157.3 million.~~approximately $215 million of our shares of common stock. At March 31, 2020, Antero had 268,926,481 shares outstanding.

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Results of Operations

~~Three Months Ended September 30, 2016 Compared to Three Months Ended September 30, 2017~~

~~The Company has four~~We have three operating segments: (1) the exploration, development and production of natural gas, NGLs, and oil; (2) ~~gathering~~marketing and ~~processing; (3) water handling and treatment; and (4) marketing~~utilization of excess firm transportation ~~capacity.~~capacity gathering and processing; and (3) equity method investment in Antero Midstream Corporation. Revenues from ~~the gathering and processing and water handling and treatment~~Antero Midstream Corporation’s operations ~~are~~were primarily derived from intersegment transactions for services provided to our exploration and production operations by Antero ~~Midstream. Intersegment~~Midstream Partners. All intersegment transactions ~~that are~~were eliminated ~~include~~upon consolidation, including revenues from water handling and treatment services provided by Antero Midstream Partners, which ~~are~~we capitalized as proved property development ~~costs by Antero.~~costs. Through March 12, 2019, the results of Antero Midstream Partners were included in our consolidated financial statements. Effective March 13, 2019, the results of Antero Midstream Partners are no longer included in our results; however, our disclosures include the segments of our unconsolidated affiliates due to their significance to our operations. See Note 3 to the unaudited condensed consolidated financial statements for further discussion on the Transactions and Note 17 to the unaudited condensed consolidated financial statements for disclosures on our reportable segments. 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~~capacity.

Three Months Ended March 31, 2019 Compared to ~~third parties.~~

~~Table of Contents~~

Three Months Ended March 31, 2020

The operating results of ~~the Company’s~~our reportable segments were as follows for the three months ended ~~September 30, 2016~~March 31, 2019 and ~~2017~~2020 (in thousands):


	Exploration and production		Gathering and processing	Water handling and treatment	Marketing	Elimination of intersegment transactions	Consolidated total
Three months ended September 30, 2016:
Sales and revenues:
Third-party	$	1,016,458	2,745	224	97,076	—	1,116,503
Intersegment		3,990	75,319	72,187	—	(151,496)	—

												Equity Method		Elimination of
												Investment in		intersegment
								Exploration				Antero		transactions and
								and				Midstream		unconsolidated		Consolidated
								production		Marketing		Corporation		affiliates		total
Three months ended March 31, 2019:
Revenue and other:
Natural gas sales								$	657,266		—		—		—		657,266
Natural gas liquids sales									313,685		—		—		—		313,685
Oil sales									48,052		—		—		—		48,052
Commodity derivative fair value losses									(77,368)		—		—		—		(77,368)
Gathering, compression, and water handling and treatment									—		—		55,889		(51,410)		4,479
Marketing									—		91,186		—		—		91,186
Other income									1,758		—		(1,781)		130		107
Total	$	1,020,448	78,064	72,411	97,076	(151,496)	1,116,503	$	943,393		91,186		54,108		(51,280)		1,037,407


Operating expenses:
Lease operating	$	13,710	—	28,978	—	(28,834)	13,854		42,969		—		11,815		(13,052)		41,732
Gathering, compression, processing, and transportation		303,753	6,400	—	—	(75,238)	234,915
Gathering and compression									212,833		—		2,935		(113,421)		102,347
Processing									169,999		—		—		—		169,999
Transportation									152,183		—		—		—		152,183
Production and ad valorem taxes									34,738		—		232		708		35,678
Marketing									—		163,084		—		—		163,084
Exploration									126		—		—		—		126
Impairment of oil and gas properties									81,244		—		—		—		81,244
Impairment of midstream assets									—		—		6,982		—		6,982
Accretion of asset retirement obligations									913		—		10		53		976
Depletion, depreciation, and amortization		172,735	18,540	7,838	—	—	199,113		218,494		—		7,650		14,057		240,201
General and administrative (before equity-based compensation)		24,856	5,068	1,647	—	(375)	31,196
General and administrative (excluding equity-based compensation)									43,482		—		1,594		14,223		59,299
Equity-based compensation		19,781	5,214	1,386	—	—	26,381		6,426		—		590		1,887		8,903
Other		31,266	(1,708)	3,070	114,611	(3,527)	143,712
Change in fair value of contingent acquisition consideration									—		—		1,049		(1,049)		—
Contract termination and rig stacking									8,360		—		—		—		8,360
Total		566,101	33,514	42,919	114,611	(107,974)	649,171		971,767		163,084		32,857		(96,594)		1,071,114
Operating income (loss)	$	454,347	44,550	29,492	(17,535)	(43,522)	467,332	$	(28,374)		(71,898)		21,251		45,314		(33,707)


Equity in earnings of unconsolidated affiliates	$	—	1,543	—	—	—	1,543	$	1,817		—		2,880		9,384		14,081
Segment Adjusted EBITDAX (1)	$	323,261	68,304	42,243	(17,535)	(43,522)	372,751

Exploration
and
production

Gathering and
processing

Water handling and treatment

Marketing

Elimination of
intersegment
transactions

Consolidated
total

Three months ended September 30, 2017:

Sales and revenues:

Third-party

$
594,244

2,609

260

50,767

—

647,880

Intersegment

3,070

97,909

92,851

—

(193,830)

—

Total

$
597,314

100,518

93,111

50,767

(193,830)

647,880

Operating expenses:

Lease operating

$
24,060

—

51,569

—

(52,138)

23,491

Gathering, compression, processing, and transportation

369,538

10,468

—

—

(97,872)

282,134

Depletion, depreciation, and amortization

176,188

22,027

8,753

—

—

206,968

General and administrative (before equity-based compensation)

29,041

4,225

2,892

—

(402)

35,756

Equity-based compensation

19,248

5,111

2,088

—

—

26,447

Other

65,259

92

3,457

78,884

(2,556)

145,136

Total

683,334

41,923

68,759

78,884

(152,968)

719,932

Operating income (loss)

$
(86,020)

58,595

24,352

(28,117)

(40,862)

(72,052)

Equity in earnings of unconsolidated affiliates

$
—

7,033

—

—

—

7,033

Segment Adjusted EBITDAX (1)

$
277,553

90,033

37,749

(28,117)

(40,862)

336,356

Table of Contents

~~(1)~~

~~See “—Non-GAAP Financial Measures” for a definition of Segment Adjusted EBITDAX (a non-GAAP measure) and a reconciliation of Segment Adjusted EBITDAX to operating income.~~


					Equity Method		Elimination of
					Investment in		intersegment
	Exploration				Antero		transactions and
	and				Midstream		unconsolidated		Consolidated
	production		Marketing		Corporation		affiliates		total
Three months ended March 31, 2020:
Revenue and other:
Natural gas sales	$	411,082		—		—		—		411,082
Natural gas liquids sales		257,673		—		—		—		257,673
Oil sales		35,646		—		—		—		35,646
Commodity derivative fair value gains		565,833		—		—		—		565,833
Gathering, compression, water handling and treatment		—		—		261,314		(261,314)		—
Marketing		—		46,073		—		—		46,073
Other income		798		—		(17,606)		17,606		798
Total	$	1,271,032		46,073		243,708		(243,708)		1,317,105

Operating expenses:
Lease operating	$	25,644		—		—		—		25,644
Gathering and compression		193,008		—		55,908		(55,908)		193,008
Processing		210,236		—		—		—		210,236
Transportation		185,380		—		—		—		185,380
Production and ad valorem taxes		25,699		—		1,498		(1,498)		25,699
Marketing		—		93,273		—		—		93,273
Exploration		210		—		—		—		210
Impairment of oil and gas properties		89,220		—		—		—		89,220
Impairment of midstream assets		—		—		664,544		(664,544)		—
Depletion, depreciation, and amortization		199,677		—		27,343		(27,343)		199,677
Accretion of asset retirement obligations		1,104		—		42		(42)		1,104
General and administrative (excluding equity-based compensation)		27,892		—		10,199		(10,199)		27,892
Equity-compensation		3,329		—		3,338		(3,338)		3,329
Total		961,399		93,273		762,872		(762,872)		1,054,672
Operating income (loss)	$	309,633		(47,200)		(519,164)		519,164		262,433

Equity in loss of unconsolidated affiliates	$	128,055		—		—		—		128,055

Table of Contents

Exploration and Production Segment Results for the Three Months Ended March 31, 2019 Compared to the Three Months Ended March 31, 2020

The following ~~tables set~~table sets forth selected ~~consolidated~~ operating data of the exploration and production segment for the three months ended ~~September 30, 2016~~March 31, 2019 compared to the three months ended ~~September 30, 2017:~~March 31, 2020:

Three Months Ended September 30,

Amount of
Increase

Percent

(in thousands)

2016

2017

(Decrease)

Change

Operating revenues and other:

Natural gas sales

$
364,373

$
409,141

$
44,768

12
%
NGLs sales

106,958

224,533

117,575

110
%
Oil sales

14,793

26,527

11,734

79
%
Gathering, compression, water handling and treatment

2,969

2,869

(100)

(3)
%
Marketing

97,076

50,767

(46,309)

(48)
%
Commodity derivative fair value gains (losses)

530,334

(65,957)

(596,291)

*

Total operating revenues and other

1,116,503

647,880

(468,623)

(42)
%
Operating expenses:

Lease operating

13,854

23,491

9,637

70
%
Gathering, compression, processing, and transportation

234,915

282,134

47,219

20
%
Production and ad valorem taxes

15,554

22,995

7,441

48
%
Marketing

114,611

78,884

(35,727)

(31)
%
Exploration

1,166

1,599

433

37
%
Impairment of unproved properties

11,753

41,000

29,247

249
%
Depletion, depreciation, and amortization

199,113

206,968

7,855

4
%
Accretion of asset retirement obligations

628

658

30

5
%
General and administrative (before equity-based compensation)

31,196

35,756

4,560

15
%
Equity-based compensation

26,381

26,447

66

—
%
Total operating expenses

649,171

719,932

70,761

11
%
Operating income (loss)

467,332

(72,052)

(539,384)

*

Other earnings (expenses):

Equity in earnings of unconsolidated affiliate

1,543

7,033

5,490

356
%
Interest expense

(59,755)

(70,059)

(10,304)

17
%
Total other expenses

(58,212)

(63,026)

(4,814)

8
%
Income (loss) before income taxes

409,120

(135,078)

(544,198)

*

Income tax (expense) benefit

(140,924)

45,078

186,002

*

Net income (loss) and comprehensive income (loss) including noncontrolling interest

268,196

(90,000)

(358,196)

*

Net income and comprehensive income attributable to noncontrolling interest

29,941

45,063

15,122

51
%
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation

$
238,255

$
(135,063)

$
(373,318)

*

Adjusted EBITDAX (1)

$
372,751

$
336,356

$
(36,395)

(10)
%


					Amount of
	Three months ended March 31,				Increase		Percent
	2019		2020		(Decrease)		Change
Production data:
Natural gas (Bcf)		199		208		9	5	%
C2 Ethane (MBbl)		3,509		4,604		1,095	31	%
C3+ NGLs (MBbl)		8,794		10,833		2,039	23	%
Oil (MBbl)		1,017		938		(79)	(8)	%
Combined (Bcfe)		279		306		27	10	%
Daily combined production (MMcfe/d)		3,099		3,366		267	9	%
Average prices before effects of derivative settlements⁽¹⁾:
Natural gas (per Mcf) ⁽²⁾	$	3.30	$	1.98	$	(1.32)	(40)	%
C2 Ethane (per Bbl)	$	10.12	$	5.82	$	(4.30)	(42)	%
C3+ NGLs (per Bbl)	$	31.63	$	21.31	$	(10.32)	(33)	%
Oil (per Bbl)	$	47.23	$	38.02	$	(9.21)	(20)	%
Weighted Average Combined (per Mcfe)	$	3.65	$	2.30	$	(1.35)	(37)	%
Average realized prices after effects of derivative settlements⁽¹⁾:
Natural gas (per Mcf)	$	3.79	$	2.88	$	(0.91)	(24)	%
C2 Ethane (per Bbl)	$	10.12	$	5.82	$	(4.30)	(42)	%
C3+ NGLs (per Bbl)	$	31.59	$	22.56	$	(9.03)	(29)	%
Oil (per Bbl)	$	47.23	$	47.29	$	0.06	0	%
Weighted Average Combined (per Mcfe)	$	4.00	$	2.99	$	(1.01)	(25)	%
Average costs (per Mcfe):
Lease operating	$	0.15	$	0.08	$	(0.07)	(47)	%
Gathering and compression	$	0.76	$	0.63	$	(0.13)	(17)	%
Processing	$	0.61	$	0.69	$	0.08	13	%
Transportation	$	0.55	$	0.61	$	0.06	11	%
Production and ad valorem taxes	$	0.12	$	0.08	$	(0.04)	(33)	%
Depletion, depreciation, amortization, and accretion	$	0.78	$	0.66	$	(0.12)	(15)	%
General and administrative (excluding equity-based compensation)	$	0.16	$	0.09	$	(0.07)	(44)	%

~~Table of Contents~~

Three Months Ended September 30,

Amount of
Increase

Percent

2016

2017

(Decrease)

Change

Production data:

Natural gas (Bcf)

128

151

23

18
%
C2 Ethane (MBbl)

1,801

2,789

988

55
%
C3+ NGLs (MBbl)

5,270

6,927

1,657

31
%
Oil (MBbl)

423

624

201

47
%
Combined (Bcfe)

172

213

41

24
%
Daily combined production (MMcfe/d)

1,875

2,317

442

24
%
Average prices before effects of derivative settlements(2):

Natural gas (per Mcf)

$
2.86

$
2.71

$
(0.15)

(5)
%
C2 Ethane (per Bbl)

$
8.00

$
8.68

$
0.68

9
%
C3+ NGLs (per Bbl)

$
17.56

$
28.92

$
11.36

65
%
Oil (per Bbl)

$
34.93

$
42.50

$
7.57

22
%
Combined (per Mcfe)

$
2.82

$
3.10

$
0.28

10
%
Average realized prices after effects of derivative settlements(2):

Natural gas (per Mcf)

$
4.30

$
3.37

$
(0.93)

(22)
%
C2 Ethane (per Bbl)

$
8.00

$
8.53

$
0.53

7
%
C3+ NGLs (per Bbl)

$
19.96

$
23.15

$
3.19

16
%
Oil (per Bbl)

$
34.93

$
45.40

$
10.47

30
%
Combined (per Mcfe)

$
3.96

$
3.39

$
(0.57)

(14)
%
Average Costs (per Mcfe):

Lease operating

$
0.08

$
0.11

$
0.03

38
%
Gathering, compression, processing, and transportation

$
1.36

$
1.32

$
(0.04)

(3)
%
Production and ad valorem taxes

$
0.09

$
0.11

$
0.02

22
%
Marketing expense, net

$
0.10

$
0.13

$
0.03

30
%
Depletion, depreciation, amortization, and accretion

$
1.16

$
0.97

$
(0.19)

(16)
%
General and administrative (before equity-based compensation)

$
0.18

$
0.17

$
(0.01)

(6)
%

(1)

~~(1)~~

See “—Non-GAAP Financial Measures” for a definition of Adjusted EBITDAX (a non-GAAP measure) and a reconciliation of Adjusted EBITDAX to net income (loss) including noncontrolling interest and net cash provided by operating activities.

~~(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, ~~(but does not include the hedge monetizations described in “—Deleveraging Activities” above),~~ 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.

*~~Not meaningful or applicable.~~

~~Discussion of Consolidated Exploration and Production Results for the Three Months Ended September 30, 2016 Compared to the Three Months Ended September 30, 2017~~

Natural gas ~~NGLs, and oil~~ sales. Revenues from production of natural gas ~~NGLs, and oil increased~~decreased from ~~$486~~$657 million for the three months ended ~~September 30, 2016~~March 31, 2019 to ~~$660~~$411 million for the three months ended ~~September 30, 2017, an increase~~March 31, 2020, a decrease of ~~$174~~$246 million, or ~~36%~~37% (calculated as the change in year-over-year volumes times the change in year-to-year average price). Our production increased by 24% over that same period, from 172 Bcfe, or 1,875 MMcfe per day, for the three months ended September 30, 2016 to 213 Bcfe, or 2,317 MMcfe per day, for the three months ended September 30, 2017. Net equivalent prices before the effects of settled derivative gains increased from $2.82 per Mcfe for the three months ended September 30, 2016 to $3.10 for the three months ended September 30, 2017, an increase of 10%. Average prices for ethane, C3+ NGLs, and oil all increased from 2016 levels, whereas average prices forIncreased natural gas declined from 2016 levels. Net equivalent prices after the effects of gains on settled derivatives (excluding hedge monetizations) decreased from $3.96 for the three months ended September 30, 2016 to $3.39 for the three months ended September 30, 2017, due to lower average hedged prices in the three months ended September 30, 2017.

~~Increased~~ production volumes accounted for an approximate ~~$115~~$30 million increase in year-over-year ~~product~~natural gas revenues (calculated as the ~~combined~~ change in year-to-year volumes times the prior year average price), and ~~increases~~changes in our ~~equivalent~~ prices, excluding the effects of derivative settlements, accounted for an approximate ~~$59~~$276 million ~~increase~~decrease in year-over-year ~~product~~ revenues (calculated as the change in the year-to-year average price times current year production volumes). ~~Production increases resulted~~

NGLs sales. Revenues from ~~an increase in the number~~production of ~~producing wells as a result of our drilling and completion program.~~

~~Table of Contents~~

~~During~~NGLs decreased from $314 million for the three months ended ~~September 30, 2016~~March 31, 2019 to $258 million for the three months ended March 31, 2020, a decrease of $56 million, or 18% (calculated as the change in year-over-year volumes times the change in year-to-year average price). Increased NGLs production volumes accounted for an approximate $76 million increase in year-over-year NGL revenues (calculated as the change in year-to-year volumes times the prior year average price), and ~~2017,~~changes in our ~~natural gas~~prices, excluding the effects of derivative settlements, accounted for an approximate $132 million decrease in year-over-year revenues ~~were negatively affected by contractual issues with certain~~(calculated as the change in the year-to-year average price times current year production volumes).

Table of Contents

Oil sales. Revenues from production of oil decreased from $48 million for the three months ended March 31, 2019 to $36 million for the three months ended March 31, 2020, a decrease of $12 million, or 26% (calculated as the change in year-over-year volumes times the change in year-to-year average price). Decreased oil production volumes accounted for an approximate $4 million decrease in year-over-year oil revenues (calculated as the change in year-to-year volumes times the prior year average price), and changes in our ~~customers. For more information on these disputes, please see Note 10 to~~prices, excluding the ~~condensed consolidated financial statements or “Item 1. Legal Proceedings” included elsewhere~~effects of derivative settlements, accounted for an approximate $8 million decrease in ~~this Quarterly Report on Form 10-Q.~~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)~~(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, 2016~~March 31, 2019 and ~~2017,~~2020, our commodity hedges resulted in derivative fair value ~~gains (losses)~~losses of ~~$530~~$77 million and ~~$(66)~~gains of $566 million, respectively. The commodity derivative fair value gains ~~and losses~~(losses) included ~~$197~~$97 million and ~~$61~~$211 million of gains on cash settled derivatives for the three months ended ~~September 30, 2016~~March 31, 2019 and ~~2017,~~March 31, 2020, respectively. Commodity derivative fair value gains (losses) for the three months ended September 30, 2017 also include gains of $750 million related to derivatives which were partially monetized prior to their settlement dates. See “—Deleveraging Activities” for further discussion.

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.

~~Gathering, compression, water handling and treatment revenues.~~ ~~Gathering, compression, water handling and treatment revenues remained consistent at $3~~Other income. Other income decreased from $2 million for the three months ended ~~September 30, 2016 and 2017. Fees for gathering, compression, water handling and treatment services provided~~March 31, 2019 to us by Antero Midstream are eliminated in consolidation. The amounts that are not eliminated represent the portion of such fees that are charged to outside working interest owners in Company-operated wells, as well as fees charged to other third parties for services provided by Antero Midstream.

~~Lease operating expense. Lease operating expense increased from $14~~$1 million for the three months ended ~~September 30, 2016 to $23~~March 31, 2020.

Lease operating expense. Lease operating expense decreased from $43 million for the three months ended ~~September 30, 2017, an increase~~March 31, 2019 to $26 million for the three months ended March 31, 2020, a decrease of ~~70%~~$17 million, or 40%. ~~This increase is primarily the result of an increase in production and the number of producing wells.~~ On a per unit basis, lease operating expenses ~~increased~~decreased from ~~$0.08 per Mcfe~~$0.15 for the three months ended ~~September 30, 2016~~March 31, 2019 to ~~$0.11 per Mcfe~~$0.08 for the three months ended ~~September 30, 2017. The increase in lease operating expenses on a per Mcfe basis~~March 31, 2020. This decrease is primarily due to ~~an increase in produced~~decreased water ~~on new well pads, which is attributable to an increase in the amount of water used in our advanced well completions. In addition, lease~~handling costs resulting from improved operating ~~expenses are expected to gradually increase on a per-unit basis as maturing properties make up a larger proportion of our production base~~efficiencies and ~~average production per existing well declines.~~cost reductions.

Gathering, compression, processing, and transportation expense. Gathering, compression, processing, and transportation expense increased from ~~$235~~$535 million for the three months ended ~~September 30, 2016~~March 31, 2019 to ~~$282~~$589 million for the three months ended ~~September 30, 2017. The increase in these expenses~~March 31, 2020. This is primarily a result of the increase in ~~production~~production. Gathering and ~~the related firm transportation, gathering,~~ compression ~~and processing expenses. On a~~costs decreased from $0.76 per Mcfe ~~basis, consolidated gathering, compression, processing~~to $0.63 per Mcfe primarily as a result of decreased costs associated with fuel as a result of a decrease in natural gas prices and a $12 million incentive fee rebate from Antero Midstream Corporation. Processing costs increased from $0.61 to $0.69 per Mcfe as a result of increased NGL production. Processing costs remained relatively unchanged per NGL barrel. Our transportation ~~expenses~~costs increased from $0.55 per Mcfe to $0.61 per Mcfe due to increased demand charges for Mountaineer Xpress pipeline, which came on line in February 2019.

Production and ad valorem tax expense. Production and ad valorem taxes decreased from ~~$1.36 per Mcfe~~$35 million for the three months ended ~~September 30, 2016~~March 31, 2019 to ~~$1.32 per Mcfe~~$26 million for the three months ended ~~September 30, 2017,~~March 31, 2020, a decrease of $9 million, or 26%. This decrease is primarily as a result of decreases in ~~fuel costs as compared to the prior year due to lower natural gas prices.~~

~~Production and ad valorem tax expense.~~ Total production and ad valorem taxes increased from $16 million for the three months ended September 30, 2016 to $23 million for the three months ended September 30, 2017 as a result of an increase in production revenues. On a per Mcfe basis, production and ad valorem taxes increased from $0.09 per Mcfe for the three months ended September 30, 2016 to $0.11 per Mcfe for the three months ended September 30, 2017 as a result of higher realizedcommodity prices. Production and ad valorem taxes as a percentage of natural gas ~~NGLs, and oil~~ revenues ~~before~~increased slightly from 5% in the ~~effects of hedging increased from 3.2%~~three months ended March 31, 2019, to 6% for the three months ended ~~September 30, 2016 to 3.5% for the three months ended September 30, 2017. As production in West Virginia increased at a higher rate than Ohio, severance taxes as a percentage~~March 31, 2020.

Impairment of ~~revenue increased due to higher severance tax rates in West Virginia as compared to Ohio.~~

~~Exploration expense~~oil and gas properties. ~~Exploration expense~~Impairment of oil and gas properties increased from $1$81 million for the three months ended ~~September 30, 2016~~March 31, 2019 to $2$89 million for the three months ended ~~September 30, 2017. These amounts represent expenses incurred for unsuccessful lease acquisition efforts.~~

~~Table~~March 31, 2020, an increase of ~~Contents~~

~~Impairment of unproved properties~~$8 million, or 10%. ~~Impairment of unproved properties increased from $12 million for the three months ended September 30, 2016~~We recognized impairments primarily related to ~~$41 million for the three months ended September 30, 2017, primarily due~~expiring leases and to ~~the expiration of certain Utica leases which~~design and initial costs related to pads we ~~elected not~~no longer plan to ~~retain and develop.~~place into service. We charge impairment expense for ~~expired or soon-to-be expired~~expiring leases when we determine they are impaired based on factors such as remaining lease terms, reservoir performance, commodity price outlooks, orand future plans to develop the acreage.

Depletion, depreciation, and amortization expense~~. Depletion, depreciation, and amortization~~ (“DD&A”) ~~increased~~. DD&A expense decreased from ~~$199~~$218 million for the three months ended ~~September 30, 2016~~March 31, 2019 to ~~$207~~$200 million for the three months ended ~~September 30, 2017, primarily because~~March 31, 2020, a decrease of ~~increased production.~~$18 million, or 9%. DD&A per Mcfe decreased ~~by 16%,~~ from ~~$1.16~~$0.78 per Mcfe during the three months ended ~~September 30, 2016~~March 31, 2019 to ~~$0.97~~$0.66 per Mcfe during the three months ended March 31, 2020, as our depletable reserve volumes at March 31, 2020 increased slightly due to increased production and our depletable cost base decreased from March 31, 2019 due to an impairment in the value of our Utica properties of $881 million in the three months ended September 30, 2017. This decrease was due to increases in our estimated recoverable reserves, due to improved well performance, and decreases in our per-unit development costs, which is due to well cost reductions and drilling and completion efficiencies that we have achieved over the last year.2019.

~~We evaluate the carrying amount~~Table of our proved natural gas, NGLs, and oil properties for impairment on a geological reservoir basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying amount exceeded the estimated undiscounted future net cash flows (measured using futures prices at the end of a quarter), we would further evaluate our proved properties and record an impairment charge if the carrying amount of our proved properties exceeded the estimated fair value of the properties. At September 30, 2017, we compared the carrying values of our proved properties to estimated future net cash flows. As estimated future net cash flows were higher than the carrying values of our proved properties at September 30, 2017, we did not further evaluate our proved properties for impairment.Contents

General and administrative expense. General and administrative expense ~~(before~~(excluding equity-based compensation expense) ~~increased~~related to the exploration and production segment decreased from ~~$31~~$43 million for the three months ended ~~September 30, 2016~~March 31, 2019 to ~~$36~~$28 million for the three months ended ~~September 30, 2017,~~March 31, 2020, a decrease of $15 million, or 36%. This decrease was primarily due to ~~increases~~approximately $6.3 million in legal and other expenses related to the Transactions in the three months ended March 31, 2019 as well as decreases in employee ~~compensation~~related expenses in the three months ended March 31, 2020 as a result of ongoing cost savings initiatives. We had 619 employees as of March 31, 2019 and ~~benefits expenses.~~531 employees as of March 31, 2020. On a per-unit basis, general and administrative expense ~~before~~excluding equity-based compensation decreased by 6%44%, from ~~$0.18~~$0.16 per Mcfe during the three months ended ~~September 30, 2016~~March 31, 2019 to ~~$0.17~~$0.09 per Mcfe during the three months ended ~~September 30, 2017, primarily due to our 24% increase in production. We had 516 employees~~March 31, 2020 as ~~of September 30, 2016 and 583 employees as of September 30, 2017.~~the expense decreased while production increased.

Equity-based compensation expense. ~~Non-cash~~Noncash equity-based compensation expense ~~remained consistent at $26~~decreased from $6 million for the three months ended ~~September 30, 2016~~March 31, 2019 to $3 million for the three months ended March 31, 2020, a decrease of $3 million, or 48%. This decrease was the result of equity award forfeitures, as well as a decrease in the total value of awards to officers and ~~2017.~~employees in 2019, which impacts future expense recognition. When an equity award is forfeited, expense previously recognized for the award is reversed. See Note 79 to the unaudited condensed consolidated financial statements included elsewhere in this ~~report~~Quarterly Report on Form 10-Q for more information on equity-based compensation awards.

~~Interest expense.~~ ~~Interest expense increased from $60~~Contract termination and rig stacking. We incurred contract termination and rig stacking costs of $8 million ~~for~~during the three months ended ~~September 30, 2016~~March 31, 2019 compared to $70 million for the three months ended September 30, 2017, primarily due to Antero Midstream’s issuance of its 5.375% senior notes due 2024 in September 2016 and increased average balances outstanding under our revolving credit facilities. Interest expense includes approximately $2.9 million and $3.0 million of non-cash amortization of deferred financing costs for the three months ended September 30, 2016 and 2017, respectively

~~Income tax (expense) benefit.~~ Income tax (expense) benefit changed from a deferred tax expense of $141 million for the three months ended September 30, 2016 to a deferred tax benefit of $45 million for the three months ended September 30, 2017. The deferred taxno expense for the three months ended ~~September 30, 2016 was due~~March 31, 2020. Contract termination and rig stacking costs represent fees incurred upon the delay or cancellation of drilling and completion contracts with third-party contractors in order to ~~pre-tax income generated for financial reporting purposes, whereas we incurred a pre-tax loss for financial reporting purposes for the three months ended September 30, 2017.~~align our drilling and completion activity level with our capital budget.

At December 31, 2016, we had approximately $1.6 billion of NOLs for U.S. federal income tax purposes that expire at various dates from 2024 through 2036 and approximately $1.4 billion of state NOLs that expire at various dates from 2017 through 2036. In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including to certain key U.S. federal income tax provisions currently available to oil and gas companies, such as deductions for intangible drilling costs. Moreover, other more general features of tax reform legislation, including changes to cost recovery rules and to the deductibility of interest expenses, may also change the taxation of oil and gas companies. If passed, such legislation could significantly affect our future taxable position. The impact of any such change would be recorded in the period in which such legislation is enacted.

~~Adjusted EBITDAX~~. Adjusted EBITDAX decreased by 10%, from $373 million for the three months ended September 30, 2016 to $336 million for the three months ended September 30, 2017. The decrease in Adjusted EBITDAX was primarily due to decreases in our average realized price for natural gas after gains on settled derivatives, partially offset by increased production. Adjusted EBITDAX does not include $750 million of realized gains from the partial monetization of certain natural gas hedges. See “—Deleveraging Activities” for further discussionDiscussion of the ~~hedge monetizations. See “—Non-GAAP Financial Measures” for a definition~~

~~Table of Contents~~

~~of Adjusted EBITDAX (a non-GAAP measure) and a reconciliation of Adjusted EBITDAX to net income (loss) including noncontrolling interest and net cash provided by operating activities.~~

~~Discussion of~~Marketing Segment ~~Results~~ for the Three Months Ended ~~September 30, 2016~~March 31, 2019 Compared to the Three Months Ended ~~September 30, 2017~~March 31, 2020

Our previous discussion of the consolidated exploration and production results includes the consolidated results from our gathering and processing, water handling and treatment, and marketing segments, whose revenues are almost entirely derived from services provided to the exploration and production segment. Our gathering and processing and water handling and treatment operations are almost entirely conducted by Antero Midstream, a master limited partnership. Antero owns 53% of Antero Midstream’s issued and outstanding common units. Antero Midstream’s distributable cash is paid to its common unitholders subsequent to the end of each quarter. Following is a summary level discussion of the various segment results which should be read in conjunction with our detailed discussion of our consolidated exploration and production results:

~~Exploration and production.~~ Revenues from the exploration and production segment decreased from $1.0 billion for the three months ended September 30, 2016 to $597 million for the three months ended September 30, 2017, primarily because of the decrease in commodity derivative fair value gains and losses of $596 million, partially offset by an increase in production revenues of $174 million from increases in production and realized prices. Total operating expenses increased from $566 million for the three months ended September 30, 2016 to $683 million for the three months ended September 30, 2017, primarily because of a 24% increase in production. Gathering, compression, processing, and transportation expenses increased by $66 million, lease operating expenses increased by $10 million, DD&A expenses increased by $3 million, impairment expense for unproved properties increased by $29 million and other items increased by $9 million.

On a per Mcfe basis, total gathering, compression, processing and transportation expenses for the exploration and production segment decreased from $1.76 per Mcfe for the three months ended September 30, 2016 to $1.73 per Mcfe for the three months ended September 30, 2017, primarily as a result of decreases in fuel costs.

~~Gathering and Processing.~~ Revenue for the gathering and processing segment increased from $78 million for the three months ended September 30, 2016 to $101 million for the three months ended September 30, 2017, an increase of $23 million, or 29%. Gathering revenues increased by $15 million from the prior year period and compression revenues increased by $8 million as additional wells on production increased throughput volumes. Total operating expenses related to the gathering and processing segment increased from $34 million for the three months ended September 30, 2016 to $42 million for the three months ended September 30, 2017 primarily as a result of increases in direct operating and depreciation expenses due to a larger base of gathering and compression assets.

In May 2016, Antero Midstream purchased a 15% equity interest in a regional gathering pipeline. In February 2017, Antero Midstream formed the Joint Venture with MarkWest, which provides natural gas processing and fractionation services. Equity in earnings of unconsolidated affiliates of $1.5 million and $7.0 million for the three months ended September 30, 2016 and 2017, respectively, represents the portion of the net income from these investments which is allocated to Antero Midstream based on its equity interests. The increase was primarily attributable to the commencement of operations of the Joint Venture in February 2017.

~~Water Handling and Treatment.~~ Revenue for the water handling and treatment segment increased from $72 million for the three months ended September 30, 2016 to $93 million for the three months ended September 30, 2017, an increase of $21 million, or 29%. The increase was primarily due to an increase in the volume of water used per well in our advanced completions during the three months ended September 30, 2017 as compared to the three months ended September 30, 2016, as well as an increase in other fluid handling services. The volume of water delivered through the systems increased from 12.9 MMBbls for the three months ended September 30, 2016 to 13.0 MMBbls for the three months ended September 30, 2017. Operating expenses for the water handling and treatment segment increased from $43 million for the three months ended September 30, 2016 to $69 million for the three months ended September 30, 2017, primarily due to the increase in other fluid handling services.

Marketing. Where permitted, we purchase and sell third-party natural gas and NGLs and market our excess firm transportation capacity, or engage third parties to conduct these activities on our behalf, in order to optimize the revenues from these transportation agreements. We have entered into long-term firm transportation agreements for ~~a significant portion of~~ our current and expected future production in order to secure guaranteed capacity to favorable markets. Marketing revenues of $97 million and $51 million and expenses of $115 million and $79 million for the three months ended September 30, 2016 and 2017, respectively, relate to these activities. Net losses on our marketing activities were $18 million and $28 million for the three months ended September 30, 2016 and 2017, respectively. Marketing costs include firm transportation costs related to current excess capacity as well as the cost of third-

~~Table of Contents~~

party purchased gas and NGLs. This includes firm transportation costs of $24 million and $27 million for the three months ended September 30, 2016 and 2017, respectively, related to unutilized excess capacity which increased due to decreased utilization of a pipeline which has higher per-unit commitment fees than the average of our transportation portfolio.

~~Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2017~~

The Company has four operating segments: (1) the exploration, development and production of natural gas, NGLs, and oil; (2) gathering and processing; (3) water handling and treatment; and (4) marketing of excess firm transportation capacity. Revenues from the gathering and processing and water handling and treatment operations are primarily derived from intersegment transactions for services provided to our exploration and production operations by Antero Midstream. Intersegment transactions that are eliminated include revenues from water handling and treatment services provided by Antero Midstream which are capitalized as proved property development costs by Antero. Marketing revenues are primarily derived from activities to purchase and sell third-party natural gas and NGLs and to market excess firm transportation capacity to third parties.

~~The operating results of the Company’s reportable segments were as follows for the nine months ended September 30, 2016 and 2017 (in thousands):~~

Exploration
and
production

Gathering and
processing

Water handling and treatment

Marketing

Elimination of
intersegment
transactions

Consolidated
total

Nine months ended September 30, 2016:

Sales and revenues:

Third-party

$
1,291,008

9,463

644

287,194

—

1,588,309

Intersegment

11,714

210,144

203,106

—

(424,964)

—

Total

$
1,302,722

219,607

203,750

287,194

(424,964)

1,588,309

Operating expenses:

Lease operating

$
37,299

—

104,009

—

(104,118)

37,190

Gathering, compression, processing, and transportation

838,936

20,567

—

—

(209,790)

649,713

Depletion, depreciation, and amortization

513,302

52,780

21,975

—

—

588,057

General and administrative (before equity-based compensation)

79,055

14,853

5,493

—

(1,102)

98,299

Equity-based compensation

56,301

14,902

4,464

—

—

75,667

Other

104,279

(809)

11,568

378,521

(10,384)

483,175

Total

1,629,172

102,293

147,509

378,521

(325,394)

1,932,101

Operating income (loss)

$
(326,450)

117,314

56,241

(91,327)

(99,570)

(343,792)

Equity in earnings of unconsolidated affiliates

$
—

2,027

—

—

—

2,027

Segment Adjusted EBITDAX (1)

$
973,101

184,996

93,064

(91,327)

(99,570)

1,060,264

~~Table of Contents~~

Exploration
and
production

Gathering and
processing

Water handling and treatment

Marketing

Elimination of
intersegment
transactions

Consolidated
total

Nine months ended September 30, 2017:

Sales and revenues:

Third-party

$
2,458,524

7,472

1,193

166,659

—

2,633,848

Intersegment

11,421

283,467

270,033

—

(564,921)

—

Total

$
2,469,945

290,939

271,226

166,659

(564,921)

2,633,848

Operating expenses:

Lease operating

$
56,991

—

131,635

—

(132,592)

56,034

Gathering, compression, processing, and transportation

1,070,522

28,492

—

—

(283,304)

815,710

Depletion, depreciation, and amortization

521,603

64,445

24,831

—

—

610,879

General and administrative (before equity-based compensation)

90,387

15,242

7,884

—

(1,438)

112,075

Equity-based compensation

58,489

14,937

5,499

—

—

78,925

Other

158,128

104

12,333

246,298

(9,672)

407,191

Total

1,956,120

123,220

182,182

246,298

(427,006)

2,080,814

Operating income (loss)

$
513,825

167,719

89,044

(79,639)

(137,915)

553,034

Equity in earnings of unconsolidated affiliates

$
—

12,887

—

—

—

12,887

Segment Adjusted EBITDAX (1)

$
853,730

257,221

129,046

(79,639)

(137,915)

1,022,443

~~(1)~~

~~See “—Non-GAAP Financial Measures” for a definition of Segment Adjusted EBITDAX (a non-GAAP measure) and a reconciliation of Segment Adjusted EBITDAX to operating income.~~

~~Table of Contents~~

~~The following tables set forth selected consolidated operating data for the nine months ended September 30, 2016 compared to the nine months ended September 30, 2017:~~

Nine Months Ended September 30,

Amount of
Increase

Percent

(in thousands)

2016

2017

(Decrease)

Change

Operating revenues and other:

Natural gas sales

$
848,936

$
1,330,062

$
481,126

57
%
NGLs sales

274,736

590,004

315,268

115
%
Oil sales

41,712

79,999

38,287

92
%
Gathering, compression, water handling and treatment

10,107

8,665

(1,442)

(14)
%
Marketing

287,194

166,659

(120,535)

(42)
%
Commodity derivative fair value gains

125,624

458,459

332,835

265
%
Total operating revenues and other

1,588,309

2,633,848

1,045,539

66
%
Operating expenses:

Lease operating

37,190

56,034

18,844

51
%
Gathering, compression, processing, and transportation

649,713

815,710

165,997

26
%
Production and ad valorem taxes

52,296

70,341

18,045

35
%
Marketing

378,521

246,298

(132,223)

(35)
%
Exploration

3,289

5,510

2,221

68
%
Impairment of unproved properties

47,223

83,098

35,875

76
%
Depletion, depreciation, and amortization

588,057

610,879

22,822

4
%
Accretion of asset retirement obligations

1,846

1,944

98

5
%
General and administrative (before equity-based compensation)

98,299

112,075

13,776

14
%
Equity-based compensation

75,667

78,925

3,258

4
%
Total operating expenses

1,932,101

2,080,814

148,713

8
%
Operating income (loss)

(343,792)

553,034

896,826

*

Other earnings (expenses):

Equity in earnings of unconsolidated affiliates

2,027

12,887

10,860

536
%
Interest expense

(185,634)

(205,311)

(19,677)

11
%
Total other expenses

(183,607)

(192,424)

(8,817)

5
%
Income (loss) before income taxes

(527,399)

360,610

888,009

*

Income tax (expense) benefit

230,755

(105,087)

(335,842)

*

Net income (loss) and comprehensive income (loss) including noncontrolling interest

(296,644)

255,523

552,167

*

Net income and comprehensive income attributable to noncontrolling interest

66,400

127,322

60,922

92
%
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation

$
(363,044)

$
128,201

$
491,245

*

Adjusted EBITDAX (1)

$
1,060,264

$
1,022,443

$
(37,821)

(4)
%

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Nine Months Ended September 30,

Amount of
Increase

Percent

2016

2017

(Decrease)

Change

Production data:

Natural gas (Bcf)

369

435

66

18
%
C2 Ethane (MBbl)

4,463

7,648

3,185

71
%
C3+ NGLs (MBbl)

14,722

19,085

4,363

30
%
Oil (MBbl)

1,373

1,880

507

37
%
Combined (Bcfe)

493

606

113

23
%
Daily combined production (MMcfe/d)

1,799

2,221

422

23
%
Average prices before effects of derivative settlements(2):

Natural gas (per Mcf)

$
2.30

$
3.06

$
0.76

33
%
C2 Ethane (per Bbl)

$
7.81

$
8.38

$
0.57

7
%
C3+ NGLs (per Bbl)

$
16.29

$
27.56

$
11.27

69
%
Oil (per Bbl)

$
30.38

$
42.56

$
12.18

40
%
Combined (per Mcfe)

$
2.36

$
3.30

$
0.94

40
%
Average realized prices after effects of derivative settlements(2):

Natural gas (per Mcf)

$
4.38

$
3.59

$
(0.79)

(18)
%
C2 Ethane (per Bbl)

$
7.81

$
8.62

$
0.81

10
%
C3+ NGLs (per Bbl)

$
19.30

$
22.37

$
3.07

16
%
Oil (per Bbl)

$
30.38

$
44.87

$
14.49

48
%
Combined (per Mcfe)

$
4.02

$
3.53

$
(0.49)

(12)
%
Average Costs (per Mcfe):

Lease operating

$
0.08

$
0.09

$
0.01

13
%
Gathering, compression, processing, and transportation

$
1.32

$
1.35

$
0.03

2
%
Production and ad valorem taxes

$
0.11

$
0.12

$
0.01

9
%
Marketing expense, net

$
0.19

$
0.13

$
(0.06)

(32)
%
Depletion, depreciation, amortization, and accretion

$
1.20

$
1.01

$
(0.19)

(16)
%
General and administrative (before equity-based compensation)

$
0.20

$
0.18

$
(0.02)

(10)
%

~~(1)~~

~~(2)~~

Average sales prices shown in the table reflect both the before and after effects of our settled derivatives. Our calculation of such after effects includes gains on settlements of derivatives (but does not include the hedge monetizations described in “—Deleveraging Activities” above), 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.

*~~Not meaningful or applicable.~~

~~Discussion of Consolidated Exploration and Production Results for the Nine Months Ended September 30, 2016 Compared to the Nine Months Ended September 30, 2017~~

~~Natural gas, NGLs, and oil sales~~. Revenues from production of natural gas, NGLs, and oil increased from $1.2 billion for the nine months ended September 30, 2016 to $2.0 billion for the nine months ended September 30, 2017, an increase of $835 million, or 72%. Our production increased by 23% over that same period, from 493 Bcfe, or 1,799 MMcfe per day, for the nine months ended September 30, 2016 to 606 Bcfe, or 2,221 MMcfe per day, for the nine months ended September 30, 2017. Net equivalent prices before the effects of settled derivative gains increased from $2.36 per Mcfe for the nine months ended September 30, 2016 to $3.30 for the nine months ended September 30, 2017, an increase of 40%. Average prices for natural gas, ethane, C3+ NGLs, and oil all increased from 2016 levels. Net equivalent prices after the effects of gains on settled derivatives (excluding hedge monetizations) decreased from $4.02 for the nine months ended September 30, 2016 to $3.53 for the nine months ended September 30, 2017, due to lower average hedged prices in the nine months ended September 30, 2017.

Increased production volumes accounted for an approximate $268 million increase in year-over-year product revenues (calculated as the combined change in year-to-year volumes times the prior year average price), and increases in our equivalent prices, excluding the effects of derivative settlements, accounted for an approximate $567 million increase in year-over-year product revenues (calculated as the change in the year-to-year average price times current year production volumes). Production increases resulted from an increase in the number of producing wells as a result of our drilling and completion program.

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During the nine months ended September 30, 2016 and 2017, our natural gas revenues were negatively affected by contractual issues with certain of our customers. For more information on these disputes, please see Note 10 to the condensed consolidated financial statements or “Item 1. Legal Proceedings” included elsewhere in this Quarterly Report on Form 10-Q.

~~Commodity derivative fair value gains.~~ To achieve more predictable cash flows, and to reduce our exposure to price fluctuations, we enter into fixed for variable price swap 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, 2016 and 2017, our hedges resulted in derivative fair value gains of $126 million and $458 million, respectively. The derivative fair value gains included $814 million and $137 million of gains on cash settled derivatives for the nine months ended September 30, 2016 and 2017, respectively. Commodity derivative fair value gains for the nine months ended September 30, 2017 includes gains of $750 million related to derivatives which were partially monetized prior to their settlement dates. See “—Deleveraging Activities” for further discussion.

~~Gathering, compression, water handling and treatment revenues.~~ Gathering, compression, water handling and treatment revenues decreased from $10 million for the nine months ended September 30, 2016 to $9 million for the nine months ended September 30, 2017, primarily attributable to the provision of such services to wells in which we hold a higher working interest than the wells to which such services were provided in 2016. Fees for gathering, compression, water handling and treatment services provided to us by Antero Midstream are eliminated in consolidation. The amounts that are not eliminated represent the portion of such fees that are charged to outside working interest owners in Company-operated wells, as well as fees charged to other third parties for services provided by Antero Midstream.

~~Lease operating expense~~. Lease operating expense increased from $37 million for the nine months ended September 30, 2016 to $56 million for the nine months ended September 30, 2017, an increase of 51%. This increase is primarily the result of an increase in production and the number of producing wells. On a per unit basis, lease operating expenses increased from $0.08 per Mcfe for the nine months ended September 30, 2016 to $0.09 for the nine months ended September 30, 2017. The increase in lease operating expenses on a per Mcfe basis is due to an increase in produced water on new well pads, which is attributable to an increase in the amount of water used in our advanced well completions. Lease operating expenses are expected to gradually increase on a per-unit basis as maturing properties make up a larger proportion of our production base and average production per existing well declines.

~~Gathering, compression, processing, and transportation expense.~~ Gathering, compression, processing, and transportation expense increased from $650 million for the nine months ended September 30, 2016 to $816 million for the nine months ended September 30, 2017. The increase in these expenses is a result of the increase in production and the related firm transportation, gathering, compression, and processing expenses. On a per Mcfe basis, consolidated gathering, compression, processing and transportation expenses increased from $1.32 per Mcfe for the nine months ended September 30, 2016 to $1.35 per Mcfe for the nine months ended September 30, 2017, primarily due to increased utilization of a pipeline, in the first half of 2017, which has higher per-unit transportation costs than the average of our transportation portfolio.

~~Production and ad valorem tax expense.~~ Total production and ad valorem taxes increased from $52 million for the nine months ended September 30, 2016 to $70 million for the nine months ended September 30, 2017 as a result of an increase in production revenues. On a per Mcfe basis, production and ad valorem taxes increased from $0.11 per Mcfe for the nine months ended September 30, 2016 to $0.12 per Mcfe for the nine months ended September 30, 2017 as a result of increases in per-unit production revenues. Production and ad valorem taxes as a percentage of natural gas, NGLs, and oil revenues before the effects of hedging decreased from 4.5% for the nine months ended September 30, 2016 to 3.5% for the nine months ended September 30, 2017, primarily attributable to the July 1, 2016 termination of a West Virginia production tax surcharge for workers’ compensation funding.

~~Exploration expense~~. Exploration expense increased from $3 million for the nine months ended September 30, 2016 to $6 million for the nine months ended September 30, 2017. These amounts represent expenses incurred for unsuccessful lease acquisition efforts.

~~Impairment of unproved properties~~. Impairment of unproved properties increased from $47 million for the nine months ended September 30, 2016 to $83 million for the nine months ended September 30, 2017, primarily due to the expiration of certain Utica

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leases, in the third quarter of 2017, which we elected not to retain and develop. We charge impairment expense for expired or soon-to-be expired leases when we determine they are impaired based on factors such as remaining lease terms, reservoir performance, commodity price outlooks, or future plans to develop the acreage.

~~Depletion, depreciation, and amortization expense~~. DD&A increased from $588 million for the nine months ended September 30, 2016 to $611 million for the nine months ended September 30, 2017, primarily because of increased production. DD&A per Mcfe decreased by 16%, from $1.20 per Mcfe during the nine months ended September 30, 2016 to $1.01 per Mcfe during the nine months ended September 30, 2017. This decrease was due to increases in our estimated recoverable reserves, due to improved well performance, and decreases in our per-unit development costs, which is due to well cost reductions and drilling and completion efficiencies that we have achieved over the last year.

We evaluate the carrying amount of our proved natural gas, NGLs, and oil properties for impairment on a geological reservoir basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying amount exceeded the estimated undiscounted future net cash flows (measured using futures prices at the end of a quarter), we would further evaluate our proved properties and record an impairment charge if the carrying amount of our proved properties exceeded the estimated fair value of the properties. At September 30, 2017, we compared the carrying values of our proved properties to estimated future net cash flows. As estimated future net cash flows were higher than the carrying values of our proved properties at September 30, 2017, we did not further evaluate our proved properties for impairment.

~~General and administrative expense~~. General and administrative expense (before equity-based compensation expense) increased from $98 million for the nine months ended September 30, 2016 to $112 million for the nine months ended September 30, 2017, primarily due to increases in employee compensation and benefits expenses. On a per-unit basis, general and administrative expense before equity-based compensation decreased by 10%, from $0.20 per Mcfe during the nine months ended September 30, 2016 to $0.18 per Mcfe during the nine months ended September 30, 2017, primarily due to our 23% increase in production. We had 516 employees as of September 30, 2016 and 583 employees as of September 30, 2017.

~~Equity-based compensation expense~~. Non-cash equity-based compensation expense increased from $76 million for the nine months ended September 30, 2016 to $79 million for the nine months ended September 30, 2017 as a result of an increase in outstanding equity awards. See Note 7 to the condensed consolidated financial statements included elsewhere in this report for more information on equity-based compensation awards.

~~Interest expense.~~ Interest expense increased from $186 million for the nine months ended September 30, 2016 to $205 million for the nine months ended September 30, 2017, primarily due to Antero Midstream’s issuance of its 5.375% senior notes due 2024 in September 2016. Interest expense includes approximately $8.5 million and $8.8 million of non-cash amortization of deferred financing costs for the nine months ended September 30, 2016 and 2017, respectively

~~Income tax (expense) benefit.~~ Income tax (expense) benefit changed from a deferred tax benefit of $231 million for the nine months ended September 30, 2016 to a deferred tax expense of $105 million for the nine months ended September 30, 2017. The deferred tax benefit for the nine months ended September 30, 2016 was due to a pre-tax loss incurred for financial reporting purposes, whereas we generated pre-tax income for financial reporting purposes for the nine months ended September 30, 2017.

~~Adjusted EBITDAX~~. Adjusted EBITDAX decreased from $1.1 billion for the nine months ended September 30, 2016 to $1.0 billion for the nine months ended September 30, 2017. The decrease in Adjusted EBITDAX was primarily due to decreases in our average realized price for natural gas after gains on settled derivatives, partially offset by increased production. Adjusted EBITDAX does not include $750 million of realized gains from the partial monetization of certain natural gas hedges. See “—Deleveraging Activities” for further discussion of the hedge monetizations. See “—Non-GAAP Financial Measures” for a definition of Adjusted EBITDAX (a non-GAAP measure) and a reconciliation of Adjusted EBITDAX to net income (loss) including noncontrolling interest and net cash provided by operating activities.

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~~Discussion of Segment Results for the Nine Months Ended September 30, 2016 Compared to the Nine Months Ended September 30, 2017~~

~~Exploration and production.~~ Revenues from the exploration and production segment increased from $1.3 billion for the nine months ended September 30, 2016 to $2.5 million for the nine months ended September 30, 2017, primarily because of an increase in production revenues of $835 million from increases in production and realized prices, as well as an increase in commodity derivative fair value gains and losses of $333 million. Total operating expenses increased from $1.6 billion for the nine months ended September 30, 2016 to $2.0 billion for the nine months ended September 30, 2017, primarily because of a 23% increase in production. Gathering, compression, processing, and transportation expenses increased by $232 million, lease operating expenses increased by $20 million, DD&A expenses increased by $8 million, impairment expense for unproved properties increased by $36 million and other items increased by $31 million.

On a per Mcfe basis, total gathering, compression, processing and transportation expenses for the exploration and production segment increased from $1.70 per Mcfe for the nine months ended September 30, 2016 to $1.76 per Mcfe for the nine months ended September 30, 2017 as a result of increased utilization of a pipeline, in the first half of 2017, which has higher per-unit transportation costs than the average of our transportation portfolio, as well as an increase in the proportion of gathering and compression expenses provided to us by Antero Midstream. Such expenses are eliminated in consolidation.

~~Gathering and Processing.~~ Revenue for the gathering and processing segment increased from $220 million for the nine months ended September 30, 2016 to $291 million for the nine months ended September 30, 2017, an increase of $71 million, or 32%. Gathering revenues increased by $47 million from the prior year period and compression revenues increased by $24 million as additional wells on production increased throughput volumes. Total operating expenses related to the gathering and processing segment increased from $102 million for the nine months ended September 30, 2016 to $123 million for the nine months ended September 30, 2017 primarily as a result of increases in direct operating and depreciation expenses due to a larger base of gathering and compression assets.

In May 2016, Antero Midstream purchased a 15% equity interest in a regional gathering pipeline. In February 2017, Antero Midstream formed the Joint Venture with MarkWest, which provides natural gas processing and fractionation services. Equity in earnings of unconsolidated affiliates of $2 million and $13 million for the nine months ended September 30, 2016 and 2017, respectively, represents the portion of the net income from these investments which is allocated to Antero Midstream based on its equity interests. The increase was due to a full nine months of investment income in the regional gathering pipeline during the nine months ended September 30 2017, as opposed to five months during the nine months ended September 30, 2016, and the commencement of operations of the Joint Venture in February 2017.

~~Water Handling and Treatment.~~ Revenue for the water handling and treatment segment increased from $204 million for the nine months ended September 30, 2016 to $271 million for the nine months ended September 30, 2017, an increase of $67 million, or 33%. The increase was due to an increase in the volume of water used per well in our advanced completions during the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016, as well as an increase in other fluid handling services The volume of water delivered through the systems increased from 31.3 MMBbls for the nine months ended September 30, 2016 to 42.1 MMBbls for the nine months ended September 30, 2017. Operating expenses for the water handling and treatment segment increased from $148 million for the nine months ended September 30, 2016 to $182 million for the nine months ended September 30, 2017, primarily due to the increase in other fluid handling services.

~~Marketing.~~Where ~~permitted,~~feasible, we purchase and sell third-party natural gas and NGLs ~~and market~~to utilize our excess firm transportation capacity, or ~~engage~~release capacity to third parties to conduct these activities on our behalf, in order to ~~optimize~~reduce our net costs related to the ~~revenues from~~unused capacity under these transportation agreements. We have entered into long-term firm transportation agreements for a significant portion of our current and expected future production in order to secure guaranteed capacity to favorable markets. Marketing revenues of $287 million and $167 million and expenses of $379 million and $246 million for the nine months ended September 30, 2016 and 2017, respectively, relate to these

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~~activities. Net~~Operating losses on our marketing activities, ~~were $92~~or our net marketing expense, decreased from $72 million, or $0.26 per Mcfe, for the three months ended March 31, 2019 to $47 million, or $0.15 per Mcfe, for the three months ended March 31, 2020. The decrease was driven by higher volumes and ~~$79~~the mitigation of some of our excess firm transportation expense.

Marketing revenues decreased from $91 million for the ~~nine~~three months ended ~~September 30, 2016~~March 31, 2019 to $46 million for the three months ended March 31, 2020, a decrease of $45 million, or 49%. The decreases in revenues is due to lower excess firm transportation capacity and ~~2017, respectively.~~ decreases in commodity prices in the three months ended March 31, 2020 compared to the three months ended March 31, 2019.

Marketing ~~costs~~expenses decreased from $163 million for the three months ended March 31, 2019 to $93 million for the three months ended March 31, 2020, a decrease of $70 million, or 43%. Marketing expenses include firm transportation costs related to current excess firm capacity as well as the cost of third-party purchased gas and NGLs. ~~This includes firm~~Firm transportation costs ~~of $96~~included in the expenses above were $68 million and ~~$74~~$47 million for the ~~nine~~three months ended ~~September 30, 2016~~March 31, 2019 and ~~2017, respectively, related~~2020, respectively.

Discussion of Antero Midstream Corporation Segment for the Three Months Ended March 31, 2019 Compared to ~~unutilized excess capacity which decreased~~the Three Months Ended March 31, 2020

Through March 12, 2019, the results of Antero Midstream Partners are included in our consolidated financial statements. Effective March 13, 2019, we no longer consolidate the results of Antero Midstream Partners in our results. As such, the three months ended March 31, 2019 include the results of Antero Midstream Partners through March 12, 2019. See Note 3 to the unaudited condensed consolidated financial statements for further discussion on the Transactions.

Antero Midstream Corporation. Revenue from the Antero Midstream Corporation segment increased from $54 million for the three months ended March 31, 2019 to $244 million for the three months ended March 31, 2020, an increase of $190 million, or 350%. The increase in operating revenue was primarily due to the ~~assumption~~three months ended March 31, 2019 only including Antero Midstream Corporation’s results following the closing of ~~certain unutilized firm transportation capacity~~the Transactions on March 12, 2019. Total operating expenses related to the segment increased from $33 million for the three months ended March 31, 2019 to $763 million for the three months ended March 31,

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2020. The increase was primarily due to impairments by Antero Midstream Corporation of $89 million on its freshwater pipelines and equipment, and an impairment charge of $575 million on its goodwill.

Discussion of Items Not Allocated to Segments for the Three Months Ended March 31, 2019 Compared to the Three Months Ended March 31, 2020

Impairment of equity investment. At 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 at March 31, 2020.

Interest expense. Our interest expense exclusive of interest expense related to Antero Midstream Partners’ indebtedness decreased from $55 million in the three months ended March 31, 2019 to $53 million in the three months ended March 31, 2020, a ~~third party beginning July 1, 2016.~~decrease of $2 million, or 3%. This decrease is due to a decrease in total indebtedness resulting from repurchases of our unsecured senior notes at prices below their stated value.

Consolidated interest expense decreased from $72 million for the three months ended March 31, 2019 to $53 million for the three months ended March 31, 2020, a decrease of $19 million, or 26%. During the three months ended March 31, 2019, interest related to Antero Midstream Partners’ debt through March 12, 2019 is included consolidated interest expense.

Interest expense includes approximately $3.1 million and $2.5 million of non-cash amortization of deferred financing costs for the three months ended March 31, 2019 and 2020, respectively.

Income tax expense/benefit. Income tax expense decreased from a deferred tax expense of $288 million and $1 million of current tax expense, with an effective tax rate of 22%, for the three months ended March 31, 2019 to a deferred tax benefit of $110 million, with an effective tax rate of 25%, for the three months ended March 31, 2020. The change was primarily a result of the increase in book income due to the Transactions and the associated deconsolidation of Antero Midstream Partners for the three months ended March 31, 2019, offset by the decrease in book income resulting from the impairment of our investment in Antero Midstream Corporation for the three months ended March 31, 2020.

Capital Resources and Liquidity

~~Historically, our~~Our primary sources of liquidity have been through net cash provided by operating activities including proceeds from derivatives, borrowings under the Credit Facility, issuances of debt and equity securities, ~~borrowings under the Prior Credit Facility~~ and ~~Prior Midstream Facility, asset sales, and net cash provided by operating activities.~~distributions/dividends from unconsolidated affiliates. Our primary use of cash has been for the exploration, development, and acquisition of oil and natural gas ~~NGLs, and oil properties, as well as for development of gathering systems and facilities, and fresh water handling and wastewater treatment infrastructure.~~properties. As we ~~pursue the development of~~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.

In addition, we may from time to time repurchase shares of our common stock. Under our prior share repurchase program, we repurchased and retired 27,193,237 common shares at a weighted average price per share of $1.57 for approximately $43 million during the three months ended March 31, 2020. During the term of this program, we repurchased approximately $215 million of our shares of common stock.

We may also seek to retire or purchase our outstanding debt securities from time to time through cash purchases, in open market purchases, privately negotiated transactions or otherwise. Any such repurchases will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors.

During the three months ended March 31, 2020, we repurchased $383 million principal amount of debt at a 21% weighted average discount, including a portion of both our 2021 notes and our 2022 notes. We recognized a gain of approximately $81 million on the early extinguishment of the debt repurchased. These repurchases, at a discount, have resulted in a net reduction in total debt outstanding and interest expense.

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As of March 31, 2020, we believe that funds from operating cash flows, ~~and~~distributions from unconsolidated affiliates, available borrowings under the Credit ~~Facility and Midstream~~ Facility, or capital market transactions 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. Our 2021 notes are due November 1, 2021 and our Credit Facility will become due 91 days prior to that date, or on August 1, 2021, if the 2021 notes are not repaid prior to August 1, 2021. If the 2021 notes remain outstanding as of August 1, 2020, the Credit Facility will be classified as a current liability as of September 30, 2020 and both the Credit Facility and the 2021 notes will be classified as current liabilities as of December 31, 2020 if still outstanding at that time. The classification of the Credit Facility as a current liability does not impact any of our financial covenants. In addition, we believe we have the ability to address the maturity of the 2021 Notes with proceeds from potential asset sales, free cash flow from operations, and available borrowings under the Credit Facility.

For more information on our outstanding indebtedness, see Note 57 to the unaudited condensed consolidated financial statements included in this Quarterly Report on Form 10-Q.

For information about the impacts of COVID-19 on our capital resources and liquidity, see “—COVID-19 Pandemic.”

The following table summarizes our cash flows for the ~~nine~~three months ended ~~September 30, 2016~~March 31, 2019 and ~~2017:~~2020:


	Nine Months Ended September 30,

					Three Months Ended March 31,				Increase
(in thousands)	2016		2017		2019		2020		(Decrease)
Net cash provided by operating activities	$	905,697		1,692,808	$	539,004		200,677	(338,327)
Net cash used in investing activities		(1,974,667)		(1,948,307)		(204,817)		(186,681)	18,136
Net cash provided by financing activities		1,064,009		247,583
Net cash provided by (used in) financing activities						285,345		(13,996)	(299,341)
Effect of deconsolidation of Antero Midstream Partners LP						(619,532)		—	619,532
Net decrease in cash and cash equivalents	$	(4,961)		(7,916)	$	—		—	—

The Company's condensed consolidated cash flow statements for the three months ended March 31, 2019 includes the cash flows related to Antero Midstream Partners for periods prior to March 13, 2019. Effective March 13, 2019, the Company's cash flows include only the operating, investing and financing activities related to Antero and; therefore, the cash flows for the three months ended March 31, 2019 are not representative of our expected future cash flows. See Note 3 to the unaudited condensed consolidated financial statements for more information.

Cash ~~Flow~~Flows Provided by Operating Activities

Net cash provided by operating activities was ~~$906~~$539 million and ~~$1.7 billion~~$201 million for the ~~nine~~three months ended ~~September 30, 2016~~March 31, 2019 and ~~2017,~~2020, respectively. ~~The increase in cash flows~~Cash flow from operations ~~from the nine months ended September 30, 2016 to the nine months ended September 30, 2017 was~~decreased primarily due to ~~$750 million~~decreases in commodity prices both before and after the effects of ~~proceeds from the partial monetization of certain of our natural gas hedges. See “—Deleveraging Activities” for further discussion.~~settled commodity derivatives and increases in gathering, compression and transportation costs.

Our net operating cash ~~flow is~~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. ~~For additional information on the impact of changing prices on our financial position, see “Item 3. Quantitative and Qualitative Disclosures About Market Risk.”~~

Cash ~~Flow~~Flows Used in Investing Activities

During the three months ended March 31, 2019 and 2020, we used cash flows in investing activities of $205 million and $187 million, respectively, primarily as a result of our capital expenditures for drilling, development, and acquisitions. In addition, cash flows in investing activities included expenditures of Antero Midstream Partners related to construction of midstream and water handling and treatment infrastructure and investments in joint ventures through March 12, 2019. Effective March 13, 2019, these expenditures are no longer consolidated in our results.

Cash flows used in investing activities decreased from ~~$2.0 billion~~$205 million for the ~~nine~~three months ended ~~September 30, 2016~~March 31, 2019 to ~~$1.9 billion~~$187 million for the ~~nine~~three months ended ~~September 30, 2017,~~March 31, 2020, primarily due to ~~decreases~~a decrease in ~~acquisitions~~capital expenditures of $160 million during the three months ended March 31, 2020 as compared to the same period in 2019, $297 million in proceeds received in connection with the Transactions impacting the three months ended March 31, 2019 and $125 million in settlement of the water earnout impacting the three months ended March 31, 2020. See Note 3 to the unaudited condensed consolidated financial statements for further discussion on the Transactions.

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Total capital expenditures for oil and gas properties decreased from $396 million during the three months ended March 31, 2019 to $311 million during the three months ended March 31, 2020 primarily due to a decrease in drilling and completion ~~costs, partially offset by increases~~activity, increased drilling and completion efficiencies and service cost deflation.

The three months ended March 31, 2019 included Antero ~~Midstream’s~~Midstream Partners’ investments in ~~the Joint Venture~~joint ventures of $25 million and capital expenditures for water handling and treatment systems and gas gathering and compression ~~assets during~~systems of $73 million. Due to the ~~nine months ended September 30, 2017. During the nine months ended September 30, 2017, our~~deconsolidation of Antero Midstream Partners on March 12, 2019, cash flows used in investing activities ~~included $947 million~~ for the three months ended March 31, 2020 do not include costs attributable to Antero Midstream Partner’s investing activity.

Our drilling and completion costs, $182 million for undeveloped leasehold additions, $179 million for acquisitions, $143 million for water handling and treatment systems, $255 million for gathering and compression systems, $217 million for investments in the Joint Venture, and $11 million for other property and equipment. During the nine months ended September 30, 2016, our cash flows used in investing activities included $1.0 billion for drilling and completion costs, $106 million for undeveloped leasehold additions, $519 million for acquisitions, $137 million for water handling and treatment systems, $154 million for gathering and compression systems, $45 million for a 15% equity interest in a regional gathering pipeline, and $2 million for other property and equipment.

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~~Our~~ capital budget for ~~2017 is $1.5 billion, which does not include the capital budget of $800~~2020 has been reduced to $750 million ~~for Antero Midstream, our consolidated subsidiary.~~from $1.15 billion. Our capital budget may be adjusted as business conditions warrant as the amount, timing, and allocation of capital expenditures is largely discretionary and within our control. If natural gas, NGLs, and oil prices decline to levels ~~below our~~that do not generate an acceptable ~~levels,~~level of corporate returns, or costs increase to levels ~~above our~~that do not generate an acceptable ~~levels,~~level of corporate returns, we ~~could choose to~~may defer a significant portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity, and to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in commodity prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, ~~success or lack of~~the relative success in drilling activities, contractual obligations, internally generated cash flows, and other factors both within and outside our control.

Cash ~~Flow~~Flows Provided by Financing Activities

~~Net~~During the three months ended March 31, 2019 and 2020, net cash flows provided by financing activities decreased from ~~$1.1 billion for~~a source of $285 million to a use of $14 million primarily as a result of the ~~nine months ended September 30, 2016 to $248 million for the nine months ended September 30, 2017, primarily due to issuances~~issuance of ~~common stock~~senior notes by Antero ~~during~~Midstream Partners prior to the ~~nine months ended September 30, 2016 to fund property acquisitions, as well as repayments on Antero’s Prior Credit Facility during~~Transactions and the ~~nine months ended September 30, 2017 using proceeds from the hedge monetizations and sale~~associated deconsolidation of Antero Midstream common units owned by Antero described under “—Deleveraging Activities.” During the nine months ended September 30, 2017, our cash flows provided by financing activities included proceeds of $311 million from the sale of Antero Midstream common units owned by Antero and net proceeds from the issuance of common units in Antero Midstream of $249 million (including $26 million issued under the Distribution Agreement),Partners, partially offset by net repayments on our ~~revolving credit facilities of $198 million, distributions of $102 million to noncontrolling interest owners in~~Credit Facility and Antero Midstream Partners’ credit facility.

Net borrowings (repayments) on our Credit Facility and ~~other items totaling $12 million. During~~Antero Midstream Partners’ credit facility changed from net payments of $270 million during the ~~nine~~three months ended ~~September 30, 2016, our cash flows provided by financing activities included proceeds~~March 31, 2019 to net borrowings of ~~$837~~$330 million ~~from~~during the ~~issuance~~three months ended March 31, 2020. Approximately $302 million of common stock, proceeds of $178 million from the sale of Antero Midstream common units owned by Antero, proceeds of $650 million from Antero Midstream’s issuance of its 5.375% senior notes due 2024, and proceeds of $20 million from the sale of common units by Antero Midstream under the Distribution Agreement, partially offset by net repaymentsborrowings on our ~~revolving credit facilities of $552 million, distributions of $51 million to noncontrolling interest owners in Antero Midstream, and other items totaling $18 million.~~

~~As a result of the aforementioned deleveraging activities, the balance outstanding under Antero’s Prior~~ Credit Facility ~~had~~in the three months ended March 31, 2020 was used to repurchase a ~~net decrease from $930~~portion of our 2021 and 2022 unsecured notes. In addition, we repurchased and retired 27,193,237 common shares for approximately $43 million ~~at June 30, 2017 to $25 million at September 30, 2017. The balance outstanding under~~during the ~~Prior Midstream Facility increased from $305 million at June 30, 2017 to $427 million at September 30, 2017.~~three months ended March 31, 2020. We did not repurchase any of our unsecured notes or shares during the three months ended March 31, 2019.

Debt Agreements and Contractual Obligations

~~Antero Resources~~ Senior Secured Revolving Credit Facility. ~~Antero’s~~Our Credit Facility is with a consortium of bank lenders. On April 29, 2020, Antero Resources entered into a Third Amendment to the Credit Facility, pursuant to which certain terms of the Credit Facility were amended, as further described herein. Borrowings under the Credit Facility are subject to borrowing base limitations based on the collateral value of our assets and are subject to regular ~~semiannual~~ redeterminations. ~~At September 30, 2017, under the Prior Credit Facility, the~~The borrowing base was ~~$4.75~~adjusted to $2.85 billion and lender commitments were ~~$4.0 billion.~~reaffirmed at $2.64 billion in the scheduled redetermination in April 2020. The next redetermination of the borrowing base is scheduled to occur in March 2018. At September 30, 2017, we had $25 million of borrowings and $700 million of letters of credit outstanding under the Prior Credit Facility, with a weighted average interest rate of 4.75%. At December 31, 2016, we had $440 million of borrowings and $710 million of letters of credit outstanding under the Prior Credit Facility, with a weighted average interest rate of 2.44%.October 2020. The maturity date of the Credit Facility is the earlier of (i) October 26, 2022 and (ii) the date that is 91 days prior to the ~~maturity~~earliest stated redemption date of any series of ~~Antero’s~~our senior notes ~~unless such series~~then outstanding.

At December 31, 2019, we had $552 million of ~~senior notes is refinanced.~~borrowings under the Credit Facility with a weighted average interest rate of 3.28% and $623 million of letters of credit outstanding. At March 31, 2020, we had $882 million of borrowings and $730 million of letters of credit outstanding under the Credit Facility. The average annualized interest rate incurred on the Credit Facility during the three months ended March 31, 2020 was approximately 3.28%. Our Credit Facility provides for borrowing under either LIBOR or an Alternative Rate of Interest.

Under the Credit Facility, “Investment Grade Period” is a period that, as long as no event of default has occurred, commences when Antero elects to give notice to the Administrative Agent that Antero has received at ~~lease~~least one of either (i) a BBB- or better rating from ~~Standard and Poor’s and~~S&P or (ii) a Baa3 or better rating from Moody’s (an “Investment Grade Rating”). An Investment Grade Period can end at Antero’s election. During any period that is not an Investment Grade Period, the Credit Facility requires Antero and its restricted subsidiaries to maintain the following two financial ratios as of the end of each fiscal quarter:

●

a current ratio, which is the ratio of our current assets (including any unused borrowing base under the facilities and excluding derivative assets) to our current liabilities (excluding derivative liabilities and lease liabilities), of not less than 1.0 to 1.0; and

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●

an interest coverage ratio, which is the ratio of EBITDAX (as defined by the credit facility agreement) to interest expense over the most recent four quarters, of not less than 2.5 to 1.0.

During an Investment Grade Period, the Credit Facility requires Antero and its restricted subsidiaries to maintain the following three financial ratios as of the end of each fiscal quarter

●

~~an interest coverage ratio, which is the ratio of EBITDAX (as defined by the credit facility agreement) to interest expense over the most recent four quarters, of not less than 2.5 to 1.0.~~

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~~During an Investment Grade Period, the Credit Facility requires Antero and its restricted subsidiaries to maintain the following three financial ratios as of the end of each fiscal quarter:~~

a ratio of total Indebtedness (as defined by the credit facility agreement) to EBITDAX (as defined by the credit facility agreement) of not more than 4.25 to 1.00; and

●

a ratio of PV-9 reflected in the most recently delivered reserve report to its total Indebtedness of not less than 1.50 to 1.00, but only if Antero does not have both (i) an unsecured rating from Moody’s of Baa3 or better and (ii) an unsecured rating from S&P of BBB- or better.

We were in compliance with ~~such~~the applicable covenants and ratios as ~~determined by the Prior Credit Facility as~~ of December 31, ~~2016~~2019 and ~~September 30, 2017.~~March 31, 2020. The actual borrowing capacity available to us may be limited by the financial ratio covenants. At ~~September 30, 2017,~~March 31, 2020, our current ratio was ~~5.73~~2.28 to 1.0 ~~(based on the $4.5 billion borrowing base under the Credit Facility)~~ and our interest coverage ratio was ~~9.01~~5.06 to 1.0.

~~Midstream~~For more information on the terms, conditions, and restrictions under the Credit Facility,. Antero Midstream has a secured revolving credit facility among Antero Midstream, certain lenders party thereto, and Wells Fargo Bank, National Association, as administrative agent, letter of credit issuer, and swing line lender. The Midstream Facility provides for lender commitments of $1.5 billion and for a letter of credit sublimit of $150 million. At September 30, 2017, Antero Midstream had a total outstanding balance under the Prior Midstream Facility of $427 million, with a weighted average interest rate of 2.82%. At December 31, 2016, Antero Midstream had a total outstanding balance under the Prior Midstream Facility of $210 million, with a weighted average interest rate of 2.23%. The Midstream Facility matures on October 26, 2022. please refer to our 2019 Form 10-K.

Senior Notes. Please refer to Note 57 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 our ~~Annual Report on~~ Form 10-K ~~for the year ended December 31, 2016~~ for information on our senior notes.

We may, from time to time, seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for equity securities, in open market purchases, privately negotiated transactions, or otherwise. Such repurchases, ~~or exchanges,~~ if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions, and other factors. The amounts involved could be material. During the three months ended March 31, 2020, we repurchased $383 million principal amount of debt at a 21% weighted average discount, including a portion of our 2021 notes and our 2022 notes.

For more information on the terms, conditions, and restrictions under the Prior Credit Facility, the Prior Midstream Facility, and senior unsecured notes, please refer to our Annual Report on Form 10-K for the year ended December 31, 2016 on file with the SEC.

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Contractual Obligations. A summary of our contractual obligations as of ~~September 30, 2017~~March 31, 2020 is provided in the table below. ~~Contractual obligations listed exclude minimum fees that we will pay to Antero Midstream, our consolidated subsidiary, under gathering and compression, and water services agreements.~~ Future capital contributions to unconsolidated affiliates are excluded from the table as neither the amounts nor the timing of the obligations can be determined in advance.

Remainder

Year Ended December 31,

(in millions)

of 2017

2018

2019

2020

2021

2022

Thereafter

Total

Antero Credit Facility(1)

$
—

—

—

—

25

—

—

25

Antero Midstream Facility(1)

—

—

—

—

—

427

—

427

Antero senior notes—principal(2)

—

—

—

—

1,000

1,100

1,350

3,450

Antero senior notes—interest(2)

77

182

182

182

155

129

111

1,018

Antero Midstream senior notes—principal(2)

—

—

—

—

—

—

650

650

Antero Midstream senior notes—interest(2)

—

35

35

35

35

35

70

245

Drilling rig and completion service commitments(3)

28

80

41

—

—

—

—

149

Firm transportation (4)

135

886

1,107

1,127

1,106

1,053

9,635

15,049

Processing, gathering, and compression services (5)

109

401

340

337

321

317

1,502

3,327

Office and equipment leases

4

13

11

9

8

8

17

70

Asset retirement obligations(6)

—

—

—

—

—

—

38

38

Total

$
353

1,597

1,716

1,690

2,650

3,069

13,373

24,448


	Remainder		Year ended December 31,
(in millions)	of 2020		2021		2022		2023		2024		2025		Thereafter		Total
Recorded contractual obligations:
Credit Facility⁽¹⁾	$	—		882		—		—		—		—		—		882
Antero senior notes—principal⁽²⁾		—		730		761		750		—		600		—		2,841
Antero senior notes—interest⁽²⁾		135		151		111		51		30		15		—		493
Operating leases⁽³⁾		228		269		285		313		342		309		1,069		2,815
Finance leases⁽³⁾		1		1		—		—		—		—		—		2
Imputed interest for leases⁽³⁾		236		289		259		225		188		149		326		1,672
Asset retirement obligations⁽⁴⁾		—		—		—		—		—		—		57		57
Unrecorded contractual obligations:
Firm transportation⁽⁵⁾		833		1,077		1,034		1,057		1,017		978		6,931		12,927
Processing, gathering, and compression services⁽⁶⁾		42		56		54		59		59		47		105		422
Drilling and completion		19		—		—		—		—		—		—		19
Land payment obligations⁽⁷⁾		2		3		—		—		—		—		—		5
Total	$	1,496		3,458		2,504		2,455		1,636		2,098		8,488		22,135

(1)

~~(1)~~

Includes outstanding principal amounts at ~~September 30, 2017.~~March 31, 2020. This table does not include future commitment fees, interest expense, or other fees on our Credit ~~Facility or the Midstream~~ Facility because they are floating rate instruments and we cannot determine with accuracy the timing of future loan advances, repayments, or future interest rates to be charged. The maturity date of the Credit Facility is the earlier of (i) October 26, 2022 and (ii) the date that is 91 days prior to the ~~maturity~~earliest stated redemption of any series of Antero’s senior notes ~~unless such series of notes is refinanced. The maturity date of the Midstream Facility is October 26, 2022~~

then outstanding.

(2)

~~(2)~~

~~Antero~~Our senior notes include ~~the 5.375%~~our 2021 notes, ~~due 2021, the 5.125%~~our 2022 notes, ~~due 2022, the~~our 5.625% notes due 2023, and ~~the~~our 5.00% notes due 2025. ~~Antero Midstream senior notes include the 5.375% notes due 2024.~~

(3)

~~(3)~~

Includes contracts for services provided by drilling rigs and completion fleets, ~~which expire at various dates from March 2018 through February 2020.~~processing, gathering and compression services agreements and office and equipment leases accounted for as leases. The values in the table represent the gross amounts that we are committed to pay; however, we will record in our financial statements our proportionate share of costs based on our working interests.

See Note 12 to the unaudited condensed consolidated financial statements for more information on the Company’s operating and finance leases.

(4)

~~(4)~~

Represents the present value of our estimated asset retirement obligations. Neither the ultimate settlement amounts nor the timing of our asset retirement obligations can be precisely determined in advance; however, we believe it is likely that a very small amount of these obligations will be settled within the next five years.

(5)

Includes firm transportation agreements with various pipelines in order to facilitate the delivery of our production to market. These contracts commit us 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 reflect our minimum daily volumes at the reservation fee rates. The values in the table represent the gross amounts that we are committed to pay; however, we will record in our financial statements our proportionate share of costs based on our working ~~interests.~~

interests and net of any fees for excess firm transportation marketed to third parties. None of these agreements were determined to be leases.

(6)

~~(5)~~

Contractual commitments for processing, gathering, and compression services agreements represent minimum commitments under long-term ~~agreements. This includes fees~~agreements not accounted for as leases. The obligations determined to be ~~paid to~~leases are included within finance and operating leases in the ~~Joint Venture owned by Antero Midstream and MarkWest, as well as Antero Midstream’s~~table above.

(7)

Includes contractual commitments for ~~the construction of its advanced wastewater treatment complex.~~land acquisition agreements. The values in the table represent the gross amounts that we are committed to pay; however, we will record in our financial statements our proportionate share of costs based on our working interests. The table does not include intracompany commitments.

~~(6)~~

Represents the present value of our estimated asset retirement obligations. Neither the ultimate settlement amounts nor the timing of our asset retirement obligations can be precisely determined in advance; however, we believe it is likely that a very small amountminimum payments due under these arrangements. None of these ~~obligations may~~agreements were determined to be ~~settled within the next five years.~~

leases.

Non-GAAP Financial Measures

“Adjusted ~~EBITDAX”~~EBITDAX is a non-GAAP financial measure that we define as net income ~~or loss,~~(loss), including noncontrolling interests, before interest expense, interest income, ~~derivative fair value~~ gains or losses ~~(excluding~~from commodity derivatives and marketing derivatives, but including net cash receipts or payments on derivative instruments included in derivative ~~fair value~~ gains or ~~losses),~~losses other than proceeds from derivative monetizations, income taxes, ~~impairment,~~impairments, depletion, depreciation, amortization, and accretion, exploration expense, ~~franchise taxes,~~ equity-based compensation, gain or loss on early extinguishment of debt, contract termination and rig stacking costs, loss on sale of equity investment shares, equity in earnings or loss of unconsolidated affiliates, water earnout, simplification transaction fees, gain or loss on sale of ~~assets.~~assets and Antero Midstream Partners related adjustments.

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Through March 12, 2019, the financial results of Antero Midstream Partners were included in our consolidated results. Effective March 13, 2019, we no longer consolidate Antero Midstream Partners and account for our interest in Antero Midstream using the equity method of accounting. See Note 5 to the unaudited condensed consolidated financial statements for more information on our equity investments. Adjusted EBITDAX ~~also~~ includes distributions ~~from unconsolidated affiliates and excludes equity~~received with respect to limited partner interests in ~~earnings or losses of unconsolidated affiliates.~~Antero Midstream Partners common units through March 12, 2019.

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“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 ~~a company’s~~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 ~~a company’s~~ 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; ~~and~~

●

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. Adjusted EBITDAX~~ forecasting; and

●

is ~~also~~ used by our Board of Directors as a performance measure in determining executive compensation. ~~Adjusted EBITDAX, as defined under the Credit Facility, is used by our lenders pursuant to covenants under the Credit Facility and the indentures governing our senior notes.~~

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.

“Segment Adjusted EBITDAX” is also used by our management team for various purposes, including as a measure of operating performance of our segments and as a basis for strategic planning and forecasting. Segment Adjusted EBITDAX is a non-GAAP financial measure that we define as operating income or loss before derivative fair value gains or losses (excluding net cash receipts or payments on derivative instruments included in derivative fair value gains or losses), impairment, depletion, depreciation, amortization, and accretion, exploration expense, franchise taxes, equity-based compensation, gain or loss on early extinguishment of debt, gain or loss on sale of assets, and gain or loss on changes in the fair value of contingent acquisition consideration. Segment Adjusted EBITDAX also includes distributions received from unconsolidated affiliates. Operating income or loss represents net income or loss, including noncontrolling interests, before interest expense and interest income, income taxes, and equity in earnings of unconsolidated affiliates. Operating income is the most directly comparable GAAP financial measure to Segment Adjusted EBITDAX because we do not account for income tax expense or interest expense on a segment basis.

~~The following tables represent a reconciliation of our operating income (loss) to Segment Adjusted EBITDAX for the three and nine months ended September 30, 2016 and 2017 (in thousands):~~

Exploration
and
production

Gathering and
processing

Water handling and treatment

Marketing

Elimination of
intersegment
transactions

Consolidated
total

Three months ended September 30, 2016:

Operating income (loss)

$
454,347

44,550

29,492

(17,535)

(43,522)

467,332

Commodity derivative fair value gains

(530,334)

—

—

—

—

(530,334)

Gains on settled derivatives

196,712

—

—

—

—

196,712

Depletion, depreciation, amortization, and accretion

173,363

18,540

7,838

—

—

199,741

Impairment of unproved properties

11,753

—

—

—

—

11,753

Exploration expense

1,166

—

—

—

—

1,166

Loss (gain) on change in fair value of contingent acquisition consideration

(3,527)

—

3,527

—

—

—

Equity-based compensation expense

19,781

5,214

1,386

—

—

26,381

Segment and consolidated Adjusted EBITDAX

$
323,261

68,304

42,243

(17,535)

(43,522)

372,751

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Exploration
and
production

Gathering and
processing

Water handling and treatment

Marketing

Elimination of
intersegment
transactions

Consolidated
total

Three months ended September 30, 2017:

Operating income (loss)

$
(86,020)

58,595

24,352

(28,117)

(40,862)

(72,052)

Commodity derivative fair value losses

65,957

—

—

—

—

65,957

Gains on settled derivatives (1)

61,479

—

—

—

—

61,479

Depletion, depreciation, amortization, and accretion

176,846

22,027

8,753

—

—

207,626

Impairment of unproved properties

41,000

—

—

—

—

41,000

Exploration expense

1,599

—

—

—

—

1,599

Loss (gain) on change in fair value of contingent acquisition consideration

(2,556)

—

2,556

—

—

—

Equity-based compensation expense

19,248

5,111

2,088

—

—

26,447

Distributions from unconsolidated affiliates

—

4,300

—

—

—

4,300

Segment and consolidated Adjusted EBITDAX

$
277,553

90,033

37,749

(28,117)

(40,862)

336,356

Exploration
and
production

Gathering and
processing

Water handling and treatment

Marketing

Elimination of
intersegment
transactions

Consolidated
total

Nine months ended September 30, 2016:

Operating income (loss)

$
(326,450)

117,314

56,241

(91,327)

(99,570)

(343,792)

Commodity derivative fair value gains

(125,624)

—

—

—

—

(125,624)

Gains on settled derivatives

813,559

—

—

—

—

813,559

Depletion, depreciation, amortization, and accretion

515,148

52,780

21,975

—

—

589,903

Impairment of unproved properties

47,223

—

—

—

—

47,223

Exploration expense

3,289

—

—

—

—

3,289

Loss (gain) on change in fair value of contingent acquisition consideration

(10,384)

—

10,384

—

—

—

Equity-based compensation expense

56,301

14,902

4,464

—

—

75,667

State franchise taxes

39

—

—

—

—

39

Segment and consolidated Adjusted EBITDAX

$
973,101

184,996

93,064

(91,327)

(99,570)

1,060,264

Exploration
and
production

Gathering and
processing

Water handling and treatment

Marketing

Elimination of
intersegment
transactions

Consolidated
total

Nine months ended September 30, 2017:

Operating income (loss)

$
513,825

167,719

89,044

(79,639)

(137,915)

553,034

Commodity derivative fair value gains

(458,459)

—

—

—

—

(458,459)

Gains on settled derivatives (1)

137,392

—

—

—

—

137,392

Depletion, depreciation, amortization, and accretion

523,547

64,445

24,831

—

—

612,823

Impairment of unproved properties

83,098

—

—

—

—

83,098

Exploration expense

5,510

—

—

—

—

5,510

Loss (gain) on change in fair value of contingent acquisition consideration

(9,672)

—

9,672

—

—

—

Equity-based compensation expense

58,489

14,937

5,499

—

—

78,925

Distributions from unconsolidated affiliates

—

10,120

—

—

—

10,120

Segment and consolidated Adjusted EBITDAX

$
853,730

257,221

129,046

(79,639)

(137,915)

1,022,443

(1) Gains on settled derivatives for the three and nine months ended September 30, 2017 do not include proceeds of $750 million related to derivatives which were partially monetized prior to their settlement dates. See “—Deleveraging Activities” for further discussion.

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The following table represents a reconciliation of our net income (loss), including noncontrolling interest, to ~~consolidated~~ Adjusted EBITDAX and a reconciliation of ~~consolidated~~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, 2016~~March 31, 2019 and ~~2017:~~2020. Adjusted EBITDAX also excludes the results of Antero Midstream Partners in order to provide comparability with the current structure of Antero Resources as effective March 13, 2019, we no longer consolidate Antero Midstream Partners results. These adjustments are disclosed in the table below as Antero Midstream Partners related adjustments.

Three months ended September 30,

Nine months ended September 30,

(in thousands)

2016

2017

2016

2017

Net income (loss) including noncontrolling interest

$
268,196

(90,000)

(296,644)

255,523

Commodity derivative fair value (gains) losses(1)

(530,334)

65,957

(125,624)

(458,459)

Gains on settled derivatives(1)(2)

196,712

61,479

813,559

137,392

Interest expense

59,755

70,059

185,634

205,311

Income tax expense (benefit)

140,924

(45,078)

(230,755)

105,087

Depletion, depreciation, amortization, and accretion

199,741

207,626

589,903

612,823

Impairment of unproved properties

11,753

41,000

47,223

83,098

Exploration expense

1,166

1,599

3,289

5,510

Equity-based compensation expense

26,381

26,447

75,667

78,925

Equity in earnings of unconsolidated affiliates

(1,543)

(7,033)

(2,027)

(12,887)

Distributions from unconsolidated affiliates

—

4,300

—

10,120

State franchise taxes

—

—

39

—

Consolidated Adjusted EBITDAX

372,751

336,356

1,060,264

1,022,443

Interest expense

(59,755)

(70,059)

(185,634)

(205,311)

Exploration expense

(1,166)

(1,599)

(3,289)

(5,510)

Changes in current assets and liabilities

17,327

29,899

35,939

130,089

State franchise taxes

—

—

(39)

—

Proceeds from derivative monetizations

—

749,906

—

749,906

Other non-cash items

(2,166)

719

(1,544)

1,191

Net cash provided by operating activities

$
326,991

1,045,222

905,697

1,692,808

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	Three months ended March 31,
(in thousands)	2019		2020
Reconciliation of net income (loss) to Adjusted EBITDAX:
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$	978,763		(338,810)
Net income and comprehensive income attributable to noncontrolling interests		46,993		—
Depletion, depreciation, amortization, and accretion		241,177		200,781
Impairment of oil and gas properties		81,244		89,220
Impairment of midstream assets		6,982		—
Commodity derivative fair value (gains) losses ⁽¹⁾		77,368		(565,833)
Gains on settled commodity derivatives ⁽¹⁾		97,092		210,926
Equity-based compensation expense		8,903		3,329
Provision for income tax expense (benefit)		288,710		(109,985)
Gain on early extinguishment of debt		—		(80,561)
Equity in (earnings) loss of unconsolidated affiliates		(14,081)		128,055
Impairment of equity investment		—		610,632
Gain on deconsolidation of Antero Midstream Partners LP		(1,406,042)		—
Distributions/dividends from unconsolidated affiliates		12,605		42,756
Interest expense, net		71,950		53,102
Exploration expense		126		210
Gain on sale of assets		—		(31)
Contract termination and rig stacking		8,360		—
Simplification transaction fees		15,482		—
		515,632		243,791

Net income and comprehensive income attributable to noncontrolling interests		(46,993)		—
Antero Midstream Partners interest expense, net ⁽²⁾		(16,815)		—
Antero Midstream Partners depreciation, accretion of ARO and accretion of contingent consideration ⁽²⁾		(21,770)		—
Antero Midstream Partners impairment		(6,982)		—
Antero Midstream Partners equity-based compensation expense ⁽²⁾		(2,477)		—
Antero Midstream Partners equity in earnings of unconsolidated affiliates ⁽²⁾		12,264		—
Antero Midstream Partners distributions from unconsolidated affiliates ⁽²⁾		(12,605)		—
Equity in earnings of Antero Midstream Partners ⁽²⁾		(15,021)		—
Distributions from Antero Midstream Partners ⁽²⁾		46,469		—
Antero Midstream Partners Simplification transaction fees		(9,185)		—
Antero Midstream Partners related adjustments		(73,115)		—
Adjusted EBITDAX	$	442,517		243,791

Reconciliation of our Adjusted EBITDAX to net cash provided by operating activities:
Adjusted EBITDAX	$	442,517		243,791
Antero Midstream Partners related adjustments		73,115		—
Interest expense, net		(71,950)		(53,102)
Exploration expense		(126)		(210)
Gain on asset sale		—		31
Changes in current assets and liabilities		109,065		7,727
Simplification transaction fees		(15,482)		—
Other non-cash items		1,865		2,440
Net cash provided by operating activities	$	539,004		200,677

(1)

~~(1)~~

The adjustments for the derivative fair value gains and losses and gains on settled derivatives have the effect of adjusting net income (loss) from operations for changes in the fair value of unsettled derivatives, which are recognized at the end of each accounting period. As a result, derivative gains included in the calculation Adjusted EBITDAX only ~~reflects~~reflect derivatives ~~which~~that settled ~~or were monetized,~~ during the period.

(2)	Amounts reflected are net of any elimination adjustments for intercompany activity and include activity related to Antero Midstream Partners through March 12, 2019 (date of the Closing). Effective March 13, 2019, Antero accounts for its

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~~(2)~~

~~Gains on settled derivatives for~~unconsolidated investment in Antero Midstream Corporation using the ~~three and nine months ended September 30, 2017 do not include proceeds~~equity method of ~~$750 million related~~accounting. See Note 5 to ~~derivatives which were partially monetized prior to their settlement dates. See “—Deleveraging Activities”~~the unaudited condensed consolidated financial statements for further ~~discussion.~~

discussion on equity method investments.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our 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 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, estimates and judgments in our ~~2016~~2019 Form 10-K. We believe these accounting policies reflect our more significant estimates and assumptions used in the preparation of our consolidated financial statements. Also, see Note 2 ofto the ~~notes to our audited~~ consolidated financial statements, included in our ~~2016~~2019 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 ~~on a geological reservoir basis whenever~~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 ~~exceeded~~exceeds the estimated undiscounted future net cash flows (measured using ~~futures~~future prices), we ~~would~~ 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. ~~Due to the low commodity price environment at~~

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~~September 30, 2017, we compared~~The estimated ~~undiscounted~~ future net cash flows ~~using futures pricing for our Utica~~have been impacted by the COVID-19 pandemic and ~~Marcellus Shale properties~~the decision in March 2020 by Saudi Arabia to reduce the ~~carrying values of those properties. Estimated~~price at which it sells oil and announcing plans to increase production. These events have caused, and continue to cause, significant volatility in future prices which are used in this evaluation. Based on future prices at March 31, 2020, the estimated undiscounted future net cash flows exceeded the carrying ~~values at September 30, 2017~~amount and ~~thus,~~ no further evaluation ~~of the proved properties for impairment is required under GAAP. As a result, we~~was required. We have not recorded any impairment expenses associated with our ~~Utica and Marcellus Basin~~ proved properties during the three months ended March 31, 2019 and ~~nine~~2020. We recorded an impairment charge of $881 million related to the Utica Shale properties during the three months ended September 30, ~~2017. Additionally, we did not record any impairment expenses for proved properties during the years ended December 31, 2014, 2015,~~2019.

Estimated undiscounted future net cash flows are very sensitive to commodity price swings at current commodity price levels and ~~2016. Based on present futures commodity pricing, we currently do not anticipate having to record any impairment charges for our proved properties~~a relatively small decline in prices could result in the ~~near future.~~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 further from March 31, 2020, 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 ~~greater precision than the futures market.~~reasonable certainty.

~~New Accounting Pronouncements~~

~~On May 28, 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09,~~ ~~Revenue from Contracts with Customers~~, which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The ASU will replace most existing revenue recognition guidance in GAAP when it becomes effective. The new standard becomes effective for the Company on January 1, 2018. The standard permits the use of either the retrospective or cumulative effect transition method. The Company has not yet selected a transition method, but expects that it will elect the cumulative effect method. To the extent applicable, upon adoption, we will be required to comply with expanded disclosure requirements, including the disaggregation of revenues to depict the nature and uncertainty of types of revenues, contract assets and liabilities, current period revenues previously recorded as a liability, performance obligations, significant judgments and estimates affecting the amount and timing of revenue recognition, determination of transaction prices, and allocation of transaction prices to performance obligations.

During the third quarter of 2017, the Company substantially completed its analysis of the impact of the standard on its contract types, and we do not believe that the adoption of ASU 2014-09 will have a material impact on its financial results. Currently, the Company is evaluating its disclosures to determine additional qualitative disclosures to provide under the standard. We continue to monitor relevant industry guidance regarding the implementation of ASU 2014-09 and will adjust our implementation strategies as necessary. We do not believe that adoption of the standard will impact our operational strategies, growth prospects, or cash flows.

~~On February 25, 2016, the FASB issued ASU No. 2016-02,~~ ~~Leases~~, which requires lessees to present nearly all leasing arrangements on the balance sheet as liabilities along with a corresponding right-of-use asset. The ASU will replace most existing lease guidance in GAAP when it becomes effective. The new standard becomes effective for the Company on January 1, 2019. Although early application is permitted, the Company does not plan to early adopt the ASU. The standard requires the use of the modified retrospective transition method. The Company is evaluating the effect that ASU 2016-02 will have on its consolidated financial statements and related disclosures. Currently, the Company is evaluating the standard’s applicability to our various contractual arrangements. We believe that adoption of the standard will result in increases to our assets and liabilities on our consolidated balance sheet as well as changes to the presentation of certain operating expenses on our consolidated statement of operations, including the accelerated recognition of expenses attributable to certain of our leasing arrangements. However, we have not yet determined the extent of the adjustments that will be required upon implementation of the standard. We continue to monitor relevant industry guidance regarding the implementation of ASU 2016-02 and will adjust our implementation strategies as necessary. We do not believe that adoption of the standard will impact our operational strategies, growth prospects, or cash flows.

Off-Balance Sheet Arrangements

As of ~~September 30, 2017,~~March 31, 2020, we did not have any ~~off-balance~~off balance sheet arrangements other than ~~operating leases and~~ contractual commitments for ~~drilling rig and completion services,~~ firm transportation, gas processing and fractionation, gathering, and compression ~~services.~~services and land payment obligations. See “—Debt Agreements and Contractual Obligations—Contractual Obligations” for our commitments under these agreements.

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Item 3.Quantitative and Qualitative Disclosures About Market Risk.

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

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Commodity Hedging Activities

Our primary market risk exposure is in the price we receive for our natural gas, NGLs, and oil production. Pricing is primarily driven by spot regional market prices applicable to our U.S. natural gas production and the prevailing worldwide price for ~~crude~~ 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 ~~product~~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 ~~financial~~ instruments ~~to receive fixed prices~~ 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, ~~cashless price~~ collars that set a floor and ceiling price for the hedged production, or basis differential swaps. These contracts are financial instruments, and do not require or allow for physical delivery of the hedged commodity. At ~~September 30, 2017, the majority of~~March 31, 2020, our ~~natural gas hedges were~~commodity derivatives included fixed price swaps and basis differential swaps at ~~NYMEX~~index-based pricing. ~~The Company was not party to any collars as of or during the nine months ended September 30, 2017.~~

At ~~September 30, 2017,~~March 31, 2020, we had in place natural gas ~~NGLs, and oil~~ swaps covering portions of our projected production ~~from 2017~~ through ~~2023.~~2024. Our commodity hedge position as of ~~September 30, 2017~~March 31, 2020 is summarized in Note ~~9(a)~~11 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 ~~which~~that settled during the ~~nine~~three months ended ~~September 30, 2017,~~March 31, 2020, our revenues would have decreased by approximately ~~$7.5~~$12 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 at ~~September 30, 2017.~~March 31, 2020.

All derivative instruments, other than those that meet the normal purchase and normal sale scope exception, 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. At ~~September 30, 2017,~~March 31, 2020, the estimated fair value of our commodity derivative instruments was a net asset of ~~$1.2~~$1.1 billion ~~comprising~~comprised of current assets and noncurrent assets and liabilities. At December 31, ~~2016,~~2019, the estimated fair value of our commodity derivative instruments was a net asset of ~~$1.6 billion comprising~~$746 million comprised of current and noncurrent assets and liabilities.

By removing price volatility from a portion of our expected production through December ~~2023,~~2024, 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.

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Counterparty and Customer Credit Risk

Our principal exposures to credit risk are through receivables resulting from the following: commodity derivative contracts ($~~1.2~~1.1 billion at ~~September 30, 2017)~~March 31, 2020); and the sale ~~and marketing~~ of our ~~oil~~natural gas, NGLs and ~~gas~~oil production ($~~234~~192 million at ~~September 30, 2017)~~March 31, 2020), which we market to energy companies, end users, and ~~refineries; and joint interest receivables ($10 million at September 30, 2017).~~refineries.

By using derivative instruments that are not traded on an exchange to hedge ~~our~~ exposures to changes in commodity prices, we expose ourselves to the credit risk of our counterparties. Credit risk is the potential failure of ~~the~~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

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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 ~~which~~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 ~~fourteen~~14 different counterparties, ~~twelve~~12 of which are lenders under our Credit Facility. The fair value of our commodity derivative contracts of approximately ~~$1.2~~$1.1 billion at ~~September 30, 2017~~March 31, 2020 included the following derivative assets by bank counterparty: ~~JP Morgan~~Wells Fargo - ~~$286 million; Morgan Stanley - $248~~$238 million; Citigroup - ~~$184 million; Scotiabank - $157 million; Wells Fargo - $148~~$232 million; Canadian Imperial Bank of Commerce - ~~$48~~$200 million; ~~Toronto Dominion~~JP Morgan - ~~$36~~$143 million; Morgan Stanley - $125 million; Scotiabank - $59 million; PNC - $34 million; BNP Paribas - ~~$24~~$19 million; Bank of Montreal - ~~$16~~$18 million; ~~Fifth Third~~TD Energy - ~~$13~~$14 million; Natixis - $9 million; SunTrust - ~~$8 million; Capital One~~$6 million and Merrill Lynch - $4 ~~million; and Natixis - $1~~ million. ~~The credit ratings of certain of these banks were downgraded several years ago because of their exposure to the sovereign debt crisis in Europe or various other economic factors.~~ 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) at ~~September 30, 2017~~March 31, 2020 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 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, 2017,~~March 31, 2020, 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. ~~Marketing receivables primarily result from sales of third-party gas and NGLs.~~ 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.

Joint interest receivables arise from our billing of entities who own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leased properties on which we drill. We have minimal control over deciding who participates in our wells.

Interest Rate Risks

Our primary exposure to interest rate risk results from outstanding borrowings under ~~our~~the Credit Facility, ~~and the Midstream Facility of our consolidated subsidiary, Antero Midstream. Each of these credit facilities~~which has a floating interest rate. The average annualized interest rate incurred on the ~~Prior~~ Credit ~~Facility and the Prior Midstream~~ Facility during the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2020 was approximately ~~3.17%~~3.28%. We estimate that a 1.0% increase in ~~each of~~ the applicable average interest rates for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2020 would have resulted in ~~a $7.0~~an estimated $1.6 million increase in interest expense.

Item ~~4.Controls~~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, 2017~~March 31, 2020 at a level of reasonable assurance.

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Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the three months ended ~~September 30, 2017~~March 31, 2020 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II—OTHER INFORMATION

Item ~~1.Legal~~1.Legal Proceedings.

~~Environmental~~

In March 2011, we received orders for compliance from federal regulatory agencies, including the U.S. Environmental Protection Agency, relating to certain of our activities in West Virginia. The orders allege that certain of our operations at several well sites are in non-compliance with certain environmental regulations, such as unpermitted discharges of fill material into wetlands or waters of the United States that are potentially in violation of the Clean Water Act. We have responded to all pending orders and are actively cooperating with the relevant agencies. We believe that these actions will result in monetary sanctions exceeding $100,000. We have had ongoing settlement discussions with the relevant agencies to resolve the orders for compliance, but we are unable to estimate the total amount of monetary sanctions to resolve such orders or costs to remediate these locations in order to bring them into compliance with applicable environmental laws and regulations. Our operations at these locations are not suspended, and management does not expect these matters to have a material adverse effect on our financial condition, results of operations, or cash flows.

~~SJGC~~

The Company is the plaintiff in a lawsuit against South Jersey Gas Company and South Jersey Resources Group, LLC (collectively, “SJGC”) pending in United States District Court in Colorado. In March 2015, the Company filed suit against SJGC seeking relief for breach of contract and damages in the amounts that SJGC had short paid, and continued to short pay, the Company in connection with two nearly identical long term gas contracts. Under those contracts, SJGC are long term purchasers of 80,000 MMBtu/day of the Company’s natural gas production. Deliveries under the contracts began in October 2011 and the term of the contracts continues through October 2019. The price for gas was based on specified indices in the contracts. Beginning in October 2014, SJGC began short paying the Company based on price indices unilaterally selected by SJGC and not the applicable index specified in the contracts. SJGC claimed that the index price specified in the contracts, and the index at which SJGC paid for deliveries from 2011 through September 2014, was no longer appropriate under the contracts because a market disruption event (as defined by the contract) had occurred and, as a result, a new index price was required to be determined by the parties. The Company rejected SJGC’s contention that a market disruption event occurred. SJGC’s actions constituted a breach of the contracts by failing to pay the Company based on the express price terms of the contracts and paying the Company based on unilaterally selected price indices in violation of the contracts’ remedial provisions. On May 8, 2017, a jury in the United States District Court in Colorado returned a unanimous verdict finding in favor of Antero’s positions in the lawsuit against SJGC. On July 21, 2017, final judgment on the jury’s unanimous verdict was entered by the court. On August 18, 2017, SJGC filed post-judgment motions with the court, which are currently pending. If the court denies those motions, SJGC will have 30 days from the court’s decision on these post-judgment motions to file an appeal. SJGC continues to short pay the Company based on indexes unilaterally selected by SJGC and not the index specified in the contract. Through September 30, 2017, the Company estimates that it is owed approximately $70 million (gross damages, including interest) more than SJGC has paid using the indices unilaterally selected by them. Substantially all of this amount has not been accrued in the Company’s financial statements. The Company will vigorously seek recovery from SJGC of all underpayments and damages, including interest, based on the contracted price.

~~WGL~~

The Company and Washington Gas Light Company and WGL Midstream, Inc. (collectively, “WGL”) were involved in a pricing dispute involving firm gas sales contracts executed June 20, 2014 (the “Contracts”) that the Company began delivering gas under in January 2016. From January 2016 through July 2017, the aggregate daily gas volumes contracted for under the Contracts was 500,000 MMBtu/day, with the aggregate daily contracted volumes having increased to 600,000 MMBtu/day during the months of August and September 2017. The Company invoiced WGL based on the natural gas index price specified in the Contracts and WGL paid the Company based on that invoice price. However, WGL asserted that the index price was no longer appropriate under the Contracts and claimed that an undefined alternative index was more appropriate for the delivery point of the gas. In July 2016, the matter was referred to arbitration by the Colorado district court. In January 2017, after hearing a week of testimony and evidence, the arbitration panel ruled in the Company’s favor. As a result, the index price has remained as specified in the Contracts and there will be no adjustments to the invoices that have been paid by WGL, nor will future invoices to WGL be adjusted based on the same claim rejected by the arbitration panel. The arbitration panel’s award was confirmed by the Colorado district court on April 14, 2017.

In March of 2017, WGL filed a second lawsuit against the Company in Colorado district court alleging breach of contract and seeking damages of more than $30 million. In this lawsuit, WGL claimed that the Company breached its contractual obligations under the Contracts by failing to deliver “TCO pool” gas. In subsequent filings, WGL explained that its claims were based on an alleged

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obligation that the Company must deliver gas to the Columbia IPP Pool (“IPP Pool”). WGL asserted this exact same claim in the arbitration and it was rejected by the arbitration panel. The arbitration panel specifically found that the Delivery Point under the Contracts was at a specific point in Braxton, West Virginia, not the IPP Pool. On August 24, 2017, the Colorado district court dismissed with prejudice WGL’s claims against the Company in its second lawsuit and found that the Company had not breached its Contracts with WGL by allegedly failing to deliver to the IPP Pool. The Court also reaffirmed the arbitration panel’s finding that the delivery point under the Contracts was not the IPP Pool. WGL has appealed this decision to the Colorado Court of Appeals decision and that appeal remains pending.

The Company is also actively engaged in pursuing cover damages against WGL based on WGL’s failure to take receipt of all of the agreed quantities of gas required under the Contracts. WGL’s failure to take the gas volumes specified in the Contracts is directly related to WGL’s lack of primary firm transportation rights at the Delivery Point. The failures by WGL to take the gas began in April 2017 and have continued each month since in varying quantities. In defense of its conduct, WGL has asserted to the Company that their failure to receive gas is excused by (1) the Company’s failure to deliver gas to the IPP Pool or (2) alleged instances of Force Majeure under the Contracts. However, as stated above, the alleged obligation that the Company must deliver gas to the IPP Pool was rejected by the arbitration panel and the Colorado district court. Further, the Contracts expressly prohibit a Force Majeure claim in circumstances in which the gas purchaser does not have primary firm transportation agreements in place to transport the purchased gas. In each instance that WGL has failed to receive the quantity of gas required under the Contracts, the Company has resold the quantities not taken and invoiced WGL for cover damages pursuant to the terms of the Contracts. WGL has refused to pay for the invoiced cover damages asinformation required by ~~the Contracts and has also short paid the Company for certain amounts of gas received by WGL. Through September 30, 2017, these damages amounted~~this item is included in Note 14 to approximately $65 million (gross damages, including interest). This amount has not been accrued in the Company’s financial statements. The Company is currently pursuing its cover damages in a lawsuit filed in Colorado district court on October 24, 2017. WGL’s failure to take receipt of all quantities of gas and resulting cover damages remains ongoing. The Company will continue to vigorously seek recovery of its cover damages and other unpaid amounts, including interest, as part of its claims against WGL.

~~Other~~

~~We are party to various other legal proceedings and claims in the ordinary course of~~ our ~~business. We believe 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 our~~unaudited condensed consolidated financial ~~position, results of operations, or cash flows.~~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 ~~our 2016~~the 2019 Form 10-K ~~and~~ in ~~our Quarterly Reports on Form 10-Q for~~addition to the ~~quarters ended March 31, 2017 and June 30, 2017. The~~ risks described in our 2016 Form 10-K and in our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2017 and June 30, 2017 could materially and adversely affect our business, financial condition, cash flows, and results of operations. Therebelow. Other than as described below, there have been no material changes to the risks described in ~~our 2016 Form 10-K and Quarterly Reports on Form 10-Q for~~ the ~~quarters ended March 31, 2017 and June 30, 2017.~~2019 10-K. We may experience additional risks and uncertainties not currently known to ~~us; or,~~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. Any such risk, in addition to those described below and in the 2019 Form 10-K, may materially and adversely affect our business, financial condition, cash flows and results of operations.

The imbalance between the supply of and demand for oil, natural gas and NGLs has caused extreme market volatility and may result in increased costs and decreased availability of storage capacity. The lack of a market or available storage for certain of our products could cause interruptions in our operations, including temporary curtailments or shut-ins, which could adversely affect our financial condition and results of operations.

The marketing of our natural gas, NGLs, and oil production is substantially dependent upon the existence of adequate markets for our products. In response to the COVID-19 pandemic, governments have tried to slow the spread of the virus by imposing social distancing guidelines, travel restrictions and stay-at-home orders, which have caused a significant decrease in the demand for natural gas, NGLs and oil. The imbalance between the supply of and demand for these products, as well as the uncertainty around the extent and timing of an economic recovery, have caused extreme market volatility and a substantial adverse effect on commodity prices in March and April. Also as a result of this imbalance, the industry is experiencing storage capacity constraints with respect to certain NGL products and oil. If we are unable to sell our production or enter into additional storage arrangements on commercially reasonable terms or at all, we could be forced to temporarily shut in a portion of our production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons. Although our production is more heavily weighted to natural gas, the lack of a market or available storage for any one NGL product or oil could result in temporary shut-ins as we may be unable to curtail the production of individual products in a meaningful way without reducing the production of other products. Based on our expectation of available storage and overall demand, we believe we may begin temporarily constraining our production, which may include partial shut-ins. We are unable to determine the extent or duration of any such shut-in. Any such shut in or curtailment, or any inability to obtain favorable terms for delivery of the natural gas, NGLs and oil we produce, could adversely affect our financial condition and results of operations.

A pandemic, epidemic or outbreak of an infectious disease, such as COVID-19, may materially adversely affect our business.

The global or national outbreak of an infectious disease, such as COVID-19, may cause disruptions to our business and operational plans, which may include (i) shortages of employees, (ii) unavailability of contractors and subcontractors, (iii) interruption of supplies from third parties upon which we rely, (iv) recommendations of, or restrictions imposed by, government and health authorities, including quarantines, to address the COVID-19 outbreak and (v) restrictions that we and our contractors and subcontractors impose, including facility shutdowns, to ensure the safety of employees and others. While it is not possible to predict their extent or duration, these disruptions may have a material adverse effect on our business, financial condition and results of operations.

Further, the effects of COVID-19 and concerns regarding its global spread have negatively impacted domestic and international demand for crude oil and natural gas, which has and could continue to contribute to price volatility, impact the price we receive for natural gas, NGLs, and oil and materially and adversely affect the demand for and marketability of our production, as well as lead to temporary curtailment of production due to lack of downstream demand or storage capacity. Additionally, to the extent the COVID-19 pandemic adversely affects our business and financial results, it may also have the effect of heightening many of the other risks set forth in “Item 1A. Risk Factors” in our 2019 Form 10-K.

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Our future tax liability may be greater than expected if our net operating loss (“NOL”) carryforwards are limited, we do not generate expected deductions, or tax authorities challenge certain of our tax positions.

As of December 31, 2019, we have U.S. federal and state NOL carryforwards of $2.2 billion and $2.0 billion, respectively, some of which expire at various dates from 2032 to 2038 while others have no expiration date. We currently expect to be able to utilize these NOL carryforwards and generate deductions to offset our future taxable income. This expectation is based upon assumptions we have made regarding, among other things, our income, capital expenditures and net working capital, and upon our NOL carryforwards not becoming subject to future limitation under Section 382 of the Internal Revenue Code of 1986, as amended (“Section 382”), or otherwise.

Section 382 generally imposes an annual limitation on the amount of NOL carryforwards that may be used to offset taxable income when a corporation has undergone an “ownership change” (as determined under Section 382). An ownership change generally occurs if one or more stockholders (or groups of stockholders) who are each deemed to own at least 5% of such corporation’s stock change their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three-year period. In the event that we were to undergo an ownership change, utilization of our NOL carryforwards would be subject to an annual limitation under Section 382, determined by multiplying the value of our stock at the time of the ownership change by the applicable long-term tax-exempt rate in effect during the month in which the ownership change occurs, subject to certain adjustments, which could result in a portion of our NOL carryforwards expiring prior to their utilization. Any unused annual limitation may be carried over to later years. Any limitation on our ability to utilize our NOL carryforwards against income or gain we generate in the future could result in future income tax expense that could adversely affect our operating results and cash flows.

Furthermore, any significant variance in our interpretation of current income tax laws, including as result of the release of final Treasury Regulations or other interpretive guidance implementing the Tax Cuts and Jobs Act, or a challenge of one or more of our tax positions by the IRS or other tax authorities could affect our tax position. While we expect to be able to utilize our NOL carryforwards and generate deductions to offset our future taxable income, in the event that deductions are not generated as expected, one or more of our tax positions are successfully challenged by the IRS (in a tax audit or otherwise), or our NOL carryforwards are subject to future limitation (including due to an ownership change under Section 382), our future tax liability may be greater than expected.

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Item 2. Unregistered Sales of Equity Securities ~~and Use of Proceeds.~~

Issuer Purchases of Equity Securities

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

Period

Total Number of Shares Purchased

Average Price Paid Per Share

Total Number of Shares Purchased as Part of Publicly Announced Plans

Maximum Number of Shares that May Yet be Purchased Under the Plan

July 1, 2017 - July 31, 2017

3,017

$
21.98

—

N/A

August 1, 2017 - August 31, 2017

—

$
—

—

N/A

September 1, 2017 - September 30, 2017

—

$
—

—

N/A


Period	Total Number of Shares Purchased ⁽¹⁾		Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans ⁽²⁾		Approximate Dollar Value of Shares that May Yet be Purchased Under the Plan ⁽²⁾
January 1, 2020 - January 31, 2020		3,960,990	$	1.87		3,948,719	$	420,144,052
February 1, 2020 - February 28, 2020		14,244,658	$	1.78		14,244,658	$	394,807,709
March 1, 2020 - March 31, 2020		8,999,860	$	1.11		8,999,860	$	—
Total		27,205,508	$	1.57		27,193,237

(1)

The total number of shares purchased includes 12,271 shares repurchased in January representing shares of our common stock transferred to us in order to satisfy tax withholding obligations incurred upon the vesting of restricted stock and restricted stock units held by our employees. There were no share repurchases in February or March relating to shares transferred to satisfy tax withholding obligations.

(2)

In October 2018, the Company’s Board of Directors authorized a $600 million share repurchase program, which expired on March 31, 2020. During the three months ended March 31, 2020, we repurchased 27,193,237 shares under this program for approximately $43 million, or a weighted average of $1.57 per share.

Item 5. Other Information

~~Table~~

On April 29, 2020, Antero Resources Corporation, certain of ~~Contents~~

~~Shares purchased represent shares of our common stock transferred to us in order to satisfy tax withholding obligations incurred upon~~its subsidiaries, as guarantors, the ~~vesting of Antero equity awards held by our employees.~~

~~Item 3. Defaults Upon Senior Securities.~~

~~None.~~

~~Item 4. Mine Safety Disclosures~~

~~Not applicable.~~

~~Item 5.Other Information.~~

~~Amended~~lenders party thereto and ~~Restated Credit Facility~~

~~On October 26, 2017, we~~JPMorgan Chase Bank, N.A., as Administrative Agent entered into ~~an amendment and restatement of the Prior Credit Facility. See “—Debt Agreements—Revolving Credit Facility” for~~ a ~~description of the~~Third Amendment (the “Third Amendment”) to our Credit Facility. The ~~description of the~~Third Amendment amends our Credit Facility ~~is a summary~~to, among other things, (i) evidence the decrease in the borrowing base to $2.85 billion and ~~is qualified in its entirety by the terms of the Credit Facility. A copy of the~~(ii) amend other provisions to our Credit Facility ~~is filed~~ as ~~Exhibit 10.1 hereto, and is incorporated herein by reference.~~

~~Disclosure pursuant to Section 13(r) of the Securities Exchange Act of 1934~~

~~Pursuant to Section 13(r) of the Securities Exchange Act of 1934, we, Antero Resources Corporation, may be required to disclose~~described in ~~our annual and quarterly reports~~Note 7 to the ~~Securities and Exchange Commission (the “SEC”), whether we or any of our “affiliates” knowingly engaged~~unaudited condensed consolidated financial statements included in certain activities, transactions or dealings relating to Iran or with certain individuals or entities targeted by United State (“US”) economic sanctions. Disclosure is generally required even where the activities, transactions or dealings were conducted in compliance with applicable law. Because the SEC defines the term “affiliate” broadly, it includes any entity under common “control” with us (and the term “control” is also construed broadly by the SEC).this Quarterly Report on Form 10-Q.

The description of the activities below has been provided to us by Warburg Pincus LLC (“Warburg”), affiliates of which: (i) beneficially own more than 10% of our outstanding common stock and/or are members of our board of directors, and (ii) beneficially own more than 10% of the equity interests of, and have the right to designate members of the board of directors of Santander Asset Management Investment Holdings Limited (“SAMIH”). SAMIH may therefore be deemed to be under common “control” with us; however, this statement is not meant to be an admission that common control exists.

The disclosure below relates solely to activities conducted by SAMIH and its affiliates. The disclosure does not relate to any activities conducted by us or by Warburg and does not involve our or Warburg’s management. Neither we nor Warburg has had any involvement in or control over the disclosed activities, and neither we nor Warburg has independently verified or participated in the preparation of the disclosure. Neither we nor Warburg is representing as to the accuracy or completeness of the disclosure nor do we or Warburg undertake any obligation to correct or update it.

~~We understand that one or more SEC-reporting affiliates of SAMIH intends to disclose in its next annual or quarterly SEC report that:~~

(a)Santander UK plc (“Santander UK”) holds two savings accounts and one current account for two customers resident in the United Kingdom (“UK”) who are currently designated by the US under the Specially Designated Global Terrorist (“SDGT”) sanctions program. Revenues and profits generated by Santander UK on these accounts in the first nine month period ended September 30, 2017 were negligible relative to the overall revenues and profits of Banco Santander SA.

(b)Santander UK holds two frozen current accounts for two UK nationals who are designated by the US under the SDGT sanctions program. The accounts held by each customer have been frozen since their designation and have remained frozen through the nine month period ended September 30, 2017. The accounts are in arrears (£1,844.73 in debit combined) and are currently being managed by Santander UK Collections & Recoveries department. No revenues or profits were generated by Santander UK on this account in the nine month period ended September 30, 2017.

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Item ~~6.Exhibits.~~

6.Exhibits


Exhibit Number		Description of Exhibit
Exhibit Number3.1		~~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*		Form of Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Form for Special Retention Awards) under the Antero Resources Corporation Long-Term Incentive Plan.
10.2*		Form of Retention Award Grant Notice and Retention Award Agreement under the Antero Resources Corporation Long-Term Incentive Plan.
10.3*		Third Amendment to Fifth Amended and Restated Credit Agreement, dated as of ~~October 26, 2017, by and~~April 29, 2020, among Antero Resources Corporation, as Borrower, certain subsidiaries of the ~~lenders~~Borrower, as Guarantors, the Lenders party thereto and ~~Wells Fargo~~JPMorgan Chase Bank, ~~National Association,~~N.A., as Administrative Agent.
31.1*		Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 7241).
31.2*		Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 7241).
32.1*		Certification of the Company’s Chief Executive Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 1350).
32.2*		Certification of the Company’s Chief Financial Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 1350).
101*		The following financial information from this Quarterly Report on Form 10-Q of Antero Resources Corporation for the quarter ended ~~September 30, 2017~~March 31, 2020 formatted in ~~XBRL (eXtensible~~iXBRL (Inline eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations and Comprehensive Income (Loss), (iii) Condensed Consolidated Statements of Equity, (iv) Condensed Consolidated Statements of Cash Flows, and (v) Notes to the Condensed Consolidated Financial Statements, tagged as blocks of text.
104		Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

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

6762

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~~SIGNATURES~~

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
~~ANTERO RESOURCES CORPORATION~~

By:	/s/ GLEN C. WARREN, JR.
	Glen C. Warren, Jr.
	President, Chief Financial Officer and Secretary

Date:	~~November 1, 2017~~April 29, 2020

6863


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	3640
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	56
Item 4.	Controls and Procedures	58
PART II—OTHER INFORMATION		59
Item 1.	Legal Proceedings	59
Item 1A.	Risk Factors	59
Item 2.	Unregistered Sales of Equity Securities	61
Item 4.5.	~~Controls and Procedures~~Other Information	61
Item 6.	Exhibits	62
~~PART II—OTHER INFORMATION~~		64
~~Item 1.~~	~~Legal Proceedings~~SIGNATURES	64
~~Item 1A.~~	~~Risk Factors~~	65
~~Item 2.~~	~~Unregistered Sales of Equity Securities and Use of Proceeds~~	65
~~Item 5.~~	~~Other Information~~	66
~~Item 6.~~	~~Exhibits~~	67
~~SIGNATURES~~		6863


	Three Months Ended September 30,
	2016		2017
Revenue:
Natural gas sales	$	364,373		409,141
Natural gas liquids sales		106,958		224,533
Oil sales		14,793		26,527
Gathering, compression, water handling and treatment		2,969		2,869
Marketing		97,076		50,767
Commodity derivative fair value gains (losses)		530,334		(65,957)
Total revenue		1,116,503		647,880
Operating expenses:
Lease operating		13,854		23,491
Gathering, compression, processing, and transportation		234,915		282,134
Production and ad valorem taxes		15,554		22,995
Marketing		114,611		78,884
Exploration		1,166		1,599
Impairment of unproved properties		11,753		41,000
Depletion, depreciation, and amortization		199,113		206,968
Accretion of asset retirement obligations		628		658
General and administrative (including equity-based compensation expense of $26,381 and $26,447 in 2016 and 2017, respectively)		57,577		62,203
Total operating expenses		649,171		719,932
Operating income (loss)		467,332		(72,052)
Other income (expenses):
Equity in earnings of unconsolidated affiliates		1,543		7,033
Interest		(59,755)		(70,059)
Total other expenses		(58,212)		(63,026)
Income (loss) before income taxes		409,120		(135,078)
Provision for income tax (expense) benefit		(140,924)		45,078
Net income (loss) and comprehensive income (loss) including noncontrolling interests		268,196		(90,000)
Net income and comprehensive income attributable to noncontrolling interests		29,941		45,063
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$	238,255		(135,063)


Earnings (loss) per common share—basic	$	0.78		(0.43)

Earnings (loss) per common share—assuming dilution	$	0.77		(0.43)

Weighted average number of shares outstanding:
Basic		306,785		315,463
Diluted		308,657		315,463


	Common Stock				Additional paid-		Accumulated		Noncontrolling		Total
	Shares		Amount		in capital		earnings		interests		equity
Balances, December 31, 2016		314,877	$	3,149		5,299,481		959,995		1,465,953		7,728,578
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		593		6		(7,574)		—		—		(7,568)
Issuance of common units by Antero Midstream Partners LP, net of underwriter discounts and offering costs		—		—		—		—		248,949		248,949
Issuance of common units in Antero Midstream Partners LP upon vesting of equity-based compensation awards, net of units withheld for income taxes		—		—		(1,559)		—		627		(932)
Sale of common units of Antero Midstream Partners LP held by Antero Resources Corporation, net of tax		—		—		205,780		—		(19,940)		185,840
Equity-based compensation		—		—		71,786		—		7,139		78,925
Net income and comprehensive income		—		—		—		128,201		127,322		255,523
Effects of changes in ownership interests in consolidated subsidiaries		—		—		996,406		—		(996,406)		—
Distributions to noncontrolling interests		—		—		—		—		(102,053)		(102,053)
Balances, September 30, 2017		315,470	$	3,155		6,564,320		1,088,196		731,591		8,387,262


	December 31, 2016		September 30, 2017
Antero:
Prior Credit Facility(a)	$	440,000		25,000
5.375% senior notes due 2021(b)		1,000,000		1,000,000
5.125% senior notes due 2022(c)		1,100,000		1,100,000
5.625% senior notes due 2023(d)		750,000		750,000
5.00% senior notes due 2025(e)		600,000		600,000
Net unamortized premium		1,749		1,588
Net unamortized debt issuance costs		(37,690)		(33,789)
Antero Midstream:
Prior Midstream Facility(g)		210,000		427,000
5.375% senior notes due 2024(h)		650,000		650,000
Net unamortized debt issuance costs		(10,086)		(9,278)
	$	4,703,973		4,510,521


Asset retirement obligations—December 31, 2016	$	32,736
Obligations settled		(21)
Obligations incurred for wells drilled and producing properties acquired		3,399
Accretion expense		1,944
Asset retirement obligations—September 30, 2017	$	38,058


		Weighted average		Aggregate
	Number of shares	grant date fair value		intrinsic value (in thousands)
Total awarded and unvested—December 31, 2016	5,353,447	$	31.77	$	126,609
Granted	828,753	$	22.21
Vested	(834,796)	$	43.46
Forfeited	(353,152)	$	27.10
Total awarded and unvested—September 30, 2017	4,994,252	$	28.56	$	99,386


				Weighted
		Weighted average		average remaining	Intrinsic
	Stock options	exercise price		contractual life	value (in thousands)
Outstanding at December 31, 2016	687,929	$	50.46	8.12	$	—
Granted	—	$	—
Exercised	—	$	—
Forfeited	(16,542)	$	50.00
Expired	—	$	—
Outstanding at September 30, 2017	671,387	$	50.47	7.32	$	—
Vested or expected to vest as of September 30, 2017	671,387	$	50.47	7.32	$	—
Exercisable at September 30, 2017	363,605	$	50.70	7.20	$	—


	Number of units	Weighted average grant date fair value
Total awarded and unvested—December 31, 2016	785,301	$	29.75
Granted	558,021	$	26.21
Vested	(41,666)	$	27.38
Forfeited	(8,623)	$	29.86
Total awarded and unvested—September 30, 2017	1,293,033	$	28.30


	Nine Months Ended September 30, 2017
Dividend yield		—	%
Volatility		42	%
Risk-free interest rate		1.40	%
Weighted average fair value of awards granted	$	26.21


	Number of units	Weighted average grant date fair value		Aggregate intrinsic value (in thousands)
Total awarded and unvested—December 31, 2016	1,331,961	$	27.31	$	41,131
Granted	377,660	$	32.52
Vested	(73,080)	$	21.34
Forfeited	(78,584)	$	28.76
Total awarded and unvested—September 30, 2017	1,557,957	$	28.78	$	49,122


	Natural gas MMbtu/day	Oil Bbls/day	Natural Gas Liquids Bbls/day	Weighted average index price
Three months ending December 31, 2017:
NYMEX ($/MMBtu)	1,370,000	—	—	$	3.46
CGTLA ($/MMBtu)	420,000	—	—	$	4.37
CCG ($/MMBtu)	70,000	—	—	$	4.68
NYMEX-WTI ($/Bbl)	—	3,000	—	$	54.75
Mont Belvieu-Ethane ($/Gallon)	—	—	20,000	$	0.25
Mont Belvieu-Propane ($/Gallon)	—	—	27,500	$	0.40
Total	1,860,000	3,000	47,500
Year ending December 31, 2018:
NYMEX ($/MMBtu)	2,002,500	—	—	$	3.50
NYMEX-WTI ($/Bbl)	—	1,000	—	$	49.96
Mont Belvieu-Propane ($/Gallon)	—	—	3,000	$	0.67
Total	2,002,500	1,000	3,000
Year ending December 31, 2019:
NYMEX ($/MMBtu)	2,330,000			$	3.50
Year ending December 31, 2020:
NYMEX ($/MMBtu)	1,417,500			$	3.25
Year ending December 31, 2021:
NYMEX ($/MMBtu)	710,000			$	3.00
Year ending December 31, 2022:
NYMEX ($/MMBtu)	850,000			$	3.00
Year ending December 31, 2023:
NYMEX ($/MMBtu)	90,000			$	2.91


	December 31, 2016			September 30, 2017
	Balance sheet location	Fair value		Balance sheet location	Fair value
		(In thousands)			(In thousands)
Asset derivatives not designated as hedges for accounting purposes:
Commodity contracts	Current assets	$	73,022	Current assets		299,796
Commodity contracts	Long-term assets		1,731,063	Long-term assets		876,293

Total asset derivatives			1,804,085			1,176,089

Liability derivatives not designated as hedges for accounting purposes:
Commodity contracts	Current liabilities		203,635	Current liabilities		4,285
Commodity contracts	Long-term liabilities		234	Long-term liabilities		427

Total liability derivatives			203,869			4,712

Net derivatives		$	1,600,216			1,171,377


	Statement of operations	Three months ended September 30,				Nine months ended September 30,
	location	2016		2017		2016		2017
Commodity derivative fair value gains (losses)	Revenue	$	530,334		(65,957)	$	125,624		458,459


	Firm transportation		Processing, gathering and compression		Drilling rigs and completion services		Office and equipment
	(a)		(b)		(c)		(d)		Total
Remainder of 2017	$	135		109		28		4		276
2018		886		401		80		13		1,380
2019		1,107		340		41		11		1,499
2020		1,127		337		—		9		1,473
2021		1,106		321		—		8		1,435
2022		1,053		317		—		8		1,378
Thereafter		9,635		1,502		—		17		11,154
Total	$	15,049		3,327		149		70		18,595


	Three Months Ended September 30,				Amount of Increase		Percent
(in thousands)	2016		2017		(Decrease)		Change
Operating revenues and other:
Natural gas sales	$	364,373	$	409,141	$	44,768	12	%
NGLs sales		106,958		224,533		117,575	110	%
Oil sales		14,793		26,527		11,734	79	%
Gathering, compression, water handling and treatment		2,969		2,869		(100)	(3)	%
Marketing		97,076		50,767		(46,309)	(48)	%
Commodity derivative fair value gains (losses)		530,334		(65,957)		(596,291)	*
Total operating revenues and other		1,116,503		647,880		(468,623)	(42)	%
Operating expenses:
Lease operating		13,854		23,491		9,637	70	%
Gathering, compression, processing, and transportation		234,915		282,134		47,219	20	%
Production and ad valorem taxes		15,554		22,995		7,441	48	%
Marketing		114,611		78,884		(35,727)	(31)	%
Exploration		1,166		1,599		433	37	%
Impairment of unproved properties		11,753		41,000		29,247	249	%
Depletion, depreciation, and amortization		199,113		206,968		7,855	4	%
Accretion of asset retirement obligations		628		658		30	5	%
General and administrative (before equity-based compensation)		31,196		35,756		4,560	15	%
Equity-based compensation		26,381		26,447		66	—	%
Total operating expenses		649,171		719,932		70,761	11	%
Operating income (loss)		467,332		(72,052)		(539,384)	*

Other earnings (expenses):
Equity in earnings of unconsolidated affiliate		1,543		7,033		5,490	356	%
Interest expense		(59,755)		(70,059)		(10,304)	17	%
Total other expenses		(58,212)		(63,026)		(4,814)	8	%
Income (loss) before income taxes		409,120		(135,078)		(544,198)	*
Income tax (expense) benefit		(140,924)		45,078		186,002	*
Net income (loss) and comprehensive income (loss) including noncontrolling interest		268,196		(90,000)		(358,196)	*
Net income and comprehensive income attributable to noncontrolling interest		29,941		45,063		15,122	51	%
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$	238,255	$	(135,063)	$	(373,318)	*

Adjusted EBITDAX (1)	$	372,751	$	336,356	$	(36,395)	(10)	%


	Remainder		Year Ended December 31,
(in millions)	of 2017		2018		2019		2020		2021		2022		Thereafter		Total
Antero Credit Facility(1)	$	—		—		—		—		25		—		—		25
Antero Midstream Facility(1)		—		—		—		—		—		427		—		427
Antero senior notes—principal(2)		—		—		—		—		1,000		1,100		1,350		3,450
Antero senior notes—interest(2)		77		182		182		182		155		129		111		1,018
Antero Midstream senior notes—principal(2)		—		—		—		—		—		—		650		650
Antero Midstream senior notes—interest(2)		—		35		35		35		35		35		70		245
Drilling rig and completion service commitments(3)		28		80		41		—		—		—		—		149
Firm transportation (4)		135		886		1,107		1,127		1,106		1,053		9,635		15,049
Processing, gathering, and compression services (5)		109		401		340		337		321		317		1,502		3,327
Office and equipment leases		4		13		11		9		8		8		17		70
Asset retirement obligations(6)		—		—		—		—		—		—		38		38
Total	$	353		1,597		1,716		1,690		2,650		3,069		13,373		24,448


Period	Total Number of Shares Purchased		Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans		Maximum Number of Shares that May Yet be Purchased Under the Plan
July 1, 2017 - July 31, 2017		3,017	$	21.98		—		N/A
August 1, 2017 - August 31, 2017		—	$	—		—		N/A
September 1, 2017 - September 30, 2017		—	$	—		—		N/A

Natural gas
MMbtu/day

Hedged Differential
($/MMBtu)

Three months ending December 31, 2017: