ensura
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
For the quarterly period ended September 30, 2017March 31, 2020
OR
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 | | (IRS Employer Identification No.) |
| | |
1615 Wynkoop Street | | 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 |
Non-accelerated | | Smaller |
Emerging | | |
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 315,632,497268,390,401 shares of common stock outstanding as of October 26, 2017.April 24, 2020.
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1
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
TheSome of the information in this report includesQuarterly 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 intendedused 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, youinvestors should keep in mind the risk factors and other cautionary statements described under the heading “Item 1A. Risk Factors” in our Annualthis Quarterly Report on Form 10-K for10-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 withoutcome 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-lookingresults 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 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 |
| general economic conditions; |
| credit markets; |
| expectations regarding the amount and timing of jury awards; |
● | uncertainty regarding our future operating results; and |
2
| our other plans, objectives, expectations and |
We caution youinvestors 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
2
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 flowflows 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 2016Annual Report on Form 10-K for the year ended December 31, 2019 (the “2019 Form 10-K”) on file with the SECSecurities 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 reportQuarterly 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 reportQuarterly 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.
3
PART I—FINANCIAL INFORMATION
Condensed Consolidated Balance Sheets
December 31, 20162019 and September 30, 2017March 31, 2020
(Unaudited)
(In thousands, except per share amounts)thousands)
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| 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 |
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Liabilities and Equity |
| ||||||
Current liabilities: |
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|
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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: |
|
|
|
|
|
|
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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) |
|
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Equity: |
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Stockholders' equity: |
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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.
4
ANTERO RESOURCES CORPORATION
Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)
Three Months Ended September 30, 2016March 31, 2019 and 20172020
(Unaudited)
(In thousands, except per share amounts)
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| Three Months Ended September 30, |
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| 2016 |
| 2017 |
| ||
Revenue: |
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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) |
|
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Earnings (loss) per common share—basic |
| $ | 0.78 |
|
| (0.43) |
|
|
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|
|
|
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|
Earnings (loss) per common share—assuming dilution |
| $ | 0.77 |
|
| (0.43) |
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|
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.
5
ANTERO RESOURCES CORPORATION
Condensed Consolidated StatementsStatement of Operations and Comprehensive Income (Loss)Equity
NineThree Months Ended September 30, 2016 and 2017March 31, 2019
(Unaudited)
(In thousands, except per share amounts)thousands)
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| Nine Months Ended September 30, |
| ||||
|
| 2016 |
| 2017 |
| ||
Revenue and other: |
|
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|
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|
|
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.
6
ANTERO RESOURCES CORPORATION
Condensed Consolidated StatementsStatement of Equity
NineThree Months Ended September 30, 2017March 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.
7
ANTERO RESOURCES CORPORATION
Condensed Consolidated Statements of Cash Flows
NineThree Months Ended September 30, 2016March 31, 2019 and 20172020
(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.
8
ANTERO RESOURCES CORPORATION
Notes to Unaudited Condensed Consolidated Financial Statements
December 31, 20162019 and September 30, 2017March 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 SECSecurities and Exchange Commission (the “SEC”) applicable to interim financial information and should be read in the context of the Company’s December 31, 20162019 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, 20162019 consolidated financial statements have beenwere 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 accompanyingThese 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 accompanyingthese 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, 20162019 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 ninethree months ended September 30, 2016March 31, 2019 and 2017.2020. The Company has no items of other comprehensive income or loss; therefore, its net income or loss is identicalequal to its comprehensive income or loss. Operating results for the period ended September 30, 2017March 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-ownedwholly 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 thatThrough March 12, 2019, Antero Midstream isPartners LP (“Antero Midstream Partners”), a VIE for which Antero is the primary beneficiary. Therefore, Antero Midstream’s accounts arepublicly traded limited partnership, was included in the Company’sconsolidated financial statements of Antero. Prior to the Closing (defined in Note 3 to the unaudited condensed consolidated financial statements. Antero is the primary beneficiarystatements), 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 outstandingPartners 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 asPartners, and we consolidated Antero IDR
9
TableMidstream Partners’ financial position and results of Contents
ANTERO RESOURCES CORPORATION
Notesoperations 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 rightsunaudited 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 managementMidstream Partners for common stock of Antero Midstream and AMGP.
Antero andCorporation, 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 servicesPartners was converted to third-parties. Therefore,an interest in Antero controls the activitiesMidstream Corporation that most significantly impact Antero Midstream’s economic performance. Antero doesprovides significant influence, but not control, AMGPover 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 investmentaccounts 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. NoncontrollingThe 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 arePartners that were owned by the public prior to the Transactions, and the holder of Antero Midstream’s incentive distribution rights. Noncontrolling interestsrights in consolidated subsidiaries is included as a componentAntero Midstream Partners.
9
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 InvestmentsInvestment in unconsolidated affiliatesaffiliate 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)UseThe Company accounts for distributions received from equity method investees under the “nature of Estimatesthe 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 formulateto make estimates and assumptions whichthat affect revenues, expenses, assets, and liabilities as well asand 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 whichthat 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, theThe markets for natural gas, NGLs, and oil have, experiencedand 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.
10
ANTERO RESOURCES CORPORATION
(e)DerivativeNotes to Unaudited Condensed Consolidated Financial InstrumentsStatements
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
10
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.
11
ANTERO RESOURCES CORPORATION
(f)Industry SegmentsNotes to Unaudited Condensed Consolidated Financial Statements
December 31, 2019 and Geographic InformationMarch 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
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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) gatheringmarketing and processing; (3) water handling and treatment; and (4) marketingutilization 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 suchthe 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.
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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 maturityretires treasury shares acquired through share repurchases and returns those shares to the status of three months or lessauthorized 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 valueretired by the number of cash and cash equivalents approximates fair value dueshares outstanding, to the short term naturebalance of these instruments. From time to time, the Company may be in the positionadditional paid-in capital as of a “book overdraft” in which outstanding checks exceed cash and cash equivalents. retirement.
11
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 formedOn 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 assetsname 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, 2017Corporation, 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”), aindirect, wholly owned subsidiary of MPLX, L.P. Antero Midstream Corporation was merged with and MarkWest each own a 50% equity interest ininto Antero Midstream Partners, with Antero Midstream Partners surviving the Joint Venture and MarkWest operates the Joint Venture assets. The Joint Venture assets consistmerger 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 conjunctionMidstream Corporation (together, along with the formationother 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 6,900,000Corporation 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.
12
ANTERO RESOURCES CORPORATION
Notes to Condensed Consolidated Financial Statements
December 31, 2016 and September 30, 2017
On September 11, 2017, Antero sold 10,000,00098,870,335 common units representing limited partnership interests in Antero Midstream for approximately $311 million. Partners.
The saleCompany 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 unitsAntero 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.
14
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, netmethod of taxes. Proceeds fromaccounting. See Note 3 to the sale were usedunaudited condensed consolidated financial statements for further discussion on the Transactions.
15
ANTERO RESOURCES CORPORATION
Notes to pay down amounts outstanding under Antero’ credit facility, dated asUnaudited 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% ofinvestments in unconsolidated affiliates for the limited partner intereststhree 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, 20162019 and September 30, 2017, respectively.March 31, 2020
(4)(6) Accrued Liabilities
Accrued liabilities as of December 31, 20162019 and September 30, 2017March 31, 2020 consisted of the following items (in thousands):
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| 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 atof December 31, 20162019 and September 30, 2017March 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) ishas 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 “PriorThird Amendment to the Credit Facility”). On October 26, 2017, Antero entered into an amendment and restatementFacility, 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’sAntero Resources’ assets and are subject to regular annualsemi-annual redeterminations. At September 30, 2017, theThe borrowing base under the Prior Credit Facility was $4.75adjusted 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 maturityearliest stated redemption date of any series of Antero’sAntero Resources’ senior notes unless such series of notes is refinanced.then outstanding.
13
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’sS&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’sAntero 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’sAntero 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’sAntero 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. InterestDuring 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%.
17
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’sAntero Resources’ election at the time of borrowing. Duringborrowing, plus an Investment Grade Period, theapplicable margin applicable to the Credit Facility borrowings is determined with reference to Antero’sbased on Antero Resources’ credit rating andwhich ranges from 0.125%62.5 basis points to 0.50% lower than rates during225 basis points. In each case, the credit facility further provides a period that is not an Investment Grade Period, depending on Antero’s credit rating1% floor for LIBOR and utilization undera 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, 20162019 and September 30, 2017.March 31, 2020.
As of September 30, 2017,March 31, 2020, Antero Resources had a totalan 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’sAntero 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’sAntero 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-ownedAntero 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 toprice 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’sAntero 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-ownedAntero 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
14
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’sAntero 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-ownedAntero 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, 2018102.813% 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
18
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’sAntero 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-ownedAntero 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, 2020currently 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 whichthat 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’sAntero 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 MayJune 1, 2018. At December 31, 2016 and September 30, 2017, there2020. 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 allfirst quarter of the properties of2020, 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.
15
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 $427Resources 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 ninethree months ended September 30, 2017March 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 Otherother 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’sAntero Resources’ Board of Directors. A total of 7,724,6131,742,720 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 totalAs part of 7,656,134 common units were available for future grantthe 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.
16
Antero Midstream Corporation common stock.
19
ANTERO RESOURCES CORPORATION
Notes to Unaudited Condensed Consolidated Financial Statements
December 31, 20162019 and September 30, 2017March 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, 2016March 31, 2019 and 20172020 (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
Restricted Stock Unit Awards
A summary of restricted stock unit awardsaward activity for the ninethree months ended September 30, 2017March 31, 2020 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
| Weighted |
| Aggregate |
| ||
|
| Number of |
| grant date |
| intrinsic value |
| ||
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’sAntero 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 1.82.3 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.
17
20
ANTERO RESOURCES CORPORATION
Notes to Unaudited Condensed Consolidated Financial Statements
December 31, 20162019 and September 30, 2017March 31, 2020
Stock Options
A summary of stock option activity for the ninethree months ended September 30, 2017March 31, 2020 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Weighted |
|
|
| ||
|
|
|
| Weighted |
| average |
| Intrinsic |
| ||
|
| Stock |
| exercise |
| contractual |
| value |
| ||
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’sAntero Resources’ common stock on the referenced dates.
As of September 30, 2017, there was $3.3 million ofMarch 31, 2020, all stock options were fully vested resulting in 0 unamortized equity-based compensation expense relatedexpense.
Performance Share Unit Awards
The Company did not have any activities with regards to unvested stock options. That expense is expected to be recognized overits 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 |
| Weighted |
| |
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 |
|
18
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 2.11.6 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 phantomAntero Midstream Corporation restricted stock unit awards activity for the ninethree months ended September 30, 2017March 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 |
| Weighted |
| Aggregate |
| ||
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 |
|
21
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’sMidstream 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 2.21.5 years.
(8)(10) Financial Instruments
The carrying values of accounts receivable and accounts payable at December 31, 20162019 and September 30, 2017March 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, 20162019 and September 30, 2017March 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, 20162019 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.
19
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 ninethree months ended September 30, 2016March 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 whichfor 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 sellspays 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 portioncall 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.
22
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 oilNGL swap positions from OctoberApril 1, 20172020 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 |
| Oil |
| Natural Gas |
| Weighted |
| |
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 | |
20
TableA portion of Contentsthe 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
NotesIn 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 $2.77 per MMBtu for the year ending December 31, 2016 and September 30, 20172024.
As of September 30, 2017,March 31, 2020, the Company’s natural gas basis swap positions, which settle on the pricing index to basis differential of TCOthe Columbia Gas Transmission pipeline (“TCO”) to the NYMEX Henry Hub natural gas price, were as follows:
|
|
|
|
|
|
|
|
| Natural gas |
| Hedged Differential ($/MMBtu) |
| |
|
|
|
|
|
|
|
Three months ending December 31, 2017: |
| 125,000 |
| $ | (0.51) |
|
As of September 30, 2017, the Company’s natural gasand NGL basis swap positions, which settle on the pricing index to basis differential of NYMEX Henry HubMont Belvieu Butane to the TCOEuropean 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 |
| Hedged Differential ($/MMBtu) |
| |
|
|
|
|
|
|
|
Three months ending December 31, 2017: |
| 125,000 |
| $ | 0.39 |
|
23
(b)Commodity Derivative Fair ValuesANTERO 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, 20162019 and September 30, 2017. NoneMarch 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 |
| Fair value |
| Balance sheet |
| 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 |
| Gross amounts |
| Net amounts |
| Gross |
| Gross amounts |
| Net amounts |
| |||||||||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | |||||||||||||||||||
| | 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) | |
21
24
ANTERO RESOURCES CORPORATION
Notes to Unaudited Condensed Consolidated Financial Statements
December 31, 20162019 and September 30, 2017March 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, 2016March 31, 2019 and 20172020 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Statement of |
| 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.
25
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 gainsMarch 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 $750less 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.
26
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 | % |
27
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 180thday 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 monetizationsor 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 flowsbased on the Company’s condensedminimum 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 statementfinancial 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 pricescosts 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.
28
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 plaintiffagreements that are not leases are presented in a lawsuit against South Jersey Gas Company and South Jersey Resources Group, LLC (collectively, “SJGC”) pendingthis 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 damagesis 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/dayU.S. Environmental Protection Agency (“EPA”) Region III for alleged violations of the Company’sfederal 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 underproduction 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 beganClean Air Act relating to the facilities that were inspected in October 2011September 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 terminformation 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 offrom August and Septemberthrough 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
22
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.
29
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 lawsuitlegal 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 claimissue 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 secondnew 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 reaffirmeddismissed WGL’s lawsuit because WGL had not adequately pled a claim against Antero Resources for the arbitration panel’s finding that the delivery pointalleged 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 sincethrough 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 infiled a lawsuit filedagainst WGL in Colorado district court on October 24, 2017. WGL’s failure2017 to take receipt of all quantities of gas and resulting cover damages remains ongoing. The Company will continue to vigorously seek recovery ofrecover 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 parta 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.
30
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 arewere 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 arewere allocated to the gathering and processing and water handling and treatment segmentsmidstream 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 arewere 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.
23
31
ANTERO RESOURCES CORPORATION
Notes to Unaudited Condensed Consolidated Financial Statements
December 31, 20162019 and September 30, 2017March 31, 2020
The operating results and assets of the Company’s reportable segments were as follows for the three months ended September 30, 2016March 31, 2019 and 20172020 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
|
| Exploration |
| Gathering and |
| Water handling and treatment |
| Marketing |
| Elimination of |
| Consolidated |
| |||||||||||||||||
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 |
| Gathering and |
| Water handling and treatment |
| Marketing |
| Elimination of |
| Consolidated |
| |
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 |
|
24
32
ANTERO RESOURCES CORPORATION
Notes to Unaudited Condensed Consolidated Financial Statements
December 31, 20162019 and September 30, 2017March 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 |
| Gathering and |
| Water handling and treatment |
| Marketing |
| Elimination of |
| Consolidated |
| |
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 |
| Gathering and |
| Water handling and treatment |
| Marketing |
| Elimination of |
| Consolidated |
| |
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-ownedwholly owned subsidiaries has fully and unconditionally guaranteed Antero’sAntero 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 CompanyAntero (as defined in the indentures governing the notes) or the sale of all or substantially all of its assets (other than by lease))
25
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 whichthat 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, 20162019 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, 2016March 31, 2019 and 20172020, and Condensed Consolidating Statements of Cash Flows for the ninethree months ended September 30, 2016March 31, 2019 and 20172020 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-ownedThe Company’s wholly owned subsidiaries are not restricted from making distributions to the Parent.
26
Company.
33
ANTERO RESOURCES CORPORATION
Notes to Unaudited Condensed Consolidated Financial Statements
December 31, 20162019 and September 30, 2017March 31, 2020
Condensed Consolidating Balance Sheet
December 31, 20162019
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
|
| Parent |
| Guarantor |
| Non-Guarantor |
| 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 | |
27
34
ANTERO RESOURCES CORPORATION
Notes to Unaudited Condensed Consolidated Financial Statements
December 31, 20162019 and September 30, 2017March 31, 2020
Condensed Consolidating Balance Sheet
September 30, 2017
March 31, 2020
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
|
| Parent |
| Guarantor |
| Non-Guarantor |
| 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 | |
28
35
ANTERO RESOURCES CORPORATION
Notes to Unaudited Condensed Consolidated Financial Statements
December 31, 20162019 and September 30, 2017March 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 | |
36
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 |
| Non-Guarantor |
| 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) | |
29
37
ANTERO RESOURCES CORPORATION
Notes to Unaudited Condensed Consolidated Financial Statements
December 31, 20162019 and September 30, 2017March 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 |
| Non-Guarantor |
| 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 | | $ | — | | | — | | | — | | | — | | | — | |
30
38
ANTERO RESOURCES CORPORATION
Notes to Unaudited Condensed Consolidated Financial Statements
December 31, 20162019 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 |
| Non-Guarantor |
| 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) |
|
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 |
| Non-Guarantor |
| 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 |
|
32
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, 2016March 31, 2020
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Parent |
| Guarantor |
| Non-Guarantor |
| 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
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 |
| Non-Guarantor |
| 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 |
| Processing, |
| Drilling rigs and completion |
| 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
The Company has entered into firm transportation agreements with various pipelines in order to facilitate the delivery of its production to market. These contracts commit the Company to transport minimum daily natural gas or NGLs volumes at negotiated
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.
35
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 isWe 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 630,000536,000 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 websiteat www.anteroresources.com under the “Investors Relations” link“Investors–SEC Filings” section as soon as reasonably practicable after they are filedfurnished or furnishedfiled 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.
36
SEC.
40
20172020 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 energyeconomy 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 precipitouslyin 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 resultsignificant 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 portionsmaintaining 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 countriesproperties 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 commoditythe 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 changesalso declined during the first quarter of 2020, the decline in natural gas (Henry Hub), propane (Mont Belvieu), andprices 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 reductionshave 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 drillingtotal 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 costsdo 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 servicesthese products, demand for natural gas and increased efficienciesNGLs 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 improvedour 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.
41
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 throughbrought 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 capacityborrowings 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 reviseour ability to access the capital budget if conditions warrant. Additionally, givenmarkets. 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 pricefinancial 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 ofto 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
37
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 213306 Bcfe, or 2,3173,366 MMcfe per day, a 24%9% increase in daily combined production compared to 172279 Bcfe, or 1,8753,099 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, 2017March 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, 2017March 31, 2020 compared to $3.96$4.00 per Mcfe for the three months ended September 30, 2016.
March 31, 2019.
For the ninethree months ended September 30, 2017,March 31, 2020, we generated consolidated cash flows from operations of $1.7 billion, consolidated$201 million, net incomeloss 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 lossincome 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 ninethree 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 excludedcash 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 ninethree months ended September 30, 2017, our net production totaled 606 Bcfe, or 2,221 MMcfe per day, a 23% increaseMarch 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 Mcfeand 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 billionMarch 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 payablethree months ended March 31, 2019 primarily due to the utilizationgain 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
42
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 consistedthe 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.
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20172020 Capital Budget and Capital Spending
Our consolidateddrilling and completion capital budget for 2017 is $2.3 billion2020 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 ninethree 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
38
of $11$24 million. Antero Midstream Partners also invested $217$25 million in a joint venture with MarkWest Energyventure. 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 hedgingfixed price natural gas swap contracts on NYMEX Henry Hub for approximately 2.9the 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 20172020 of approximately 171613 Bcf of natural gas at a weighted average index price of $3.71$2.87 per Mcf, 106 million gallonsMMBtu. At March 31, 2020, we also had basis swaps for the period from April 2020 through December 2024 for approximately 89.5 Bcf of propaneour 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 $4.75reduced to $2.85 billion and lender commitments were $4.0 billion. Underremained 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. Ourredetermination in April 2020. The borrowing base under theour Credit Facility is redetermined annuallysemi-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 hedgederivative 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 maturityearliest stated redemption date of any series of Antero’sour senior notes unless such seriesthen 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 ninethree months ended September 30, 2017, Antero Midstream issued and sold 777,262March 31, 2020, pursuant to our share repurchase program, we repurchased 27,193,237 shares of our common units understock (approximately 9% of total shares outstanding at commencement of the Distribution Agreement, resulting in net proceedsprogram) 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 hadapproximately $43 million. During the capacity to issue additional common units under the Distribution Agreement up toterm 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.
43
Results of Operations
Three Months Ended September 30, 2016 Compared to Three Months Ended September 30, 2017
The Company has fourWe have three operating segments: (1) the exploration, development and production of natural gas, NGLs, and oil; (2) gatheringmarketing and processing; (3) water handling and treatment; and (4) marketingutilization 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 treatmentAntero Midstream Corporation’s operations arewere primarily derived from intersegment transactions for services provided to our exploration and production operations by Antero Midstream. IntersegmentMidstream Partners. All intersegment transactions that arewere eliminated includeupon consolidation, including revenues from water handling and treatment services provided by Antero Midstream Partners, which arewe 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 capacitycapacity.
Three Months Ended March 31, 2019 Compared to third parties.
39
Three Months Ended March 31, 2020
The operating results of the Company’sour reportable segments were as follows for the three months ended September 30, 2016March 31, 2019 and 20172020 (in thousands):
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| $ | 1,016,458 |
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| 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 |
| Gathering and |
| Water handling and treatment |
| Marketing |
| Elimination of |
| Consolidated |
| |
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 |
|
44
|
| |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | 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 | |
40
45
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 settable sets forth selected consolidated operating data of the exploration and production segment for the three months ended September 30, 2016March 31, 2019 compared to the three months ended September 30, 2017:March 31, 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Three Months Ended September 30, |
| Amount of |
| 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) | % |
41
| | | | | | | | | | | | | |
| | | | | | | | 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) | % | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Three Months Ended September 30, |
| Amount of |
| 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) |
|
|
| 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, |
*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 increaseddecreased from $486$657 million for the three months ended September 30, 2016March 31, 2019 to $660$411 million for the three months ended September 30, 2017, an increaseMarch 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 productnatural gas revenues (calculated as the combined change in year-to-year volumes times the prior year average price), and increaseschanges in our equivalent prices, excluding the effects of derivative settlements, accounted for an approximate $59$276 million increasedecrease 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 numberproduction of producing wells as a result of our drilling and completion program.
42
DuringNGLs decreased from $314 million for the three months ended September 30, 2016March 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 gasprices, 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).
46
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 toprices, excluding the condensed consolidated financial statements or “Item 1. Legal Proceedings” included elsewhereeffects 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, 2016March 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, 2016March 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 $3Other 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 providedMarch 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 $23March 31, 2020.
Lease operating expense. Lease operating expense decreased from $43 million for the three months ended September 30, 2017, an increaseMarch 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 increaseddecreased from $0.08 per Mcfe$0.15 for the three months ended September 30, 2016March 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 basisMarch 31, 2020. This decrease is primarily due to an increase in produceddecreased water on new well pads, which is attributable to an increase in the amount of water used in our advanced well completions. In addition, leasehandling 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 baseefficiencies 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, 2016March 31, 2019 to $282$589 million for the three months ended September 30, 2017. The increase in these expensesMarch 31, 2020. This is primarily a result of the increase in productionproduction. Gathering and the related firm transportation, gathering, compression and processing expenses. On acosts decreased from $0.76 per Mcfe basis, consolidated gathering, compression, processingto $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 expensescosts 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, 2016March 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 beforeincreased 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 percentageMarch 31, 2020.
Impairment of revenue increased due to higher severance tax rates in West Virginia as compared to Ohio.
Exploration expenseoil and gas properties. Exploration expenseImpairment of oil and gas properties increased from $1$81 million for the three months ended September 30, 2016March 31, 2019 to $2$89 million for the three months ended September 30, 2017. These amounts represent expenses incurred for unsuccessful lease acquisition efforts.
43
Impairment of unproved properties$8 million, or 10%. Impairment of unproved properties increased from $12 million for the three months ended September 30, 2016We recognized impairments primarily related to $41 million for the three months ended September 30, 2017, primarily dueexpiring leases and to the expiration of certain Utica leases whichdesign and initial costs related to pads we elected notno longer plan to retain and develop.place into service. We charge impairment expense for expired or soon-to-be expiredexpiring 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, 2016March 31, 2019 to $207$200 million for the three months ended September 30, 2017, primarily becauseMarch 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, 2016March 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.
47
General and administrative expense. General and administrative expense (before(excluding equity-based compensation expense) increasedrelated to the exploration and production segment decreased from $31$43 million for the three months ended September 30, 2016March 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 increasesapproximately $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 compensationrelated 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 beforeexcluding equity-based compensation decreased by 6%44%, from $0.18$0.16 per Mcfe during the three months ended September 30, 2016March 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 employeesMarch 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-cashNoncash equity-based compensation expense remained consistent at $26decreased from $6 million for the three months ended September 30, 2016March 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 reportQuarterly Report on Form 10-Q for more information on equity-based compensation awards.
Interest expense. Interest expense increased from $60Contract termination and rig stacking. We incurred contract termination and rig stacking costs of $8 million forduring the three months ended September 30, 2016March 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 dueMarch 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
44
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 ofMarketing Segment Results for the Three Months Ended September 30, 2016March 31, 2019 Compared to the Three Months Ended September 30, 2017March 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-
45
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 |
| Gathering and |
| Water handling and treatment |
| Marketing |
| Elimination of |
| Consolidated |
| |
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 |
|
46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Exploration |
| Gathering and |
| Water handling and treatment |
| Marketing |
| Elimination of |
| Consolidated |
| |
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 |
|
|
|
47
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 |
| 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) | % |
48
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Nine Months Ended September 30, |
| Amount of |
| 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) | % |
|
|
|
|
*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.
49
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.
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 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
50
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.
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 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.
51
Discussion of Segment Results for the Nine Months Ended September 30, 2016 Compared to the Nine Months Ended September 30, 2017
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 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 marketto utilize our excess firm transportation capacity, or engagerelease capacity to third parties to conduct these activities on our behalf, in order to optimizereduce our net costs related to the revenues fromunused 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
52
activities. NetOperating losses on our marketing activities, were $92or 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 $79the mitigation of some of our excess firm transportation expense.
Marketing revenues decreased from $91 million for the ninethree months ended September 30, 2016March 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 costsexpenses 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 firmFirm transportation costs of $96included in the expenses above were $68 million and $74$47 million for the ninethree months ended September 30, 2016March 31, 2019 and 2017, respectively, related2020, respectively.
Discussion of Antero Midstream Corporation Segment for the Three Months Ended March 31, 2019 Compared to unutilized excess capacity which decreasedthe 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 assumptionthree months ended March 31, 2019 only including Antero Midstream Corporation’s results following the closing of certain unutilized firm transportation capacitythe 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,
48
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, ourOur 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 ofdevelop 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.
49
As of March 31, 2020, we believe that funds from operating cash flows, anddistributions 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 ninethree months ended September 30, 2016March 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 FlowFlows Provided by Operating Activities
Net cash provided by operating activities was $906$539 million and $1.7 billion$201 million for the ninethree months ended September 30, 2016March 31, 2019 and 2017,2020, respectively. The increase in cash flowsCash flow from operations from the nine months ended September 30, 2016 to the nine months ended September 30, 2017 wasdecreased primarily due to $750 milliondecreases 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 isflows 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 FlowFlows 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 ninethree months ended September 30, 2016March 31, 2019 to $1.9 billion$187 million for the ninethree months ended September 30, 2017,March 31, 2020, primarily due to decreasesa decrease in acquisitionscapital 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.
50
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 increasesactivity, increased drilling and completion efficiencies and service cost deflation.
The three months ended March 31, 2019 included Antero Midstream’sMidstream Partners’ investments in the Joint Venturejoint ventures of $25 million and capital expenditures for water handling and treatment systems and gas gathering and compression assets duringsystems of $73 million. Due to the nine months ended September 30, 2017. During the nine months ended September 30, 2017, ourdeconsolidation 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.
53
Our capital budget for 2017 is $1.5 billion, which does not include the capital budget of $8002020 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 ourthat do not generate an acceptable levels,level of corporate returns, or costs increase to levels above ourthat do not generate an acceptable levels,level of corporate returns, we could choose tomay 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 ofthe relative success in drilling activities, contractual obligations, internally generated cash flows, and other factors both within and outside our control.
Cash FlowFlows Provided by Financing Activities
NetDuring the three months ended March 31, 2019 and 2020, net cash flows provided by financing activities decreased from $1.1 billion fora 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 issuancesissuance of common stocksenior notes by Antero duringMidstream Partners prior to the nine months ended September 30, 2016 to fund property acquisitions, as well as repayments on Antero’s Prior Credit Facility duringTransactions and the nine months ended September 30, 2017 using proceeds from the hedge monetizations and saleassociated 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 inCredit Facility and Antero Midstream Partners’ credit facility.
Net borrowings (repayments) on our Credit Facility and other items totaling $12 million. DuringAntero Midstream Partners’ credit facility changed from net payments of $270 million during the ninethree months ended September 30, 2016, our cash flows provided by financing activities included proceedsMarch 31, 2019 to net borrowings of $837$330 million fromduring the issuancethree 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 hadin the three months ended March 31, 2020 was used to repurchase a net decrease from $930portion 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 underduring 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’sOur 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, theThe borrowing base was $4.75adjusted 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 maturityearliest stated redemption date of any series of Antero’sour senior notes unless such seriesthen 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 leaseleast one of either (i) a BBB- or better rating from Standard and Poor’s andS&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 |
51
| 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
● | 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), of not less than 1.0 to 1.0; |
|
|
54
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 suchthe applicable covenants and ratios as determined by the Prior Credit Facility as of December 31, 20162019 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 5.732.28 to 1.0 (based on the $4.5 billion borrowing base under the Credit Facility) and our interest coverage ratio was 9.015.06 to 1.0.
MidstreamFor 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.
55
52
Contractual Obligations. A summary of our contractual obligations as of September 30, 2017March 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) |
| Includes outstanding principal amounts at |
(2) |
|
|
(3) |
| Includes contracts for services provided by drilling rigs and completion fleets, |
(4) |
|
(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 |
(6) |
| Contractual commitments for processing, gathering, and compression services agreements represent minimum commitments under long-term |
(7) | Includes contractual commitments for |
|
|
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 (excludingfrom 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.
53
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 equityreceived with respect to limited partner interests in earnings or losses of unconsolidated affiliates.Antero Midstream Partners common units through March 12, 2019.
56
“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’sour 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 |
| helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital and legal structure from our operating structure; |
| is used by our management team for various purposes, including as a measure of our operating performance, in presentations to our Board of Directors, and as a basis for strategic planning and |
● | is |
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 |
| Gathering and |
| Water handling and treatment |
| Marketing |
| Elimination of |
| Consolidated |
| |
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 |
|
57
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Exploration |
| Gathering and |
| Water handling and treatment |
| Marketing |
| Elimination of |
| Consolidated |
| |
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 |
| Gathering and |
| Water handling and treatment |
| Marketing |
| Elimination of |
| Consolidated |
| |
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 |
| Gathering and |
| Water handling and treatment |
| Marketing |
| Elimination of |
| Consolidated |
| |
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.
58
The following table represents a reconciliation of our net income (loss), including noncontrolling interest, to consolidated Adjusted EBITDAX and a reconciliation of consolidatedour 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, 2016March 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 |
|
54
| | | | | | | |
| | 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) |
| 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 |
(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 |
55
|
|
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 20162019 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 20162019 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 wheneverfor 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 exceededexceeds the estimated undiscounted future net cash flows (measured using futuresfuture 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
59
September 30, 2017, we comparedThe estimated undiscounted future net cash flows using futures pricing for our Uticahave been impacted by the COVID-19 pandemic and Marcellus Shale propertiesthe decision in March 2020 by Saudi Arabia to reduce the carrying values of those properties. Estimatedprice 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, 2017amount and thus, no further evaluation of the proved properties for impairment is required under GAAP. As a result, wewas 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 nine2020. 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 propertiesa 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-balanceoff 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.
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.
56
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 productcommodity 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 ofMarch 31, 2020, our natural gas hedges werecommodity derivatives included fixed price swaps and basis differential swaps at NYMEXindex-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, 2017March 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 whichthat settled during the ninethree 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 comprisingcomprised 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.
61
Counterparty and Customer Credit Risk
Our principal exposures to credit risk are through receivables resulting from the following: commodity derivative contracts ($1.21.1 billion at September 30, 2017)March 31, 2020); and the sale and marketing of our oilnatural gas, NGLs and gasoil production ($234192 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 thea 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
57
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 whichthat 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 fourteen14 different counterparties, twelve12 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, 2017March 31, 2020 included the following derivative assets by bank counterparty: JP MorganWells 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 DominionJP 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 ThirdTD 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, 2017March 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 ourthe Credit Facility, and the Midstream Facility of our consolidated subsidiary, Antero Midstream. Each of these credit facilitieswhich has a floating interest rate. The average annualized interest rate incurred on the Prior Credit Facility and the Prior Midstream Facility during the ninethree months ended September 30, 2017March 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 ninethree months ended September 30, 2017March 31, 2020 would have resulted in a $7.0an estimated $1.6 million increase in interest expense.
Item 4.Controls4.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, 2017March 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, 2017March 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.Legal1.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 amountedthis 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 ourunaudited condensed consolidated financial position, results of operations, or cash flows.statements and is incorporated herein.
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 2016the 2019 Form 10-K and in our Quarterly Reports on Form 10-Q foraddition 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:
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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 |
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July 1, 2017 - July 31, 2017 |
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| 3,017 |
| $ | 21.98 |
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| — |
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| N/A |
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August 1, 2017 - August 31, 2017 |
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| — |
| $ | — |
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| — |
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| N/A |
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September 1, 2017 - September 30, 2017 |
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| — |
| $ | — |
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| — |
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| N/A |
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| | | | | | | | | | | | | |
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) |
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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
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 uponits 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.
Amendedlenders party thereto and Restated Credit Facility
On October 26, 2017, weJPMorgan 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 theThird Amendment (the “Third Amendment”) to our Credit Facility. The description of theThird Amendment amends our Credit Facility is a summaryto, 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 disclosedescribed in our annual and quarterly reportsNote 7 to the Securities and Exchange Commission (the “SEC”), whether we or any of our “affiliates” knowingly engagedunaudited 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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6.Exhibits
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Exhibit | | Description of Exhibit | |
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3.2 | | | |
10.1* | | | |
10.2* | | | |
10.3* | | | |
31.1* | | | |
31.2* | | | |
32.1* | | | |
32.2* | | | |
101* | | The following financial information from this Quarterly Report on Form 10-Q of Antero Resources Corporation for the quarter ended | |
104 | | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101). | |
The exhibits marked with the asterisk symbol (*) are filed or furnished with this Quarterly Report on Form 10-Q.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
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ANTERO RESOURCES CORPORATION | |
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By: | /s/ GLEN C. WARREN, JR. |
| Glen C. Warren, Jr. |
| President, Chief Financial Officer and Secretary |
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Date: |
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