Exhibit 99.1
Antero Resources Reports Fourth Quarter Results, Announces 2022 Guidance and Return of Capital Program
Denver, Colorado, February 16, 2022—Antero Resources Corporation (NYSE: AR) (“Antero Resources,” “Antero,” or the “Company”) today announced its fourth quarter 2021 financial and operating results, year end 2021 estimated proved reserves, as well as its 2022 capital budget and guidance. In addition, Antero announced targets for returning capital to shareholders. The relevant consolidated financial statements are included in Antero Resources’ Annual Report on Form 10-K for the year ended December 31, 2021.
Fourth Quarter 2021 Highlights Include:
| · | Net production averaged 3.2 Bcfe/d, including 160 MBbl/d of liquids |
| · | Realized pre-hedge natural gas equivalent price of $6.48 per Mcfe, a $0.65 per Mcfe premium to NYMEX pricing |
| o | Realized pre-hedge C3+ NGL price of $58.25 per barrel, or 75% of WTI, a 111% increase from the prior year period |
| o | Realized pre-hedge natural gas price of $5.89 per Mcf, a $0.06 per Mcf premium to NYMEX Henry Hub pricing |
| · | Net Income was $901 million, Adjusted Net Income was $157 million (Non-GAAP) |
| · | Adjusted EBITDAX was $420 million (Non-GAAP); net cash provided by operating activities was $475 million |
| · | Free Cash Flow was $237 million (Non-GAAP) |
| · | Total Debt and Net Debt at quarter end was $2.1 billion, an $875 million reduction from year end 2020 (Non-GAAP) |
| · | Net Debt to trailing last twelve month Adjusted EBITDAX declined to 1.3x (Non-GAAP) |
| · | Estimated proved reserves were 17.7 Tcfe at year end 2021 and proved developed reserves increased to 12.8 Tcfe (72% Proved Developed) |
| · | Estimated future development cost for 5.0 Tcfe of proved undeveloped reserves is $0.31 per Mcfe |
Capital Return Program, 2022 Guidance and Other Highlights:
| · | Targeting return of capital to shareholders of 25% to 50% of Free Cash Flow annually going forward |
| o | Initiated with a board-approved share repurchase program of up to $1.0 billion |
| · | Announced plans to redeem all remaining Senior Notes due 2025 on March 1, 2022 |
| · | Drilling and completion capital budget is $675 to $700 million |
| · | Net production is expected to average 3.2 to 3.3 Bcfe/d, including 175 to 185 MBbl/d of liquids (NGLs and oil) |
| · | Expanded 2025 Net Zero emissions target to include Scope 2 emissions |
| · | Received Responsibly Sourced Gas certification following completion of initial Project Canary Pilot |
Paul Rady, Chairman, President and Chief Executive Officer of Antero Resources commented, “This past year proved to be an important inflection point for Antero as we shifted to a maintenance capital program and generated approximately $850 million of Free Cash Flow. This substantial Free Cash Flow was used to reduce debt during the year, driving leverage down to 1.3x as of December 31, 2021. Looking ahead to 2022, our capital budget reflects another year of maintenance capital that is projected to generate $1.5 to $1.7 billion in Free Cash Flow based on current commodity prices. This Free Cash Flow outlook allows us to continue to reduce debt while also returning substantial capital to our shareholders.”
Michael Kennedy, Chief Financial Officer of Antero Resources said, “The dramatic reduction in our absolute debt, below $2.0 billion in the first quarter of 2022, enables us to initiate a return of capital program. Going forward we will target returning 25% to 50% of Free Cash Flow annually to our shareholders, beginning with the $1.0 billion share repurchase program that is effective immediately. This plan puts Antero in the unique position of reducing leverage below 1.0x in 2022 while maintaining a peer-leading return of capital profile.”
For a discussion of the non-GAAP financial measures including Adjusted Net Income, Adjusted EBITDAX, Free Cash Flow and Net Debt please see “Non-GAAP Financial Measures.”
Return of Capital Program
Antero is initially targeting a return of capital of 25% to 50% of Free Cash Flow annually going forward, beginning with the implementation of the share repurchase program. Antero’s Board of Directors authorized a share repurchase program that allows the Company to repurchase up to $1.0 billion of outstanding common stock. This represents approximately 16% of Antero’s market capitalization based on the current share price. The open market share repurchase program is expected to commence during the first quarter of 2022.
The actual amount, timing and nature of any returns of capital to shareholders is subject to review and approval by Antero’s Board of Directors. The shares may be repurchased from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws. The timing, as well as the number and value of shares repurchased under the program, will be determined by the Company at its discretion and will depend on a variety of factors, including the market price of the Company’s common stock, general market and economic conditions and applicable legal requirements. The exact number of shares to be repurchased by the Company is not guaranteed and the program may be suspended, modified, or discontinued at any time without prior notice.
Debt Reduction
As of December 31, 2021, Antero’s total debt was $2.1 billion with no borrowings under the Company’s revolving credit facility. Net Debt to trailing twelve month Adjusted EBITDAX was 1.3x. In late January, Antero announced that on March 1, 2022 it will redeem all $585 million of outstanding senior notes due 2025 at 101.25% of par, plus accrued and unpaid interest on March 1, 2022. The redemption is expected to reduce annual interest expense by approximately $30 million. The Company intends to utilize cash on hand and borrowings under its revolving credit facility to fund this senior note redemption. Borrowings utilized to fund the redemption are expected to be paid down in 2022 with Free Cash Flow.
Project Canary Natural Gas Certification
The pilot project to certify environmental performance of multiple pads with Project Canary was completed in early 2022. This rigorous independent assessment and certification process evaluated the engineering, operational and environmental standards that Antero employs in its operations. The certification confirms Antero’s strong operational and environmental performance and supports the Company’s continuous improvement and ESG goals, which was expanded to include targeting Net Zero Scope 2 emissions by 2025.
2022 Capital Budget and Guidance
Antero’s drilling and completion capital budget reflects service cost inflation that is projected in 2022, partially offset by expected savings associated with the transition to regional sand from Antero’s local sand mine. The net impact, including the sand savings, is a projected 5% cost increase in 2022 as compared to 2021. In addition, the budget reflects Antero’s election to increase its working interest in wells to be drilled by the drilling partnership with QL Capital Partners to 85% in 2022 from 80% in 2021, resulting in approximately $35 to $40 million of incremental capital net to Antero.
Production is expected to increase throughout the year in 2022. Volumes in the first half of 2022 are expected to average 3.1 to 3.2 Bcfe/d as a result of the limited drilling and completion activity that occurred at the end of 2021 as well as adverse winter weather that reduced activity during the beginning of the first quarter of 2022. With well completions accelerating in the second quarter as winter weather subsides, combined with the Shell ethane cracker near Pittsburgh that is expected to be placed in service in the second half of 2022, net production is expected to average between 3.3 to 3.4 Bcfe/d during the second half of 2022. In 2023, Antero expects an additional 1% to 2% production growth from the second half of 2022 reflecting its higher working interest election in the drilling partnership during 2022.
The following is a summary of Antero Resources’ 2022 capital budget.
| Capital Budget ($ in Millions) | Low | High | ||||||
| Drilling & Completion | $ | 675 | $ | 700 | ||||
| Land | $ | 65 | $ | 75 | ||||
| Total E&P Capital | $ | 740 | $ | 775 | ||||
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# of Wells | Net Wells | Average Lateral Length | ||
| Drilled Wells | 70 to 80 | 13,800 Feet | ||
| Completed Wells | 60 to 65 | 13,300 Feet | ||
The following is a summary of Antero Resources’ 2022 production, pricing and cash expense guidance.
| Production Guidance | Low | High | ||||||
| Net Daily Natural Gas Equivalent Production (Bcfe/d) | 3.2 | 3.3 | ||||||
| Net Daily Natural Gas Production (Bcf/d) | 2.2 | 2.25 | ||||||
| Total Net Daily Liquids Production (MBbl/d): | 175 | 185 | ||||||
| Net Daily C3+ NGL Production (MBbl/d) | 105 | 110 | ||||||
| Net Daily Ethane Production (MBbl/d) | 62 | 65 | ||||||
| Net Daily Oil Production (MBbl/d) | 8 | 10 | ||||||
| Realized Pricing Guidance (Before Hedges) | Low | High | ||||||
| Natural Gas Realized Price Premium vs. NYMEX Henry Hub ($/Mcf) | $ | 0.15 | $ | 0.25 | ||||
| C3+ NGL Realized Price Differential vs. Mont Belvieu ($/Gal) | $ | 0.00 | $ | 0.00 | ||||
| Oil Realized Price Differential vs. WTI Oil ($/Bbl) | $ | (7.00 | ) | $ | (9.00 | ) | ||
| Cash Expense Guidance | Low | High | ||||||
| Cash Production Expense ($/Mcfe)(1) | $ | 2.25 | $ | 2.35 | ||||
| Marketing Expense, Net of Marketing Revenue ($/Mcfe) | $ | 0.06 | $ | 0.08 | ||||
| G&A Expense ($/Mcfe)(2) | $ | 0.10 | $ | 0.12 | ||||
| (1) | Includes lease operating expenses and gathering, compression, processing and transportation expenses (“GP&T”) and production and ad valorem taxes. Assumes LP gathering fee rebates of $12 million are received each quarter in 2022. | |
| (2) | Excludes equity-based compensation. |
Free Cash Flow
Antero generated $237 million and $849 million of Free Cash Flow during the fourth quarter and full year of 2021, respectively.
| Three Months Ended December 31, | Year Ended December 31, | |||||||||||||||
| 2020 | 2021 | 2020 | 2021 | |||||||||||||
| Net cash provided by operating activities | $ | 243,130 | 475,164 | 735,640 | 1,660,116 | |||||||||||
| Less: Net cash used in investing activities | (145,998 | ) | (205,329 | ) | (530,061 | ) | (710,784 | ) | ||||||||
| Less: Proceeds from sale of assets, net | (657 | ) | — | (216,490 | ) | (3,192 | ) | |||||||||
| Less: Settlement of water earnout | — | — | (125,000 | ) | — | |||||||||||
| Less: Distributions to non-controlling interests in Martica | (18,671 | ) | (32,641 | ) | (35,920 | ) | (97,424 | ) | ||||||||
| Free Cash Flow | $ | 77,804 | 237,194 | (171,831 | ) | 848,716 | ||||||||||
| Changes in Working Capital (1) | 80,473 | (64,634 | ) | 203,666 | (151,722 | ) | ||||||||||
| Free Cash Flow before Changes in Working Capital | $ | 158,277 | 172,560 | 31,835 | 696,994 | |||||||||||
| (1) | Working capital adjustments in the fourth quarter of 2021 include $61.1 million in changes in current assets and liabilities and a $3.5 million increase in accounts payable and accrued liabilities for additions to property and equipment. Working capital adjustments for 2021 include $114.7 million in changes in current assets and liabilities and a $37.0 million increase in accounts payable and accrued liabilities for additions to property and equipment. See the cash flow statement in this release for details. |
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Fourth Quarter 2021 Financial Results
Net income was $901 million, or $2.65 per diluted share, compared to net income of $70 million, or $0.24 per diluted share, in the prior year period. Adjusted Net Income was $157 million, or $0.46 per diluted share, compared to Adjusted Net Loss of $3 million, or $0.01 per diluted share, in the prior year period.
Adjusted EBITDAX was $420 million, a 40% increase compared to the prior year quarter, driven by higher realized natural gas and NGL prices.
Net daily natural gas equivalent production in the fourth quarter averaged 3.2 Bcfe/d, including 160 MBbl/d of liquids, as detailed in the table below. Fourth quarter volumes were down sequentially as just 40% of the Company’s 2021 completion activity occurred during the second half of 2021, including less than 20% of annual completion activity in the fourth quarter. Antero chose not to accelerate activity in the second half of 2021 in order to adhere to the capital budget. In addition, liquids volumes were down sequentially in the fourth quarter as four of the 14 completions were dry gas Utica wells.
Antero’s average realized natural gas price before hedging was $5.89 per Mcf, representing a 124% increase compared to the prior year period. Antero realized a $0.06 per Mcf premium to the average NYMEX Henry Hub. The premium to NYMEX was lower than expected due to the significant decline in daily pricing during the months of November and December relative to NYMEX first-of-month pricing. Antero sells its gas both on a first-of-month and daily basis, which is an industry standard for operational purposes.
The following table details the components of average net production and average realized prices for the three months ended December 31, 2021:
| Three Months Ended December 31, 2021 | ||||||||||||||||||||
| Combined | ||||||||||||||||||||
| Natural | ||||||||||||||||||||
| Natural | Gas | |||||||||||||||||||
| Gas | Oil | C3+ NGLs | Ethane | Equivalent | ||||||||||||||||
| (MMcf/d) | (Bbl/d) | (Bbl/d) | (Bbl/d) | (MMcfe/d) | ||||||||||||||||
| Average Net Production | 2,233 | 7,489 | 107,304 | 44,891 | 3,191 | |||||||||||||||
Combined | ||||||||||||||||||||
| Natural | ||||||||||||||||||||
| Natural | Gas | |||||||||||||||||||
| Gas | Oil | C3+ NGLs | Ethane | Equivalent | ||||||||||||||||
| Average Realized Prices | ($/Mcf) | ($/Bbl) | ($/Bbl) | ($/Bbl) | ($/Mcfe) | |||||||||||||||
| Average realized prices before settled derivatives | $ | 5.89 | $ | 69.53 | $ | 58.25 | $ | 16.81 | $ | 6.48 | ||||||||||
| NYMEX average price | $ | 5.83 | $ | 77.45 | $ | 5.83 | ||||||||||||||
| Premium / (Differential) to NYMEX | $ | 0.06 | $ | (7.92 | ) | $ | 0.65 | |||||||||||||
| Settled commodity derivatives | $ | (3.10 | ) | $ | (9.36 | ) | $ | (5.84 | ) | — | $ | (2.33 | ) | |||||||
| Average realized prices after settled derivatives | $ | 2.79 | $ | 60.17 | $ | 52.41 | $ | 16.81 | $ | 4.15 | ||||||||||
| Differential to NYMEX | $ | (3.04 | ) | $ | (17.28 | ) | $ | (1.68 | ) | |||||||||||
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Antero’s average realized C3+ NGL price before hedging was $58.25 per barrel, a 111% increase versus the prior year period. Antero shipped 50% of its total C3+ NGL net production on Mariner East 2 for export and realized a $0.03 per gallon premium to Mont Belvieu pricing on these volumes at Marcus Hook, PA. Antero sold the remaining 50% of C3+ NGL net production at a $0.04 per gallon discount to Mont Belvieu pricing at Hopedale, OH. The resulting blended price on 107,304 Bbl/d of net C3+ NGL production was $52.98 per barrel, which was a $0.01 per gallon discount to Mont Belvieu pricing. Antero expects to sell approximately 50% of its C3+ NGL production in 2022 at Marcus Hook for international export at a premium to Mont Belvieu.
| Three Months Ended December 31, 2021 | ||||||||||||||
| Pricing Point | Net C3+ NGL Production (Bbl/d) | % by Destination | Premium (Discount) To Mont Belvieu ($/Gal) | |||||||||||
| Propane / Butane exported on ME2 | Marcus Hook, PA | 54,188 | 50 | % | $ | 0.03 | ||||||||
| Remaining C3+ NGL volume | Hopedale, OH | 53,116 | 50 | % | $ | (0.04 | ) | |||||||
| Total C3+ NGLs/Blended Premium | 107,304 | 100 | % | $ | (0.01 | ) | ||||||||
All-in cash expense, which includes lease operating, gathering, compression, processing and transportation, production and ad valorem taxes was $2.45 per Mcfe in the fourth quarter, a 16% increase compared to $2.12 per Mcfe average during the fourth quarter of 2020. The increase from a year ago was due primarily to a $0.18 increase in gathering, processing and transportation expense driven by higher fuel costs as a result of higher natural gas prices and a $0.12 per Mcfe increase due to higher production taxes as a result of higher commodity prices.
Net marketing expense was $0.10 per Mcfe in the fourth quarter, an increase from $0.08 during the fourth quarter of 2020 due to lower production volume and lower third party marketing volumes.
Fourth Quarter 2021 Operating Update
Antero placed 10 horizontal Marcellus wells to sales during the fourth quarter with an average lateral length of 15,393 feet. All 10 wells have been online for at least 60 days and the average 60-day rate per well was 28.5 MMcfe/d, including approximately 1,306 Bbl/d of liquids assuming 25% ethane recovery. Wells placed on line in 2021 were ahead of type curve projections, leading to capital efficiency improvements during the year.
Antero also placed four horizontal Utica dry gas wells to sales during the fourth quarter with an average lateral length of 10,046 feet. All four wells have been on line for at least 60 days and the average 60-day rate per well was 25.0 MMcf/d at an average BTU of 1120.
Fourth Quarter 2021 Capital Investment
Antero’s accrued drilling and completion capital expenditures for the three months ended December 31, 2021, were $152 million. In addition to capital invested in drilling and completion costs, the Company invested $30 million in land during the fourth quarter. A portion of the land spend was used to acquire 4,000 net acres which hold approximately 20 incremental drilling locations at an average cost of less than $1 million per location. The acreage is located in Antero’s core Marcellus liquids-rich window and is expected to be developed within the Company’s five-year development program. For a reconciliation of accrued capital expenditures to cash capital expenditures see the table in the Non-GAAP Financial Measures section.
Balance Sheet and Liquidity
As of December 31, 2021, Antero’s Net Debt was $2.1 billion with no borrowings under the Company’s revolving credit facility. Net Debt to trailing twelve month Adjusted EBITDAX ratio was 1.3x as of December 31, 2021.
Year End Proved Reserves
At December 31, 2021, Antero’s estimated proved reserves were 17.7 Tcfe, a 1% increase versus the prior year. Estimated proved reserves were comprised of 58% natural gas, 41% NGLs and 1% oil.
Estimated proved developed reserves were 12.8 Tcfe, a 7% increase over the prior year. The percentage of estimated proved reserves classified as proved developed increased to 72% at year end 2021, compared to 67% at year end 2020. Antero's proved undeveloped locations have an average estimated BTU of 1263, with an average lateral length of approximately 14,143 feet. At year end 2021, Antero’s five year development plan included 276 PUD locations.
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Antero's 5.0 Tcfe of estimated proved undeveloped reserves will require an estimated $1.5 billion of future development capital over the next five years, resulting in an estimated average future development cost for proved undeveloped reserves of $0.31 per Mcfe.
The following table presents a summary of changes in estimated proved reserves (in Tcfe).
| Proved reserves, December 31, 2020 (1) | 17.6 | |||
| Extensions, discoveries, and other additions | 0.5 | |||
| Revisions | 1.5 | |||
| Sales of reserves in place (2) | (0.7 | ) | ||
| Production | (1.2 | ) | ||
| Proved reserves, December 31, 2021 (1) | 17.7 | |||
| (1) | Proved reserves are reported consolidated with Martica Holdings, LLC. Martica Holdings, LLC had 254 Bcfe and 167 Bcfe of proved reserves as of year end 2020 and 2021, respectively. |
| (2) | Sales of reserves were related to the drilling partnership entered into in 2021 which assumes their participation at a 20% working interest in wells spud in 2021 and 15% working interest in expected wells spud in 2022 through 2024. |
Commodity Derivative Positions
Antero did not enter into any new natural gas, NGL or oil hedges during the fourth quarter of 2021. As of December 31, 2021, the Company has hedged 438 Bcf of natural gas at a weighted average index price of $2.49 per MMBtu through 2023 with fixed price swap positions.
Please see Antero’s Annual Report on Form 10-K for the year ended December 31, 2021, for more information on all commodity derivative positions. For detail on current commodity positions, please see the Hedge Profile presentations at www.anteroresources.com.
Conference Call
A conference call is scheduled on Thursday, February 17, 2022 at 9:00 am MT to discuss the financial and operational results. A brief Q&A session for security analysts will immediately follow the discussion of the results. To participate in the call, dial in at 877-407-9079 (U.S.), or 201-493-6746 (International) and reference “Antero Resources.” A telephone replay of the call will be available until Thursday, February 24, 2022 at 9:00 am MT at 877-660-6853 (U.S.) or 201-612-7415 (International) using the conference ID: 13726193. A simultaneous webcast of the call may be accessed over the internet at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Thursday, February 24, 2022 at 9:00 am MT.
Presentation
An updated presentation will be posted to the Company's website before the conference call. The presentation can be found at www.anteroresources.com on the homepage. Information on the Company's website does not constitute a portion of, and is not incorporated by reference into this press release.
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Non-GAAP Financial Measures
Adjusted Net Income (Loss)
Adjusted Net Income (Loss) as set forth in this release represents net income (loss), adjusted for certain items. Antero believes that Adjusted Net Income (Loss) is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Adjusted Net Income (Loss) is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for net income (loss) as an indicator of financial performance. The GAAP measure most directly comparable to Adjusted Net Income is net income. The following table reconcile net income (loss) to Adjusted Net Income (Loss) (in thousands):
| Three Months Ended December 31, | Year Ended December 31, | |||||||||||||||
| 2020 | 2021 | 2020 | 2021 | |||||||||||||
| Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation | $ | 69,830 | 901,385 | (1,267,897 | ) | (186,899 | ) | |||||||||
| Net income and comprehensive income attributable to noncontrolling interests | 25,483 | 56,636 | 7,486 | 32,790 | ||||||||||||
| Unrealized commodity derivative (gains) losses | (150,925 | ) | (1,025,870 | ) | 725,011 | 748,540 | ||||||||||
| Payments for (proceeds from) derivative monetizations | 9,066 | — | (9,007 | ) | 4,569 | |||||||||||
| Amortization of deferred revenue, VPP | (9,332 | ) | (11,403 | ) | (14,507 | ) | (45,236 | ) | ||||||||
| Loss (gain) on sale of assets | 348 | 595 | 348 | (2,232 | ) | |||||||||||
| Impairment of oil and gas properties | 67,808 | 20,905 | 223,770 | 90,523 | ||||||||||||
| Impairment of equity method investment | — | — | 610,632 | — | ||||||||||||
| Equity-based compensation | 6,316 | 5,248 | 23,317 | 20,437 | ||||||||||||
| Loss (gain) on early extinguishment of debt | (597 | ) | 10,355 | (175,962 | ) | 93,191 | ||||||||||
| Loss on convertible note equitization | — | — | — | 50,777 | ||||||||||||
| Equity in (earnings) loss of unconsolidated affiliate | (20,748 | ) | (19,464 | ) | 62,660 | (77,085 | ) | |||||||||
| Contract termination and rig stacking | 1,973 | — | 14,290 | 4,305 | ||||||||||||
| Tax effect of reconciling items (1) | 23,123 | 244,471 | (351,465 | ) | (212,859 | ) | ||||||||||
| 22,345 | 182,858 | (151,324 | ) | 520,821 | ||||||||||||
| Martica adjustments (2) | (25,632 | ) | (25,509 | ) | (21,841 | ) | (76,719 | ) | ||||||||
| Adjusted Net Income (Loss) | $ | (3,287 | ) | 157,349 | (173,165 | ) | 444,102 | |||||||||
| Fully Diluted Shares Outstanding (3) | 304,172 | 340,106 | 272,433 | 308,146 | ||||||||||||
| (1) | Deferred taxes were 24% for 2020 and 2021. |
| (2) | Adjustments reflect noncontrolling interest in Martica not otherwise adjusted in amounts above. |
| (3) | Share count for year ended December 31, 2020 and 2021 does not include dilutive effect of restricted stock units, performance share units and 2026 convertible notes due to net income loss during the period |
Net Debt
Net Debt is calculated as total debt less cash and cash equivalents. Management uses Net Debt to evaluate the Company’s financial position, including its ability to service its debt obligations. The GAAP measure most directly comparable to Adjusted Net Income is net income.
The following table reconciles consolidated total debt to Net Debt as used in this release (in thousands):
| December 31, | ||||||||
| 2020 | 2021 | |||||||
| Credit Facility | $ | 1,017,000 | — | |||||
| 5.125% senior notes due 2022 | 660,516 | — | ||||||
| 5.625% senior notes due 2023 | 574,182 | — | ||||||
| 5.000% senior notes due 2025 | 590,000 | 584,635 | ||||||
| 8.375% senior notes due 2026 | — | 325,000 | ||||||
| 7.625% senior notes due 2029 | — | 584,000 | ||||||
| 5.375% senior notes due 2030 | — | 600,000 | ||||||
| 4.250% convertible senior notes due 2026 | 287,500 | 81,570 | ||||||
| Unamortized discount, net | (111,886 | ) | (27,772 | ) | ||||
| Unamortized debt issuance costs | (15,719 | ) | (21,989 | ) | ||||
| Total debt | $ | 3,001,593 | 2,125,444 | |||||
| Less: Cash and cash equivalents | — | — | ||||||
| Net Debt | $ | 3,001,593 | 2,125,444 | |||||
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Free Cash Flow
Free Cash Flow is a measure of financial performance not calculated under GAAP and should not be considered in isolation or as a substitute for cash flow from operating, investing, or financing activities, as an indicator of cash flow or as a measure of liquidity. The Company defines Free Cash Flow as net cash provided by operating activities, less net cash used in investing activities, which includes drilling and completion capital and leasehold capital, less proceeds from asset sales and less distributions to non-controlling interests in Martica.
The Company has not provided projected net cash provided by operating activities or a reconciliation of Free Cash Flow to projected net cash provided by operating activities, the most comparable financial measure calculated in accordance with GAAP. The Company is unable to project net cash provided by operating activities for any future period because this metric includes the impact of changes in operating assets and liabilities related to the timing of cash receipts and disbursements that may not relate to the period in which the operating activities occurred. The Company is unable to project these timing differences with any reasonable degree of accuracy without unreasonable efforts.
Free Cash Flow is a useful indicator of the Company’s ability to internally fund its activities and to service or incur additional debt. There are significant limitations to using Free Cash Flow as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the Company’s net income, the lack of comparability of results of operations of different companies and the different methods of calculating Free Cash Flow reported by different companies. Free Cash Flow does not represent funds available for discretionary use because those funds may be required for debt service, land acquisitions and lease renewals, other capital expenditures, working capital, income taxes, exploration expenses, and other commitments and obligations.
Adjusted EBITDAX
Adjusted EBITDAX is a non-GAAP financial measure that we define as net income (loss), adjusted for certain items detailed below.
Adjusted EBITDAX as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. Adjusted EBITDAX should not be considered in isolation or as a substitute for operating income or loss, net income or loss, cash flows provided by operating, investing, and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. Adjusted EBITDAX provides no information regarding our capital structure, borrowings, interest costs, capital expenditures, working capital movement, or tax position. Adjusted EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, exploration expenses, and other commitments and obligations. However, our management team believes Adjusted EBITDAX is useful to an investor in evaluating our financial performance because this measure:
| · | is widely used by investors in the oil and natural gas industry to measure operating performance without regard to items excluded from the calculation of such term, which may vary substantially from company to company depending upon accounting methods and the book value of assets, capital structure and the method by which assets were acquired, among other factors; |
| · | helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital and legal structure from our operating structure; |
| · | is used by our management team for various purposes, including as a measure of our operating performance, in presentations to our Board of Directors, and as a basis for strategic planning and forecasting: and |
| · | is used by our Board of Directors as a performance measure in determining executive compensation. |
There are significant limitations to using Adjusted EBITDAX as a measure of performance, including the inability to analyze the effects of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations of different companies, and the different methods of calculating Adjusted EBITDAX reported by different companies.
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The GAAP measures most directly comparable to Adjusted EBITDAX are net income (loss) and net cash provided by operating activities. The following table represents a reconciliation of Antero’s net income (loss), including noncontrolling interest, to Adjusted EBITDAX and a reconciliation of Antero’s Adjusted EBITDAX to net cash provided by operating activities per our consolidated statements of cash flows, in each case, for the three months and years ended December 31, 2020 and 2021. Adjusted EBITDAX also excludes the noncontrolling interests in Martica and these adjustments are disclosed in the table below as Martica related adjustments.
| Three Months Ended | Year Ended | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| (in thousands) | 2020 | 2021 | 2020 | 2021 | ||||||||||||
| Reconciliation of net income (loss) to Adjusted EBITDAX: | ||||||||||||||||
| Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation | $ | 69,830 | 901,385 | (1,267,897 | ) | (186,899 | ) | |||||||||
| Net income and comprehensive income attributable to noncontrolling interests | 25,483 | 56,636 | 7,486 | 32,790 | ||||||||||||
| Unrealized commodity derivative (gains) losses | (150,925 | ) | (1,025,870 | ) | 725,011 | 748,540 | ||||||||||
| Payments for (proceeds from) derivative monetizations | 9,066 | — | (9,007 | ) | 4,569 | |||||||||||
| Amortization of deferred revenue, VPP | (9,332 | ) | (11,403 | ) | (14,507 | ) | (45,236 | ) | ||||||||
| Loss (gain) on sale of assets | 348 | 595 | 348 | (2,232 | ) | |||||||||||
| Interest expense, net | 46,916 | 43,748 | 199,872 | 181,868 | ||||||||||||
| Loss (gain) on early extinguishment of debt | (597 | ) | 10,355 | (175,962 | ) | 93,191 | ||||||||||
| Loss on convertible note equitizations | — | — | — | 50,777 | ||||||||||||
| Income tax expense (benefit) | 23,685 | 263,491 | (397,482 | ) | (74,077 | ) | ||||||||||
| Depletion, depreciation, amortization, and accretion | 209,831 | 178,716 | 865,291 | 745,829 | ||||||||||||
| Impairment of oil and gas properties | 67,808 | 20,905 | 223,770 | 90,523 | ||||||||||||
| Impairment of equity method investment | — | — | 610,632 | — | ||||||||||||
| Exploration expense | 188 | 474 | 1,083 | 6,566 | ||||||||||||
| Equity-based compensation expense | 6,316 | 5,248 | 23,317 | 20,437 | ||||||||||||
| Equity in (earnings) loss of unconsolidated affiliate | (20,748 | ) | (19,464 | ) | 62,660 | (77,085 | ) | |||||||||
| Dividends from unconsolidated affiliate | 42,755 | 31,284 | 171,022 | 136,609 | ||||||||||||
| Contract termination and rig stacking | 1,973 | — | 14,290 | 4,305 | ||||||||||||
| Transaction expense | 582 | 193 | 7,244 | 3,295 | ||||||||||||
| 323,179 | 456,293 | 1,047,171 | 1,733,770 | |||||||||||||
| Martica related adjustments (1) | (23,983 | ) | (36,032 | ) | (45,155 | ) | (116,468 | ) | ||||||||
| Adjusted EBITDAX | $ | 299,196 | 420,261 | 1,002,016 | 1,617,302 | |||||||||||
| Reconciliation of our Adjusted EBITDAX to net cash provided by operating activities: | ||||||||||||||||
| Adjusted EBITDAX | $ | 299,196 | 420,261 | 1,002,016 | 1,617,302 | |||||||||||
| Martica related adjustments (1) | 23,983 | 36,032 | 45,155 | 116,468 | ||||||||||||
| Interest expense, net | (46,916 | ) | (43,748 | ) | (199,872 | ) | (181,868 | ) | ||||||||
| Exploration expense | (188 | ) | (474 | ) | (1,083 | ) | (6,566 | ) | ||||||||
| Changes in current assets and liabilities | (30,156 | ) | 61,132 | (109,047 | ) | 114,673 | ||||||||||
| Transaction expense | (582 | ) | (193 | ) | (7,244 | ) | (3,295 | ) | ||||||||
| Proceeds from (payments for) derivative monetizations | (9,066 | ) | — | 9,007 | (4,569 | ) | ||||||||||
| Other items | 6,859 | 2,154 | (3,292 | ) | 7,971 | |||||||||||
| Net cash provided by operating activities | $ | 243,130 | 475,164 | 735,640 | 1,660,116 | |||||||||||
| (1) | Adjustments reflect noncontrolling interests in Martica not otherwise adjusted in amounts above. |
Drilling and Completion Capital Expenditures
For a reconciliation between cash paid for drilling and completion capital expenditures and drilling and completion accrued capital expenditures during the period, please see the capital expenditures section below (in thousands):
| Three Months Ended December 31, | ||||||||
| 2020 | 2021 | |||||||
| Drilling and completion costs (cash basis) | $ | 132,345 | 153,276 | |||||
| Change in accrued capital costs | (47,931 | ) | (1,639 | ) | ||||
| Adjusted drilling and completion costs (accrual basis) | $ | 84,414 | 151,637 | |||||
| 9 |
Notwithstanding their use for comparative purposes, the Company’s non-GAAP financial measures may not be comparable to similarly titled measures employed by other companies.
Antero Resources is an independent natural gas and natural gas liquids company engaged in the acquisition, development and production of unconventional properties located in the Appalachian Basin in West Virginia and Ohio. In conjunction with its affiliate, Antero Midstream (NYSE: AM), Antero is one of the most integrated natural gas producers in the U.S. The Company’s website is located at www.anteroresources.com.
This release includes "forward-looking statements." Such forward-looking statements are subject to a number of risks and uncertainties, many of which are not under Antero Resources’ control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero Resources expects, believes or anticipates will or may occur in the future, such as those regarding our return of capital, expected results, future commodity prices, future production targets, realizing potential future fee rebates or reductions, including those related to certain levels of production, future earnings, leverage targets and debt repayment, future capital spending plans, improved and/or increasing capital efficiency, estimated realized natural gas, NGL and oil prices, expected drilling and development plans, projected well costs and cost savings initiatives, future financial position, the participation level of our drilling partner and the financial and production results to be achieved as a result of that drilling partnership, the other key assumptions underlying our projections, and future marketing opportunities, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero Resources believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Except as required by law, Antero Resources expressly disclaims any obligation to and does not intend to publicly update or revise any forward-looking statements.
In addition, many of the standards and metrics used in preparing this release and the ESG Report continue to evolve and are based on management expectations and assumptions believed to be reasonable at the time of preparation but should not be considered guarantees. The standards and metrics used, and the expectations and assumptions they are based on, have not been verified by any third party. In addition, while we seek to align these disclosures with the recommendations of various third-party frameworks, such as the Task Force on Climate-Related Financial Disclosures, we cannot guarantee strict adherence to these framework recommendations. Additionally, our disclosures based on these frameworks may change due to revisions in framework requirements, availability of information, changes in our business or applicable governmental policy, or other factors, some of which may be beyond our control. The calculation of methane leak loss rate disclosed in the ESG Report is based on ONE Future protocol, which is based on the EPA Greenhouse Gas Reporting Program. With respect to its emissions goal, Antero Resources anticipates achieving Net Zero Scope 1 and Scope 2 emissions by 2025 through operational efficiencies and the purchase of carbon offsets. Scope 1 emissions are the Company’s direct greenhouse gas emissions, and Scope 2 emissions are the Company’s indirect greenhouse gas emissions associated with the purchase of electricity, steam, heat or cooling; however, such goals are aspirational and we could face unexpected material costs as a result of our efforts to meet these goals. Moreover, given uncertainties related to the use of emerging technologies, the state of markets for and availability of verified quality carbon offsets, we cannot predict whether or not we will be able to timely meet these goals, if at all. Moreover, with regards to our participation in, or certification under, various frameworks, we may incur certain costs associated with such frameworks and cannot guarantee that such participation or certification will have the intended results on our or our products’ ESG profile.
This release and the ESG Report contain statements based on hypothetical or severely adverse scenarios and assumptions, and these statements should not necessarily be viewed as being representative of current or actual risk or forecasts of expected risk. These scenarios cannot account for the entire realm of possible risks and have been selected based on what we believe to be a reasonable range of possible circumstances based on information currently available to us and the reasonableness of assumptions inherent in certain scenarios; however, our selection of scenarios may change over time as circumstances change. While future events discussed in this release or the report may be significant, any significance should not be read as necessarily rising to the level of materiality of certain disclosures included in Antero Resources' SEC filings. The goals discussed in this earnings release are aspirational; we could face unexpected material costs as a result of our efforts to meet these goals and may ultimately meet such goals through the purchase of offsets or credits and not reductions in our actual GHG emissions. Moreover, given uncertainties related to the use of emerging technologies, the state of markets for and the availability of verified quality carbon offsets, we cannot predict whether or not we will be able to timely meet these goals, if at all. Moreover, with regards to our participation in, or certification under, various frameworks, we may incur certain costs associated with such frameworks and cannot guarantee that such participation or certification will have the intended results on our or our products’ ESG profile.
Antero Resources cautions you that these forward-looking statements are subject to all of the risks and uncertainties, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil most of which are difficult to predict and many of which are beyond the Antero Resources’ control. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, impacts of world health event, including the COVID-19 pandemic, cybersecurity risks and the other risks described under the heading "Item 1A. Risk Factors" in Antero Resources’ Annual Report on Form 10-K for the year ended December 31, 2021.
For more information, contact Michael Kennedy, Chief Financial Officer of Antero Resources at (303) 357-6782 or mkennedy@anteroresources.com.
10
ANTERO RESOURCES CORPORATION
Condensed Consolidated Balance Sheets
(In thousands)
| December 31, | ||||||||
| 2020 | 2021 | |||||||
| Assets | ||||||||
| Current assets: | ||||||||
| Accounts receivable | $ | 28,457 | 78,998 | |||||
| Accrued revenue | 425,314 | 591,442 | ||||||
| Derivative instruments | 105,130 | 757 | ||||||
| Other current assets | 15,238 | 14,922 | ||||||
| Total current assets | 574,139 | 686,119 | ||||||
| Property and equipment: | ||||||||
| Oil and gas properties, at cost (successful efforts method): | ||||||||
| Unproved properties | 1,175,178 | 1,042,118 | ||||||
| Proved properties | 12,260,713 | 12,646,303 | ||||||
| Gathering systems and facilities | 5,802 | 5,802 | ||||||
| Other property and equipment | 74,361 | 116,522 | ||||||
| 13,516,054 | 13,810,745 | |||||||
| Less accumulated depletion, depreciation, and amortization | (3,869,116 | ) | (4,283,700 | ) | ||||
| Property and equipment, net | 9,646,938 | 9,527,045 | ||||||
| Operating leases right-of-use assets | 2,613,603 | 3,419,912 | ||||||
| Derivative instruments | 47,293 | 14,369 | ||||||
| Investment in unconsolidated affiliate | 255,082 | 232,399 | ||||||
| Other assets | 13,790 | 16,684 | ||||||
| Total assets | $ | 13,150,845 | 13,896,528 | |||||
| Liabilities and Equity | ||||||||
| Current liabilities: | ||||||||
| Accounts payable | $ | 26,728 | 24,819 | |||||
| Accounts payable, related parties | 69,860 | 76,240 | ||||||
| Accrued liabilities | 343,524 | 457,244 | ||||||
| Revenue distributions payable | 198,117 | 444,873 | ||||||
| Derivative instruments | 31,242 | 559,851 | ||||||
| Short-term lease liabilities | 266,024 | 456,347 | ||||||
| Deferred revenue, VPP | 45,257 | 37,603 | ||||||
| Other current liabilities | 2,302 | 11,140 | ||||||
| Total current liabilities | 983,054 | 2,068,117 | ||||||
| Long-term liabilities: | ||||||||
| Long-term debt | 3,001,593 | 2,125,444 | ||||||
| Deferred income tax liability, net | 412,252 | 318,126 | ||||||
| Derivative instruments | 99,172 | 181,806 | ||||||
| Long-term lease liabilities | 2,348,785 | 2,964,115 | ||||||
| Deferred revenue, VPP | 156,024 | 118,366 | ||||||
| Other liabilities | 59,694 | 54,462 | ||||||
| Total liabilities | 7,060,574 | 7,830,436 | ||||||
| Commitments and contingencies (Notes 15 and 16) | ||||||||
| 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; 268,672 shares and 313,930 shares issued and outstanding as of December 31, 2020 and 2021, respectively | 2,686 | 3,139 | ||||||
| Additional paid-in capital | 6,195,497 | 6,371,398 | ||||||
| Accumulated deficit | (430,478 | ) | (617,377 | ) | ||||
| Total stockholders' equity | 5,767,705 | 5,757,160 | ||||||
| Noncontrolling interests | 322,566 | 308,932 | ||||||
| Total equity | 6,090,271 | 6,066,092 | ||||||
| Total liabilities and equity | $ | 13,150,845 | 13,896,528 | |||||
11
ANTERO RESOURCES CORPORATION
Condensed Consolidated Statements of Operations and Comprehensive Loss (Unaudited)
(In thousands, except per share amounts)
| Three Months Ended December 31, | Year Ended December 31, | |||||||||||||||
| 2020 | 2021 | 2020 | 2021 | |||||||||||||
| Revenue and other: | ||||||||||||||||
| Natural gas sales | $ | 595,151 | 1,210,470 | 1,809,952 | 3,442,028 | |||||||||||
| Natural gas liquids sales | 364,387 | 644,472 | 1,161,683 | 2,147,499 | ||||||||||||
| Oil sales | 34,037 | 47,906 | 112,270 | 201,232 | ||||||||||||
| Commodity derivative fair value gains (losses) | 196,851 | 323,553 | 79,918 | (1,936,509 | ) | |||||||||||
| Marketing | 108,717 | 155,993 | 310,572 | 718,921 | ||||||||||||
| Amortization of deferred revenue, VPP | 9,332 | 11,403 | 14,507 | 45,236 | ||||||||||||
| Other income | 617 | 474 | 2,797 | 1,025 | ||||||||||||
| Total revenue | 1,309,092 | 2,394,271 | 3,491,699 | 4,619,432 | ||||||||||||
| Operating expenses: | ||||||||||||||||
| Lease operating | 27,029 | 25,238 | 98,865 | 96,793 | ||||||||||||
| Gathering, compression, processing, and transportation | 653,754 | 624,510 | 2,530,838 | 2,499,174 | ||||||||||||
| Production and ad valorem taxes | 35,294 | 67,300 | 106,775 | 197,910 | ||||||||||||
| Marketing | 134,498 | 183,876 | 469,404 | 811,698 | ||||||||||||
| Exploration | 188 | 474 | 1,083 | 6,566 | ||||||||||||
| General and administrative (including equity-based compensation expense) | 33,218 | 36,313 | 134,482 | 145,006 | ||||||||||||
| Impairment of oil and gas properties | 67,808 | 20,905 | 223,770 | 90,523 | ||||||||||||
| Depletion, depreciation, and amortization | 209,740 | 177,843 | 861,870 | 742,009 | ||||||||||||
| Accretion of asset retirement obligations | 91 | 873 | 3,421 | 3,820 | ||||||||||||
| Contract termination and rig stacking | 1,973 | — | 14,290 | 4,305 | ||||||||||||
| Loss (gain) on sale of assets | 348 | 595 | 348 | (2,232 | ) | |||||||||||
| Total operating expenses | 1,163,941 | 1,137,927 | 4,445,146 | 4,595,572 | ||||||||||||
| Operating income (loss) | 145,151 | 1,256,344 | (953,447 | ) | 23,860 | |||||||||||
| Other income (expense): | ||||||||||||||||
| Interest expense, net | (46,916 | ) | (43,748 | ) | (199,872 | ) | (181,868 | ) | ||||||||
| Equity in earnings (loss) of unconsolidated affiliate | 20,748 | 19,464 | (62,660 | ) | 77,085 | |||||||||||
| Gain (loss) on early extinguishment of debt | 597 | (10,355 | ) | 175,962 | (93,191 | ) | ||||||||||
| Loss on convertible note equitizations | — | — | — | (50,777 | ) | |||||||||||
| Impairment of equity method investment | — | — | (610,632 | ) | — | |||||||||||
| Transaction expense | (582 | ) | (193 | ) | (7,244 | ) | (3,295 | ) | ||||||||
| Total other expense | (26,153 | ) | (34,832 | ) | (704,446 | ) | (252,046 | ) | ||||||||
| Income (loss) before income taxes | 118,998 | 1,221,512 | (1,657,893 | ) | (228,186 | ) | ||||||||||
| Income tax benefit (expense) | (23,685 | ) | (263,491 | ) | 397,482 | 74,077 | ||||||||||
| Net income (loss) and comprehensive income (loss) including noncontrolling interests | 95,313 | 958,021 | (1,260,411 | ) | (154,109 | ) | ||||||||||
| Less: net income and comprehensive income attributable to noncontrolling interests | 25,483 | 56,636 | 7,486 | 32,790 | ||||||||||||
| Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation | $ | 69,830 | 901,385 | (1,267,897 | ) | (186,899 | ) | |||||||||
| Income (loss) per share—basic | $ | 0.26 | 2.87 | (4.65 | ) | (0.61 | ) | |||||||||
| Income (loss) per share—diluted | $ | 0.24 | 2.65 | (4.65 | ) | (0.61 | ) | |||||||||
| Weighted average number of shares outstanding: | ||||||||||||||||
| Basic | 268,653 | 313,917 | 272,433 | 308,146 | ||||||||||||
| Diluted | 304,172 | 340,106 | 272,433 | 308,146 | ||||||||||||
12
ANTERO RESOURCES CORPORATION
Condensed Consolidated Statements of Cash Flows
(In thousands)
| Year Ended December 31, | ||||||||||||
| 2019 | 2020 | 2021 | ||||||||||
| Cash flows provided by (used in) operating activities: | ||||||||||||
| Net loss including noncontrolling interests | $ | (293,136 | ) | (1,260,411 | ) | (154,109 | ) | |||||
| Adjustments to reconcile net loss to net cash provided by operating activities: | ||||||||||||
| Depletion, depreciation, amortization, and accretion | 918,629 | 865,291 | 745,829 | |||||||||
| Impairments | 1,782,816 | 834,402 | 90,523 | |||||||||
| Commodity derivative fair value losses (gains) | (463,972 | ) | (79,918 | ) | 1,936,509 | |||||||
| Gains (losses) on settled commodity derivatives | 325,090 | 794,684 | (1,183,400 | ) | ||||||||
| Proceeds from (payments for) derivative monetizations | — | 9,007 | (4,569 | ) | ||||||||
| Deferred income tax benefit | (79,158 | ) | (397,273 | ) | (74,293 | ) | ||||||
| Equity-based compensation expense | 23,559 | 23,317 | 20,437 | |||||||||
| Equity in (earnings) loss of unconsolidated affiliate | 143,216 | 62,660 | (77,085 | ) | ||||||||
| Distributions/dividends of earnings from unconsolidated affiliate | 157,956 | 171,022 | 136,609 | |||||||||
| Amortization of deferred revenue | — | (14,507 | ) | (45,236 | ) | |||||||
| Amortization of debt issuance costs, debt discount, debt premium and other | 10,681 | 12,027 | 12,492 | |||||||||
| (Gain) loss on sale of assets | 951 | 348 | (2,232 | ) | ||||||||
| Loss on the sale of equity method investment shares | 108,745 | — | — | |||||||||
| Water earnout | (125,000 | ) | — | — | ||||||||
| Gain on deconsolidation of Antero Midstream Partners LP | (1,406,042 | ) | — | — | ||||||||
| (Gain) loss on early extinguishment of debt | (36,419 | ) | (175,962 | ) | 93,191 | |||||||
| Loss on convertible note equitizations | — | — | 50,777 | |||||||||
| Changes in current assets and liabilities: | ||||||||||||
| Accounts receivable | 31,631 | (9,492 | ) | (55,567 | ) | |||||||
| Accrued revenue | 156,941 | (107,428 | ) | (166,128 | ) | |||||||
| Other current assets | (1,025 | ) | (5,507 | ) | 316 | |||||||
| Accounts payable including related parties | (27,996 | ) | (19,282 | ) | (1,184 | ) | ||||||
| Accrued liabilities | (25,762 | ) | 37,954 | 77,584 | ||||||||
| Revenue distributions payable | (102,839 | ) | (5,203 | ) | 246,757 | |||||||
| Other current liabilities | 4,592 | (89 | ) | 12,895 | ||||||||
| Net cash provided by operating activities | 1,103,458 | 735,640 | 1,660,116 | |||||||||
| Cash flows provided by (used in) investing activities: | ||||||||||||
| Additions to unproved properties | (88,682 | ) | (45,129 | ) | (79,138 | ) | ||||||
| Drilling and completion costs | (1,254,118 | ) | (826,265 | ) | (601,175 | ) | ||||||
| Additions to water handling and treatment systems | (24,416 | ) | — | — | ||||||||
| Additions to gathering systems and facilities | (48,239 | ) | — | — | ||||||||
| Additions to other property and equipment | (6,700 | ) | (2,963 | ) | (35,623 | ) | ||||||
| Settlement of water earnout | — | 125,000 | — | |||||||||
| Investments in unconsolidated affiliates | (25,020 | ) | — | — | ||||||||
| Proceeds from sale of common stock of Antero Midstream Corporation | 100,000 | — | — | |||||||||
| Proceeds from the Antero Midstream Partners LP Transactions | 296,611 | — | — | |||||||||
| Proceeds from asset sales | 1,983 | 701 | 3,192 | |||||||||
| Proceeds from VPP sale, net | — | 215,789 | — | |||||||||
| Change in other liabilities | — | — | (672 | ) | ||||||||
| Change in other assets | 7,091 | 2,806 | 2,632 | |||||||||
| Net cash used in investing activities | (1,041,490 | ) | (530,061 | ) | (710,784 | ) | ||||||
| Cash flows provided by (used in) financing activities: | ||||||||||||
| Repurchases of common stock | (38,772 | ) | (43,443 | ) | — | |||||||
| Issuance of senior notes | 650,000 | — | 1,800,000 | |||||||||
| Issuance of convertible notes | — | 287,500 | — | |||||||||
| Repayment of senior notes | (191,092 | ) | (1,219,019 | ) | (1,554,657 | ) | ||||||
| Borrowings (repayments) on bank credit facilities, net | 232,000 | 465,000 | (1,017,000 | ) | ||||||||
| Payment of debt issuance costs | (4,547 | ) | (8,984 | ) | (31,474 | ) | ||||||
| Sale of noncontrolling interest | — | 351,000 | 51,000 | |||||||||
| Distributions to noncontrolling interests | (85,076 | ) | (35,920 | ) | (97,424 | ) | ||||||
| Employee tax withholding for settlement of equity compensation awards | (2,389 | ) | (422 | ) | (13,270 | ) | ||||||
| Convertible note equitizations | — | — | (85,648 | ) | ||||||||
| Other | (2,560 | ) | (1,291 | ) | (859 | ) | ||||||
| Net cash provided by (used in) financing activities | 557,564 | (205,579 | ) | (949,332 | ) | |||||||
| Effect of deconsolidation of Antero Midstream Partners LP | (619,532 | ) | — | — | ||||||||
| Net increase in cash and cash equivalents | — | — | — | |||||||||
| Cash and cash equivalents, beginning of period | — | — | — | |||||||||
| Cash and cash equivalents, end of period | $ | — | — | — | ||||||||
| Supplemental disclosure of cash flow information: | ||||||||||||
| Cash paid during the period for interest | $ | 224,331 | 192,302 | 141,930 | ||||||||
| Increase (decrease) in accounts payable and accrued liabilities for additions to property and equipment | (15,897 | ) | (94,619 | ) | 37,049 | |||||||
13
The following table set forth unaudited selected financial data for the three months ended December 31, 2020 and 2021:
| Three Months Ended | Amount of | |||||||||||||||
| December 31, | Increase | Percent | ||||||||||||||
| 2020 | 2021 | (Decrease) | Change | |||||||||||||
| Revenue: | ||||||||||||||||
| Natural gas sales | $ | 595,151 | 1,210,470 | 615,319 | 103 | % | ||||||||||
| Natural gas liquids sales | 364,387 | 644,472 | 280,085 | 77 | % | |||||||||||
| Oil sales | 34,037 | 47,906 | 13,869 | 41 | % | |||||||||||
| Commodity derivative fair value gains | 196,851 | 323,553 | 126,702 | 64 | % | |||||||||||
| Marketing | 108,717 | 155,993 | 47,276 | 43 | % | |||||||||||
| Amortization of deferred revenue, VPP | 9,332 | 11,403 | 2,071 | 22 | % | |||||||||||
| Other income | 617 | 474 | (143 | ) | (23 | )% | ||||||||||
| Total revenue | 1,309,092 | 2,394,271 | 1,085,179 | 83 | % | |||||||||||
| Operating expenses: | ||||||||||||||||
| Lease operating | 27,029 | 25,238 | (1,791 | ) | (7 | )% | ||||||||||
| Gathering and compression | 217,973 | 210,847 | (7,126 | ) | (3 | )% | ||||||||||
| Processing | 211,322 | 190,938 | (20,384 | ) | (10 | )% | ||||||||||
| Transportation | 224,459 | 222,725 | (1,734 | ) | (1 | )% | ||||||||||
| Production and ad valorem taxes | 35,294 | 67,300 | 32,006 | 91 | % | |||||||||||
| Marketing | 134,498 | 183,876 | 49,378 | 37 | % | |||||||||||
| Exploration | 188 | 474 | 286 | 152 | % | |||||||||||
| General and administrative (excluding equity-based compensation) | 26,902 | 31,065 | 4,163 | 15 | % | |||||||||||
| Equity-based compensation | 6,316 | 5,248 | (1,068 | ) | (17 | )% | ||||||||||
| Depletion, depreciation, and amortization | 209,740 | 177,843 | (31,897 | ) | (15 | )% | ||||||||||
| Impairment of oil and gas properties | 67,808 | 20,905 | (46,903 | ) | (69 | )% | ||||||||||
| Accretion of asset retirement obligations | 91 | 873 | 782 | * | ||||||||||||
| Contract termination and rig stacking | 1,973 | — | (1,973 | ) | * | |||||||||||
| Loss on sale of assets | 348 | 595 | 247 | 71 | % | |||||||||||
| Total operating expenses | 1,163,941 | 1,137,927 | (26,014 | ) | (2 | )% | ||||||||||
| Operating income | 145,151 | 1,256,344 | 1,111,193 | * | ||||||||||||
| Other earnings (expenses): | ||||||||||||||||
| Interest expense, net | (46,916 | ) | (43,748 | ) | 3,168 | (7 | )% | |||||||||
| Equity in earnings of unconsolidated affiliate | 20,748 | 19,464 | (1,284 | ) | (6 | )% | ||||||||||
| Gain (loss) on early extinguishment of debt | 597 | (10,355 | ) | (10,952 | ) | * | ||||||||||
| Transaction expenses | (582 | ) | (193 | ) | 389 | (67 | )% | |||||||||
| Total other expense | (26,153 | ) | (34,832 | ) | (8,679 | ) | 33 | % | ||||||||
| Income before income taxes | 118,998 | 1,221,512 | 1,102,514 | * | ||||||||||||
| Income tax expense | (23,685 | ) | (263,491 | ) | (239,806 | ) | * | |||||||||
| Net income and comprehensive income including noncontrolling interests | 95,313 | 958,021 | 862,708 | * | ||||||||||||
| Less: net income and comprehensive income attributable to noncontrolling interests | 25,483 | 56,636 | 31,153 | 122 | % | |||||||||||
| Net income and comprehensive income attributable to Antero Resources Corporation | $ | 69,830 | 901,385 | 831,555 | * | |||||||||||
| Adjusted EBITDAX | $ | 299,196 | 420,261 | 121,065 | 40 | % | ||||||||||
* Not meaningful
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The following table set forth selected operating data for the three months ended December 31, 2020 and 2021:
| Three Months Ended | Amount of | |||||||||||||||
| December 31, | Increase | Percent | ||||||||||||||
| 2020 | 2021 | (Decrease) | Change | |||||||||||||
| Production data (1): | ||||||||||||||||
| Natural gas (Bcf) | 226 | 205 | (21 | ) | (9 | )% | ||||||||||
| C2 Ethane (MBbl) | 5,023 | 4,130 | (893 | ) | (18 | )% | ||||||||||
| C3+ NGLs (MBbl) | 12,174 | 9,872 | (2,302 | ) | (19 | )% | ||||||||||
| Oil (MBbl) | 1,104 | 689 | (415 | ) | (38 | )% | ||||||||||
| Combined (Bcfe) | 336 | 294 | (42 | ) | (13 | )% | ||||||||||
| Daily combined production (MMcfe/d) | 3,650 | 3,191 | (459 | ) | (13 | )% | ||||||||||
| Average prices before effects of derivative settlements (2): | ||||||||||||||||
| Natural gas (per Mcf) | $ | 2.63 | 5.89 | 3.26 | 124 | % | ||||||||||
| C2 Ethane (per Bbl) | $ | 5.56 | 16.81 | 11.25 | 202 | % | ||||||||||
| C3+ NGLs (per Bbl) | $ | 27.64 | 58.25 | 30.61 | 111 | % | ||||||||||
| Oil (per Bbl) | $ | 30.83 | 69.53 | 38.70 | 126 | % | ||||||||||
| Weighted Average Combined (per Mcfe) | $ | 2.96 | 6.48 | 3.52 | 119 | % | ||||||||||
| Average realized prices after effects of derivative settlements (2): | ||||||||||||||||
| Natural gas (per Mcf) | $ | 2.76 | 2.79 | 0.03 | 1 | % | ||||||||||
| C2 Ethane (per Bbl) | $ | 5.44 | 16.81 | 11.37 | 209 | % | ||||||||||
| C3+ NGLs (per Bbl) | $ | 28.84 | 52.41 | 23.57 | 82 | % | ||||||||||
| Oil (per Bbl) | $ | 41.63 | 60.17 | 18.54 | 45 | % | ||||||||||
| Weighted Average Combined (per Mcfe) | $ | 3.12 | 4.15 | 1.03 | 33 | % | ||||||||||
| Average costs (per Mcfe): | ||||||||||||||||
| Lease operating | $ | 0.08 | 0.09 | 0.01 | 13 | % | ||||||||||
| Gathering and compression | $ | 0.65 | 0.72 | 0.07 | 11 | % | ||||||||||
| Processing | $ | 0.63 | 0.65 | 0.02 | 3 | % | ||||||||||
| Transportation | $ | 0.67 | 0.76 | 0.09 | 13 | % | ||||||||||
| Production taxes | $ | 0.11 | 0.23 | 0.12 | 109 | % | ||||||||||
| Marketing, net | $ | 0.08 | 0.09 | 0.01 | 13 | % | ||||||||||
| Depletion, depreciation, amortization and accretion | $ | 0.62 | 0.61 | (0.01 | ) | (2 | )% | |||||||||
| General and administrative (excluding equity-based compensation) | $ | 0.08 | 0.11 | 0.03 | 38 | % | ||||||||||
| (1) | Production volumes exclude volumes related to VPP transaction. |
| (2) | Average sales prices shown in the table reflect both the before and after effects of the Company’s settled commodity derivatives. The calculation of such after effects includes gains on settlements of commodity derivatives, which do not qualify for hedge accounting because the Company does not designate or document them as hedges for accounting purposes. Oil and NGLs production was converted at 6 Mcf per Bbl to calculate total Bcfe production and per Mcfe amounts. This ratio is an estimate of the equivalent energy content of the products and does not necessarily reflect their relative economic value. |
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