Exhibit 99.1
Antero Resources Reports Fourth Quarter Results, Announces 2021 Guidance, Proved Reserves and Drilling Partnership
Denver, Colorado, February 17, 2020— Antero Resources Corporation (NYSE: AR) (“Antero Resources”, “Antero”, or the “Company”) today announced its fourth quarter and full year 2020 financial and operational results as well as its 2021 capital budget, guidance and proved reserves as of December 31, 2020. In addition, Antero announced the formation of a drilling partnership. The relevant consolidated financial statements are included in Antero Resource’s Annual Report on Form 10-K for the year ended December 31, 2020.
Fourth Quarter 2020 Highlights Include:
| · | Net production averaged 3,650 MMcfe/d, including 199,000 Bbl/d of liquids |
| · | Realized natural gas equivalent price including hedges averaged $3.12 per Mcfe, a $0.46 premium to NYMEX pricing |
| · | Net income was $70 million |
| · | Adjusted EBITDAX was $299 million (Non-GAAP); net cash provided by operating activities was $243 million |
| · | Drilling and completion capital expenditures were $84 million, a 69% reduction from the year ago period |
| · | Free Cash Flow before changes in working capital was $155 million (Non-GAAP) |
| · | Achieved record 60-day rate per well of 33.9 MMcfe/d for 10 wells placed on-line during the quarter |
| · | Proved reserves were 17.6 Tcfe at year end 2020 and proved developed reserves increased to 11.9 Tcfe (67% Proved Developed) |
| · | Future development cost for 5.8 Tcfe of proved undeveloped reserves is $0.27 per Mcfe |
2021 Guidance and Other Highlights:
| · | Announced formation of a $500 to $550 million drilling partnership to fund drilling of 60 incremental wells from 2021 through 2024, enabling Antero to fill unutilized firm transportation capacity, receive additional low pressure gathering fee rebates and realize a cash drilling carry. This partnership begins immediately and includes all wells spud since January 1, 2021. |
| · | Drilling and completion capital budget of $590 million net to Antero, down 21% from 2020 |
| · | Maintenance level capital program includes 60 to 65 well completions in 2021, average lateral length of 13,150 feet |
| · | Well cost average of $660 per lateral foot, declining to $635 per lateral foot for the second half of 2021 |
| · | Net production is expected to average 3.3 to 3.4 Bcfe/d, including 170,000 to 175,000 Bbl/d of liquids (NGLs and oil) |
| · | Natural gas realizations expected to be a $0.10 to $0.20 per MMBtu premium to NYMEX, before hedges |
| · | Received $85 million in net litigation proceeds in February 2021 for underpayment of a natural gas contract |
Paul Rady, Chairman and Chief Executive Officer of Antero Resources commented, “Antero’s unique position of having market leading exposure to attractive C3+ NGL prices, a premium firm transportation portfolio and extensive premium core drilling inventory creates a highly accretive development program in 2021. In addition, the drilling partnership announced today and the incremental gross production generated thereby is estimated to add incremental free cash flow to Antero of $400 million through 2025, assuming current strip prices. This significant incremental free cash flow results from filling of our premium firm transportation capacity, capturing additional LP gathering incentive fees from Antero Midstream and realizing carry payments from our drilling partner.”
Mr. Rady continued, “Our 2021 capital budget reflects our shift to a maintenance level capital plan and the benefit from our well cost savings initiatives that we launched in 2019. We are targeting total well costs of $635 per lateral foot for the second half of 2021, a 35% reduction from $970 in the initial 2019 budget. Our ability to reduce costs and lower capital spending, combined with the benefits of the drilling partnership, puts us in position to generate over $500 million of free cash flow in 2021 and exceed $1.5 billion of cumulative free cash flow through 2025, based on today’s commodity strip. We intend to use the free cash flow to reduce debt, which will rapidly decrease our leverage profile from 3.1x at year end 2020 to below 2-times in 2021, at current strip prices.”
Glen Warren, President, and Chief Financial Officer of Antero Resources said, “Through a combination of asset sales and discounted debt repurchases, we reduced absolute debt by over $800 million since the start of our deleveraging program. Assuming strip pricing, we are in position to achieve our leverage target of below 2-times this year. Longer term, we will remain focused on maintaining a low leverage profile, while maximizing free cash flow. Finally, as we approach our leverage targets, we can begin to consider further return of capital to our shareholders.”
For a discussion of the non-GAAP financial measures including Adjusted EBITDAX and Free Cash Flow please see “Non-GAAP Financial Measures.”
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Drilling Partnership Announcement
Antero announced the formation of a $500 to $550 million drilling partnership with QL Capital Partners (“QL”), an affiliate of Quantum Energy Partners. Antero is uniquely positioned to take on a drilling partner due to unutilized firm transportation, a deep liquids-rich drilling inventory and already established LP gathering incentive program with Antero Midstream. Under the terms of the agreement, QL will fund 20% of total development capital spending in 2021 and between 15% and 20% of total development capital spending on an annual basis from 2022 through 2024 in exchange for a proportionate working interest percentage in each well spud. Each calendar year represents a tranche including 2021 which begins with wells spud as of January 1, 2021. In addition, QL will pay a drilling carry to Antero on a tranche by tranche basis, at the end of the year following the tranche year, if certain return thresholds are achieved. Assuming QL’s full participation through 2024, the partnership will enable the drilling and completion of approximately 60 incremental wells relative to Antero’s prior base case of maintenance level capital plans. Antero’s 2021 net capital spending and net production remains unchanged at the maintenance capital level. Please see Antero’s Annual Report on Form 10-K for additional details on the drilling partnership. RBC Capital Markets and Vinson & Elkins LLP acted as exclusive financial and legal advisors, respectively, to the Company.
The following tables provide a guidance summary for 2021 and targets for 2022 through 2024 for the prior base case compared to the full commitment by QL under the drilling partnership. The Company’s board of directors has not approved any capital budget or development plan beyond 2021. The first incremental wells will be completed in the fourth quarter of 2021, and therefore will have limited impact on the 2021 development plan. Under these assumptions, from 2022 through 2024 there would be minimal impact to production, capital expenditures or wells drilled and completed on a net basis to Antero.
2021 Prior Base vs Drilling Partnership | Prior Base Case | Drilling Partnership (1) | Incremental | |||||||||||||||||
| Low | High | Low | High | Gross Wells | ||||||||||||||||
| Drilled Wells | 65 | 70 | 80 | 85 | 15 | |||||||||||||||
| Completed Wells | 60 | 65 | 65 | 70 | 5 | |||||||||||||||
2021 – 2024 Prior Base vs Drilling Partnership | Prior Base Case | Drilling Partnership (1) | Incremental Gross Wells | |||||||||
| Drilled Wells | 250 | 310 | 60 | |||||||||
| Completed Wells | 255 | 315 | 60 | |||||||||
| (1) | Represents gross wells pro forma for the drilling partnership |
| 2022 - 2025 Base Case vs Drilling Partnership | Prior Base | Drilling Partnership | Delta | Free Cash | ||||||||||||||||||||
| Low | High | Low | High | (Midpoint) | Flow Impact (3) | |||||||||||||||||||
| GP&T Expense ($/Mcfe) (1) | $ | 1.90 | $ | 2.05 | $ | 1.87 | $ | 2.04 | $ | (0.02 | ) | $ | 75 | |||||||||||
| Net Marketing Expense ($/Mcfe) | $ | 0.10 | $ | 0.12 | $ | 0.03 | $ | 0.05 | $ | (0.07 | ) | $ | 260 | |||||||||||
| Net Interest Expense ($/Mcfe) | $ | 0.05 | $ | 0.06 | $ | 0.04 | $ | 0.05 | $ | (0.01 | ) | $ | 20 | |||||||||||
| Estimated carry Payments ($MM) | $ | 50 | ||||||||||||||||||||||
| Free Cash Flow ($MM) (2) | $ | 405 | ||||||||||||||||||||||
| (1) | Represents $75 MM of incremental midstream fee rebates earned due to drilling partnership. |
| (2) | For a description of the non-GAAP financial measure Free Cash Flow, please read "Non-GAAP Financial Measures." |
| (3) | Assumes maintenance level net capital spending in 2022, 2023, 2024 and 2025. |
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The drilling partnership is forecast to increase Antero’s Free Cash Flow by approximately $400 million through 2025 compared to Antero’s prior base case plan by accelerating the decline in unutilized firm transportation expense, capturing midstream fee rebates, achieving carry payments from our drilling partner, as well as lower interest costs due to lower total debt. As a result, Antero expects to achieve its absolute debt target of below $2.0 billion in 2023, based on current strip pricing.
Resolution of Washington Gas Light Company Litigation
Antero received proceeds of $85 million, net of royalty payments, from Washington Gas Light Company (“WGL”) in February 2021. The payment is due to a favorable judgment on previously disclosed contractual disputes involving firm gas sales contracts between Antero and WGL during the years 2016 to 2018. The judgment was affirmed on December 10, 2020, and the judgment was satisfied in full with WGL’s payment. The net proceeds from the litigation judgement were realized as gas revenue in the first quarter of 2021 and are included in EBITDAX and Free Cash Flow. In addition, the proceeds were used to pay down Antero’s credit facility. For further information on this litigation, please see Antero's Annual Report on Form 10-K for the year ended December 31, 2020.
February Winter Weather Event
Antero has not been faced with curtailments to date due to the winter weather in February across the U.S. This has enabled Antero through its firm transportation portfolio to deliver certain equity and third party volumes that had not been contractually committed on a first of month basis, to locations that required additional gas volumes. This sales point flexibility enabled Antero to redirect equity volumes as well as purchase third party gas and market those volumes in the Midwest and on the Gulf Coast where gas was needed most and prices were elevated due to freeze offs throughout much of the central and southwestern U.S. Antero has realized incremental revenue of $75 million to date, net of royalties and taxes that will result in improved natural gas realizations and reduced net marketing expense during the first quarter of 2021.
2021 Capital Budget and Guidance
The following is a summary of Antero Resources’ 2021 capital budget.
| Capital Budget ($ in Millions) | ||||
| Drilling & Completion | $ | 590 | ||
| Land | $ | 45 | ||
| Total E&P Capital | $ | 635 | ||
Gross | Average | |||||||
| With Drilling Partnership | Wells | Lateral Length | ||||||
| Drilled Wells | 80 to 85 | 13,250 feet | ||||||
| Completed Wells | 65 to 70 | 13,150 feet |
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The following is a summary of Antero Resources’ 2021 production, pricing and cash expense guidance.
| Production Guidance | ||||
| Net Daily Natural Gas Equivalent Production (MMcfe/d) | 3,300 - 3,400(1) | |||
| Net Daily Natural Gas Production (MMcf/d) | 2,300 – 2,350 | |||
| Total Net Daily Liquids Production (Bbl/d): | 170,000 – 175,000 |
| Realized Pricing Guidance | ||||
| Natural Gas Realized Price vs. NYMEX Henry Hub ($/Mcf) | $0.10 – $0.20 | |||
| C3+ NGL Realized Price vs. Mont Belvieu ($/Gal) | $0.00 – $0.05 | |||
| Oil Realized Price vs. WTI Oil ($/Bbl) | ($9.00) – ($11.00) | |||
| Cash Expense Guidance | Low | High | ||||||
| Cash Production Expense ($/Mcfe)(2) | $ | 2.18 | $ | 2.23 | ||||
| Marketing Expense, Net of Marketing Revenue ($/Mcfe) | $ | 0.08 | $ | 0.10 | ||||
| G&A Expense ($/Mcfe)(3) | $ | 0.08 | $ | 0.10 | ||||
| (1) | Assumes C3+ NGL price strip as of February 15, 2021 of $35 per Bbl. At this price, all NGL volumes are economic to process and are allocated to the royalty owner. In 2020, C3+ NGL prices averaged $21.68 per Bbl and were uneconomic to process. This resulted in Antero being allocated all gross NGL volumes relative to royalty owners. The net impact in 2020 was an increase to production of 140 MMcfe/d and a $0.04 per Mcfe decrease in realizations. Based on gross wellhead volume, Antero’s 2021 production guidance approximates 2020 production volumes. | |
| (2) | Includes lease operating expenses and gathering, compression, processing and transportation expenses (“GP&T”) and production and ad valorem taxes. Assumes no LP gathering fee rebates are received during 2021. | |
| (3) | Excludes equity-based compensation. |
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Natural Gas and NGL Price Realizations
The Company expects to realize a $0.10 to $0.20 per MMBtu price premium compared to the NYMEX Henry Hub price for its natural gas sales during 2021, as Antero’s firm transportation portfolio delivers access to premium priced markets in the Midwest Gulf and Coast. The winter weather event in February is expected to result in first quarter 2020 realized natural gas prices at a $0.30 to $0.40 premium to NYMEX. Antero is forecasting an average realized price for C3+ NGLs in the range of a $0.00 to a $0.05 per gallon premium relative to Mont Belvieu pricing. Antero expects to sell at least 50% of its C3+ NGL production in 2021 at Marcus Hook, PA for export at a premium to Mont Belvieu pricing.
Cash Production Expense and Net Marketing Expense
Antero forecasts cash production expenses to be in the range of $2.18 to $2.23 per Mcfe. The slight increase in production expenses as compared to 2020 reflects the expectation that Antero Resources will not receive any low pressure gathering fee rebates from Antero Midstream in 2021 and reflects the expected incremental 5,000 Bbl/d of NGL volume commitments on Mariner East 2, beginning April 1, 2021.
Antero forecasts net marketing expense to be in the range of $0.08 to $0.10 per Mcfe. This guidance reflects the impact from the winter weather in February and the current narrow strip for local basis in 2021. However, if local basis widens, as it did in 2020, net marketing expense is expected to be near the low end of the guidance range as more long-haul transportation is utilized.
Well Cost Savings
Antero’s drilling and completion capital budget is based on an average well cost of $660 per lateral foot during 2021, normalized for a 12,000 foot lateral. Well costs are expected to average $675 per lateral foot during the first half of 2021, before declining to $635 per lateral foot in the second half of 2021 driven by various sand and completion initiatives.
Antero plans to complete 65 to 70 gross wells in 2021. The average lateral length on completed wells is expected to be 13,150 feet. Antero plans to drill 80 to 85 gross wells with an average lateral length of 13,250 feet. Drilled wells include 70 in the Marcellus and 10 to 15 in the Ohio Utica. The 2021 capital budget assumes an average of 3 drilling rigs and 2 completion crews on a gross basis for the drilling partnership.
Fourth Quarter 2020 Free Cash Flow
Antero generated $155 million in Free Cash Flow before changes in working capital during the fourth quarter. After adjusting for working capital investments, Free Cash Flow was $125 million.
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| Three Months Ended | ||||||||
| December 31, | ||||||||
| 2019 | 2020 | |||||||
| Net cash provided by operating activities | $ | 147,940 | 243,130 | |||||
| Less: Capital expenditures, including land (accrual basis) | (315,358 | ) | (99,212 | ) | ||||
| Less: Distributions to non-controlling interests in Martica | — | (18,671 | ) | |||||
| Free Cash Flow | $ | (167,418 | ) | 125,247 | ||||
| Changes in working capital | 91,780 | 30,156 | ||||||
| Free Cash Flow before Changes in Working Capital | $ | (75,638 | ) | 155,403 | ||||
Fourth Quarter 2020 Financial Results
For the three months ended December 31, 2020, Antero reported GAAP net income of $70 million, or $0.24 per diluted share, compared to a GAAP net loss of $482 million, or $1.61 per diluted share, in the prior year period. Adjusted Net Loss (non-GAAP measure) for the three months ended December 31, 2020 was $11 million, or $0.03 per diluted share, compared to Adjusted Net Loss of $6 million during the three months ended December 31, 2019, or $0.02 per diluted share.
Adjusted EBITDAX (non-GAAP measure) for the three months ended December 31, 2020 was $299 million, an increase of 1% versus the prior year period as lower operating costs and increased production offset a decrease in realized prices due to lower realized hedge gains. The $299 million of reported Adjusted EBITDAX includes a non-cash adjustment that increased fuel expense by $19 million or $0.07 per Mcfe during the fourth quarter.
The following table details the components of average net production and average realized prices for the three months ended December 31, 2020:
| Three Months Ended December 31, 2020 | ||||||||||||||||||||
| Combined | ||||||||||||||||||||
| Natural | ||||||||||||||||||||
| Natural Gas | Oil | C3+ NGLs | Ethane | Gas Equivalent | ||||||||||||||||
| (MMcf/d) | (Bbl/d) | (Bbl/d) | (Bbl/d) | (MMcfe/d) | ||||||||||||||||
| Average Net Production | 2,457 | 12,000 | 132,326 | 54,598 | 3,650 | |||||||||||||||
| Combined | ||||||||||||||||||||
| Natural | ||||||||||||||||||||
| Natural Gas | Oil | C3+ NGLs | Ethane | Gas Equivalent | ||||||||||||||||
| Average Realized Prices | ($/Mcf) | ($/Bbl) | ($/Bbl) | ($/Bbl) | ($/Mcfe) | |||||||||||||||
| Average realized prices before settled derivatives | $ | 2.63 | $ | 30.83 | $ | 27.64 | $ | 5.56 | $ | 2.96 | ||||||||||
| Settled commodity derivatives | 0.13 | 10.80 | 1.20 | (0.12 | ) | 0.16 | ||||||||||||||
| Average realized prices after settled derivatives | $ | 2.76 | $ | 41.63 | $ | 28.84 | $ | 5.44 | $ | 3.12 | ||||||||||
| NYMEX average price | $ | 2.66 | $ | 42.45 | $ | 2.66 | ||||||||||||||
| Premium / (Differential) to NYMEX | $ | 0.10 | $ | (0.82 | ) | $ | 0.46 | |||||||||||||
Net daily natural gas equivalent production in the fourth quarter averaged 3,650 MMcfe/d, including 198,924 Bbl/d of liquids (67% natural gas by volume). Net gas equivalent production increased 15% from the prior year period. Throughput on Antero Midstream’s low pressure gathering system exceeded the growth incentive fee threshold of 2,900 MMcf/d during the fourth quarter of 2020, resulting in a $12 million rebate to Antero Resources.
Antero’s average realized natural gas price before hedging was $2.63 per Mcf, representing a 5% increase versus the prior year period. Despite a sharp widening in the regional basis differential during the quarter, Antero realized a $0.03 per Mcf discount to the average NYMEX Henry Hub price through the use of its premium firm transportation to NYMEX-based markets. Including hedges, Antero’s average realized natural gas price was $2.76 per Mcf, a $0.10 premium to the average NYMEX price.
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Antero’s average realized C3+ NGL price before hedging was $27.64 per barrel, a 26% sequential improvement and a 7% decrease versus the prior year period. Antero shipped 43% of its total C3+ NGL net production on Mariner East 2 for export and realized an $0.11 per gallon premium to Mont Belvieu pricing on these volumes at Marcus Hook, PA. Antero sold the remaining 57% of C3+ NGL net production at a $0.06 per gallon discount to Mont Belvieu pricing at Hopedale, OH. The resulting blended price on 132,326 Bbl/d of net C3+ NGL production was $27.64 per barrel, which was a $0.02 per gallon premium to Mont Belvieu pricing. Antero expects to sell at least 50% of its C3+ NGL production in 2021 at Marcus Hook for export at a premium to Mont Belvieu.
| Three months ended December 31, 2020 | ||||||||||||||
| Pricing Point | Net C3+ NGL Production | % by Destination | Premium (Discount) To Mont Belvieu | |||||||||||
| Propane / Butane exported on ME2 | Marcus Hook, PA | 57,225 | 43 | % | $ | 0.11 | ||||||||
| Remaining C3+ NGL volume | Hopedale, OH | 75,101 | 57 | % | $ | (0.06 | ) | |||||||
| Total C3+ NGLs/Blended Premium | 132,326 | 100 | % | $ | 0.02 | |||||||||
All-in cash expense, which includes lease operating, gathering, compression, processing and transportation, production and ad valorem taxes was $2.14 per Mcfe in the fourth quarter, a 3% increase compared to $2.08 per Mcfe average during the fourth quarter of 2019. The increase from a year ago was due to an increase in transportation expense as Antero utilized higher tariff long-haul firm transportation to capture higher realized natural gas prices. Lease operating expense was $0.08 per Mcfe in the fourth quarter, an 11% decline from the year ago period driven by a decrease in water handling costs as Antero increased water blending and reuse in completion operations.
G&A expense was $0.08 per Mcfe, a 20% decrease from the fourth quarter of 2019 primarily due to a lower employee headcount and a 15% increase in production.
Per unit net marketing expense declined to $0.08 per Mcfe in the fourth quarter, compared to $0.17 per Mcfe reported in the prior year period. The decline was driven primarily by higher production volumes during the quarter and wide regional basis differentials resulting in less unutilized transportation capacity. This fourth quarter net marketing expense was the lowest since Antero’s full firm transportation portfolio was completed in 2018. As basis differentials widened during the fourth quarter of 2020, Antero’s firm transportation portfolio allowed for the flow of its production without any shut-ins or curtailments and shielded it from the wide regional basis to NYMEX prices.
Fourth Quarter 2020 Operating Update
Marcellus Shale — Antero placed 11 horizontal Marcellus wells to sales during the fourth quarter with an average lateral length of 15,788 feet. Ten of the 11 new wells have been on-line for at least 60 days and the average 60-day rate per well was a company record 33.9 MMcfe/d, including approximately 1,822 Bbl/d of liquids assuming 25% ethane recovery. For the full year 2020, Antero averaged over 6,400 feet per day when drilling the lateral section of its wells. Additionally, Antero’s ongoing emphasis on completion efficiencies resulted in an improvement during 2020 to 8.0 stages completed per day, up from 5.8 stages per day in 2019.
These efficiency gains led to average all-in well costs of $690 per lateral foot during the fourth quarter, normalized to a 12,000 foot lateral. This represents a nearly 30% reduction in all-in well cost per lateral foot since the beginning of 2019. The vast majority of the improvement in well costs has been driven by operational efficiency and process changes and are therefore expected to be sustainable.
Fourth Quarter and 2020 Capital Investment
Antero’s drilling and completion capital expenditures for the three months ended December 31, 2020, were $84 million. For the full year 2020 drilling and completion capital expenditures were $735 million, 2% below full year guidance of $750 million. In addition to capital invested in drilling and completion costs, the Company invested $13 million in land during the fourth quarter and $48 million for the full year. For a reconciliation of accrued capital expenditures to cash capital expenditures see the table in the Non-GAAP Financial Measures section.
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Balance Sheet and Liquidity
As of December 31, 2020, Antero’s total debt was $3.0 billion, of which $1.0 billion were borrowings outstanding under the Company’s revolving credit facility. Antero has a borrowing base of $2.85 billion with lender commitments that total $2.64 billion. After deducting letters of credit outstanding of $730 million, the Company had approximately $900 million in available liquidity at December 31, 2020. Net debt to trailing twelve month Adjusted EBITDA ratio (non-GAAP) was 3.1x as of December 31, 2020.
Pro forma for the closing of Antero’s 8.375% senior notes due in 2026 and 7.625% senior notes due in 2029, the convertible senior note equitization transaction, the redemptions of the remaining senior notes due 2022 and receipt of proceeds from the WGL litigation judgement, all of which occurred subsequent to year end 2020, Antero had $471 outstanding under its credit facility and $1.4 billion of liquidity.
The following table reconciles Antero’s pro forma credit facility outstanding with the credit facility amount outstanding as of December, 31st 2020:
| $(MM) | ||||
| Bank credit facility outstanding as of December 31, 2020 | $ | 1,017 | ||
| Net proceeds from 8.375% senior note offering used to repay credit facility | (144 | ) | ||
| Net proceeds from 7.625% senior note offering used to repay credit facility | (381 | ) | ||
| WGL litigation net proceeds | (85 | ) | ||
| Convertible senior note equitization transaction | 64 | |||
| Pro forma bank credit facility outstanding | $ | 471 | ||
Year End Proved Reserves
At December 31, 2020, Antero’s estimated proved reserves were 17.6 Tcfe, a 7% decrease versus the prior year. Estimated proved reserves were comprised of 57% natural gas, 42% NGLs and 1% oil.
Estimated proved developed reserves were 11.9 Tcfe, a 1% increase over the prior year. The percentage of estimated proved reserves classified as proved developed increased to 67% at year-end 2020, compared to 62% at year-end 2019. Antero's proved undeveloped locations have an average estimated BTU of 1264, with an average lateral length of approximately 13,261 feet. At year end 2020, Antero’s five year development plan included 256 PUD locations compared to 328 at year end 2019. The year over year decrease was driven by the shift to a maintenance capital program, which had a net impact of reducing the year end 2020 five year plan by 72 PUD locations.
Antero's 5.8 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 $0.27 per Mcfe.
The following table presents a summary of changes in estimated proved reserves (in Tcfe).
| Proved reserves, December 31, 2019 | 18.9 | |||
| Extensions, discoveries, and other additions | 1.1 | |||
| Performance revisions | 0.5 | |||
| Revisions to five-year development plan | (0.8 | ) | ||
| Price revisions | (1.1 | ) | ||
| Sales of reserves in place | (0.1 | ) | ||
| Revisions to ethane recovery | 0.5 | |||
| Production | (1.3 | ) | ||
| Proved reserves, December 31, 2020 (1) | 17.6 |
| (1) | 2020 proved reserves are reported consolidated with Martica Holdings, LLC. Martica Holdings, LLC had 254 Bcfe of proved reserves as of year end 2020. |
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Commodity Derivative Positions
As of December 31, 2020, the Company has hedged 1.3 Tcf of natural gas at a weighted average index price of $2.67 per MMBtu through 2023 with fixed price swap positions. Antero also has oil and ethane fixed price swap positions, including oil positions that total 3,000 Bbl/d for 2021 and ethane positions that total 19,000 Bbl/d during the first quarter of 2021.
Please see Antero’s Annual Report on Form 10-K for the year ended December 31, 2020, for more information on all commodity derivative positions, including basis swaps and natural gas calls.
The following tables summarize Antero’s hedge position as of December 31, 2020:
Fixed price natural gas positions from January 1, 2021 through December 31, 2023 were as follows:
| Natural gas MMBtu/day | Weighted average index price | |||||||
| Year ending December 31, 2021: | ||||||||
| NYMEX ($/MMBtu) | 2,160,000 | $ | 2.77 | |||||
| Year ending December 31, 2022: | ||||||||
| NYMEX ($/MMBtu) | 1,155,486 | $ | 2.50 | |||||
| Year ending December 31, 2023: | ||||||||
| NYMEX ($/MMBtu) | 43,000 | $ | 2.37 | |||||
Ethane and oil derivative contract positions from January 1, 2021 through December 31, 2021 were as follows:
|
Derivative |
Liquids Hedges (Bbl/d) |
Weighted average index price ($/Gal) |
Weighted average basis differential $/Gal |
Weighted average index price ($/Bbl) | |||||||||||||
| Quarter ending March 31, 2021: | |||||||||||||||||
| Total OPIS Ethane Mt Belvieu | Fixed swap | 19,000 | $ | 0.20 | |||||||||||||
| Year ending December 31, 2021: | |||||||||||||||||
| Total NYMEX Crude Oil | 3,000 | $ | 55.16 | ||||||||||||||
2020 Asset Sales Program Accounting Treatment
For the three months and twelve months ended December 31, 2020, Martica Holdings, LLC (“Martica”), the entity associated with the previously announced ORRI transaction, is included in the Company’s consolidated financial statements and all significant intercompany accounts and transactions have been eliminated. The noncontrolling interest in the Company’s consolidated financial statements for the three and twelve months ended December 31, 2020 represents the interest in Martica, not owned by Antero.
Under the VPP transaction entered into during the third quarter of 2020, all production volumes and reserves are treated as a divestiture and not included in the results. Net proceeds are recorded as deferred revenue as of December 31, 2020. Revenue is recognized as volumes and are delivered using the unit-of-production method over the term of the VPP.
For more information, please see Antero’s Annual Report on Form 10-K for the year ended December 31, 2020.
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Conference Call
A conference call is scheduled on Thursday, February 18, 2021 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 for the quarter. 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 25, 2021 at 9:00 am MT at 877-660-6853 (U.S.) or 201-612-7415 (International) using the conference ID: 13714534.
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 25, 2021 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.
Non-GAAP Financial Measures
Adjusted Net Loss
Adjusted Net Loss as set forth in this release represents net income (loss), adjusted for certain items. Antero believes that Adjusted Net Loss and Adjusted Net Loss per share is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Adjusted Net 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 following tables reconcile net income (loss) to Adjusted Net Loss (in thousands):
| Three Months Ended | Year Ended | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2019 | 2020 | 2019 | 2020 | |||||||||||||
| Net income (loss) attributable to Antero Resources Corp | $ | (482,196 | ) | 69,830 | $ | (340,129 | ) | (1,267,897 | ) | |||||||
| Unrealized commodity derivative gains (losses) | 71,171 | (152,038 | ) | (138,882 | ) | 723,773 | ||||||||||
| Amortization of deferred revenue, VPP | — | (9,332 | ) | — | (14,507 | ) | ||||||||||
| Impairment of oil and gas properties | 46,732 | 67,808 | 1,300,444 | 223,770 | ||||||||||||
| Impairment of midstream assets | — | — | 7,800 | — | ||||||||||||
| Impairment of equity method investment | 467,590 | — | 467,590 | 610,632 | ||||||||||||
| Equity-based compensation | 4,232 | 6,316 | 21,082 | 23,317 | ||||||||||||
| Income from water earnout | (125,000 | ) | — | (125,000 | ) | — | ||||||||||
| Gain on deconsolidation of Antero Midstream LP | — | — | (1,406,042 | ) | — | |||||||||||
| Gain on early extinguishment of debt | (36,419 | ) | (597 | ) | (36,419 | ) | (175,962 | ) | ||||||||
| Loss on sale of assets | — | 348 | 951 | 348 | ||||||||||||
| Loss on the sale of equity method investment shares | 108,745 | — | 108,745 | — | ||||||||||||
| Equity in earnings (loss) of unconsolidated affiliates | 53,023 | (20,748 | ) | 155,481 | 62,660 | |||||||||||
| Contract termination and rig stacking | — | 1,973 | 14,026 | 14,290 | ||||||||||||
| Simplification transaction fees | — | — | 15,482 | — | ||||||||||||
| Tax effect of reconciling items (1) | (138,097 | ) | 25,478 | (90,163 | ) | (352,031 | ) | |||||||||
| Other tax items | 24,041 | — | 17,528 | — | ||||||||||||
| Adjusted Net Loss | $ | (6,178 | ) | (10,962 | ) | $ | (27,506 | ) | (151,607 | ) | ||||||
| Fully Diluted Shares Outstanding | 300,142 | 304,172 | 306,400 | 272,433 | ||||||||||||
| (1) | Deferred taxes were approximately 23% for 2019 and 24% for 2020. |
10
Per Share Amounts
| Three Months Ended | Year Ended | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2019 | 2020 | 2019 | 2020 | |||||||||||||
| Net income (loss) attributable to Antero Resources Corp | $ | (1.61 | ) | 0.24 | $ | (1.11 | ) | (4.65 | ) | |||||||
| Unrealized commodity derivative gains (losses) | 0.24 | (0.51 | ) | (0.45 | ) | 2.66 | ||||||||||
| Amortization of deferred revenue, VPP | — | (0.03 | ) | — | (0.05 | ) | ||||||||||
| Impairment of oil and gas properties | 0.16 | 0.22 | 4.24 | 0.82 | ||||||||||||
| Impairment of midstream assets | — | — | 0.03 | — | ||||||||||||
| Impairment of equity method investment | 1.56 | — | 1.53 | 2.24 | ||||||||||||
| Equity-based compensation | 0.01 | 0.02 | 0.07 | 0.09 | ||||||||||||
| Income from water earnout | (0.42 | ) | — | (0.41 | ) | — | ||||||||||
| Gain on deconsolidation of Antero Midstream LP | — | — | (4.59 | ) | — | |||||||||||
| Gain on early extinguishment of debt | (0.12 | ) | — | (0.12 | ) | (0.65 | ) | |||||||||
| Loss on the sale of equity method investment shares | 0.36 | — | 0.35 | — | ||||||||||||
| Equity in earnings (loss) of unconsolidated affiliates | 0.18 | (0.07 | ) | 0.51 | 0.23 | |||||||||||
| Contract termination and rig stacking | — | 0.01 | 0.05 | 0.05 | ||||||||||||
| Simplification transaction fees | — | — | 0.05 | — | ||||||||||||
| Tax effect of reconciling items (1) | (0.46 | ) | 0.08 | (0.30 | ) | (1.30 | ) | |||||||||
| Other tax items | 0.08 | — | 0.06 | — | ||||||||||||
| Adjusted Net Loss | $ | (0.02 | ) | (0.03 | ) | $ | (0.09 | ) | (0.56 | ) | ||||||
| (1) | Deferred taxes were approximately 23% for 2019 and 24% for 2020. |
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 following table reconciles consolidated total debt to Net Debt as used in this release (in thousands):
| December 31, | ||||||||
| 2019 | 2020 | |||||||
| AR bank credit facility | $ | 552,000 | 1,017,000 | |||||
| 5.375% AR senior notes due 2021 | 952,500 | — | ||||||
| 5.125% AR senior notes due 2022 | 923,041 | 660,516 | ||||||
| 5.625% AR senior notes due 2023 | 750,000 | 574,182 | ||||||
| 5.000% AR senior notes due 2025 | 600,000 | 590,000 | ||||||
| 4.250% AR convertible senior notes due 2026 | — | 287,500 | ||||||
| Net unamortized premium | 791 | (111,886 | ) | |||||
| Net unamortized debt issuance costs | (19,464 | ) | (15,719 | ) | ||||
| Consolidated total debt | $ | 3,758,868 | 3,001,593 | |||||
| Less: AR cash and cash equivalents | — | — | ||||||
| Net Debt | $ | 3,758,868 | 3,001,593 | |||||
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 drilling and completion capital and leasehold capital, 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. 2021 Free Cash Flow estimate is based on current strip pricing and assumes aggregate dividends from Antero Midstream of $137 million in 2021, based on Antero Midstream’s publicly announced 2021 dividend guidance and net proceeds of $85 million from the WGL litigation settlement. In addition, Free Cash Flow through 2025 assumes annual maintenance level capital spending of $635 million, annual dividends from Antero Midstream of $125 million, based on Antero Midstream’s publicly announced 2021 dividend guidance, full participation by QL in the drilling partnership and strip pricing as of February 16, 2021.
11
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.
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. Adjusted EBITDAX includes distributions received with respect to limited partner interests in Antero Midstream Partners common units through March 12, 2019.
Adjusted EBITDAX as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. Adjusted EBITDAX should not be considered in isolation or as a substitute for operating income or loss, net income or loss, cash flows provided by operating, investing, and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. Adjusted EBITDAX provides no information regarding our capital structure, borrowings, interest costs, capital expenditures, working capital movement, or tax position. Adjusted EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, exploration expenses, and other commitments and obligations. However, our management team believes Adjusted EBITDAX is useful to an investor in evaluating our financial performance because this measure:
| · | is widely used by investors in the oil and natural gas industry to measure operating performance without regard to items excluded from the calculation of such term, which may vary substantially from company to company depending upon accounting methods and the book value of assets, capital structure and the method by which assets were acquired, among other factors; |
| · | helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital and legal structure from our operating structure; |
| · | is used by our management team for various purposes, including as a measure of our operating performance, in presentations to our Board of Directors, and as a basis for strategic planning and forecasting: and |
| · | is used by our Board of Directors as a performance measure in determining executive compensation. |
There are significant limitations to using Adjusted EBITDAX as a measure of performance, including the inability to analyze the effects of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations of different companies, and the different methods of calculating Adjusted EBITDAX reported by different companies.
The following table represents a reconciliation of our net income (loss), including noncontrolling interest, to Adjusted EBITDAX and a reconciliation of our Adjusted EBITDAX to net cash provided by operating activities per our consolidated statements of cash flows, in each case, for the three months and years ended December 31, 2019 and 2020. Adjusted EBITDAX also excludes the noncontrolling interests in Martica and these adjustments are disclosed in the table below as Martica related adjustments.
12
| Three Months Ended | Year Ended | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| (in thousands) | 2019 | 2020 | 2019 | 2020 | ||||||||||||
| Reconciliation of net income (loss) to Adjusted EBITDAX: | ||||||||||||||||
| Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation | $ | (482,196 | ) | 69,830 | $ | (340,129 | ) | (1,267,897 | ) | |||||||
| Net income and comprehensive income attributable to noncontrolling interests | — | 25,483 | 46,993 | 7,486 | ||||||||||||
| Unrealized commodity derivative gains (losses) | 71,171 | (150,925 | ) | (138,882 | ) | 725,011 | ||||||||||
| Proceeds from derivative monetizations | — | 9,066 | — | (9,007 | ) | |||||||||||
| Amortization of deferred revenue, VPP | — | (9,332 | ) | — | (14,507 | ) | ||||||||||
| Loss on sale of assets | — | 348 | 951 | 348 | ||||||||||||
| Gain on deconsolidation of Antero Midstream Partners LP | — | — | (1,406,042 | ) | — | |||||||||||
| Interest expense, net | 54,243 | 46,916 | 228,111 | 199,872 | ||||||||||||
| Gain on early extinguishment of debt | (36,419 | ) | (597 | ) | (36,419 | ) | (175,962 | ) | ||||||||
| Provision for income tax expense (benefit) | (107,442 | ) | 23,685 | (74,110 | ) | (397,482 | ) | |||||||||
| Depletion, depreciation, amortization, and accretion | 191,802 | 209,831 | 918,629 | 865,291 | ||||||||||||
| Impairment of oil and gas properties | 46,732 | 67,808 | 1,300,444 | 223,770 | ||||||||||||
| Impairment of midstream assets | — | — | 14,782 | — | ||||||||||||
| Impairment of equity method investment | 467,590 | — | 467,590 | 610,632 | ||||||||||||
| Exploration expense | 236 | 188 | 884 | 1,083 | ||||||||||||
| Equity-based compensation expense | 4,232 | 6,316 | 23,559 | 23,317 | ||||||||||||
| Equity in (earnings) loss of unconsolidated affiliates | 53,023 | (20,748 | ) | 143,216 | 62,660 | |||||||||||
| Distributions/dividends from unconsolidated affiliates | 48,715 | 42,755 | 157,956 | 171,022 | ||||||||||||
| Loss on the sale of equity method investment shares | 108,745 | — | 108,745 | — | ||||||||||||
| Contract termination and rig stacking | — | 1,973 | 14,026 | 14,290 | ||||||||||||
| Water earnout | (125,000 | ) | — | (125,000 | ) | — | ||||||||||
| Simplification transaction fees | — | — | 15,482 | — | ||||||||||||
| Transaction expense | — | 582 | — | 7,244 | ||||||||||||
| 295,432 | 323,179 | 1,320,786 | 1,047,171 | |||||||||||||
| Antero Midstream Partners related adjustments (1) | — | — | (73,115 | ) | — | |||||||||||
| Martica related adjustments (2) | — | (23,983 | ) | — | (45,155 | ) | ||||||||||
| Adjusted EBITDAX | $ | 295,432 | 299,196 | $ | 1,247,671 | 1,002,016 | ||||||||||
| Reconciliation of our Adjusted EBITDAX to net cash provided by operating activities: | ||||||||||||||||
| Adjusted EBITDAX | $ | 295,432 | 299,196 | $ | 1,247,671 | 1,002,016 | ||||||||||
| Antero Midstream Partners related adjustments (1) | — | — | 73,115 | — | ||||||||||||
| Martica related adjustments (2) | — | 23,983 | — | 45,155 | ||||||||||||
| Interest expense, net | (54,243 | ) | (46,916 | ) | (228,111 | ) | (199,872 | ) | ||||||||
| Exploration expense | (236 | ) | (188 | ) | (884 | ) | (1,083 | ) | ||||||||
| Changes in current assets and liabilities | (91,780 | ) | (30,156 | ) | 35,542 | (109,047 | ) | |||||||||
| Simplification transaction fees | — | — | (15,482 | ) | — | |||||||||||
| Transaction expense | — | (582 | ) | — | (7,244 | ) | ||||||||||
| Proceeds from derivative monetizations | — | (9,066 | ) | — | 9,007 | |||||||||||
| Other items | (1,233 | ) | 6,859 | (8,393 | ) | (3,292 | ) | |||||||||
| Net cash provided by operating activities | $ | 147,940 | 243,130 | $ | 1,103,458 | 735,640 | ||||||||||
| (1) | Amounts reflected are net of any elimination adjustments for intercompany activity and include activity related to Antero Midstream Partners through March 12, 2019. Effective March 13, 2019, Antero accounts for its unconsolidated investment in Antero Midstream Corporation using the equity method of accounting. |
| (2) | Adjustments reflect noncontrolling interests in Martica not otherwise adjusted in amounts above. |
13
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, | ||||||||
| 2019 | 2020 | |||||||
| Drilling and completion costs (as reported; cash basis) | $ | 296,187 | 132,345 | |||||
| Change in accrued capital costs | 3,441 | (47,931 | ) | |||||
| Adjusted drilling and completion costs (accrual basis) | $ | 299,628 | 84,414 | |||||
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 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.
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 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, 2020.
For more information, contact Michael Kennedy – SVP – Finance, at (303) 357-6782 or mkennedy@anteroresources.com.
14
ANTERO RESOURCES CORPORATION
Consolidated Balance Sheets
(In thousands, except per share amounts)
| December 31, | ||||||||
| 2019 | 2020 | |||||||
| Assets | ||||||||
| Current assets: | ||||||||
| Accounts receivable | $ | 46,419 | 28,457 | |||||
| Accounts receivable, related parties | 125,000 | — | ||||||
| Accrued revenue | 317,886 | 425,314 | ||||||
| Derivative instruments | 422,849 | 105,130 | ||||||
| Other current assets | 10,731 | 15,238 | ||||||
| Total current assets | 922,885 | 574,139 | ||||||
| Property and equipment: | ||||||||
| Oil and gas properties, at cost (successful efforts method): | ||||||||
| Unproved properties | 1,368,854 | 1,175,178 | ||||||
| Proved properties | 11,859,817 | 12,260,713 | ||||||
| Gathering systems and facilities | 5,802 | 5,802 | ||||||
| Other property and equipment | 71,895 | 74,361 | ||||||
| 13,306,368 | 13,516,054 | |||||||
| Less accumulated depletion, depreciation, and amortization | (3,327,629 | ) | (3,869,116 | ) | ||||
| Property and equipment, net | 9,978,739 | 9,646,938 | ||||||
| Operating leases right-of-use assets | 2,886,500 | 2,613,603 | ||||||
| Derivative instruments | 333,174 | 47,293 | ||||||
| Investment in unconsolidated affiliate | 1,055,177 | 255,082 | ||||||
| Other assets | 21,094 | 13,790 | ||||||
| Total assets | $ | 15,197,569 | 13,150,845 | |||||
| Liabilities and Equity | ||||||||
| Current liabilities: | ||||||||
| Accounts payable | $ | 14,498 | 26,728 | |||||
| Accounts payable, related parties | 97,883 | 69,860 | ||||||
| Accrued liabilities | 400,850 | 343,524 | ||||||
| Revenue distributions payable | 207,988 | 198,117 | ||||||
| Derivative instruments | 6,721 | 31,242 | ||||||
| Short-term lease liabilities | 305,320 | 266,023 | ||||||
| Deferred revenue, VPP | — | 45,257 | ||||||
| Other current liabilities | 6,879 | 2,303 | ||||||
| Total current liabilities | 1,040,139 | 983,054 | ||||||
| Long-term liabilities: | ||||||||
| Long-term debt | 3,758,868 | 3,001,593 | ||||||
| Deferred income tax liability | 781,987 | 412,252 | ||||||
| Derivative instruments | 3,519 | 99,172 | ||||||
| Long-term lease liabilities | 2,583,678 | 2,348,785 | ||||||
| Deferred revenue, VPP | — | 156,024 | ||||||
| Other liabilities | 58,635 | 59,694 | ||||||
| Total liabilities | 8,226,826 | 7,060,574 | ||||||
| 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; 295,941 shares and 268,672 shares issued and outstanding at December 31, 2019 and 2020, respectively | 2,959 | 2,686 | ||||||
| Additional paid-in capital | 6,130,365 | 6,195,497 | ||||||
| Accumulated earnings (deficit) | 837,419 | (430,478 | ) | |||||
| Total stockholders' equity | 6,970,743 | 5,767,705 | ||||||
| Noncontrolling interests | — | 322,566 | ||||||
| Total equity | 6,970,743 | 6,090,271 | ||||||
| Total liabilities and equity | $ | 15,197,569 | 13,150,845 | |||||
15
ANTERO RESOURCES CORPORATION
Consolidated Statements of Operations and Comprehensive Income (Loss)
(In thousands, except per share amounts)
| Three Months Ended December 31, | Year Ended December 31, | |||||||||||||||
| 2019 | 2020 | 2019 | 2020 | |||||||||||||
| Revenue and other: | ||||||||||||||||
| Natural gas sales | $ | 512,076 | 595,151 | $ | 2,247,162 | 1,809,952 | ||||||||||
| Natural gas liquids sales | 316,556 | 364,387 | 1,219,162 | 1,161,683 | ||||||||||||
| Oil sales | 39,874 | 34,037 | 177,549 | 112,270 | ||||||||||||
| Commodity derivative fair value gains (losses) | (7,875 | ) | 196,851 | 463,972 | 79,918 | |||||||||||
| Gathering, compression, water handling and treatment | — | — | 4,478 | — | ||||||||||||
| Marketing | 91,296 | 108,717 | 292,207 | 310,572 | ||||||||||||
| Amortization of deferred revenue, VPP | — | 9,332 | — | 14,507 | ||||||||||||
| Other income | 811 | 648 | 4,160 | 2,797 | ||||||||||||
| Total revenue | 952,738 | 1,309,123 | 4,408,690 | 3,491,699 | ||||||||||||
| Operating expenses: | ||||||||||||||||
| Lease operating | 27,203 | 27,029 | 145,720 | 98,865 | ||||||||||||
| Gathering, compression, processing, and transportation | 551,424 | 653,754 | 2,146,647 | 2,530,838 | ||||||||||||
| Production and ad valorem taxes | 29,633 | 35,294 | 125,142 | 106,775 | ||||||||||||
| Marketing | 140,975 | 134,498 | 549,814 | 469,404 | ||||||||||||
| Exploration | 236 | 188 | 884 | 1,083 | ||||||||||||
| Impairment of oil and gas properties | 46,732 | 67,808 | 1,300,444 | 223,770 | ||||||||||||
| Impairment of midstream assets | — | — | 14,782 | — | ||||||||||||
| Depletion, depreciation, and amortization | 190,861 | 209,740 | 914,867 | 861,870 | ||||||||||||
| Accretion of asset retirement obligations | 941 | 91 | 3,762 | 3,421 | ||||||||||||
| General and administrative (including equity-based compensation expense) | 32,189 | 33,218 | 178,696 | 134,482 | ||||||||||||
| Contract termination and rig stacking | — | 1,973 | 14,026 | 14,290 | ||||||||||||
| Loss on sale of assets | — | 348 | 951 | 348 | ||||||||||||
| Total operating expenses | 1,020,194 | 1,163,941 | 5,395,735 | 4,445,146 | ||||||||||||
| Operating income (loss) | (67,456 | ) | 145,182 | (987,045 | ) | (953,447 | ) | |||||||||
| Other income (expense): | ||||||||||||||||
| Interest expense, net | (54,243 | ) | (46,916 | ) | (228,111 | ) | (199,872 | ) | ||||||||
| Equity in earnings (loss) of unconsolidated affiliates | (53,023 | ) | 20,748 | (143,216 | ) | (62,660 | ) | |||||||||
| Gain on early extinguishment of debt | 36,419 | 597 | 36,419 | 175,962 | ||||||||||||
| Gain on deconsolidation of Antero Midstream Partners LP | — | — | 1,406,042 | — | ||||||||||||
| Water earnout | 125,000 | — | 125,000 | — | ||||||||||||
| Loss on the sale of equity method investment shares | (108,745 | ) | — | (108,745 | ) | — | ||||||||||
| Impairment of equity method investment | (467,590 | ) | — | (467,590 | ) | (610,632 | ) | |||||||||
| Transaction expense | — | (582 | ) | — | (7,244 | ) | ||||||||||
| Total other income (expenses) | (522,182 | ) | (26,153 | ) | 619,799 | (704,446 | ) | |||||||||
| Loss before income taxes | (589,638 | ) | 119,029 | (367,246 | ) | (1,657,893 | ) | |||||||||
| Provision for income tax benefit (expense) | 107,442 | (23,685 | ) | 74,110 | 397,482 | |||||||||||
| Net income (loss) and comprehensive income (loss) including noncontrolling interests | (482,196 | ) | 95,344 | (293,136 | ) | (1,260,411 | ) | |||||||||
| Less: net income (loss) and comprehensive income (loss) attributable to noncontrolling interests | — | 25,483 | 46,993 | 7,486 | ||||||||||||
| Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation | $ | (482,196 | ) | 69,861 | $ | (340,129 | ) | (1,267,897 | ) | |||||||
| Income (loss) per share—basic | $ | (1.61 | ) | 0.26 | $ | (1.11 | ) | (4.65 | ) | |||||||
| Income (loss) per share—diluted | $ | (1.61 | ) | 0.21 | $ | (1.11 | ) | (4.65 | ) | |||||||
| Weighted average number of shares outstanding: | ||||||||||||||||
| Basic | 300,142 | 268,653 | 306,400 | 272,433 | ||||||||||||
| Diluted | 300,142 | 338,967 | 306,400 | 272,433 | ||||||||||||
16
ANTERO RESOURCES CORPORATION
Consolidated Statements of Cash Flows
(In thousands)
| Year Ended December 31, | ||||||||||||
| 2018 | 2019 | 2020 | ||||||||||
| Cash flows provided by (used in) operating activities: | ||||||||||||
| Net loss including noncontrolling interests | $ | (45,701 | ) | (293,136 | ) | (1,260,411 | ) | |||||
| Adjustments to reconcile net loss to net cash provided by operating activities: | ||||||||||||
| Depletion, depreciation, amortization, and accretion | 975,284 | 918,629 | 865,291 | |||||||||
| Impairments | 559,095 | 1,782,816 | 834,402 | |||||||||
| Commodity derivative fair value losses (gains) | 87,594 | (463,972 | ) | (79,918 | ) | |||||||
| Gains on settled commodity derivatives | 243,112 | 325,090 | 794,684 | |||||||||
| Premium paid on derivative contract | (13,318 | ) | — | — | ||||||||
| Proceeds from derivative monetizations | 370,365 | — | 9,007 | |||||||||
| Gains on settled marketing derivatives | 72,687 | — | — | |||||||||
| Marketing derivative fair value gains | (94,081 | ) | — | — | ||||||||
| Loss on sale of assets | — | 951 | 348 | |||||||||
| Equity-based compensation expense | 70,414 | 23,559 | 23,317 | |||||||||
| Deferred income tax benefit | (128,857 | ) | (79,158 | ) | (397,482 | ) | ||||||
| Gain on early extinguishment of debt | — | (36,419 | ) | (175,962 | ) | |||||||
| Loss on the sale of equity method investment shares | — | 108,745 | — | |||||||||
| Equity in (earnings) loss of unconsolidated affiliates | (40,280 | ) | 143,216 | 62,660 | ||||||||
| Water earnout | — | (125,000 | ) | — | ||||||||
| Gain on deconsolidation of Antero Midstream Partners LP | — | (1,406,042 | ) | — | ||||||||
| Distributions/dividends of earnings from unconsolidated affiliates | 46,415 | 157,956 | 171,022 | |||||||||
| Amortization of deferred revenue | — | — | (14,507 | ) | ||||||||
| Amortization of debt issuance costs, debt discount, debt premium and other | 4,681 | 10,681 | 12,236 | |||||||||
| Changes in current assets and liabilities: | ||||||||||||
| Accounts receivable | (15,156 | ) | 31,631 | (9,492 | ) | |||||||
| Accrued revenue | (174,706 | ) | 156,941 | (107,428 | ) | |||||||
| Other current assets | (5,817 | ) | (1,025 | ) | (5,507 | ) | ||||||
| Accounts payable including related parties | 9,307 | (27,996 | ) | (19,282 | ) | |||||||
| Accrued liabilities | 63,562 | (25,762 | ) | 37,954 | ||||||||
| Revenue distributions payable | 101,210 | (102,839 | ) | (5,203 | ) | |||||||
| Other current liabilities | (3,823 | ) | 4,592 | (89 | ) | |||||||
| Net cash provided by operating activities | 2,081,987 | 1,103,458 | 735,640 | |||||||||
| Cash flows provided by (used in) investing activities: | ||||||||||||
| Additions to unproved properties | (172,387 | ) | (88,682 | ) | (45,129 | ) | ||||||
| Drilling and completion costs | (1,488,573 | ) | (1,254,118 | ) | (826,265 | ) | ||||||
| Additions to water handling and treatment systems | (97,699 | ) | (24,416 | ) | — | |||||||
| Additions to gathering systems and facilities | (444,413 | ) | (48,239 | ) | — | |||||||
| Additions to other property and equipment | (7,514 | ) | (6,700 | ) | (2,963 | ) | ||||||
| Settlement of water earnout | — | — | 125,000 | |||||||||
| Investments in unconsolidated affiliates | (136,475 | ) | (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 | |||||||||
| Proceeds from VPP sale, net | — | — | 215,789 | |||||||||
| Change in other assets | (3,663 | ) | 7,091 | 2,806 | ||||||||
| Net cash used in investing activities | (2,350,724 | ) | (1,041,490 | ) | (530,061 | ) | ||||||
| Cash flows provided by (used in) financing activities: | ||||||||||||
| Repurchases of common stock | (129,084 | ) | (38,772 | ) | (43,443 | ) | ||||||
| Issuance of senior notes by Antero Midstream Partners LP | — | 650,000 | — | |||||||||
| Issuance of convertible notes | — | — | 287,500 | |||||||||
| Repayment of senior notes | — | (191,092 | ) | (1,219,019 | ) | |||||||
| Borrowings (repayments) on bank credit facilities, net | 660,379 | 232,000 | 465,000 | |||||||||
| Payments of deferred financing costs | (2,169 | ) | (4,547 | ) | (8,984 | ) | ||||||
| Sale of noncontrolling interest | — | — | 351,000 | |||||||||
| Distributions to noncontrolling interests in Antero Midstream Partners LP | (267,271 | ) | (85,076 | ) | — | |||||||
| Distributions to noncontrolling interests in Martica Holdings LLC | — | — | (35,920 | ) | ||||||||
| Employee tax withholding for settlement of equity compensation awards | (17,020 | ) | (2,389 | ) | (422 | ) | ||||||
| Other | (4,539 | ) | (2,560 | ) | (1,291 | ) | ||||||
| Net cash provided by (used in) financing activities | 240,296 | 557,564 | (205,579 | ) | ||||||||
| Effect of deconsolidation of Antero Midstream Partners LP | — | (619,532 | ) | — | ||||||||
| Net decrease in cash and cash equivalents | (28,441 | ) | — | — | ||||||||
| Cash and cash equivalents, beginning of period | 28,441 | — | — | |||||||||
| Cash and cash equivalents, end of period | $ | — | — | — | ||||||||
17
The following table set forth selected operating data for the three months ended December 31, 2019 and 2020
| Three Months Ended | Amount of | |||||||||||||||
| December 31, | Increase | Percent | ||||||||||||||
| (in thousands) | 2019 | 2020 | (Decrease) | Change | ||||||||||||
| Revenue: | ||||||||||||||||
| Natural gas sales | $ | 512,076 | 595,151 | $ | 83,075 | 16 | % | |||||||||
| Natural gas liquids sales | 316,556 | 364,387 | 47,831 | 15 | % | |||||||||||
| Oil sales | 39,874 | 34,037 | (5,837 | ) | (15 | )% | ||||||||||
| Commodity derivative fair value gains (losses) | (7,875 | ) | 196,851 | 204,726 | (2,600 | )% | ||||||||||
| Marketing | 91,296 | 108,717 | 17,421 | 19 | % | |||||||||||
| Amortization of deferred revenue, VPP | — | 9,332 | 9,332 | * | ||||||||||||
| Other income | 810 | 617 | (193 | ) | (24 | )% | ||||||||||
| Total revenue | 952,737 | 1,309,092 | 356,355 | 37 | % | |||||||||||
| Operating expenses: | ||||||||||||||||
| Lease operating | 27,203 | 27,029 | (174 | ) | (1 | )% | ||||||||||
| Gathering and compression | 193,078 | 217,973 | 24,895 | 13 | % | |||||||||||
| Processing | 180,886 | 211,322 | 30,436 | 17 | % | |||||||||||
| Transportation | 177,460 | 224,459 | 46,999 | 26 | % | |||||||||||
| Production and ad valorem taxes | 29,633 | 35,294 | 5,661 | 19 | % | |||||||||||
| Marketing | 140,975 | 134,498 | (6,477 | ) | (5 | )% | ||||||||||
| Exploration | 236 | 188 | (48 | ) | (20 | )% | ||||||||||
| Impairment of oil and gas properties | 46,732 | 67,808 | 21,076 | 45 | % | |||||||||||
| Depletion, depreciation, and amortization | 190,861 | 209,740 | 18,879 | 10 | % | |||||||||||
| Accretion of asset retirement obligations | 941 | 91 | (850 | ) | (90 | )% | ||||||||||
| General and administrative (excluding equity-based compensation) | 27,957 | 26,902 | (1,055 | ) | (4 | )% | ||||||||||
| Equity-based compensation | 4,232 | 6,316 | 2,084 | 49 | % | |||||||||||
| Contract termination and rig stacking | — | 1,973 | 1,973 | * | ||||||||||||
| Loss on sale of assets | — | 348 | 348 | * | ||||||||||||
| Total operating expenses | 1,020,194 | 1,163,941 | 143,747 | 14 | % | |||||||||||
| Operating income (loss) | (67,457 | ) | 145,151 | 212,608 | (315 | )% | ||||||||||
| Other earnings (expenses): | ||||||||||||||||
| Interest expense, net | (54,243 | ) | (46,916 | ) | 7,327 | (14 | )% | |||||||||
| Equity in earnings (loss) of unconsolidated affiliates | (53,023 | ) | 20,748 | 73,771 | (139 | )% | ||||||||||
| Gain on early extinguishment of debt | 36,419 | 597 | (35,822 | ) | (98 | )% | ||||||||||
| Water earnout | 125,000 | — | (125,000 | ) | * | |||||||||||
| Loss on the sale of equity method investment shares | (108,745 | ) | — | 108,745 | * | |||||||||||
| Impairment of equity method investments | (467,590 | ) | — | 467,590 | * | |||||||||||
| Transaction expense | — | (582 | ) | (582 | ) | * | ||||||||||
| Total other expense | (522,182 | ) | (26,153 | ) | 496,029 | (95 | )% | |||||||||
| Income (loss) before income taxes | (589,639 | ) | 118,998 | 708,637 | (120 | )% | ||||||||||
| Provision for income tax (expense) benefit | 107,442 | (23,685 | ) | (131,127 | ) | (122 | )% | |||||||||
| Net income (loss) and comprehensive income (loss) including noncontrolling interests | (482,197 | ) | 95,313 | 577,510 | (120 | )% | ||||||||||
| Less: net income and comprehensive income attributable to noncontrolling interests | — | 25,483 | 25,483 | * | ||||||||||||
| Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation | (482,197 | ) | 69,830 | 552,027 | (114 | )% | ||||||||||
| Adjusted EBITDAX | $ | 295,432 | 299,196 | $ | 3,764 | 1 | % | |||||||||
* Not meaningful
18
The following table set forth selected operating data for the three months ended December 31, 2019 and 2020:
| Three Months Ended | Amount of | |||||||||||||||
| December 31, | Increase | Percent | ||||||||||||||
| 2019 | 2020 | (Decrease) | Change | |||||||||||||
| Production data (1): | ||||||||||||||||
| Natural gas (Bcf) | 205 | 226 | 21 | 10 | % | |||||||||||
| C2 Ethane (MBbl) | 4,325 | 5,023 | 698 | 16 | % | |||||||||||
| C3+ NGLs (MBbl) | 9,603 | 12,174 | 2,571 | 27 | % | |||||||||||
| Oil (MBbl) | 809 | 1,104 | 295 | 36 | % | |||||||||||
| Combined (Bcfe) | 293 | 336 | 43 | 15 | % | |||||||||||
| Daily combined production (MMcfe/d) | 3,185 | 3,650 | 465 | 15 | % | |||||||||||
| Average prices before effects of derivative settlements (2): | ||||||||||||||||
| Natural gas (per Mcf) | $ | 2.50 | 2.63 | 0.13 | 5 | % | ||||||||||
| C2 Ethane (per Bbl) | $ | 7.44 | 5.56 | (1.88 | ) | (25 | )% | |||||||||
| C3+ NGLs (per Bbl) | $ | 29.61 | 27.64 | (1.97 | ) | (7 | )% | |||||||||
| Oil (per Bbl) | $ | 49.29 | 30.83 | (18.46 | ) | (37 | )% | |||||||||
| Weighted Average Combined (per Mcfe) | $ | 2.96 | 2.96 | — | — | % | ||||||||||
| Average realized prices after effects of derivative settlements (2): | ||||||||||||||||
| Natural gas (per Mcf) | $ | 2.87 | 2.76 | (0.11 | ) | (4 | )% | |||||||||
| C2 Ethane (per Bbl) | $ | 7.44 | 5.44 | (2.00 | ) | (27 | )% | |||||||||
| C3+ NGLs (per Bbl) | $ | 27.95 | 28.84 | 0.89 | 3 | % | ||||||||||
| Oil (per Bbl) | $ | 53.57 | 41.63 | (11.94 | ) | (22 | )% | |||||||||
| Weighted Average Combined (per Mcfe) | $ | 3.18 | 3.12 | (0.06 | ) | (2 | )% | |||||||||
| Average costs (per Mcfe): | ||||||||||||||||
| Lease operating | $ | 0.09 | 0.08 | (0.01 | ) | (11 | )% | |||||||||
| Gathering and compression | $ | 0.66 | 0.65 | (0.01 | ) | (2 | )% | |||||||||
| Processing | $ | 0.62 | 0.63 | 0.01 | 2 | % | ||||||||||
| Transportation | $ | 0.61 | 0.67 | 0.06 | 10 | % | ||||||||||
| Production taxes | $ | 0.10 | 0.11 | 0.01 | 10 | % | ||||||||||
| Marketing, net | $ | 0.17 | 0.08 | (0.09 | ) | (53 | )% | |||||||||
| Depletion, depreciation, amortization and accretion | $ | 0.65 | 0.62 | (0.03 | ) | (5 | )% | |||||||||
| General and administrative (excluding equity-based compensation) | $ | 0.10 | 0.08 | (0.02 | ) | (20 | )% | |||||||||
| (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 our settled commodity derivatives. Our calculation of such after effects includes gains on settlements of commodity derivatives, which do not qualify for hedge accounting because we do not designate or document them as hedges for accounting purposes. Oil and NGLs production was converted at 6 Mcf per Bbl to calculate total Bcfe production and per Mcfe amounts. This ratio is an estimate of the equivalent energy content of the products and does not necessarily reflect their relative economic value. |
19