Antero Resources Corporation — 2020 Form 10-K
Reporting period: Fiscal year ended December 31, 2020; filed February 17, 2021. The filing also provides unaudited fourth-quarter results. Antero is an Appalachian Basin-focused natural gas, NGL and oil producer, with approximately 515,000 net acres. It owns a 29.2% interest in Antero Midstream, accounted for under the equity method.
Financial and operating performance
| Metric | 2020 | 2019 |
|---|---|---|
| Total revenue | $3.492 billion | $4.409 billion |
| Operating loss | $953 million | $987 million |
| Net loss attributable to Antero | $1.268 billion; $4.65 per share | $340 million; $1.11 per share |
| Adjusted EBITDAX (non-GAAP) | $1.002 billion | $1.248 billion |
| Cash from operations | $736 million | $1.103 billion |
| Cash used in investing | $530 million | $1.041 billion |
| Cash from (used in) financing | $(206) million | $558 million |
Fourth quarter: Revenue was $1.309 billion, operating income was $145 million, and net income attributable to Antero was $70 million, or $0.26 per basic share ($0.24 diluted).
- Production rose 11% to 1,310 Bcfe, averaging 3,578 MMcfe/d. However, realized combined sales price after derivative settlements declined 12% to $2.96/Mcfe.
- Natural gas sales fell 19% to $1.810 billion; NGL sales declined 5% to $1.162 billion; oil sales declined 37% to $112 million. Total revenue declined 21%.
- Cash derivative settlements provided approximately $795 million in 2020, versus $325 million in 2019. Derivatives are not designated for hedge accounting, so fair-value changes contribute to reported earnings volatility.
- Operating costs included $2.531 billion for gathering, compression, processing and transportation; lease operating expense fell to $99 million. Impairments included $224 million for oil and gas properties and $611 million for the Antero Midstream investment.
- Year-end debt principal was approximately $3.129 billion, including $1.017 billion drawn on the revolving credit facility. The facility had a $2.85 billion borrowing base, $2.64 billion in lender commitments and $730 million of letters of credit. Cash and cash equivalents were zero; current assets were $574 million and current liabilities $983 million.
Changes, capital allocation and outlook
- Proved reserves declined 7% to 17.635 Tcfe. Lower prices reduced reserves by 1.126 Tcfe; revisions to the five-year development plan reduced them by 790 Bcfe. Extensions, performance and higher assumed ethane recovery partly offset these reductions. Proved undeveloped reserves were 5.762 Tcfe, or 33% of proved reserves.
- 2020 consolidated capital expenditures were approximately $785 million. The 2021 budget is $635 million—$590 million for drilling and completion and $45 million for leasehold—with plans for three rigs, two completion crews and 65–70 horizontal wells. Management said the plan would be adjusted for liquidity, results and commodity prices.
- Antero repurchased $1.4 billion principal amount of notes in 2020 at a weighted average 13% discount, recording a $176 million extinguishment gain. Asset-sale proceeds, including $351 million from the Martica royalty transaction and $216 million net proceeds from a volumetric production payment, were directed toward debt reduction. The VPP proceeds are deferred revenue recognized as contracted volumes are delivered.
- Subsequent to year-end, Antero issued $500 million of 8.375% notes due 2026 and $700 million of 7.625% notes due 2029, redeemed its remaining 2022 notes, and completed an equity offering and repurchase of $150 million principal amount of convertible notes. A QL Capital drilling partnership announced in February 2021 is expected to fund 20% of 2021 development capital and 15%–20% annually in 2022–2024, subject to the agreement’s conditions.
Management commentary, risks and contingencies
Management cited COVID-19-related commodity-price volatility, lower realized prices and reduced activity as important 2020 conditions. It reported no significant supply-chain interruptions or material operational disruption from employee safety protocols. Management expected operating cash flow, credit availability and capital-market transactions to meet requirements for at least 12 months, based on December 31, 2020 strip prices; this depends on market conditions and the April 2021 borrowing-base redetermination.
- Key exposures include commodity prices and hedge effectiveness, concentrated Appalachian operations, reserve and development uncertainty, pipeline and processing access, and more than $12.7 billion of minimum firm-transportation commitments over their contract terms. Lower production could leave costly capacity underused.
- Management estimated 2021 net marketing costs of $0.08–$0.10/Mcfe for unutilized transportation capacity, assuming production remained at 2020 levels. A 2021 commodity-price hedge position covered a substantial majority of expected natural gas production; hedges also limit upside if market prices exceed contracted prices.
- Approximately $1.5 billion of future development costs was estimated for proved undeveloped reserves over five years. Lease renewal requirements and the five-year development rule could reduce booked reserves if drilling or renewals are delayed.
- EPA and state environmental notices alleged air-permitting violations at certain facilities; negotiations were ongoing, and management did not expect a material adverse effect. Antero and royalty owners received approximately $107 million from WGL in February 2021 following a favorable judgment. Other ordinary-course claims were also disclosed; the filing does not provide a clear quantified estimate of potential exposure for them.
- Management reported effective disclosure controls and internal control over financial reporting. The independent auditor issued unqualified opinions and identified reserve estimates used in depletion expense as a critical audit matter.
Investor facts to verify
- Available revolver capacity and liquidity after accounting for outstanding borrowings, letters of credit, covenants and the April 2021 borrowing-base redetermination.
- Cash generation and debt-service capacity if commodity prices weaken or hedge benefits decline; review the post-year-end note issuances, redemptions and convertible-note equity transactions.
- Realized prices, hedge settlement cash flows, counterparty exposure and the proportion of production hedged for 2021 and later years.
- Execution and funding of the 2021 drilling budget and QL partnership, including conditions, cost exposure and any effect on production and reserves.
- Reserve sensitivity to prices, costs, development timing, lease renewals and ethane-recovery assumptions; PV-10 and standardized measure are estimates, not market valuations.