Antero Resources Corporation (NYSE: AR) — 2022 Form 10-K
Reporting period: Fiscal year ended December 31, 2022. This is an annual filing; the supplied text does not provide a clear, standalone fourth-quarter income statement or cash-flow summary. Antero develops and produces natural gas, NGLs and oil, primarily in the Appalachian Basin, where it held approximately 504,000 net acres. It also markets excess transportation capacity and owns 29.1% of Antero Midstream.
Financial performance and position
| Metric | FY 2022 | Prior comparable period |
|---|---|---|
| Total revenue | $7.14 billion | $4.62 billion in 2021 |
| Operating income | $2.57 billion | $23.9 million in 2021 |
| Net income attributable to Antero | $1.90 billion; diluted EPS $5.78 | Net loss of $186.9 million; diluted loss per share $0.61 in 2021 |
| Cash from operations | $3.05 billion | $1.66 billion in 2021 |
| Cash used in investing activities | $943.6 million | $710.8 million in 2021 |
| Cash used in financing activities | $2.11 billion | $949.3 million in 2021 |
| Year-end debt | $1.20 billion principal; $1.18 billion carrying value | $2.18 billion principal in 2021 |
| Year-end cash and cash equivalents | $0 reported | $0 reported |
- Revenue included $8.29 billion from produced natural gas, NGL and oil sales, offset by $1.62 billion of commodity-derivative fair-value losses; total revenue also includes marketing and other items.
- Production was 1.17 Tcfe, down 2% from 2021; average daily production was 3,204 MMcfe. Combined realized sales price after derivative settlements rose 41% to $5.46/Mcfe.
- Operating costs included $2.61 billion for gathering, compression, processing and transportation, and $287 million in production and ad valorem taxes. DD&A was $681 million; impairment expense was $150 million, including a $48 million sand-mine impairment.
- At year-end, the revolving facility had a $3.5 billion borrowing base, $1.5 billion of lender commitments, $35 million drawn, $504 million of letters of credit and $961 million of available borrowing capacity. The company reported compliance with its debt covenants.
- Net derivative liability was $431 million at year-end. The company paid $1.91 billion on settled commodity derivatives during 2022, as shown in the cash-flow reconciliation.
- Current assets were $788 million and current liabilities were $1.77 billion. The filing reports no cash balance; liquidity therefore depends on operating cash flow and facility availability.
Material changes versus 2021
- Higher commodity prices drove the earnings recovery: natural gas sales increased 60% to $5.52 billion, NGL sales increased 16% to $2.50 billion, and oil sales increased 37% to $276 million. Production volumes declined 2% overall.
- Operating income rose substantially from $23.9 million to $2.57 billion, and operating cash flow increased to $3.05 billion. The company reported $449 million of income tax expense in 2022, versus a $74 million tax benefit in 2021.
- Debt principal declined by approximately $980 million. Antero redeemed or repurchased about $1.0 billion of senior notes, recording a $46 million loss on early extinguishment.
- The company repurchased 25 million shares for approximately $874 million under its expanded $2.0 billion authorization. No common-stock dividend had been declared or paid.
- Proved reserves were 17.76 Tcfe, up 30 Bcfe (about 0.2%). Proved developed reserves increased to 75% of proved reserves; proved undeveloped reserves decreased to 4.39 Tcfe, or 25%.
Outlook, management commentary and risks
- 2023 plan: Net capital budget of $1.025–$1.075 billion, including $875–$925 million for drilling and completion and $150 million for leasehold expenditures. Antero plans to complete 60–65 net horizontal wells. The budget excludes acquisitions other than leasehold purchases and may change with prices, liquidity and drilling results.
- Management said operating cash flow and available revolver borrowings, based on December 31, 2022 strip prices, should cover expected cash needs for at least 12 months. This outlook is conditional on commodity prices and other assumptions.
- 2023 costs include notable post-year-end items: a $202 million cash payment in January 2023 to settle a swaption, funded by revolver borrowings, and a $24 million payment to terminate a 200,000 MMBtu/day Equitrans transportation commitment, also funded by the facility.
- Hedging was reduced as liquidity and leverage improved. The filing estimates approximately 1% of 2023 production hedged through fixed-price swaps, assuming production matches 2022 levels; additional basis and option arrangements also existed. Commodity prices, Appalachian basis differentials and hedge settlements remain material uncertainties.
- Firm transportation, processing, gathering, compression and water-service commitments are substantial: minimum-volume obligations were approximately $11.1 billion over contract terms. The filing gives differing 2023 net marketing-cost estimates under different production assumptions; verify the applicable assumption and estimate.
- Other material risks include lease expirations and development of PUD reserves (estimated $1.9 billion of development costs over five years), customer concentration, operating and infrastructure interruptions, inflation, regulatory and environmental requirements, and climate-related costs. The company disclosed pending royalty-related litigation and environmental notices; management did not expect the environmental matters to have a material adverse effect, while potential royalty-case outcomes were not estimable.
- The company has a stated goal of net-zero Scope 1 and Scope 2 emissions by 2025, but says timing, costs and availability of credible offsets are uncertain. The filing also discusses proposed methane rules and the federal methane fee beginning in 2024.
Most important facts for investors to verify
- Whether realized prices, production volumes and hedge settlements support the 2023 cash-flow and capital-budget assumptions, particularly after the swaption settlement.
- Available liquidity after revolver borrowings, letters of credit, minimum-volume commitments and other contractual obligations; reconcile the $11.1 billion service commitments with the broader $15.56 billion contractual-obligation schedule, which also includes leases and other items.
- Execution and funding of the 60–65-well plan, including service-cost inflation, lease renewals and the five-year schedule for developing PUD reserves.
- Use of capital for debt reduction versus share repurchases, the remaining repurchase authorization and the 1% stock-buyback excise tax applicable from 2023.
- Developments in royalty litigation, environmental notices, methane regulation and the company’s ability to meet its 2025 emissions goal.
KPMG issued an unqualified opinion on the consolidated financial statements and stated that internal control over financial reporting was effective as of December 31, 2022.