Amplify Energy Corp. — Q2 2023 Form 10-Q
Reporting period: Three and six months ended June 30, 2023. The unaudited filing covers an oil and gas producer operating in Oklahoma, the Rockies, offshore Southern California, East Texas/North Louisiana and the Eagle Ford.
Financial performance and position
Unless otherwise noted, amounts are in millions. Comparisons are with the corresponding 2022 period.
| Metric | Q2 2023 | Q2 2022 | First half 2023 | First half 2022 |
|---|---|---|---|---|
| Total revenue | $72.0 | $121.8 | $151.8 | $233.2 |
| Operating income (loss) | $6.6 | $32.3 | $33.2 | $(13.9) |
| Net income (loss) | $9.8 | $29.2 | $362.6 | $(19.4) |
| Operating cash flow | Not separately clear in the filing text | Not separately clear in the filing text | $95.2 | $30.4 |
- Q2 operations: Oil and gas sales were $67.4 million, down 40% year over year. Average production increased to 21.2 MBoe/d from 20.4 MBoe/d, while realized price fell to $34.97/Boe from $60.74/Boe. Q2 diluted EPS was $0.24, versus $0.73.
- First-half earnings: Reported net income and EPS of $362.6 million and $8.91 were substantially affected by an $84.9 million pipeline-related litigation settlement gain and a $259.4 million deferred income tax benefit. The latter followed release of substantially all of the deferred-tax valuation allowance. These items make reported earnings a poor standalone indicator of recurring performance.
- Costs and margins: Q2 lease operating expense was $34.9 million ($18.10/Boe), compared with $33.3 million ($17.91/Boe). First-half lease operating expense was $67.9 million ($18.48/Boe). Lower gathering/transportation and production taxes partly offset lower commodity revenue; management attributed the cost-per-Boe increase in lease operations partly to the Beta restart.
- Debt and liquidity: At June 30, debt was $120.0 million, down from $190.0 million at year-end 2022; cash was $1.9 million. Working capital was negative $12.7 million. First-half financing cash outflow was $72.2 million, principally net repayment of $70.0 million on the revolving facility. The company reported compliance with its then-existing credit-facility covenants at June 30.
- Cash investment and obligations: First-half property and equipment additions were $16.9 million; restricted investments increased by $4.2 million. Long-term asset retirement obligations were $118.6 million, in addition to a current portion.
Material changes and developments
- Compared with Q2 2022, oil and gas sales declined despite slightly higher production, primarily because realized commodity prices fell. First-half production averaged 20.3 MBoe/d, broadly level with 20.4 MBoe/d a year earlier.
- Beta Field operations had been suspended following the 2021 Southern California pipeline incident. Federal regulatory approvals to restart were received April 10, 2023; the restart increased production but also contributed to higher lease operating costs.
- On July 31, 2023, after quarter-end, the company replaced its revolving facility. The new facility had $120.0 million outstanding, a $150.0 million initial borrowing base and $135.0 million of elected commitments, with maturity July 31, 2027. Its next borrowing-base redetermination was expected in Q4 2023.
Outlook, risks and unusual items
- Management expects operating cash flow and availability under the new credit facility to support normal needs and currently planned 2023 development activity, subject to production, commodity prices and costs. It expects remainder-of-year funding from internally generated cash, facility borrowings and potentially capital markets, but said it did not anticipate near-term capital-markets activity. No specific full-year production, revenue or earnings guidance is provided in the filing text.
- Commodity prices remain volatile. The new facility requires hedging at least 75% of projected production from proved developed producing reserves for the first 24 months and 50% for the following 12 months. The company also describes its general target as hedging approximately 50%–75% over a one-to-three-year period.
- The company estimates total incident costs of approximately $190–$210 million, subject to substantial uncertainty. Its $50 million class-action settlement is to be funded under insurance; criminal resolutions include federal and state penalties and other obligations. The OPA 90 claims process and natural-resource-damage assessment remain ongoing, and potentially uncovered costs could be material. The company cautions that insurance may not cover all losses. Incident-specific loss-of-production coverage expired March 31, 2023.
- The company received approximately $85 million net from its settlement with the vessels and related parties; proceeds were used to reduce debt and enhance liquidity. The first-half results also include $15.1 million of pipeline incident loss. Insurance recoveries, claims and final incident costs remain subject to uncertainty.
- Offshore decommissioning funding is a continuing cash commitment: the filing estimates $4.0 million of required sinking-fund payments for the remainder of 2023 and $15.8 million annually for 2024–2033. The company also supports offshore decommissioning obligations with $161.3 million of surety bonds.
- Management said disclosure controls were effective at June 30, 2023; no material change in internal control over financial reporting was reported during the quarter.
Important facts for investors to verify
- Progress and final costs of the pipeline incident, including insurance coverage, remaining investigations, OPA 90 claims and natural-resource damages.
- Liquidity headroom and covenant compliance under the new credit facility, especially ahead of the Q4 2023 borrowing-base redetermination.
- Whether Beta production and operating costs develop as expected after restart, and how commodity prices affect cash generation.
- Whether the deferred tax assets recognized after the valuation-allowance release are ultimately realizable.
- Ongoing offshore decommissioning funding requirements and related restricted cash availability.