California Resources Corporation — 2023 Form 10-K
Reporting period: Fiscal year ended December 31, 2023. This is an annual report, not a standalone fourth-quarter report; quarterly results are not separately provided in the supplied filing text.
Business context
CRC is a California-only oil and natural gas producer and an early-stage carbon capture and storage (CCS) developer. It reported average net production of 86 MBoe/d, approximately 60% oil, from operations across 97 fields. At year-end, it held 1.7 million net mineral acres and estimated 377 MMBoe of proved reserves.
Financial and operating metrics
| Metric | 2023 | 2022 |
|---|---|---|
| Total operating revenue | $2.801 billion | $2.707 billion |
| Oil, natural gas and NGL sales | $2.155 billion | $2.643 billion |
| Operating income | $808 million | $812 million |
| Net income | $564 million | $524 million |
| Diluted EPS | $7.78 | $6.75 |
| Cash from operations | $653 million | $690 million |
| Capital investments | $185 million | $379 million |
| Year-end cash and equivalents | $496 million | $307 million |
| Long-term debt, principal | $545 million | $600 million |
Total operating revenue rose about 3%, while operating income declined slightly and net income increased about 8%. Net margin was approximately 20% of revenue, versus 19% in 2022; operating margin was approximately 29%, versus 30%. Revenue includes a $12 million net derivative loss in 2023, compared with a $551 million loss in 2022; derivative settlements and fair-value changes make year-over-year revenue comparisons less indicative of underlying commodity sales.
Production declined about 5% to 86 MBoe/d from 91 MBoe/d, primarily due to natural decline. Oil, NGL and natural gas sales fell $488 million, mainly reflecting lower oil prices and volumes. Oil realized price before derivative settlements was $80.41/Bbl, down from $98.26/Bbl; NGL realization was $48.94/Bbl, down from $64.33/Bbl. California natural gas realization rose to $8.59/Mcf from $7.68/Mcf.
Operating cash flow decreased 5%, to $653 million. Investing cash outflow was $175 million, compared with $317 million in 2022, chiefly because capital investment was lower. Financing cash outflow was $289 million, including $143 million of share repurchases, $81 million of dividends and $56 million of debt repurchases. Year-end liquidity was $973 million: $496 million of cash plus $477 million available under the revolver after letters of credit. CRC reported compliance with debt covenants and no revolver borrowings at year-end. The $545 million Senior Notes carry a 7.125% coupon and mature in 2026.
Year-end proved reserves were 377 MMBoe, down from 417 MMBoe. The standardized measure of discounted future net cash flows was $4.069 billion, down from $6.726 billion; non-GAAP PV-10 was $5.533 billion. These reserve-based estimates use prescribed SEC pricing and assumptions and are not fair value estimates.
Material changes and notable items
- Production fell from 91 to 86 MBoe/d, while reported operating costs rose to $26.24/Boe from $23.75/Boe. CRC cited lower volumes, compensation costs and maintenance activity; costs excluding the reporting effects of Wilmington production-sharing contracts were $23.99/Boe.
- Proved reserves decreased by 40 MMBoe. Additions from performance, extensions and improved recovery were offset by production, price revisions, divestitures and 12 MMBoe of regulatory-related revisions associated with California’s SB 1137 and related uncertainty.
- CRC recorded a $35 million release of a valuation allowance related to the Lost Hills sale, contributing to a lower effective tax rate of 25%, versus 31% in 2022.
- A 2023 reorganization generated a $10 million severance charge. CRC reported approximately $15 million of savings in 2023 and expects annualized savings of approximately $65 million in 2024.
- Asset retirement obligations were $521 million at year-end, excluding amounts associated with assets held for sale. CRC disclosed a $12 million recorded liability for maintenance costs related to a disputed offshore-platform decommissioning order; it expects its share of costs to be approximately $12–$15 million and is appealing the order.
Outlook, management commentary and risks
- 2024 capital plan: $300–$340 million, excluding additional capital related to the Aera merger. CRC expects $250–$260 million for oil and gas development, $30–$40 million for facility and power-plant maintenance, $15–$25 million for carbon management and $5–$15 million for corporate and other activities. Permitting delays could reduce the program by up to $100 million.
- Permitting: CRC reported significant delays in California well permits. It planned one active rig in Kern County during the first half of 2024 and potentially more rigs in the second half if permits resume. About $75 million of planned Kern County development and $25 million of Wilmington development related to wells without permits at filing time. Management cautioned there is no certainty permits will be obtained on schedule or at all.
- Aera merger, subsequent event: The February 7, 2024 agreement provides for an all-stock combination, expected to close in the second half of 2024 subject to approvals and other conditions. CRC agreed to issue 21.17 million shares, subject to adjustments, and assume Aera’s $950 million debt. It expects existing CRC holders to own approximately 77.1% of the combined company. CRC plans to fund or refinance the assumed debt using cash, revolver borrowings and capital markets financing, with a committed $500 million bridge facility available subject to conditions. A higher dividend after closing is expected, subject to board approval.
- Returns to shareholders: The stated annual dividend policy is $1.24 per share, subject to quarterly board approval. In February 2024, the repurchase authorization was increased to $1.35 billion and extended through December 31, 2025; these authorizations do not obligate CRC to make payments or purchases.
- Carbon TerraVault: CRC has six carbon dioxide management agreements, which remain subject to definitive agreements and final investment decisions. EPA issued draft Class VI permits for one Elk Hills project in December 2023; final permit decisions were anticipated in the second half of 2024. CCS development depends on permits, counterparties, financing, and incentives including tax credits. Brookfield’s future JV funding is milestone- and project-approval-dependent.
- Principal risks: Commodity-price volatility and hedging limits; California permitting and regulatory changes; production decline and reserve uncertainty; operating, environmental, wildfire, earthquake and water-related risks; and execution, financing and incentive risks in the early-stage CCS business. CRC also identified concentration in California and dependence on a limited number of refinery customers (three refineries accounted for 44% of 2023 sales before hedging).
Most important facts for investors to verify
- Whether and when the Aera merger closes, the final share issuance and debt funding mix, and the combined company’s leverage and liquidity.
- Whether California well permits resume as planned, especially for Kern County and Wilmington, and the resulting effect on the 2024 capital plan, production and proved reserves.
- Commodity prices, hedge coverage and settlements: CRC had hedged approximately 75% of anticipated oil production through 2024 and 45% through 2025 at year-end 2023.
- Whether operating-cost savings reach management’s approximately $65 million annualized target while production declines are managed.
- Progress toward final CCS permits, definitive customer agreements, Brookfield funding milestones and monetization of applicable tax credits.
- Changes in asset retirement obligations, the offshore-platform appeal and cost-sharing arrangements, and other environmental or regulatory contingencies.