California Resources Corporation (CRC) Q3 2026 earnings review
California Resources beats cash profit plan, but oil discounts widen
California Resources Corporation, the California oil, gas and carbon storage producer, beat its third-quarter cash profit plan on summer electricity sales while its core oil business faced wider price discounts and higher field costs. Cash profit reached $341 million as the Elk Hills power plant earned $35 million, offsetting a $315 million net loss caused by non-cash oil hedge charges. Chief executive Francisco Leon closed the Crimson pipeline purchase, agreed to sell the Utah oil fields for $90 million, and resumed share buybacks.
| Cash profit (Adjusted EBITDAX) | $341M beat $285–325M plan; +1% from a year ago |
|---|---|
| Oil price before hedges (% of Brent) | 91% 95% last quarter; 97% a year ago |
| Free cash flow | $147M +29% from last quarter; -22% from a year ago |
| Q4 cash profit outlook | $340–380M assumes $102.90/Bbl Brent oil |
⚖️ Verdict: ⚪ Neutral
The story is unchanged because seasonal power profits and a $103 oil price assumption in the fourth-quarter plan mask persistent weakness in the oil fields. While resuming buybacks at $30 million and exiting Utah clean up capital allocation, the price the company receives for its oil before hedges fell to 91% of Brent, and the fourth-quarter plan keeps it at 91–93% despite owning the new pipelines. Well operating costs also missed the company's plan on higher steamflood fuel and maintenance bills.
The question now is whether the 91–93% oil price realization is a temporary pipeline dispute or a lasting discount from California refinery closures. If the Crimson pipelines fix the bottleneck, realizations should recover toward 96% of Brent and add roughly $40 million a quarter in cash profit; if refinery demand has permanently shifted to waterborne imports, the discount will stick. The full-year 2027 outlook next quarter will show which side is right.
🐂 Bull Case
Power Plant Profit and Oil Prices Lifted Cash Profit
California Resources Corporation (CRC), an oil, gas and carbon management producer in California, tracks Adjusted EBITDAX — cash profit before interest, taxes, depreciation, exploration and one-offs. After missing its target last quarter, the company beat the top of its $285–325 million third-quarter plan by $16 million.
- Third-quarter Adjusted EBITDAX: $341 million, up 1% from last quarter and 1% from a year ago
- Electricity revenue minus generation costs: $35 million, compared with a $18–24 million plan and a $4 million loss last quarter
- Fourth-quarter Adjusted EBITDAX outlook: $340–380 million, based on $102.90 per barrel Brent oil
The third-quarter beat came from its Elk Hills power plant and higher Brent crude prices ($91.36 per barrel versus the $83.14 plan). Electricity profit beat the plan "primarily due to higher prices for resource adequacy revenue and sales from electricity delivered to the wholesale market", the company said. The fourth-quarter plan rises again because management assumes $102.90 Brent oil, even as power profit drops back to $5–11 million.
What to watch: fourth-quarter cash profit against actual Brent oil prices. If oil averages below $102.90 per barrel, cash profit will trail the $340–380 million outlook.
Portfolio Moves Center the Business on California
"As we look to 2027, CRC is moving from acquisition to optimization," chief executive Francisco Leon said. He wants the oil producer to focus on "lowering costs, improving capital efficiency and putting our midstream, power and carbon opportunities to work".
The company closed its purchase of Crimson Midstream, a California pipeline operator, and agreed to sell its Uinta Basin oil fields in Utah for about $90 million in cash. Those fields produced 2 thousand barrels of oil per day and 9 million cubic feet of gas per day this quarter. Selling Utah cleans up a reversal from earlier this year, when management briefly planned to add a Utah drilling rig before calling the asset non-core.
Meanwhile, general and administrative overhead excluding one-offs fell to $79 million from $89 million last quarter as savings from the December 2025 Berry merger took hold. Management also kept its 2027 drilling, completion and well-maintenance capital plan at $450–475 million across six California rigs, matching the 5% lower budget it set three months ago.
What to watch: the full-year 2027 outlook arriving with fourth-quarter results. It will show whether the Crimson pipelines and Berry cost savings lower per-barrel operating expenses.
Buybacks Resumed Alongside a 4% Dividend Increase
Share buybacks had nearly stopped this year, falling from $353 million in the first half of 2025 to $10 million in the first quarter of 2026 and zero in the second. Management blamed the second-quarter pause on legal trading restrictions while it negotiated the Crimson pipeline deal and refinanced debt.
With the Crimson deal signed, the producer bought back 0.6 million shares for $30 million at an average price of $53.48. The board also raised the quarterly cash dividend by 4% to $0.42 per share, after paying $36 million in dividends during the third quarter. Total cash returned to shareholders reached $66 million, or 45% of the quarter's $147 million in free cash flow.
What to watch: fourth-quarter share repurchases after the $90 million Utah sale closes by year-end. A larger buyback would show that deal restrictions, rather than tight cash, caused the first-half pause.
🐻 Bear Case
Oil Price Discounts Worsened and Field Costs Rose
Leon praised the company's "ongoing focus on sustainable efficiency gains", and management previously called second-quarter pipeline bottlenecks a temporary issue. Yet the price CRC received for its oil before hedges fell further behind the Brent benchmark, and field operating costs missed the company's own plan.
- Oil price before hedges: 91% of Brent ($83.42 per barrel), down from 95% in Q2 and 97% a year ago
- Fourth-quarter oil realization outlook: 91–93% of Brent, showing no recovery by year-end
- Operating costs: $386 million (35.2% of revenue before derivatives, up 3.4 percentage points from Q2), worse than the $360–380 million plan
Operating costs — the direct expense of running oil and gas wells — rose "primarily due to higher prices for natural gas purchased and used in steamflood operations, and higher workover activity", the company said. Steamflooding burns natural gas to heat heavy underground oil so it flows. At the same time, receiving 91% of Brent instead of 95% costs about $40 million a quarter on 121 thousand barrels a day. Management's fourth-quarter plan keeps operating costs high at $370–390 million and oil prices at 91–93% of Brent.
What to watch: first-quarter 2027 oil price realizations after a full quarter of owning the Crimson pipelines. If realizations stay near 91–93% of Brent, the discount is a lasting California market shift rather than a temporary dispute.
Oil Hedges Kept Capping Cash Prices at 79% of Brent
CRC uses commodity derivatives — financial price hedges — to lock in oil prices, which protects cash flow when crude falls but caps revenue when crude rises. Because Brent crude averaged $91.36 per barrel in the third quarter, those contracts cost the company $121 million in cash oil settlements.
After those hedge payments, the producer kept $72.46 per barrel of oil, or 79% of Brent, matching the 79% share it kept in the second quarter and down from 98% a year ago. Rising oil prices also reduced the accounting value of future hedge contracts, creating a $540 million non-cash charge that pushed the company to a $315 million net loss. If Brent reaches management's $102.90 fourth-quarter assumption, hedge payments will take an even larger cut of oil revenue.
What to watch: cash derivative settlements in the fourth-quarter report. They will show how much of the rally above $90 Brent actually reaches the company's bank account.
Carbon and Power Deals Remain Non-Binding while Losses Continue
Through its Carbon TerraVault unit, the company wants to turn depleted underground oil fields into paid storage sites for carbon dioxide and pair them with low-carbon power plants. This quarter it signed a memorandum of understanding with Bloom Energy to evaluate "the potential development of 1 gigawatt (GW) or more of solid-oxide fuel cell power generation paired with carbon capture and storage".
As the release notes, such agreements are non-binding and require binding customer contracts, investment decisions and federal permits. After nearly two years of similar announcements, the company still has no binding power-purchase deal with a data center and no major third-party carbon revenue. The carbon segment lost $8 million in Adjusted EBITDAX, matching its first- and second-quarter losses, and management cut segment capital spending to $1 million (with $0–2 million planned for the fourth quarter). Meanwhile, legacy offshore platform costs took another $6 million ($26 million over nine months), and the release gave no update on state carbon-program rules or permits.
What to watch: segment revenue in the full-year filing and any binding customer contract. Until a paying customer signs a binding deal, the carbon and power business remains a cash drain.
💲 Other KPIs
Total output in thousand barrels of oil equivalent per day rose 2.0% from last quarter and 11.0% from a year ago, landing inside the 151–154 outlook. By our math, excluding the roughly 22 MBoe/d added by the December 2025 Berry merger, output from wells owned a year ago fell about 5%. New gas processing connections lifted natural gas volumes 7.0% from last quarter.
Cash left after capital investments rose 28.9% from $114 million last quarter (and a $32 million outflow in the first quarter), but fell 21.8% from $188 million a year ago. Operating cash flow rose to $305 million as the company sold oil inventory built up in the second quarter, while capital spending rose to $158 million.
By our math, carrying debt of $1,281 million minus $35 million of available cash edged down from $1,238 million at the end of June as cash dipped by $8 million to help close the Crimson pipeline deal. Total current liabilities on the balance sheet rose 54.5% since December to $1,622 million because higher oil prices increased hedge liabilities.
🔮 Guidance
New. The plan calls for 151 MBoe/d at the middle of the range, down 0.7% from the third quarter and up 10.2% from a year ago. The forecast still includes the Utah fields (about 3.5 MBoe/d) until the sale closes at year-end, while oil drops by 1 percentage point to 79% of total output.
New. The middle of the range ($360 million) is up 5.6% from the third quarter and up 43.4% from a year ago. By our math, adding this to nine-month results puts the full year at $1,323–1,363 million, above the $1,200–1,300 million full-year target set last quarter, because management raised its Brent oil assumption from $84.51 to $102.90 per barrel.
Unchanged against the upper half of what the prior full-year plan left for the fourth quarter. At the $120 million middle of the range, spending drops 24.1% from the third quarter and is flat against a year ago as the company runs five drilling rigs before adding a sixth rig in early 2027.
New. The $380 million middle of the range is down 1.6% from the third quarter's $386 million actual result, but $10 million higher than the range management had planned for the third quarter, showing that higher well-maintenance and steamflood fuel costs are sticking around.
New. At the middle of the range, overhead rises to $97 million ($88 million excluding stock compensation), up 11.4% from $79 million excluding one-offs in the third quarter.
New. Depreciation, depletion and amortization averages $134 million (down from $137 million in Q3), production and property taxes average $73 million (down from $81 million), and net interest expense averages $30 million (up from $26 million).
New. Net electricity profit drops from $35 million in the third quarter to $8 million at the middle of the range as summer power demand ends. Marketing profit ($13 million midpoint), transport costs ($32.5 million) and other net operating expenses ($25 million) stay near third-quarter levels.
Cut on oil. The 92% middle of the range for oil sits 1 percentage point below what management's prior 94% full-year target implied for the fourth quarter, keeping oil discounts near the third quarter's 91% level. Natural gas realizations remain high at 113% of NYMEX after winter pricing begins.
Unchanged. Management kept its preliminary 2027 well-spending plan at $450–475 million across six California rigs, up from the $370–390 million planned for 2026, and will issue a complete 2027 plan next quarter.
❓ Key Questions
Why did oil price discounts widen to 91% of Brent?
Management said in Q2 that pipeline disputes were temporary and predicted 93% of Brent in Q3 and a Q4 recovery. Instead, Q3 fell to 91% and Q4 is planned at 91–93% even after closing the Crimson pipeline purchase.
Why does Q4 assume $102.90 Brent oil, and what is hedged?
The $340–380 million Q4 cash profit plan rests on $102.90 per barrel Brent, up $11.54 from Q3 actuals. Investors need to know how much of that increase is lost to oil price hedges capped near $68–84 per barrel.
What earnings will the Crimson pipelines add in 2027?
The company closed the Crimson Midstream purchase and sold the Utah fields for $90 million, but did not update its full-year 2026 table or disclose how much pipeline tariff profit Crimson adds and how much cash profit the Utah sale removes.
When will a data center or carbon customer sign a binding contract?
The Bloom Energy fuel-cell agreement is another non-binding memorandum of understanding, while the carbon unit lost $8 million and spent just $1 million in capital. Investors need a date for first binding third-party revenue.