Increasing Second Half 2026 Activity to Accelerate Development of Long Duration Oil Inventory
Raising 2026E Adjusted EBITDAX Guidance by 42% Driven by Strong Oil Prices, Increased Target Synergies and Expected Operating Efficiencies
LONG BEACH, Calif., May 05, 2026 (GLOBE NEWSWIRE) -- California Resources Corporation (NYSE: CRC) (CRC) today reported its financial and operating results for the first quarter of 2026. In addition, CRC announced plans to increase second half 2026 drilling activity, materially enhancing full-year expectations and building momentum into 2027. The Company plans to host a conference call and webcast at 1 p.m. ET (10 a.m. PT) on Wednesday, May 6, 2026. Conference call details can be found within this release.
Highlights
- Delivered average net production of 154 thousand barrels of oil equivalent per day (MBoe/d) (81% oil); oil volumes were reduced by approximately 1.5 thousand barrels of oil per day (MBo/d) due to the impact of higher oil prices on production sharing contracts
- Reported a net loss of $711 million, primarily driven by the non-cash loss in the fair value of its outstanding commodity derivatives1, adjusted net income1 of $79 million and $304 million of adjusted EBITDAX1
- Generated net cash provided by operating activities of $99 million or $247 million of net cash provided by operating activities before net changes in operating assets and liabilities1
- Delivered $32 million of negative free cash flow1 or $116 million of free cash flow before net changes in operating assets and liabilities1
- Returned $46 million to shareholders, including $36 million in dividends and $10 million in share repurchases2
- Ended the first quarter of 2026 with $1,251 million in borrowing capacity and including $25 million in available cash and cash equivalents3 representing $1,276 million of liquidity1, 3
- Optimized capital structure and extended maturities through recent $350 million follow-on offering of 7.000% senior notes due 2034 (2034 Senior Notes) and subsequent redemption of $350 million 8.250% senior notes due 2029 (2029 Senior Notes)
- Preparing for first carbon dioxide (CO2) injection at California's inaugural carbon capture and storage (CCS) project at CRC's Elk Hills cryogenic gas plant; see Carbon TerraVault's First Quarter 2026 Update for additional information
2026 Guidance Highlights
- Increased mid-point of expected Berry merger annual synergy target range by 12% to $90 - $100 million
- Increased expected drilling, completions and workover capital1 investments by approximately $100 million to accelerate high-return drilling projects in California and Utah
- Reduced facilities capital by $10 million, reflecting ongoing field consolidation
- Increased capital budget range to $520 - $560 million with a full-year average of five rigs
- Targeting 2026E gross production exit rate of approximately 175 MBoe/d, representing ~1% entry-to-exit production growth
- Higher oil prices, increased drilling activity and improved operating efficiencies drive a 42% increase in 2026E adjusted EBITDAX1 to a guidance midpoint of $1,450 million
"We continued to demonstrate the strength of our integrated portfolio strategy, delivering solid results while advancing high-return oil developments and capturing incremental merger-related synergies," said Francisco Leon, CRC's President and Chief Executive Officer. "With higher oil prices and an attractive drilling return portfolio, we see a clear opportunity to accelerate development across our multi-decade resource inventory. As a result, we are adding incremental drilling activity this year to drive higher production, EBITDAX and cash flow. Our low-decline, capital-efficient conventional asset base underpins this strategy and we are moving decisively to unlock its value. CRC is a different kind of energy company, and our consistent results reinforce our ability to create durable, long-term value for our shareholders while meeting California's energy needs."
First Quarter 2026 Results
- Operating expenses were in line with expectations reflecting solid execution and the ongoing capture of Berry merger-related synergies
- General and administrative expenses were slightly higher than expectations primarily driven by the timing of legal fees and cash-settled stock-based compensation related to a higher share price
- Invested total capital of $131 million including drilling, completions and workover capital1 of $70 million; total capital was at the high-end of expectations driven by strategic acceleration of investments to support planned second half 2026 drilling activity
| Select Production, Price and Financial Results and Non-GAAP Measures | 1st Quarter | 4th Quarter | ||||||
| ($ in millions except production and prices) | 2026 | 2025 | ||||||
| Net oil production per day (MBbl/d)5 | 124 | 109 | ||||||
| Realized oil price without derivative settlements ($ per Bbl) | $ | 74.53 | $ | 61.14 | ||||
| Realized oil price with derivative settlements1 ($ per Bbl)1 | $ | 69.37 | $ | 64.27 | ||||
| Net NGL production per day (MBbl/d)5 | 10 | 9 | ||||||
| Realized NGL price ($ per Bbl) | $ | 44.98 | $ | 42.86 | ||||
| Net natural gas production per day (Mmcf/d)5 | 117 | 113 | ||||||
| Realized natural gas price ($ per Mcf) | $ | 3.56 | $ | 3.91 | ||||
| Net total production per day (MBoe/d)5 | 154 | 137 | ||||||
| Margin from purchased commodities1 | $ | 18 | $ | 13 | ||||
| Electricity revenue net of electricity generation expenses1 | $ | 6 | $ | 40 | ||||
| Net (loss) gain from commodity sales derivatives | $ | (848 | ) | $ | 126 | |||
| Other operating expenses net of other revenue1 | $ | 44 | $ | 75 | ||||
| Select Financial Statement Data and Non-GAAP Measures: | 1st Quarter | 4th Quarter | ||||||
| ($ and shares in millions, except per share amounts) | 2026 | 2025 | ||||||
| Total operating revenues before net (loss) gain from commodity derivatives1 | $ | 967 | $ | 798 | ||||
| Operating costs | $ | 365 | $ | 325 | ||||
| General and administrative expenses | $ | 106 | $ | 95 | ||||
| Adjusted general and administrative expenses1 | $ | 99 | $ | 89 | ||||
| Taxes other than on income | $ | 67 | $ | 55 | ||||
| Transportation costs | $ | 26 | $ | 20 | ||||
| Operating (loss) income | $ | (711 | ) | $ | 47 | |||
| Interest and debt expense, net | $ | 29 | $ | 29 | ||||
| Income tax (benefit) provision | $ | (49 | ) | $ | 11 | |||
| Deferred income tax (benefit) provision | $ | (50 | ) | $ | 22 | |||
| Net (loss) income | $ | (711 | ) | $ | 12 | |||
| Weighted-average common shares outstanding - diluted | 88.7 | 85.1 | ||||||
| Net (loss) income per share - diluted | $ | (8.02 | ) | $ | 0.14 | |||
| Adjusted net income1 | $ | 79 | $ | 40 | ||||
| Adjusted net income per share1 - diluted | $ | 0.88 | $ | 0.47 | ||||
| Net cash provided by operating activities | $ | 99 | $ | 235 | ||||
| Adjusted EBITDAX1 | $ | 304 | $ | 251 | ||||
| Free cash flow1 | $ | (32 | ) | $ | 115 | |||
| Capital investments | $ | 131 | $ | 120 | ||||
Guidance
The following table provides key second quarter and full year 2026 financial and operating guidance4. CRC is positioned to accelerate activity in the summer of 2026, increasing to a seven rig program in the second half of 2026, which includes 6 rigs in California and 1 rig in Utah. CRC currently holds the permits necessary to execute a majority of its planned capital program, subject to commodity prices and market conditions. See Attachment 2 for further information on CRC's second quarter and full year 2026 guidance.
| 2Q26E | Total Year 2026E | |||
| Net Production (MBoe/d) | 148 - 150 | 149 - 155 | ||
| Percentage Oil | 81% | 81% | ||
| Capital Investments ($ millions) | $120 - $140 | $520 - $560 | ||
| Adjusted EBITDAX1 ($ millions) | $370 - $410 | $1,400 - $1,500 | ||
Shareholder Returns
On May 5, 2026, CRC's Board of Directors declared a quarterly cash dividend of $0.405 per share of common stock, payable to shareholders of record on May 29, 2026. The dividend is expected to be paid on June 18, 2026.
In the first quarter 2026, CRC repurchased 0.2 million shares of its common stock for $10 million2 at an average price of $45.70 per share and returned $36 million in dividends to shareholders. Since mid-2021, the Company has returned approximately $1,619 million to shareholders2, including $1,180 million in share repurchases and $439 million in dividends.
Balance Sheet and Liquidity
In April 2026, CRC's lenders reaffirmed its $1,500 million borrowing base under its Revolving Credit Facility as part of its semi-annual redetermination.
On March 23, 2026, CRC completed a $350 million follow-on offering of Senior Notes due 2034, generating net proceeds of $347 million, reflecting approximately $2 million of issuance premium and $5 million of issuance costs. The net proceeds, combined with cash on hand, were used to redeem $350 million of CRC's outstanding Senior Notes due 2029.
As of March 31, 2026, CRC had liquidity of $1,276 million1,3, consisting of $25 million in available cash and cash equivalents3 and $1,251 million of available borrowing capacity under its Revolving Credit Facility (which reflects $1,460 million of borrowing capacity less $184 million of outstanding letters of credit and $25 million outstanding on the Revolving Credit Facility).
Participation in Upcoming Investor Conferences
CRC is scheduled to participate in the following events in May, June and July 2026:
- Goldman Sachs Eleventh Annual Leverage Finance and Credit Conference, May 28, Dana Point, CA
- 2026 RBC Capital Markets Global Energy, Power & Infrastructure Conference, June 2, New York, NY
- BofA Securities Energy and Power Credit Conference, June 3, New York, NY
- JP Morgan Natural Resources Conference, June 23, New York, NY
- RBC Capital Markets Energy Transition Conference 2026, June 25, London, UK
- TD Cowen 24th Annual Calgary Energy, Power & Utilities Conference, July 7 and 8, Calgary, AB
CRC’s presentation materials will be available on the day of the event on its website. See the Events and Presentations page under the Investor Relations section at www.crc.com.
Conference Call Details
A conference call and webcast is planned for 1 p.m. ET (10 a.m. PT) on Wednesday, May 6, 2026. To participate in the call, dial (877) 328-5505 (International calls dial +1 (412) 317-5421) or access via webcast at www.crc.com. Participants may also pre-register for the conference call at https://dpregister.com/sreg/10207969/103b95d691e. A digital replay of the conference call will be available for approximately 90 days.
1 See Attachment 3 for the non-GAAP financial measures of adjusted net income (loss), adjusted net income (loss) per share - basic and diluted, net cash provided by operating activities before net changes in operating assets and liabilities, adjusted EBITDAX, free cash flow, free cash flow before net changes in operating assets and liabilities, adjusted general and administrative expenses, total operating revenues before net (loss) gain from commodity derivatives, margin from purchased commodities, electricity revenue net of electricity generation expenses and other operating expenses net of other revenue, including reconciliations to the most directly comparable GAAP measure without unreasonable effort. See Attachment 2 for the 2Q26 and 2026 estimates of the non-GAAP measures of adjusted EBITDAX, adjusted general and administrative expenses, margin from purchased commodities, other operating expenses net of other revenue and electricity revenue net of electricity generation expenses, including reconciliations to its most directly comparable GAAP measure, without unreasonable effort. See Attachment 1 for a reconciliation of drilling completion and workover capital to total capital investments, and non-cash commodity derivative (loss) gain from combined derivatives to net (loss) gain from combined derivatives, reported under GAAP.
2 All of CRC’s future quarterly dividends and share repurchases are subject to commodity prices, debt agreement covenants and Board of Directors' approval. The total value of shares purchased excludes commissions and excise taxes. Commissions paid on share repurchases were not significant in all periods presented.
3 Excludes restricted cash of $15 million.
4 2Q26 guidance assumes Brent price of $105.36 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $2.77 per mcf. Total year 2026 guidance assumes Brent price of $90.58 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $3.61 per mcf.
5 Net production per day for the periods presented reflects the impact of transaction timing. Berry Corporation volumes contributed for approximately 14 days in 2025 following the transaction close. Production amounts shown are reported results and are not presented on a pro forma basis.
About California Resources Corporation
California Resources Corporation (CRC) is an independent energy and carbon management company advancing the energy transition. CRC is committed to environmental stewardship while safely providing local, responsibly sourced energy. CRC is also focused on maximizing the value of its land, mineral ownership, and energy expertise for decarbonization by developing CCS and other emissions reducing projects. For more information about CRC, please visit crc.com.
About Carbon TerraVault
Carbon TerraVault (CTV), CRC’s carbon management business, is developing services to capture, transport and permanently store carbon dioxide (CO2) for its customers. CTV is engaged in a series of proposed CCS projects to inject CO2 captured from industrial sources into depleted reservoirs deep underground for permanent sequestration. For more information, visit carbonterravault.com.
Forward-Looking Statements
Information set forth in this communication, including financial estimates and statements as to the effects of the Berry Merger, constitute “forward-looking statements” within the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 and other securities laws. All statements other than historical facts are forward-looking statements, and include statements regarding the benefits of the Berry Merger, CRC's future financial position, business strategy, projected revenues, earnings, costs, capital expenditures and plans and objectives and intentions of management for the future. Words such as “expect,” “could,” “may,” “anticipate,” “intend,” “plan,” “ability,” “believe,” “seek,” “see,” “will,” “would,” “estimate,” “forecast,” “target,” “guidance,” “outlook,” “opportunity” or “strategy” or similar expressions are generally intended to identify forward-looking statements. These forward-looking statements are based upon the current beliefs and expectations of the management of CRC and are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, projected in, or implied by, such statements.
Although CRC believes the expectations and forecasts reflected in its forward-looking statements are reasonable, they are inherently subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond its control. No assurance can be given that such forward-looking statements will be correct or achieved or that the assumptions are accurate or will not change over time. Particular uncertainties that could cause CRC’s actual results to be materially different than those expressed in its forward-looking statements are described in its most recent Annual Report on Form 10-K and its other periodic filings with the SEC. These factors include, but are not limited to: fluctuations in commodity prices; production levels and/or pricing by OPEC, OPEC+ or U.S. producers; government policy, war and political conditions and events; integration efforts and projected synergies and other benefits in connection with the Berry Merger and other acquisitions; divestitures and joint ventures; regulatory actions and changes that affect the oil and gas industry generally and us in particular; the efforts of activists to delay or prevent oil and gas activities or the development of CRC’s carbon management segment; changes in business strategy and the ability and financial resources to execute our capital plan in a timely manner; lower-than-expected production; changes to estimates of reserves and related future cash flows; the recoverability of resources and unexpected geologic conditions; general economic conditions and trends; results from operations and competition in the industries in which it operates; CRC’s ability to realize the anticipated benefits from prior or future efforts to reduce costs; environmental risks and liability; the benefits contemplated by its energy transition strategies and initiatives; CRC’s ability to successfully identify, develop and finance carbon capture and storage projects, power projects and other renewable energy efforts; delays from government approvals and otherwise that could affect the timing of first injection of CO2; future dividends and share repurchases and de-leveraging efforts; and natural disasters, accidents, mechanical failures, power outages, labor difficulties, cybersecurity breaches or attacks or other catastrophic events.
CRC cautions you not to place undue reliance on forward-looking statements contained in this document, which speak only as of the date hereof, and CRC is under no obligation, and expressly disclaims any obligation to update, alter or otherwise revise any forward-looking statements, whether as a result of new information, future events or otherwise. This communication may also contain information from third-party sources. This data may involve a number of assumptions and limitations, and CRC has not independently verified them and does not warrant the accuracy or completeness of such third-party information.
Contacts:
| Daniel Juck (Investor Relations) 818-661-3700 CRC_IR@crc.com | Hailey Bonus (Media) 714-874-7732 CRC.Communications@crc.com |
| Attachment 1 | ||||||||||||
| STATEMENTS OF OPERATIONS, SELECT FINANCIAL INFORMATION | ||||||||||||
| 1st Quarter | 4th Quarter | 1st Quarter | ||||||||||
| ($ and shares in millions, except per share amounts) | 2026 | 2025 | 2025 | |||||||||
| Statements of Operations: | ||||||||||||
| Revenues | ||||||||||||
| Oil, natural gas and natural gas liquids sales | $ | 905 | $ | 679 | $ | 814 | ||||||
| Net (loss) gain from commodity derivatives | (848 | ) | 126 | 6 | ||||||||
| Revenue from marketing of purchased commodities | 41 | 60 | 64 | |||||||||
| Electricity revenue | 11 | 52 | 22 | |||||||||
| Other revenue | 10 | 7 | 6 | |||||||||
| Total operating revenues | 119 | 924 | 912 | |||||||||
| Operating Expenses | ||||||||||||
| Operating costs | 365 | 325 | 316 | |||||||||
| General and administrative expenses | 106 | 95 | 72 | |||||||||
| Depreciation, depletion and amortization | 133 | 129 | 131 | |||||||||
| Asset impairment | — | 57 | — | |||||||||
| Taxes other than on income | 67 | 55 | 70 | |||||||||
| Costs related to marketing of purchased commodities | 23 | 47 | 50 | |||||||||
| Electricity generation expenses | 5 | 12 | 10 | |||||||||
| Transportation costs | 26 | 20 | 20 | |||||||||
| Accretion expense | 27 | 29 | 29 | |||||||||
| Net loss on natural gas purchase derivatives | 24 | 26 | (6 | ) | ||||||||
| Measurement period adjustments, net | — | — | 1 | |||||||||
| Other operating expenses, net | 54 | 82 | 33 | |||||||||
| Total operating expenses | 830 | 877 | 726 | |||||||||
| Operating (Loss) Income | (711 | ) | 47 | 186 | ||||||||
| Non-Operating (Expenses) Income | ||||||||||||
| Interest and debt expense, net | (29 | ) | (29 | ) | (27 | ) | ||||||
| Equity loss from unconsolidated subsidiaries | (2 | ) | (1 | ) | (1 | ) | ||||||
| Loss on early extinguishment of debt | (21 | ) | — | (1 | ) | |||||||
| Other non-operating income, net | 3 | 6 | 5 | |||||||||
| (Loss) Income Before Income Taxes | (760 | ) | 23 | 162 | ||||||||
| Income tax benefit (provision) | 49 | (11 | ) | (47 | ) | |||||||
| Net (Loss) Income | $ | (711 | ) | $ | 12 | $ | 115 | |||||
| Net income per share - basic | $ | (8.02 | ) | $ | 0.14 | $ | 1.27 | |||||
| Net income per share - diluted | $ | (8.02 | ) | $ | 0.14 | $ | 1.26 | |||||
| Adjusted net income | $ | 79 | $ | 40 | $ | 98 | ||||||
| Adjusted net income per share - basic | $ | 0.89 | $ | 0.47 | $ | 1.08 | ||||||
| Adjusted net income per share - diluted(1) | $ | 0.88 | $ | 0.47 | $ | 1.07 | ||||||
| Weighted-average common shares outstanding - basic | 88.7 | 84.6 | 90.6 | |||||||||
| Weighted-average common shares outstanding - diluted(1) | 88.7 | 85.1 | 91.2 | |||||||||
| Effective tax rate | 6 | % | 48 | % | 29 | % | ||||||
| 1st Quarter | 4th Quarter | 1st Quarter | ||||||||||
| ($ in millions) | 2026 | 2025 | 2025 | |||||||||
| Cash Flow Data: | ||||||||||||
| Net cash provided by operating activities | $ | 99 | $ | 235 | $ | 186 | ||||||
| Net cash used in investing activities | $ | (136 | ) | $ | (508 | ) | $ | (79 | ) | |||
| Net cash (used in) provided by financing activities | $ | (55 | ) | $ | 209 | $ | (265 | ) | ||||
| March 31 | December 31, | |||||||||||
| ($ in millions) | 2026 | 2025 | ||||||||||
| Select Balance Sheet Information: | ||||||||||||
| Total current assets | $ | 788 | $ | 938 | ||||||||
| Property, plant and equipment, net | $ | 5,904 | $ | 5,905 | ||||||||
| Total current liabilities | $ | 1,441 | $ | 1,050 | ||||||||
| Long-term debt, net | $ | 1,310 | $ | 1,283 | ||||||||
| Noncurrent asset retirement obligations | $ | 906 | $ | 913 | ||||||||
| Total stockholders' equity | $ | 2,918 | $ | 3,674 | ||||||||
| (1) Adjusted net income per share - diluted for the three months ended March 31, 2026 is calculated using weighted average shares outstanding of 89.5 million shares. | ||||||||||||
| GAINS AND LOSSES FROM COMMODITY DERIVATIVES | |||||||||||
| 1st Quarter | 4th Quarter | 1st Quarter | |||||||||
| ($ millions) | 2026 | 2025 | 2025 | ||||||||
| Non-cash (loss) gain from commodity sales derivatives | $ | (792 | ) | $ | 95 | $ | 22 | ||||
| Net settlements and premiums | (56 | ) | 31 | (16 | ) | ||||||
| Net (loss) gain from commodity sales derivatives | $ | (848 | ) | $ | 126 | $ | 6 | ||||
| Non-cash loss (gain) from natural gas purchase derivatives | $ | 12 | $ | 22 | $ | (18 | ) | ||||
| Settlements | 12 | 4 | 12 | ||||||||
| Net loss (gain) from natural gas purchase derivatives | $ | 24 | $ | 26 | $ | (6 | ) | ||||
| Non-cash (loss) gain from combined commodity derivatives | $ | (804 | ) | $ | 73 | $ | 40 | ||||
| Net settlements and premiums from combined derivatives | (68 | ) | 27 | (28 | ) | ||||||
| Net (loss) gain from combined commodity derivatives | $ | (872 | ) | $ | 100 | $ | 12 | ||||
| CAPITAL INVESTMENTS | ||||||||||
| 1st Quarter | 4th Quarter | 1st Quarter | ||||||||
| ($ millions) | 2026 | 2025 | 2025 | |||||||
| Facilities(1) | $ | 37 | $ | 46 | $ | 16 | ||||
| Drilling and completions | 53 | 38 | 15 | |||||||
| Workovers | 17 | 18 | 19 | |||||||
| Other | 9 | 9 | — | |||||||
| Oil and natural gas segment | 116 | 111 | 50 | |||||||
| Carbon management segment | 12 | 11 | 2 | |||||||
| Corporate and other(1) | 3 | (2 | ) | 3 | ||||||
| Total capital investment | $ | 131 | $ | 120 | $ | 55 | ||||
| (1) Certain amounts previously reported in the Q1 2025 earnings release have been corrected. This correction relates to reporting of $8 million of capital as Corporate and other in Q1 2025 and this amount was reclassified to Facilities in Q4 2025. | ||||||||||
| LIQUIDITY | ||||||||
| ($ millions) | March 31, 2026 | December 31, 2025 | ||||||
| Available cash and cash equivalents(1) | $ | 25 | $ | 117 | ||||
| Revolving credit facility: | ||||||||
| Borrowing capacity | 1,460 | 1,460 | ||||||
| Revolver balance drawn | (25 | ) | — | |||||
| Outstanding letters of credit | (184 | ) | (176 | ) | ||||
| Availability | $ | 1,251 | $ | 1,284 | ||||
| Liquidity | $ | 1,276 | $ | 1,401 | ||||
| (1) Excludes restricted cash of $15 million at both March 31, 2026 and December 31, 2025. | ||||||||
| Attachment 2 | ||||||||
| CRC GUIDANCE | Consolidated 2Q26E | Oil and Natural Gas Segment | Carbon Management Segment | |||||
| Net production (MBoe/d) | 148 - 150 | |||||||
| Net oil production (%) | 81% | |||||||
| Operating costs ($ millions) | $335 - $355 | $335 - $355 | ||||||
| General and administrative expenses ($ millions) | $90 - $100 | $13 - $17 | $2 - $4 | |||||
| Adjusted general and administrative expenses ($ millions) | $85 - $95 | $13 - $17 | $2 - $4 | |||||
| Depreciation, depletion and amortization ($ millions) | $145 - $157 | $140 - $150 | ||||||
| Capital investments ($ millions) | $120 - $140 | $115 - $130 | $2 - $5 | |||||
| Adjusted EBITDAX ($ millions) | $370 - $410 | |||||||
| Margin from purchased commodities ($ millions) (1) | $10 - $15 | |||||||
| Electricity revenue net of electricity generation expenses ($ millions) | $(6) - $(2) | |||||||
| Other operating expenses net of other revenue ($ millions) (2) | $10 - $20 | $2 - $10 | ||||||
| Transportation costs ($ millions) | $25 - $30 | $19 - $24 | ||||||
| Taxes other than on income ($ millions) | $60 - $70 | $55 - $60 | ||||||
| Interest and debt expense ($ millions) | $30 - $35 | |||||||
| Other Assumptions: | ||||||||
| Brent ($/Bbl) | $105.36 | |||||||
| NYMEX ($/Mcf) | $2.77 | |||||||
| Price realization oil - % of Brent: | 94% - 97% | |||||||
| Price realization NGLs - % of Brent: | 44% - 50% | |||||||
| Price realization natural gas - % of NYMEX: | 38% - 44% | |||||||
| Current income tax provision ($ millions) (3) | $2 -$4 | |||||||
| Effective tax rate | 6% - 9% | |||||||
| CRC GUIDANCE | Consolidated 2026E | Oil and Natural Gas Segment | Carbon Management Segment | |||||
| Net production (MBoe/d) | 149 - 155 | |||||||
| Net oil production (%) | 81% | |||||||
| Operating costs ($ millions) | $1,415 - $1,485 | $1,415 - $1,485 | ||||||
| General and administrative expenses ($ millions) | $360 - $380 | $50 - $60 | $6 - $12 | |||||
| Adjusted general and administrative expenses ($ millions) | $325 - $340 | $50 - $60 | $6 - $12 | |||||
| Depreciation, depletion and amortization ($ millions) | $595 - $615 | $575 - $590 | ||||||
| Capital investments ($ millions) | $520 - $560 | $500 - $525 | $12 - $20 | |||||
| Adjusted EBITDAX ($ millions) | $1,400 - $1,500 | |||||||
| Margin from purchased commodities ($ millions) (1) | $50 - $65 | |||||||
| Electricity revenue net of electricity generation expenses ($ millions) | $25 - $45 | |||||||
| Other operating expenses net of other revenue ($ millions) (2) | $75 - $85 | $20 - $30 | ||||||
| Transportation costs ($ millions) | $105 - $115 | $65 - $70 | ||||||
| Taxes other than on income ($ millions) | $270 - $280 | $238 - $243 | ||||||
| Interest and debt expense ($ millions) | $120 - $130 | |||||||
| Other Assumptions: | ||||||||
| Brent ($/Bbl) | $90.58 | |||||||
| NYMEX ($/Mcf) | $3.61 | |||||||
| Price realization oil - % of Brent: | 94% - 98% | |||||||
| Price realization NGLs - % of Brent: | 50% - 55% | |||||||
| Price realization natural gas - % of NYMEX: | 67% - 72% | |||||||
| Current income tax provision ($ millions) (3) | $5 - $8 | |||||||
| Effective tax rate | 12% - 16% | |||||||
(1) Margin from purchased commodities is calculated as the difference between revenue from marketing of purchased commodities and costs related to marketing of purchased commodities, and excludes costs of transportation.
(2) Other operating revenue and expenses, net is calculated as the difference between other revenue and other operating expenses, net and includes exploration expense and CMB expenses. CMB expenses includes lease cost for sequestration easements, advocacy, and other startup related costs.
See Attachment 3 for management's disclosure of its use of these non-GAAP measures and how these measures provide useful information to investors about CRC's results of operations and financial condition.
(3) Current income tax composition is subject to variability and depends on a number of factors, including but not limited to, final taxable income determinations, the availability and utilization of net operating loss carryforwards (NOLs), applicable tax credits, and other differences between book and taxable income. Accordingly, the current provision may vary from period to period and should not be viewed as indicative of future tax obligations.
FORWARD LOOKING NON-GAAP RECONCILIATIONS
| 2Q26E | ||||||||||||||||||||
| Consolidated | Oil and Natural Gas Segment | Carbon Management Segment | ||||||||||||||||||
| ($ millions) | Low | High | Low | High | Low | High | ||||||||||||||
| General and administrative expenses | $ | 90 | $ | 100 | $ | 13 | $ | 17 | $ | 2 | $ | 4 | ||||||||
| Equity-settled stock-based compensation | (5 | ) | (5 | ) | — | — | — | — | ||||||||||||
| Estimated adjusted general and administrative expenses | $ | 85 | $ | 95 | $ | 13 | $ | 17 | $ | 2 | $ | 4 | ||||||||
| Consolidated | ||||||||
| 2Q26E | ||||||||
| ($ millions) | Low | High | ||||||
| Revenue from marketing of purchased commodities | $ | 15 | $ | 32 | ||||
| Costs related to marketing of purchased commodities | (5 | ) | (17 | ) | ||||
| Margin from purchased commodities | $ | 10 | $ | 15 | ||||
| Consolidated | ||||||||
| 2Q26E | ||||||||
| ($ millions) | Low | High | ||||||
| Other operating expenses, net | $ | 14 | $ | 30 | ||||
| Other revenue | (4 | ) | (10 | ) | ||||
| Other operating expenses net of other revenue | $ | 10 | $ | 20 | ||||
| 2026E | ||||||||||||||||||||
| Consolidated | Oil and Natural Gas Segment | Carbon Management Segment | ||||||||||||||||||
| ($ millions) | Low | High | Low | High | Low | High | ||||||||||||||
| General and administrative expenses | $ | 360 | $ | 380 | $ | 50 | $ | 60 | $ | 6 | $ | 12 | ||||||||
| Equity-settled stock-based compensation | (35 | ) | (40 | ) | — | — | — | — | ||||||||||||
| Estimated adjusted general and administrative expenses | $ | 325 | $ | 340 | $ | 50 | $ | 60 | $ | 6 | $ | 12 | ||||||||
| Consolidated | ||||||||
| 2026E | ||||||||
| ($ millions) | Low | High | ||||||
| Revenue from marketing of purchased commodities | $ | 143 | $ | 168 | ||||
| Costs related to marketing of purchased commodities | (93 | ) | (103 | ) | ||||
| Margin from purchased commodities | $ | 50 | $ | 65 | ||||
| Consolidated | ||||||||
| 2026E | ||||||||
| ($ millions) | Low | High | ||||||
| Other operating expenses, net | $ | 101 | $ | 119 | ||||
| Other revenue | (26 | ) | (34 | ) | ||||
| Other operating expenses net of other revenue | $ | 75 | $ | 85 | ||||
| Attachment 3 |
| NON-GAAP RECONCILIATIONS |
| To supplement the presentation of its financial results prepared in accordance with U.S. generally accepted accounting principles (GAAP), management uses certain non-GAAP measures to assess its financial condition, results of operations and cash flows. These measures are also widely used by the industry, the investment community and CRC's lenders. Although these are non-GAAP measures, the amounts included in the calculations were computed in accordance with GAAP. Certain items excluded from these non-GAAP measures are significant components in understanding and assessing CRC's financial performance, such as CRC's cost of capital and tax structure, as well as the effect of acquisition and development costs of CRC's assets. Management believes that the non-GAAP measures presented, when viewed in combination with CRC's financial and operating results prepared in accordance with GAAP, provide a more complete understanding of the factors and trends affecting the Company's performance. The non-GAAP measures presented herein may not be comparable to other similarly titled measures of other companies. Below are additional disclosures regarding each of these non-GAAP measures, including reconciliations to their most directly comparable GAAP measure where applicable. |
| ADJUSTED NET INCOME (LOSS) | ||||||||||||
| Adjusted net income (loss) and adjusted net income (loss) per share are non-GAAP measures. CRC defines adjusted net income as net income excluding the effects of significant transactions and events that affect earnings but vary widely and unpredictably in nature, timing and amount. These events may recur, even across successive reporting periods. Management believes these non-GAAP measures provide useful information to the industry and the investment community interested in comparing CRC's financial performance between periods. Reported earnings are considered representative of management's performance over the long term. Adjusted net income (loss) is not considered to be an alternative to net income (loss) reported in accordance with GAAP. The following table presents a reconciliation of the GAAP financial measure of net income and net income attributable to common stock per share to the non-GAAP financial measures of adjusted net income and adjusted net income per share. | ||||||||||||
| 1st Quarter | 4th Quarter | 1st Quarter | ||||||||||
| ($ millions, except per share amounts) | 2026 | 2025 | 2025 | |||||||||
| Net (loss) income | $ | (711 | ) | $ | 12 | $ | 115 | |||||
| Unusual, infrequent and other items: | ||||||||||||
| Non-cash derivative loss (gain) on Brent based commodity contracts | 792 | (95 | ) | (22 | ) | |||||||
| Non-cash derivative loss on natural gas derivative contracts | 12 | 22 | — | |||||||||
| Asset impairment | — | 57 | — | |||||||||
| Severance and termination costs | 25 | 12 | 2 | |||||||||
| Merger-related costs | 1 | 20 | 3 | |||||||||
| Loss on early extinguishment of debt | 21 | — | 1 | |||||||||
| Offshore platform expense | 10 | 12 | — | |||||||||
| Measurement period adjustments | — | — | 1 | |||||||||
| Other, net | 8 | 11 | (9 | ) | ||||||||
| Total unusual, infrequent and other items | 869 | 39 | (24 | ) | ||||||||
| Income tax (benefit) provision of adjustments at the combined tax rate | (79 | ) | (11 | ) | 7 | |||||||
| Adjusted net income | $ | 79 | $ | 40 | $ | 98 | ||||||
| Net income (loss) per share – basic | $ | (8.02 | ) | $ | 0.14 | $ | 1.27 | |||||
| Net income (loss) per share – diluted | $ | (8.02 | ) | $ | 0.14 | $ | 1.26 | |||||
| Adjusted net income per share – basic | $ | 0.89 | $ | 0.47 | $ | 1.08 | ||||||
| Adjusted net income per share – diluted | $ | 0.88 | $ | 0.47 | $ | 1.07 | ||||||
| ADJUSTED EBITDAX | ||||||||||||
| CRC defines adjusted EBITDAX as earnings before interest expense; income taxes; depreciation, depletion and amortization; exploration expense; other unusual, infrequent and out-of-period items; and other non-cash items. CRC believes this measure provides useful information in assessing its financial condition, results of operations and cash flows and is widely used by the industry, the investment community and its lenders. Although this is a non-GAAP measure, the amounts included in the calculation were computed in accordance with GAAP. Certain items excluded from this non-GAAP measure are significant components in understanding and assessing CRC’s financial performance, such as its cost of capital and tax structure, as well as depreciation, depletion and amortization of CRC's assets. This measure should be read in conjunction with the information contained in CRC’s financial statements prepared in accordance with GAAP. A version of adjusted EBITDAX is a material component of certain of its financial covenants under CRC's Revolving Credit Facility and is provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP. These materials include forward-looking non-GAAP financial measures, including adjusted EBITDAX. CRC is unable to provide a reconciliation of such forward-looking non-GAAP measures to the most directly comparable forward-looking GAAP financial measures because certain information needed to reconcile these measures is dependent on future events, many of which are outside of CRC’s control and cannot be reasonably predicted at this time. These items include, but are not limited to, changes in working capital, the timing and amount of capital accruals, and other non-cash or unusual items. Accordingly, a quantitative reconciliation is not available without unreasonable efforts. The following table represents a reconciliation of the GAAP financial measures of net income and net cash provided by operating activities to the non-GAAP financial measure of adjusted EBITDAX. CRC has included non-GAAP measures of adjusted EBITDAX for its oil and gas segment and its carbon management segment below. Management believes these segment non-GAAP measures are useful for investors to understand the results of our core businesses. | ||||||||||||
| 1st Quarter | 4th Quarter | 1st Quarter | ||||||||||
| ($ millions, except per BOE amounts) | 2026 | 2025 | 2025 | |||||||||
| Net (loss) income | $ | (711 | ) | $ | 12 | $ | 115 | |||||
| Interest and debt expense | 29 | 29 | 27 | |||||||||
| Depreciation, depletion and amortization | 133 | 129 | 131 | |||||||||
| Income tax (benefit) provision | (49 | ) | 11 | 47 | ||||||||
| Exploration expense | — | 1 | — | |||||||||
| Interest income | (1 | ) | (5 | ) | (3 | ) | ||||||
| Equity loss from unconsolidated subsidiaries | 2 | 1 | 1 | |||||||||
| Unusual, infrequent and other items (1) | 869 | 39 | (24 | ) | ||||||||
| Non-cash items | ||||||||||||
| Accretion expense | 27 | 29 | 29 | |||||||||
| Stock-based compensation | 7 | 6 | 6 | |||||||||
| Pension and post-retirement benefits | (2 | ) | (1 | ) | (1 | ) | ||||||
| Adjusted EBITDAX | $ | 304 | $ | 251 | $ | 328 | ||||||
| Net cash provided by operating activities | $ | 99 | $ | 235 | $ | 186 | ||||||
| Cash interest payments | 1 | 42 | 11 | |||||||||
| Cash interest received | (1 | ) | (5 | ) | (3 | ) | ||||||
| Exploration expense | — | 1 | — | |||||||||
| Working capital changes | 205 | (22 | ) | 134 | ||||||||
| Adjusted EBITDAX | $ | 304 | $ | 251 | $ | 328 | ||||||
| Net (loss) income per Boe | $ | (51.19 | ) | $ | 0.96 | $ | 9.09 | |||||
| Adjusted EBITDAX per Boe | $ | 21.89 | $ | 19.85 | $ | 25.92 | ||||||
| (1) See Adjusted Net Income (Loss) reconciliation. | ||||||||||||
| SEGMENT ADJUSTED EBITDAX | ||||||||||||
| This measure should be read in conjunction with Note 16 Segment Information in CRC’s 2025 Annual Report. A reconciliation of the non-GAAP measure of segment adjusted EBITDAX cannot be reconciled to the comparable measure of operating cash flow prepared in accordance with GAAP without unreasonable effort. | ||||||||||||
| Oil and Natural Gas Segment | 1st Quarter | 4th Quarter | 1st Quarter | |||||||||
| ($ millions) | 2026 | 2025 | 2025 | |||||||||
| Segment profit | $ | 281 | $ | 46 | $ | 266 | ||||||
| Depreciation, depletion and amortization | 128 | 127 | 126 | |||||||||
| Exploration expense | — | 1 | — | |||||||||
| Accretion expense | 27 | 29 | 29 | |||||||||
| Adjusted income items(1) | 3 | 66 | 1 | |||||||||
| Adjusted EBITDAX - Oil and Natural Gas | $ | 439 | $ | 269 | $ | 422 | ||||||
| Carbon Management Segment | ||||||||||||
| Segment loss | $ | (12 | ) | $ | (20 | ) | $ | (25 | ) | |||
| Interest on contingent liability (related to Carbon TerraVault JV) | 3 | 3 | 3 | |||||||||
| Equity loss from unconsolidated subsidiary | 1 | 2 | 1 | |||||||||
| Adjusted income items(1) | — | — | — | |||||||||
| Adjusted EBITDAX - Carbon Management | $ | (8 | ) | $ | (15 | ) | $ | (21 | ) | |||
| (1) Certain amounts previously reported in the Q4 2025 earnings release have been corrected. This correction relates to reporting of adjusted income items in Carbon Management in Q1 2025 and this amount was reclassified to Oil and Natural Gas in Q1 2026. | ||||||||||||
| FREE CASH FLOW | ||||||||||||
| Management uses free cash flow, which is defined by CRC as net cash provided by operating activities less capital investments, as a measure of liquidity. The following table presents a reconciliation of CRC's net cash provided by operating activities to free cash flow. | ||||||||||||
| 1st Quarter | 4th Quarter | 1st Quarter | ||||||||||
| ($ millions) | 2026 | 2025 | 2025 | |||||||||
| Net cash provided by operating activities | $ | 99 | $ | 235 | $ | 186 | ||||||
| Capital investments | (131 | ) | (120 | ) | (55 | ) | ||||||
| Free cash flow | $ | (32 | ) | $ | 115 | $ | 131 | |||||
| FREE CASH FLOW BEFORE NET CHANGES IN OPERATING ASSETS AND LIABILITIES | ||||||||||||
| Management uses free cash flow before changes in operating assets and liabilities, which is defined by CRC as net cash provided by operating activities less net changes in operating assets and liabilities and capital investments, as a measure of liquidity. The following table presents a reconciliation of CRC's net cash provided by operating activities to free cash flow before net changes in operating assets and liabilities. | ||||||||||||
| 1st Quarter | 4th Quarter | 1st Quarter | ||||||||||
| ($ millions) | 2026 | 2025 | 2025 | |||||||||
| Net cash provided by operating activities | $ | 99 | $ | 235 | $ | 186 | ||||||
| Net changes in operating assets and liabilities | 148 | (24 | ) | 66 | ||||||||
| Net cash provided by operating activities before net changes in operating assets and liabilities | 247 | 211 | 252 | |||||||||
| Capital investments | (131 | ) | (120 | ) | (55 | ) | ||||||
| Free cash flow before net changes in operating assets and liabilities | $ | 116 | $ | 91 | $ | 197 | ||||||
| ADJUSTED GENERAL & ADMINISTRATIVE EXPENSES | ||||||||||||
| Management uses a measure called adjusted general and administrative (G&A) expenses and adjusted G&A per BOE to provide useful information to investors interested in comparing CRC's costs between periods and performance to its peers. | ||||||||||||
| 1st Quarter | 4th Quarter | 1st Quarter | ||||||||||
| ($ millions) | 2026 | 2025 | 2025 | |||||||||
| General and administrative expenses | $ | 106 | $ | 95 | $ | 72 | ||||||
| Stock-based compensation | (7 | ) | (6 | ) | (6 | ) | ||||||
| Adjusted G&A expenses | $ | 99 | $ | 89 | $ | 66 | ||||||
| G&A per BOE | $ | 7.63 | $ | 7.51 | $ | 5.69 | ||||||
| Adjusted G&A per BOE | $ | 7.13 | $ | 7.04 | $ | 5.22 | ||||||
| TOTAL OPERATING REVENUES BEFORE NET (LOSS) GAIN FROM COMMODITY DERIVATIVES | ||||||||||
| Management uses a measure called total operating revenues before net (loss) gain from commodity derivatives, which is calculated as the difference between total operating revenues less net (loss) gain from commodity derivatives. | ||||||||||
| 1st Quarter | 4th Quarter | 1st Quarter | ||||||||
| ($ millions) | 2026 | 2025 | 2025 | |||||||
| Total operating revenues | $ | 119 | $ | 924 | $ | 912 | ||||
| Less: Net (loss) gain from commodity derivatives | (848 | ) | 126 | 6 | ||||||
| Total operating revenues before net (loss) gain from commodity derivatives | $ | 967 | $ | 798 | $ | 906 | ||||
| MARGIN FROM PURCHASED COMMODITIES | ||||||||||||
| Management uses a measure called margin from purchased commodities, which is calculated as the difference between revenue from purchased commodities and costs related to purchased commodities. This non-GAAP measure excludes transportation costs. | ||||||||||||
| 1st Quarter | 4th Quarter | 1st Quarter | ||||||||||
| ($ millions) | 2026 | 2025 | 2025 | |||||||||
| Revenue from purchased commodities | $ | 41 | $ | 60 | $ | 64 | ||||||
| Costs related to purchased commodities | (23 | ) | (47 | ) | (50 | ) | ||||||
| Margin from purchased commodities | $ | 18 | $ | 13 | $ | 14 | ||||||
| ELECTRICITY REVENUE NET OF ELECTRICITY GENERATION EXPENSES | ||||||||||||
| Management uses a measure called electricity revenue net of electricity generation expenses, which is calculated as the difference between electricity revenue and electricity generation expenses. | ||||||||||||
| 1st Quarter | 4th Quarter | 1st Quarter | ||||||||||
| ($ millions) | 2026 | 2025 | 2025 | |||||||||
| Electricity revenue | $ | 11 | $ | 52 | $ | 22 | ||||||
| Electricity generation expenses | (5 | ) | (12 | ) | (10 | ) | ||||||
| Electricity revenue net of electricity generation expenses | $ | 6 | $ | 40 | $ | 12 | ||||||
| OTHER OPERATING EXPENSES NET OF OTHER REVENUE | ||||||||||||
| Management uses a measure called other operating expenses net of other revenue, which is calculated as the difference between other operating expenses, net and other revenue. | ||||||||||||
| 1st Quarter | 4th Quarter | 1st Quarter | ||||||||||
| ($ millions) | 2026 | 2025 | 2025 | |||||||||
| Other operating expenses, net(1) | $ | 54 | $ | 82 | $ | 33 | ||||||
| Other revenue | (10 | ) | (7 | ) | (6 | ) | ||||||
| Other operating expenses net of other revenue | $ | 44 | $ | 75 | $ | 27 | ||||||
| (1) Other operating expenses, net includes carbon management expenses beginning in 2025. | ||||||||||||
| Attachment 4 | ||||||
| PRODUCTION STATISTICS | ||||||
| 1st Quarter | 4th Quarter | 1st Quarter | ||||
| Net Production Per Day | 2026 | 2025 | 2025 | |||
| Oil (MBbl/d) | ||||||
| San Joaquin Basin | 96 | 82 | 84 | |||
| Los Angeles Basin | 17 | 17 | 18 | |||
| Uinta Basin | 3 | 1 | — | |||
| Other Basins | 8 | 9 | 9 | |||
| Total | 124 | 109 | 111 | |||
| NGLs (MBbl/d) | ||||||
| San Joaquin Basin | 10 | 9 | 10 | |||
| Total | 10 | 9 | 10 | |||
| Natural Gas (MMcf/d) | ||||||
| San Joaquin Basin | 95 | 97 | 101 | |||
| Los Angeles Basin | 1 | 1 | 1 | |||
| Sacramento Basin | 10 | 11 | 12 | |||
| Uinta Basin | 8 | 1 | — | |||
| Other Basins | 3 | 3 | 3 | |||
| Total | 117 | 113 | 117 | |||
| Total Net Production (MBoe/d) | 154 | 137 | 141 | |||
| Gross Operated and Net Non-Operated | 1st Quarter | 4th Quarter | 1st Quarter | |||
| Production Per Day | 2026 | 2025 | 2025 | |||
| Oil (MBbl/d) | ||||||
| San Joaquin Basin | 103 | 88 | 90 | |||
| Los Angeles Basin | 21 | 21 | 22 | |||
| Uinta Basin | 4 | 1 | — | |||
| Other Basins | 9 | 10 | 11 | |||
| Total | 137 | 120 | 123 | |||
| NGLs (MBbl/d) | ||||||
| San Joaquin Basin | 10 | 11 | 10 | |||
| Other Basins | 1 | — | — | |||
| Total | 11 | 11 | 10 | |||
| Natural Gas (MMcf/d) | ||||||
| San Joaquin Basin | 127 | 130 | 134 | |||
| Los Angeles Basin | 6 | 6 | 7 | |||
| Sacramento Basin | 13 | 14 | 15 | |||
| Uinta Basin | 11 | 1 | — | |||
| Other Basins | 3 | 4 | 3 | |||
| Total | 160 | 155 | 159 | |||
| Total Gross Production (MBoe/d) | 175 | 157 | 160 | |||
| Attachment 5 | ||||||||||||
| PRICE STATISTICS | ||||||||||||
| 1st Quarter | 4th Quarter | 1st Quarter | ||||||||||
| 2026 | 2025 | 2025 | ||||||||||
| Oil ($ per Bbl) | ||||||||||||
| Realized price with derivative settlements | $ | 69.37 | $ | 64.27 | $ | 72.01 | ||||||
| Realized price without derivative settlements | $ | 74.53 | $ | 61.14 | $ | 73.57 | ||||||
| NGLs ($/Bbl) | $ | 44.98 | $ | 42.86 | $ | 54.64 | ||||||
| Natural gas ($/Mcf) | ||||||||||||
| Realized price with derivative settlements | $ | 3.56 | $ | 3.91 | $ | 4.12 | ||||||
| Realized price without derivative settlements | $ | 3.56 | $ | 3.91 | $ | 4.12 | ||||||
| Index Prices | ||||||||||||
| Brent oil ($/Bbl) | $ | 77.90 | $ | 63.08 | $ | 74.92 | ||||||
| WTI oil ($/Bbl) | $ | 71.93 | $ | 59.14 | $ | 71.42 | ||||||
| NYMEX average monthly settled price ($/MMBtu) | $ | 5.04 | $ | 3.55 | $ | 3.65 | ||||||
| Realized Prices as Percentage of Index Prices | ||||||||||||
| Oil with derivative settlements as a percentage of Brent | 89 | % | 102 | % | 96 | % | ||||||
| Oil without derivative settlements as a percentage of Brent | 96 | % | 97 | % | 98 | % | ||||||
| Oil with derivative settlements as a percentage of WTI | 96 | % | 109 | % | 101 | % | ||||||
| Oil without derivative settlements as a percentage of WTI | 104 | % | 103 | % | 103 | % | ||||||
| NGLs as a percentage of Brent | 58 | % | 68 | % | 73 | % | ||||||
| NGLs as a percentage of WTI | 63 | % | 72 | % | 77 | % | ||||||
| Natural gas with derivative settlements as a percentage of NYMEX contract month average | 71 | % | 110 | % | 113 | % | ||||||
| Natural gas without derivative settlements as a percentage of NYMEX contract month average | 71 | % | 110 | % | 113 | % | ||||||
| Attachment 6 | ||||||||||
| FIRST QUARTER 2026 DRILLING ACTIVITY | ||||||||||
| San Joaquin | Los Angeles | Ventura | Sacramento | |||||||
| Wells Drilled | Basin | Basin | Basin | Basin | Total | |||||
| Development Wells | ||||||||||
| Primary | 1 | — | — | — | 1 | |||||
| Waterflood | 17 | — | — | — | 17 | |||||
| Steamflood | 44 | — | — | — | 44 | |||||
| Total (1) | 62 | — | — | — | 62 | |||||
| (1) Includes steam injectors and drilled but uncompleted wells, which are not included in the SEC definition of wells drilled. | ||||||||||
