California Resources Corporation Reports Second Quarter 2026 Financial and Operating Results

Strengthens California's Leading Energy Platform Through Strategic Acquisition

Sustainable Operational Efficiency Gains Enhance 2026 Outlook and Further Reduces Estimated Long-Term Maintenance Capital

LONG BEACH, Calif., Aug. 10, 2026 (GLOBE NEWSWIRE) -- California Resources Corporation (NYSE: CRC) today reported its financial and operating results for the second quarter of 2026. The Company plans to host a conference call and webcast at 1 p.m. ET (10 a.m. PT) on Monday, August 10, 2026. Conference call details can be found within this release.

Highlights

• Delivered average net production of 149 thousand barrels of oil equivalent per day (MBoe/d) (81% oil)
• Reported net income of $514 million which includes the non-cash gain from changes in the fair value of outstanding commodity derivatives, adjusted net income1 of $88 million and $338 million of adjusted EBITDAX1
• Generated net cash provided by operating activities of $263 million or $300 million of net cash provided by operating activities before net changes in operating assets and liabilities1  
• Delivered $114 million of free cash flow1 or $151 million of free cash flow before net changes in operating assets and liabilities1
• Returned $36 million to shareholders through dividends2
• Ended the quarter with $1,279 million in borrowing capacity and $43 million in available cash and cash equivalents3, representing $1,322 million of liquidity1, 3

Other Highlights

• Announced the signing of a definitive purchase agreement to acquire Crimson Midstream Holdings, LLC (“Crimson”) from CorEnergy Infrastructure Trust, Inc. for total cash consideration of $63 million, subject to customary adjustments. See California Resources Corporation Expands Integrated California Energy Infrastructure Platform Through Strategic Midstream Acquisition for additional information
• Lowered California long-term maintenance capital outlook by reducing drilling, completions and workover capital expectations by approximately 5% to a $450 million to $475 million range with six drilling rigs, compared to seven previously
• Optimized capital structure, reduced annual interest payments and extended maturities through recent $550 million offering of 7.250% senior notes due 2035 (2035 Senior Notes) and subsequent redemption of all remaining 8.250% senior notes due 2029 (2029 Senior Notes)
• Announced the Golden Valley Technology Hub project, a proposed data center development in partnership with Beacon Data Centers (Beacon), at CRC's Elk Hills field. See www.goldenvalleytechhub.com for additional information
• Implemented more than 100% of the annual Berry merger synergy target, representing $103 million of annualized savings six months ahead of schedule
• Achieved first carbon dioxide (CO2) injection and revenue at Carbon TerraVault I (CTV I), California's inaugural carbon capture and storage (CCS) project. See Carbon TerraVault Provides Second Quarter 2026 Update for additional information

"Our teams are executing exceptionally well, delivering durable operational improvements across our asset base,” said Francisco Leon, CRC’s President and Chief Executive Officer. “Recent efficiency gains and continued Berry synergy capture are strengthening our long-term outlook. Specifically, we are now able to maintain flat California production with fewer rigs and less maintenance capital, creating operational and financial momentum into 2027 and beyond.

"Today, we also announced the planned acquisition of Crimson’s California pipeline systems and storage assets, a strategic infrastructure investment that strengthens our California platform. In parallel, our team continued to advance the Golden Valley Technology Hub with Beacon, leveraging CRC’s assets to meet California’s growing AI demand for reliable power. These developments strengthen CRC’s integrated energy platform, reinforce our commitment to California and create long-term value for our shareholders, Californians and the communities we serve.”

Second Quarter 2026 Results

• Operating expenses and general and administrative expenses were in line with expectations reflecting solid execution and the ongoing capture of Berry merger-related synergies
• Invested total capital of $149 million including drilling, completions and workover capital1 of $101 million; total capital was higher than initial expectations driven by a 25% increase in drilling activity across the California portfolio
• Built approximately 137 thousand barrels of oil (MBo) of inventory due to temporary takeaway constraints, equivalent to approximately 1.5 MBo/d, which, together with weaker differentials and higher operating and transportation costs, reduced second quarter adjusted EBITDAX1 and net cash provided by operating activities before net changes in operating assets and liabilities1 by approximately $25 million. The substantial majority of this inventory was sold in July 2026
  
  

Select Production, Price and Financial Results and Non-GAAP Measures 2nd Quarter  1st Quarter($ in millions except production and prices)  2026    2026 Net oil production per day (MBbl/d)  120    124 Realized oil price without derivative settlements ($ per Bbl) $91.55   $74.53 Realized oil price with derivative settlements ($ per Bbl)1 $76.43   $69.37 Net NGL production per day (MBbl/d)  10    10 Realized NGL price ($ per Bbl) $49.62   $44.98 Net natural gas production per day (Mmcf/d)  115    117 Realized natural gas price ($ per Mcf) $1.84   $3.56 Net total production per day (MBoe/d)  149    154       Margin from purchased commodities1 $11   $18 Electricity revenue net of electricity generation expenses1 $(4)  $6 Net gain (loss) from commodity sales derivatives1 $205   $(848)Other operating expenses net of other revenue1 $56   $44 

Select Financial Statement Data and Non-GAAP Measures: 2nd Quarter  1st Quarter($ and shares in millions, except per share amounts)  2026    2026 Total operating revenues before net (loss) gain from commodity derivatives1 $1,092   $967       Operating costs $347   $365 General and administrative expenses $97   $106 Adjusted general and administrative expenses1 $89   $99 Taxes other than on income $66   $67 Transportation costs $30   $26 Operating income (loss) $511   $(711)Interest and debt expense, net $28   $29 Income tax benefit $(56)  $(49)Deferred income tax benefit $(55)  $(50)Net income (loss) $514   $(711)Weighted-average common shares outstanding - diluted  89.3    88.7 Net income (loss) per share - diluted $5.76   $(8.02)      Adjusted net income1 $88   $79 Adjusted net income per share1- diluted $0.99   $0.88 Net cash provided by operating activities $263   $99 Net cash provided by operating activities before net changes in operating assets and liabilities1 $300   $247 Capital investments $149   $131 Adjusted EBITDAX1 $338   $304 Free cash flow1 $114   $(32)

2026 Guidance Highlights

CRC reaffirmed its full-year 2026 total capital outlook and reduced expected full-year 2026 drilling, completions and workover capital by $10 million to $370 million to $390 million while targeting approximately 1% entry-to-exit gross production growth. Stronger operating efficiencies across the portfolio, together with the impact of lower estimated oil prices on production-sharing contracts, provide increased confidence in achieving these targets and strengthen the Company’s long-term outlook.

CRC expects to operate an average of five rigs in California and one rig in Utah during the second half of 2026 and currently holds sufficient permits to support its 2026 capital program. The Company also continues to build its permit inventory in support of anticipated 2027 operations. Following the closing of the pending transaction, CRC expects to provide additional financial and operating guidance. The following table provides key current third-quarter and full-year 2026 financial and operating guidance4. See Attachment 2 for additional information.

CRC Guidance3Q26ETotal Year
2026ENet Production (MBoe/d)151 - 154150 - 155Percentage Oil80%80%Capital Investments ($ millions)$150 - $170$520 - $560Adjusted EBITDAX1($ millions)$285 - $325$1,200 - $1,300

Shareholder Returns

On August 10, 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 September 4, 2026. The dividend is expected to be paid on September 18, 2026.

In the second quarter 2026, CRC returned $36 million in dividends to shareholders. Since 2021, the Company has returned approximately $1,655 million to shareholders, including $1,180 million in share repurchases and $475 million in dividends2.

Balance Sheet and Liquidity

In June 2026, CRC completed an offering of $550 million of 2035 Senior Notes. The proceeds, together with cash on hand, were used to redeem all $550 million of the Company’s outstanding 2029 Senior Notes for total consideration of $573 million. The redemption resulted in a $28 million loss on extinguishment of debt, including a $23 million premium paid and $5 million write-off of unamortized debt issuance costs, net of unamortized premium. Following this redemption, CRC had outstanding $750 million of 2034 Senior Notes and $550 million of 2035 Senior Notes.

As of June 30, 2026, CRC had liquidity of $1,322 million1,3, consisting of $43 million in available cash and cash equivalents3 and $1,279 million of available borrowing capacity under its Revolving Credit Facility (which reflects $1,460 million of borrowing capacity less $181 million of outstanding letters of credit and no balance outstanding on the Revolving Credit Facility).

Participation in Upcoming Investor Conferences

CRC is scheduled to participate in the following events in August and September 2026:

• Citi 2026 Natural Resources Conference, August 12 and 13, Las Vegas, NV
• Seaport 15th Annual Summer Investor Conference, August 18, Virtual
• Daniel Energy Partners, Executive Series, September 1 to 3, Pebble Beach, CA
• Barclays 40th Annual Energy-Power Conference, September 9 and 10, New York, NY
• NYSE Energy & Utilities Investor Access Day, September 24, Virtual
• PEP Energy Conference 2026, September 29, Austin, TX

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 Monday, August 10, 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/10209577/1041fba52bd. 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 3Q26 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 $13 million.
4 3Q26 guidance assumes Brent price of $83.14 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $2.95 per mcf. Total year 2026 guidance assumes Brent price of $84.51 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $3.55 per mcf.

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 www.crc.com.

About Carbon TerraVault

Carbon TerraVault (CTV), CRC’s carbon management business, develops services to capture, transport and permanently store carbon dioxide (CO2) for its customers. CTV is advancing a portfolio of carbon capture and storage (CCS) projects, including CTV I, which is now operational and injecting CO2 for permanent sequestration in a depleted reservoir deep underground. For more information, visit www.carbonterravault.com.

Forward-Looking Statements

Information set forth in this communication, including financial estimates and statements as to the effects of the Berry Merger and the Crimson acquisition, 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 and the Crimson acquisition, 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, Crimson acquisition 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
[email protected] Bonus (Media)
714-874-7732
[email protected]

Attachment 1STATEMENTS OF OPERATIONS, SELECT FINANCIAL INFORMATION             2nd Quarter 1st Quarter 2nd Quarter Six Months Six Months($ and shares in millions, except per share amounts)  2026   2026   2025   2026   2025            Statements of Operations:          Revenues          Oil, natural gas and natural gas liquids sales $1,056  $905  $702  $1,961  $1,516 Net gain (loss) from commodity derivatives  205   (848)  157   (643)  163 Revenue from marketing of purchased commodities  26   41   56   67   120 Electricity revenue  6   11   58   17   80 Other revenue  4   10   5   14   11 Total operating revenues  1,297   119   978   1,416   1,890            Operating Expenses          Operating costs  347   365   295   712   611 General and administrative expenses  97   106   79   203   151 Depreciation, depletion and amortization  131   133   128   264   259 Taxes other than on income  66   67   47   133   117 Costs related to marketing of purchased commodities  15   23   41   38   91 Electricity generation expenses  10   5   5   15   15 Transportation costs  30   26   20   56   40 Accretion expense  27   27   28   54   57 Net loss on natural gas purchase derivatives  5   24   3   29   (3)Measurement period adjustments, net  (2)  —   —   (2)  1 Other operating expenses, net  60   54   65   114   98 Total operating expenses  786   830   711   1,616   1,437 Operating Income (Loss)  511   (711)  267   (200)  453            Non-Operating (Expenses) Income          Interest and debt expense, net  (28)  (29)  (25)  (57)  (52)Equity loss from unconsolidated subsidiaries  (2)  (2)  —   (4)  (1)Loss on early extinguishment of debt  (28)  (21)  —   (49)  (1)Other non-operating income, net  5   3   —   8   5            Income (Loss) Before Income Taxes  458   (760)  242   (302)  404 Income tax benefit (provision)  56   49   (70)  105   (117)Net Income (Loss) $514  $(711) $172  $(197) $287            Net income per share - basic $5.79  $(8.02) $1.93  $(2.22) $3.20 Net income per share - diluted $5.76  $(8.02) $1.92  $(2.22) $3.18            Adjusted net income $88  $79  $98  $167  $196 Adjusted net income per share - basic $0.99  $0.89  $1.10  $1.88  $2.18 Adjusted net income per share - diluted(1) $0.99  $0.88  $1.10  $1.87  $2.17            Weighted-average common shares outstanding - basic  88.8   88.7   89.0   88.7   89.8 Weighted-average common shares outstanding - diluted(1)  89.3   88.7   89.4   88.7   90.3            Effective tax rate (12)%  6%  29%  35%  29%           

             2nd Quarter 1st Quarter 2nd Quarter Six Months Six Months($ in millions)  2026   2026   2025   2026   2025 Cash Flow Data:          Net cash provided by operating activities $263  $99  $165  $362  $351 Net cash used in investing activities $(153) $(136) $(51) $(289) $(130)Net cash used in financing activities $(94) $(55) $(256) $(149) $(521)             June 30, December 31,      ($ in millions)  2026   2025       Select Balance Sheet Information:          Total current assets $697  $938       Property, plant and equipment, net $5,923  $5,905       Total current liabilities $1,055  $1,050       Long-term debt, net $1,281  $1,283       Noncurrent asset retirement obligations $923  $913       Total stockholders' equity $3,402  $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. Adjusted net income per share - diluted for the six months ended June 30, 2026 is calculated using weighted average shares outstanding of 89.3 million shares.

GAINS AND LOSSES FROM COMMODITY DERIVATIVES     2nd Quarter 1st Quarter 2nd Quarter Six Months Six Months($ millions)  2026   2026   2025   2026   2025            Non-cash gain (loss) from commodity sales derivatives $370  $(792) $140  $(422) $162 Net settlements and premiums  (165)  (56)  17   (221)  1 Net gain (loss) from commodity sales derivatives $205  $(848) $157  $(643) $163                 Non-cash (gain) loss from natural gas purchase derivatives $(20) $12  $(4) $(8) $(22)Settlements  25   12   7   37   19 Net loss (gain) from natural gas purchase derivatives $5  $24  $3  $29  $(3)                      Non-cash gain (loss) from combined commodity derivatives $390  $(804) $144  $(414) $184 Net settlements and premiums from combined derivatives  (190)  (68)  10   (258)  (18)Net gain (loss) from combined commodity derivatives $200  $(872) $154  $(672) $166            

CAPITAL INVESTMENTS                       2nd Quarter 1st Quarter 2nd Quarter Six Months Six Months($ millions)  2026   2026   2025   2026  2025               Facilities(1) $38  $37  $17  $75  $25Drilling and completions  77   53   19   130   34Workovers  24   17   15   41   34Other  6   9   —   15   —Oil and natural gas segment  145   116   51   261   93Carbon management segment  3   12   5   15   7Corporate and other  1   3   —   4   11Total capital investment $149  $131  $56  $280  $111 

LIQUIDITY     ($ millions) June 30, 2026 December 31, 2025Available cash and cash equivalents(1) $43  $117      Revolving credit facility:    Borrowing capacity  1,460   1,460 Outstanding letters of credit  (181)  (176)Availability $1,279  $1,284      Liquidity $1,322  $1,401      (1) Excludes restricted cash of $13 million and $15 million at June 30, 2026 and December 31, 2025, respectively.

      Attachment 2CRC GUIDANCE Consolidated
3Q26E Oil and Natural Gas
Segment Carbon Management
SegmentNet production (MBoe/d) 151 - 154    Net oil production (%) 80%    Operating costs ($ millions) $360 - $380 $360 - $380  General and administrative expenses ($ millions) $82 - $92 $12 - $16 $0 - $2Adjusted general and administrative expenses ($ millions) $75 - $85 $12 - $16 $0 - $2Depreciation, depletion and amortization ($ millions) $126 - $138 $120 - $130  Capital investments ($ millions) $150 - $170 $150 - $165 $0 - $2Adjusted EBITDAX ($ millions) $285 - $325           Margin from purchased commodities ($ millions)(1) $11 - $15    Electricity revenue net of electricity generation expenses ($ millions) $18 - $24    Other operating expenses net of other revenue ($ millions)(2) $20 - $32   $4 - $12Transportation costs ($ millions) $30 - $35 $20 - $24  Taxes other than on income ($ millions) $70 - $80 $62 - $68  Interest and debt expense ($ millions) $27 - $31           Other Assumptions:      Brent ($/Bbl) $83.14    NYMEX ($/Mcf) $2.95    Price realization oil - % of Brent: 91% - 94%    Price realization NGLs - % of Brent: 48% - 54%    Price realization natural gas - % of NYMEX: 97% - 103%           Current income tax provision ($ millions)(3) $(2) - $2    Effective tax rate 33% - 37%    

CRC GUIDANCE Consolidated
2026E Oil and Natural Gas
Segment Carbon Management
SegmentNet production (MBoe/d) 150 - 155    Net oil production (%) 80%    Operating costs ($ millions) $1,425 - $1,475 $1,425 - $1,475  General and administrative expenses ($ millions) $365 - $385 $51 - $63 $4 - 10Adjusted general and administrative expenses ($ millions) $335 - $350 $51 - $63 $4 - 10Depreciation, depletion and amortization ($ millions) $520 - $540 $500 - $510  Capital investments ($ millions) $520 - $560 $505 - $530 $10 - $18Adjusted EBITDAX ($ millions) $1,200 - $1,300           Margin from purchased commodities ($ millions) (1) $50 - $65    Electricity revenue net of electricity generation expenses ($ millions) $20 - $40    Other operating expenses net of other revenue ($ millions) (2) $135 - $145   $20 - $30Transportation costs ($ millions) $115 - $125 $75 - $85  Taxes other than on income ($ millions) $272 - $282 $240 - $246  Interest and debt expense ($ millions) $115 - $125           Other Assumptions:      Brent ($/Bbl) $84.51    NYMEX ($/Mcf) $3.55    Price realization oil - % of Brent: 92% - 96%    Price realization NGLs - % of Brent: 52% - 57%    Price realization natural gas - % of NYMEX: 80% - 85%           Current income tax provision ($ millions) (3) $(2) - $2    Effective tax rate 33% - 37%    

(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

  3Q26E  Consolidated Oil and Natural Gas
Segment Carbon Management
Segment($ millions) Low High Low High Low HighGeneral and administrative expenses $82  $92  $12 $16 $— $2Equity-settled stock-based compensation  (7)  (7)  —  —  —  —Estimated adjusted general and administrative expenses $75  $85  $12 $16 $— $2             

       Consolidated  3Q26E($ millions) Low HighRevenue from marketing of purchased commodities $32  $48 Costs related to marketing of purchased commodities  (21)  (33)Margin from purchased commodities $11  $15      

       Consolidated  3Q26E($ millions) Low HighOther operating expenses, net $23  $39 Other revenue  (3)  (7)Other operating expenses net of other revenue $20  $32      

  2026E  Consolidated Oil and Natural Gas
Segment Carbon Management
Segment($ millions) Low High Low High Low HighGeneral and administrative expenses $365  $385  $51 $63 $4 $10Equity-settled stock-based compensation  (30)  (35)  —  —  —  —Estimated adjusted general and administrative expenses $335  $350  $51 $63 $4 $10             

       Consolidated  2026E($ millions) Low HighRevenue from marketing of purchased commodities $138  $163 Costs related to marketing of purchased commodities  (88)  (98)Margin from purchased commodities $50  $65      

       Consolidated  2026E($ millions) Low HighOther operating expenses, net $156  $174 Other revenue  (21)  (29)Other operating expenses net of other revenue $135  $145      

Attachment 3NON-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.       2nd Quarter 1st Quarter 2nd Quarter Six Months Six Months($ millions, except per share amounts)  2026   2026   2025   2026   2025 Net income (loss) $514  $(711) $172  $(197) $287 Unusual, infrequent and other items:          Non-cash derivative (gain) loss on Brent based commodity contracts  (370)  792   (140)  422   (162)Non-cash derivative (gain) loss on natural gas derivative contracts  (20)  12   —   (8)  — Severance and termination costs  —   25   6   25   8 Merger-related costs  1   1   —   2   3 Loss on early extinguishment of debt  28   21   —   49   1 Offshore platform expense  10   10   —   20   — Litigation and settlements  —   —   25   —   25 Measurement period adjustments, net  (2)  —   —   (2)  1 Other, net  12   8   6   20   (3)Total unusual, infrequent and other items  (341)  869   (103)  528   (127)Income tax (benefit) provision of adjustments at the combined tax rate  (85)  (79)  29   (164)  36            Adjusted net income $88  $79  $98  $167  $196            Net income (loss) per share – basic $5.79  $(8.02) $1.93  $(2.22) $3.20 Net income (loss) per share – diluted $5.76  $(8.02) $1.92  $(2.22) $3.18 Adjusted net income per share – basic $0.99  $0.89  $1.10  $1.88  $2.18 Adjusted net income per share – diluted $0.99  $0.88  $1.10  $1.87  $2.17 

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.

       2nd Quarter 1st Quarter 2nd Quarter Six Months Six Months($ millions, except per BOE amounts)  2026   2026   2025   2026   2025 Net (loss) income $514  $(711) $172  $(197) $287 Interest and debt expense  28   29   25   57   52 Depreciation, depletion and amortization  131   133   128   264   259 Income tax (benefit) provision  (56)  (49)  70   (105)  117 Interest income  —   (1)  (2)  (1)  (5)Equity loss from unconsolidated subsidiaries  2   2   —   4   1 Exploration expense  27   —   1   27   1 Unusual, infrequent and other items(1)  (341)  869   (103)  528   (127)Non-cash items          Accretion expense  27   27   28   54   57 Stock-based compensation  8   7   7   15   13 Pension and post-retirement benefits  (2)  (2)  (2)  (4)  (3)Adjusted EBITDAX $338  $304  $324  $642  $652            Net cash provided by operating activities $263  $99  $165  $362  $351 Cash interest payments  26   1   39   27   50 Cash interest received  —   (1)  (2)  (1)  (5)Cash income taxes  16   —   39   16   39 Exploration expense  27   —   1   27   1 Working capital changes  6   205   82   211   216 Adjusted EBITDAX $338  $304  $324  $642  $652            Net (loss) income per Boe $37.93  $(51.19) $13.78  $(7.18) $11.42 Adjusted EBITDAX per Boe $24.94  $21.89  $25.95  $23.40  $25.93            (1)See Adjusted Net Income (Loss) reconciliation.

SEGMENT ADJUSTED EBITDAX       This measure should be read in conjunction with Note 16Segment Informationin 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 2nd Quarter 1st Quarter 2nd Quarter Six Months Six Months($ millions)  2026   2026   2025   2026   2025 Segment profit $427  $281  $194  $711  $460 Depreciation, depletion and amortization  124   128   121   251   247 Exploration expense  27   —   1   27   1 Accretion expense  27   27   28   54   57 Adjusted income items  3   3   2   7   3 Adjusted EBITDAX - Oil and Natural Gas $608  $439  $346  $1,050  $768            Carbon Management Segment          Segment loss $(13) $(12) $(20) $(25) $(45)Interest on contingent liability (related to Carbon TerraVault JV)  3   3   2   6   5 Equity loss from unconsolidated subsidiary  2   1   1   3   2 Adjusted EBITDAX - Carbon Management $(8) $(8) $(17) $(16) $(38)                      

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.             2nd Quarter 1st Quarter 2nd Quarter Six Months Six Months($ millions)  2026   2026   2025   2026   2025            Net cash provided by operating activities $263  $99  $165  $362  $351 Capital investments  (149)  (131)  (56)  (280)  (111)Free cash flow $114  $(32) $109  $82  $240            

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.             2nd Quarter 1st Quarter 2nd Quarter Six Months Six Months($ millions)  2026   2026   2025   2026   2025            Net cash provided by operating activities $263  $99  $165  $362  $351 Net changes in operating assets and liabilities  37   148   56   185   122 Net cash provided by operating activities before net changes in operating assets and liabilities  300   247   221  $547  $473 Capital investments  (149)  (131)  (56)  (280)  (111)Free cash flow before net changes in operating assets and liabilities $151  $116  $165  $267  $362 

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.             2nd Quarter 1st Quarter 2nd Quarter Six Months Six Months($ millions)  2026   2026   2025   2026   2025 General and administrative expenses $97  $106  $79  $203  $151 Stock-based compensation  (8)  (7)  (7)  (15)  (13)Adjusted G&A expenses $89  $99  $72  $188  $138            G&A per BOE $7.16  $7.63  $6.33  $7.40  $6.01 Adjusted G&A per BOE $6.57  $7.13  $5.77  $6.85  $5.49            

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.             2nd Quarter 1st Quarter 2nd Quarter Six Months Six Months($ millions) 2026  2026  2025 2026 2025Total operating revenues $1,297 $119  $978 $1,416  $1,890Less: Net gain (loss) from commodity derivatives  205  (848)  157  (643)  163Total operating revenues before net gain (loss) from commodity derivatives $1,092 $967  $821 $2,059  $1,727            

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.             2nd Quarter 1st Quarter 2nd Quarter Six Months Six Months($ millions)  2026   2026   2025   2026   2025 Revenue from purchased commodities $26  $41  $56  $67  $120 Costs related to purchased commodities  (15)  (23)  (41)  (38)  (91)Margin from purchased commodities $11  $18  $15  $29  $29             

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.             2nd Quarter 1st Quarter 2nd Quarter Six Months Six Months($ millions)  2026   2026   2025   2026   2025 Electricity revenue $6  $11  $58  $17  $80 Electricity generation expenses  (10)  (5)  (5)  (15)  (15)Electricity revenue net of electricity generation expenses $(4) $6  $53  $2  $65             

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.             2nd Quarter 1st Quarter 2nd Quarter Six Months Six Months($ millions)  2026   2026   2025   2026   2025 Other operating expenses, net $60  $54  $65  $114  $98 Other revenue  (4)  (10)  (5)  (14)  (11)Other operating expenses net of other revenue $56  $44  $60  $100  $87            

Attachment 4PRODUCTION STATISTICS                       2nd Quarter 1st Quarter 2nd Quarter Six Months Six MonthsNet Production Per Day 2026 2026 2025 2026 2025Oil (MBbl/d)          San Joaquin Basin 93 96 83 94 84Los Angeles Basin 15 17 17 16 17Uinta Basin 3 3 — 3 —Other Basins 9 8 9 9 9Total 120 124 109 122 110           NGLs (MBbl/d)          San Joaquin Basin 10 10 10 10 10Total 10 10 10 10 10           Natural Gas (MMcf/d)          San Joaquin Basin 93 95 96 95 99Los Angeles Basin 1 1 1 1 1Sacramento Basin 10 10 12 10 12Uinta Basin 9 8 — 9 —Other Basins 2 3 2 2 2Total 115 117 111 117 114           Total Net Production (MBoe/d) 149 154 137 152 139           

Gross Operated and Net Non-Operated 2nd Quarter 1st Quarter 2nd Quarter Six Months Six MonthsProduction Per Day 2026 2026 2025 2026 2025Oil (MBbl/d)          San Joaquin Basin 102 103 89 102 90Los Angeles Basin 21 21 21 21 21Uinta Basin 4 4 — 4 —Other Basins 9 9 11 10 11Total 136 137 121 137 122           NGLs (MBbl/d)          San Joaquin Basin 10 10 11 10 11Uinta Basin 1 — — 1 —Other Basins — 1 — — —Total 11 11 11 11 11           Natural Gas (MMcf/d)          San Joaquin Basin 128 127 134 128 134Los Angeles Basin 6 6 6 6 6Sacramento Basin 13 13 14 13 15Uinta Basin 12 11 — 11 —Other Basins 3 3 4 3 3Total 162 160 158 161 158           Total Gross Production (MBoe/d) 174 175 158 175 159            

Attachment 5PRICE STATISTICS            2nd Quarter 1st Quarter 2nd Quarter Six Months Six Months   2026   2026   2025   2026   2025 Oil ($ per Bbl)          Realized price with derivative settlements $76.43  $69.37  $66.73  $72.88  $69.39 Realized price without derivative settlements $91.55  $74.53  $65.07  $82.97  $69.34            NGLs ($/Bbl) $49.62  $44.98  $42.41  $47.29  $48.60            Natural gas ($/Mcf)          Realized price without derivative settlements $1.84  $3.56  $2.79  $2.72  $3.46            Index Prices          Brent oil ($/Bbl) $96.87  $77.90  $66.76  $87.38  $70.84 WTI oil ($/Bbl) $92.79  $71.93  $63.74  $82.36  $67.58 NYMEX average monthly settled price ($/MMBtu) $2.90  $5.04  $3.44  $3.97  $3.55            Realized Prices as Percentage of Index Prices          Oil with derivative settlements as a percentage of Brent  79%  89%  100%  83%  98%Oil without derivative settlements as a percentage of Brent  95%  96%  97%  95%  98%           Oil with derivative settlements as a percentage of WTI  82%  96%  105%  88%  103%Oil without derivative settlements as a percentage of WTI  99%  104%  102%  101%  103%           NGLs as a percentage of Brent  51%  58%  64%  54%  69%NGLs as a percentage of WTI  53%  63%  67%  57%  72%           Natural gas with derivative settlements as a percentage of NYMEX contract month average  63%  71%  81%  69%  97%           Natural gas without derivative settlements as a percentage of NYMEX contract month average  63%  71%  81%  69%  97%

Attachment 6SECOND QUARTER 2026 DRILLING ACTIVITY              San Joaquin Los Angeles Sacramento Uinta Other  Wells Drilled Basin Basin Basin Basin Basins Total             Development Wells            Primary 22 1 — 1 — 24Waterflood 33 1 — — — 34Steamflood 39 — — — — 39Total(1) 94 2 — 1 — 97
(1)Includes steam injectors and drilled but uncompleted wells, which are not included in the SEC definition of wells drilled.