EX-99.1 2 a2025q2erex991.htm EX-99.1 Document


crclogo_greenxgray-text.jpg                                

California Resources Corporation Reports Second Quarter 2025 Financial and Operating Results

Company Raises 2025E Production and Adjusted EBITDAX Guidance, Reduces Drilling, Completions and Workover Capital Program

Returned Quarterly Record of $287 Million to Shareholders

LONG BEACH, California, August 5, 2025 - California Resources Corporation (NYSE: CRC) reported financial and operating results for the second quarter of 2025. The Company is hosting a conference call and webcast at 1 p.m. ET (10 a.m. PT) on Wednesday, August 6, 2025. Conference call details can be found within this release.

Second Quarter Highlights

•Delivered average net production of 137 thousand barrels of oil equivalent per day (MBoe/d) (80% oil), at the high end of guidance, with drilling, completions and workover capital of $34 million, and added a second rig in Kern County
•Reported net income of $172 million and net income per diluted share of $1.92; reported adjusted net income1 of $98 million and adjusted net income per diluted share of $1.10
•Generated net cash provided by operating activities of $165 million, $109 million in free cash flow1 and $324 million in adjusted EBITDAX1, exceeding quarterly guidance
•Ended the second quarter of 2025 with $56 million in available cash3 (excluding restricted cash), $983 million in available borrowing capacity and $1,039 million of liquidity1
•Returned a record $287 million to shareholders2, including $252 million in share repurchases and $35 million in dividends

Other Highlights

•Implemented the targeted $235 million in annualized Aera merger-related synergies since July 2024; expecting to realize $185 million in 2025 and the remaining $50 million in 2026
•Lowered 2025 drilling, completions and workover capital program by $5 million, and raised the midpoint of 2025 net production and adjusted EBITDAX1 guidance to 136 MBoe/d (79% oil) and $1,235 million, respectively
•Received authorization to construct from the U.S. Environmental Protection Agency (EPA) for carbon dioxide (CO2) injection wells for the 26R storage reservoir. See Carbon TerraVault's Second Quarter 2025 Update for additional information

Page 1

"We delivered a very solid second quarter that reflects the strength of our assets, the discipline of our execution, and our focus on long-term value creation," said CRC President and CEO Francisco Leon. “Our team's ability to scale efficiently has nearly doubled our revenue and strengthened profitability – while fully implementing merger synergies ahead of schedule. That performance gives us the flexibility to sharpen our focus on what matters most: driving returns, building resilience, and setting up CRC for continued success. I want to thank all CRC employees for their dedication and efforts that continue to make CRC a different kind of energy company.”

Second Quarter 2025 Comparative Financial Results

Selected Production, Price and Financial Results and non-GAAP measures
2nd Quarter
1st Quarter
($ in millions except production and prices)
20252025
Net oil production per day (MBbl/d)109 111 
Realized oil price with derivative settlements ($ per Bbl)$66.73 $72.01 
Net NGL production per day (MBbl/d)10 10 
Realized NGL price ($ per Bbl)$42.41 $54.64 
Net natural gas production per day (Mmcf/d)111 117 
Realized natural gas price with derivative settlements ($ per Mcf)$2.79 $4.12 
Net total production per day (MBoe/d)137 141 
Margin from purchased commodities1
$15 $14 
Electricity margin1
$53 $12 
Net gain from commodity derivatives
$157 $6 
Other operating expenses net of other revenue1
$60 $27 
Selected Financial Statement Data and non-GAAP measures:2nd Quarter1st Quarter
($ and shares in millions, except per share amounts)20252025
Statements of Operations:
Total operating revenues
$978 $912 
Operating costs$295 $316 
General and administrative expenses$79 $72 
Adjusted general and administrative expenses1
$72 $66 
Taxes other than on income$47 $70 
Transportation costs$20 $20 
Operating income
$267 $186 
Interest and debt expense, net
$25 $27 
Income tax provision
$70 $47 
Deferred income tax provision$6 $35 
Net income
$172 $115 
Weighted-average common shares outstanding - diluted89.4 91.2 
Net income per share - diluted
$1.92 $1.26 
Non-GAAP Measures, Cash Flow and Select Balance Sheet Data
Adjusted net income1
$98 $98 
Adjusted net income per share1 - diluted
$1.10 $1.07 
Adjusted EBITDAX1
$324 $328 
Net cash provided by operating activities$165 $186 
Capital investments$56 $55 
Free cash flow1
$109 $131 
Cash and cash equivalents$72 $214 

Page 2

Guidance

The following table provides select third quarter 2025E and full year 2025E guidance4. CRC expects to run a two-rig program in the second half of 2025. CRC currently holds permits in excess of its planned 2025 capital program requirements. See Attachment 2 for CRC's third quarter 2025E and full year 2025E guidance.

3Q25E
Total Year
2025E
Net Production (MBoe/d)135-139134 - 138
Percentage Oil
~79%~79%
Capital Investments ($ millions)
$84 - $108$280 - $330
Adjusted EBITDAX1 ($ millions)
$310 - $340$1,195 - $1,275

Shareholder Returns

CRC is committed to returning cash to shareholders through dividends and repurchases of its common stock. In line with this strategy, CRC’s Board of Directors has extended its Share Repurchase Program through June 30, 2026. As of June 30, 2025, CRC had $205 million remaining for share repurchases under its authorized Share Repurchase Program.

During the second quarter of 2025, CRC paid dividends of $35 million and repurchased 5.52 million common shares for $252 million (an average price of $45.73 per share)2. Share repurchases include 4.95 million shares from IKAV Impact S.a.r.l (IKAV), representing 23% of the total shares issued in the Aera Merger, at $46.00 per share, for $228 million. CRC funded shareholder returns with cash on hand.

On August 5, 2025, CRC's Board of Directors declared a quarterly cash dividend2 of $0.3875 per share of common stock, payable to shareholders of record on August 27, 2025. The dividend is expected to be paid on September 12, 2025.

Since May 2021, the Company has returned nearly $1.5 billion to shareholders2, including approximately $1.1 billion in share repurchases and $337 million in dividends.

Balance Sheet and Liquidity

CRC plans to redeem or refinance the $122 million outstanding balance of its 2026 Senior Notes in the second half of 2025.

CRC's borrowing base under its Revolving Credit Facility is $1,500 million. As of June 30, 2025, CRC had $56 million in available cash and cash equivalents4, $983 million of available borrowing capacity under its Revolving Credit Facility (which reflects $1,150 million of borrowing capacity less $167 million of outstanding letters of credit) and liquidity1 of $1,039 million.

Page 3

Participation in Upcoming Investor Conference

CRC plans to participate in the following events in August and September 2025:

•Citi’s 2025 Global Energy & Power Conference, August 13 - 14, Las Vegas, NV
•Barclays 39th Annual CEO Energy-Power Conference, September 2 - 4, New York, NY
•Goldman Sachs Global Sustainability Forum, September 25, New York, NY
•PEP Energy Conference September 29 - 30, Austin, TX

CRC’s presentation materials will be available on the day of the event on its website. See "Events and Presentations" under the Investor Relations section on www.crc.com.

Conference Call Details

A conference call and webcast is scheduled for 1 p.m. ET (10 a.m. PT) on Wednesday, August 6, 2025. 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/10200260/ff49e72f54. 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 operating costs per BOE, 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, liquidity and adjusted general and administrative expenses including reconciliations to their most directly comparable GAAP measure, where applicable. See Attachment 2 for the 3Q25E and 2025E estimates of the non-GAAP measures of adjusted EBITDAX and adjusted general and administrative expenses, including reconciliations to its most directly comparable GAAP measure.
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 excise taxes. Commissions paid on share repurchases were not significant in all periods presented.
3 Excludes restricted cash of $16 million at June 30, 2025.
4 3Q25E guidance assumes Brent price of $66.00 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $3.40 per mcf. Total year 2025E guidance assumes Brent price of $68.00 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $3.65 per mcf. CRC's share of production under PSC contracts decreases when commodity prices rise and increases when prices fall.

About California Resources Corporation

California Resources Corporation (CRC) is an independent energy and carbon management company committed to 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, is developing projects to capture, transport and permanently store CO2 for its CRC affiliates and its customers. CTV is engaged in a series of proposed CCS projects that if developed will inject CO2 captured from industrial sources into depleted oil and gas reservoirs deep underground for permanent sequestration. For more information, visit carbonterravault.com.

Page 4

Forward-Looking Statements

This document contains statements that CRC believes to be “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than historical facts are forward-looking statements, and include statements regarding CRC's future financial position, business strategy, projected revenues, earnings, costs, capital expenditures and plans and objectives 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 subject to risks and uncertainties that could cause actual results to differ materially from those expressed 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 Securities and Exchange Commission. 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 benefits in connection with the Aera 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 prevent oil and gas activities or the development of CRC’s carbon management segment; changes in business strategy and capital plan; 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; 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 filing date, and CRC undertakes no obligation to update this information. This document 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:
Joanna Park (Investor Relations)
818-661-3731
Joanna.Park@crc.com
Daniel Juck (Investor Relations)
818-661-6045
Daniel.Juck@crc.com
Hailey Bonus (Media)
714-874-7732
Hailey.Bonus@crc.com

Page 5

Attachment 1
STATEMENTS OF OPERATIONS, SELECT FINANCIAL INFORMATION
2nd Quarter1st Quarter2nd QuarterSix MonthsSix Months
($ and shares in millions, except per share amounts)20252025202420252024
Statements of Operations:  
Revenues  
Oil, natural gas and natural gas liquids sales
$702 $814 $412 $1,516 $841 
Net gain (loss) from commodity derivatives157 6 5 163 (66)
Revenue from marketing of purchased commodities56 64 51 120 125 
Electricity sales58 22 36 80 51 
Other revenue
5 6 10 11 17 
     Total operating revenues978 912 514 1,890 968 
Operating Expenses
Operating costs295 316 156 611 332 
General and administrative expenses79 72 63 151 120 
Depreciation, depletion and amortization128 131 53 259 106 
Asset impairment— — 13 — 13 
Taxes other than on income47 70 39 117 77 
Costs related to marketing of purchased commodities41 50 43 91 97 
Electricity generation expenses5 10 14 15 22 
Transportation costs20 20 17 40 37 
Accretion expense 28 29 13 57 25 
Net loss (gain) on natural gas purchase derivatives
3 (6)1 (3)2 
Measurement period adjustments, net
— 1 — 1 — 
Other operating expenses, net65 33 65 98 110 
     Total operating expenses711 726 477 1,437 941 
Net gain on asset divestitures
— — 1 — 7 
Operating Income 267 186 38 453 34 
Non-Operating (Expenses) Income
Interest and debt expense, net
(25)(27)(17)(52)(30)
Loss from investment in unconsolidated subsidiaries— (1)(4)(1)(7)
Loss on early extinguishment of debt— (1)— (1)— 
Other non-operating income (loss), net— 5 (6)5 (5)
Income Before Income Taxes242 162 11 404 (8)
Income tax (provision) benefit
(70)(47)(3)(117)6 
Net Income $172 $115 $8 $287 $(2)
Net income per share - basic $1.93 $1.27 $0.12 $3.20 $(0.03)
Net income per share - diluted$1.92 $1.26 $0.11 $3.18 $(0.03)
Adjusted net income$98 $98 $42 $196 $96 
Adjusted net income per share - basic$1.10 $1.08 $0.62 $2.18 $1.40 
Adjusted net income per share - diluted$1.10 $1.07 $0.60 $2.17 $1.35 
Weighted-average common shares outstanding - basic89.0 90.6 68.1 89.8 68.6 
Weighted-average common shares outstanding - diluted89.4 91.2 70.0 90.3 68.6 
Effective tax rate29 %29 %27 %29 %75 %
Page 6

2nd Quarter1st Quarter2nd QuarterSix MonthsSix Months
($ in millions)20252025202420252024
Cash Flow Data:
Net cash provided by operating activities$165 $186 $97 $351 $184 
Net cash used in investing activities$(51)$(79)$(33)$(130)$(82)
Net cash (used in) provided by financing activities$(256)$(265)$564 $(521)$433 
June 30,December 31,
($ in millions)20252024
Select Balance Sheet Information:
Total current assets$728 $1,024 
Property, plant and equipment, net$5,560 $5,680 
Deferred tax asset$33 $73 
Total current liabilities$928 $980 
Long-term debt, net$888 $1,132 
Noncurrent asset retirement obligations$969 $995 
Deferred tax liability$185 $113 
Total stockholders' equity$3,407 $3,538 

GAINS AND LOSSES FROM COMMODITY DERIVATIVES
2nd Quarter1st Quarter2nd QuarterSix MonthsSix Months
($ millions)20252025202420252024
Non-cash commodity derivative gain (loss)$140 $22 $11 $162 $(48)
Net received (paid) on settled commodity derivatives17 (16)(6)1 (18)
      Net gain (loss) from commodity derivatives$157 $6 $5 $163 $(66)
Non-cash derivative (gain) loss $(4)$(18)$(3)$(22)$(4)
Net paid on settled commodity derivatives7 12 4 19 6 
      Net loss (gain) on natural gas purchase derivatives
$3 $(6)$1 $(3)$2 
Page 7

CAPITAL INVESTMENTS
2nd Quarter1st Quarter2nd QuarterSix MonthsSix Months
($ millions)20252025202420252024
Facilities$17 $8 $17 $25 $31 
Drilling and completions
19 15 18 34 33 
Workovers
15 19 11 34 18 
Oil and natural gas segment
51 42 46 93 82 
Carbon management segment
5 2 (2)7 2 
Corporate and other— 11 (10)11 4 
Total capital investment
$56 $55 $34 $111 $88 
Page 8

Attachment 2
THIRD QUARTER 2025E GUIDANCE
Consolidated
3Q25E
Oil and Natural Gas
Segment
Carbon Management
Segment
Net production (MBoe/d)
135-139
Net oil production (%)
~79%
Operating costs ($ millions)
$300 - $330
 
$300 - $330
General and administrative expenses ($ millions)
$74 - $88
$10 - $14
$2 - $4
Adjusted general and administrative expenses ($ millions)
$70 - $80
$10 - $14
$2 - $4
Depreciation, depletion and amortization ($ millions)
$131 - $135
$112 - $118
Capital investments ($ millions)
$84 - $108
$71 - $89
$8 - $10
Drilling, completion and workover ($ millions)
$46 - $54
$46 - $54
Adjusted EBITDAX ($ millions)
$310 - $340
$280 - $305
$(15) - $(11)
Margin from purchased commodities ($ millions) (1)
$17 - $25
Electricity margin ($ millions) (2)
$75 - $100
Other operating expenses net of other revenue ($ millions) (3)
$0 - $20
$7 - $13
Transportation costs ($ millions)
$20 - $26
$9 - $13
Taxes other than on income ($ millions)
$64 - $74
$52 - $57
Interest and debt expense ($ millions)
$25 - $29
Other Assumptions:
Brent ($/Bbl)$66.00
NYMEX ($/Mcf)$3.40
Price realization oil - % of Brent:
94% to 100%
Price realization NGLs - % of Brent:
54% to 60%
Price realization natural gas - % of NYMEX:
94% to 104%
Deferred income taxes
95% - 105%
Effective tax rate
29%


Page 9

THIRD QUARTER 2025E GUIDANCE
Consolidated
2025E		Oil and Natural Gas
 2025E		Carbon Management
2025E
Net production (MBoe/d)
134 - 138
Net oil production (%)
~79%
Operating costs ($ millions)
$1,220 - $1,280
$1,220 - $1,280
General and administrative expenses ($ millions)
$310 - $335
$40 - $55
$10 - $15
Adjusted general and administrative expenses ($ millions)
$290 - $310
$40 - $55
$10 - $15
Depreciation, depletion and amortization ($ millions)
$515 - $530
$447 - $462
Capital investments ($ millions)
$280 - $330
$245 - $275
$20 - $30
Drilling, completion and workover ($ millions)
$160 - $175
$160 - $175
Adjusted EBITDAX ($ millions)
$1,195 - $1,275
$1,210 - $1,340
($68) - ($64)
Margin from purchased commodities ($ millions) (1)
$65 - $80
Electricity margin ($ millions) (2)
$175 - $190
Other operating expenses net of other revenue ($ millions) (3)
$80 - $135
$45 - $60
Transportation costs ($ millions)
$82 - $94
$39 - $43
Taxes other than on income ($ millions)
$235 - $260
$190 - $220
Interest and debt expense ($ millions)
$100 - $110
Commodity Assumptions:
Brent ($/Bbl)$68.00
NYMEX ($/Mcf)$3.65
Price realization oil - % of Brent:
95% to 99%
Price realization NGLs - % of Brent:
60% to 68%
Price realization natural gas - % of NYMEX:
90% to 110%
Deferred income taxes
43% - 49%
Effective tax rate
29%

(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) Electricity margin is calculated as the difference between electricity sales and electricity generation expenses.
(3) 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.
FORWARD LOOKING NON-GAAP RECONCILIATIONS
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. We have included a reconciliation of the GAAP measure of segment profit to segment adjusted EBITDAX.
3Q25E
Consolidated
Oil and Natural Gas
Segment
Carbon Management
Segment
($ millions)LowHighLowHighLowHigh
General and administrative expenses$74 $88 $10 $14 $2 $4 
Equity-settled stock-based compensation(4)(8)— — — — 
Estimated adjusted general and administrative expenses$70 $80 $10 $14 $2 $4 
Page 10


Total Year 2025E
Consolidated
Oil and Natural Gas Segment
Carbon Management Segment
($ millions)LowHighLowHighLowHigh
General and administrative expenses$310 $335 $40 $55 $10 $15 
Equity-settled stock-based compensation(20)(25)— — — — 
Estimated adjusted general and administrative expenses$290 $310 $40 $55 $10 $15 
Consolidated
3Q25E
2025E
($ millions)LowHighLowHigh
Net income$75 $79 $375 $405 
Interest and debt expense
2528100110
Interest income
(1)(3)(5)(13)
Depreciation, depletion and amortization131135515530
Income taxes2932150170
Exploration expense
— — — 6
Loss from investment on unconsolidated subsidiaries
— — (5)5
Unusual, infrequent and other items21 31 (60)$(80)
Other non-cash items
   Accretion expense2630105117
   Stock-settled compensation482025
Estimated adjusted EBITDAX$310 $340 $1,195 $1,275 
Net cash provided by operating activities$303 $323 $820 $860 
Cash interest6888108
Cash income taxes4 6 4553
Working capital changes(3)3 242254
Estimated adjusted EBITDAX$310 $340 $1,195 $1,275 
Oil and Natural Gas Segment
3Q25E
2025E
($ millions)LowHighLowHigh
Segment profit$140 $150 $650 $750 
Depreciation, depletion and amortization112118447462
Unusual, infrequent and other items3 7 3 8 
Other non-cash items
   Accretion expense2530110120
Estimated adjusted EBITDAX$280 $305 $1,210 $1,340 
Carbon Management Segment
3Q25E
2025E
($ millions)LowHighLowHigh
Segment loss$(23)$(13)$(92)$(72)
Interest and debt expense, net51145
Loss from investment on unconsolidated subsidiary31103
Other non-cash items
Stock-settled compensation— — — — 
Estimated adjusted EBITDAX$(15)$(11)$(68)$(64)
Page 11

Consolidated
3Q25E
2025E
($ millions)LowHighLowHigh
Revenue from marketing of purchased commodities
$50 $65 $218 $256 
Costs related to marketing of purchased commodities
(33)(40)(153)(176)
Margin from purchased commodities
$17 $25 $65 $80 
Consolidated
3Q25E
2025E
($ millions)LowHighLowHigh
Electricity sales
$83 $115 $213 $235 
Electricity generation expenses
(8)(15)(38)(45)
Electricity margin
$75 $100 $175 $190 
Consolidated
3Q25E
2025E
($ millions)LowHighLowHigh
Other operating expenses, net
$— $25 $90 $160 
Other revenue
— (5)(10)(25)
Operating expenses net of other revenue
$— $20 $80 $135 
Page 12

Attachment 3
NON-GAAP FINANCIAL MEASURES AND 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. The non-GAAP measures include adjusted net income (loss), adjusted net income (loss) per share, adjusted EBITDAX, adjusted EBITDAX per Boe, adjusted EBITDAX for the oil and natural gas segment, adjusted EBITDAX for the carbon management business, net cash provided by operating activities before net changes in operating assets and liabilities, free cash flow, liquidity, adjusted general and administrative expenses and adjusted G&A per Boe. 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 Quarter1st Quarter2nd QuarterSix MonthsSix Months
($ millions, except per share amounts)20252025202420252024
Net income $172 $115 $8 $287 $(2)
Unusual, infrequent and other items:
Non-cash derivative (gain) loss
(140)(22)(11)(162)48 
Asset impairment— — 13 — 13 
Severance and termination costs6 2 1 8 1 
Aera merger-related costs
— 3 13 3 26 
Increased power and fuel costs due to power plant maintenance— — 15 — 36 
Net gain on asset divestitures— — (1)— (7)
Loss on early extinguishment of debt— 1 — 1 — 
Litigation and settlement related expenses
25 — 7 25 7 
Measurement period adjustments— 1 — 1 — 
Other, net6 (9)10 (3)12 
Total unusual, infrequent and other items(103)(24)47 (127)136 
Income tax provision (benefit) of adjustments at the blended tax rate
29 7 (13)36 (38)
Adjusted net income$98 $98 $42 $196 $96 
Net income (loss) per share – basic
$1.93 $1.27 $0.12 $3.20 $(0.03)
Net income (loss) per share – diluted
$1.92 $1.26 $0.11 $3.18 $(0.03)
Adjusted net income per share – basic
$1.10 $1.08 $0.62 $2.18 $1.40 
Adjusted net income per share – diluted
$1.10 $1.07 $0.60 $2.17 $1.35 
Page 13

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.

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. Management believes these segment non-GAAP measures are useful for investors to understand the results of the oil and gas business and its developing carbon management business.

2nd Quarter1st Quarter2nd QuarterSix MonthsSix Months
($ millions, except per BOE amounts)20252025202420252024
Net income $172 $115 $8 $287 $(2)
Interest and debt expense25 27 17 52 30 
Depreciation, depletion and amortization128 131 53 259 106 
Income tax provision70 47 3 117 (6)
Exploration expense1 — — 1 1 
Interest income(2)(3)(8)(5)(14)
Loss from investment in unconsolidated subsidiaries— 1 — 1 
Unusual, infrequent and other items (1)
(103)(24)47 (127)136 
Non-cash items
   Accretion expense28 29 13 57 25 
   Stock-based compensation7 6 6 13 11 
   Pension and post-retirement benefits(2)(1)— (3)1 
Adjusted EBITDAX$324 $328 $139 $652 $288 
Net cash provided by operating activities$165 $186 $97 $351 $184 
Cash interest payments39 11 1 50 22 
Cash interest received(2)(3)(8)(5)(14)
Cash income taxes39 — 4 39 26 
Exploration expenditures1 — — 1 1 
Adjustments to working capital changes82 134 45 216 69 
Adjusted EBITDAX$324 $328 $139 $652 $288 
Adjusted EBITDAX per Boe$25.95 $25.92 $20.23 $25.93 $20.86 
(1) See Adjusted Net Income (Loss) reconciliation.

Page 14

SEGMENT ADJUSTED EBITDAX
CRC defines segments adjusted EBITDAX as segment profit adjusted for depreciation, depletion and amortization; exploration expense, other unusual, infrequent and out-of-period items and other non-cash items. CRC believes this segment measure provides useful information in assessing the financial results of each segment. Although this is a non-GAAP measure, the amounts included in the calculation were computed in accordance with GAAP. This measure should be read in conjunction with Note 16 Segment Information in CRC’s 2024 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 & Natural Gas Segment
2nd Quarter1st Quarter2nd QuarterSix MonthsSix Months
($ millions, except per BOE amounts)20252025202420252024
Segment profit$194 $266 $117 $460 $249 
Depreciation, depletion and amortization121 126 47 247 96 
Exploration expense1 — — 1 1 
Accretion expense28 29 13 57 25 
Adjusted income items2 1 28 3 42 
Adjusted EBITDAX - Oil and Natural Gas$346 $422 $205 $768 $413 
Carbon Management Segment
Segment loss$(20)$(25)$(24)$(45)$(38)
Interest on contingent liability (related to Carbon TerraVault JV)2 3 2 5 3 
Loss from investment in unconsolidated subsidiaries1 1 — 2 — 
Adjusted income items— — 1 — 1 
Adjusted EBITDAX - Carbon Management$(17)$(21)$(21)$(38)$(34)

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. CRC defines free cash flow after special items as free cash flow before transaction and integration costs from the Aera Merger.
2nd Quarter1st Quarter2nd QuarterSix MonthsSix Months
($ millions)20252025202420252024
Net cash provided by operating activities$165 $186 $97 $351 $184 
Capital investments(56)(55)(34)(111)(88)
Free cash flow$109 $131 $63 $240 $96 
Add: Aera merger-related costs
— 3 13 3 26 
Free cash flow after special items
$109 $134 $76 $243 $122 




Page 15

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 Quarter1st Quarter2nd QuarterSix MonthsSix Months
($ millions)20252025202420252024
General and administrative expenses$79 $72 $63 $151 $120 
Stock-based compensation(7)(6)(6)(13)(11)
Information technology infrastructure
— — (1)(3)
Other— — — — (1)
Adjusted G&A expenses$72 $66 $56 $138 $105 
Adjusted G&A per BOE$5.77 $5.22 $8.15 $5.49 $7.60 

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 and exudes transportation costs.
2nd Quarter1st Quarter2nd QuarterSix MonthsSix Months
($ millions)20252025202420252024
Revenue from purchased commodities
$56 $64 $51 $120 $125 
Costs related to purchased commodities
(41)(50)(43)(91)(97)
Margin from purchased commodities
$15 $14 $8 $29 $28 
ELECTRICITY MARGIN
Management uses a measure called electricity margin, which is calculated as the difference between electricity sales and electricity generation expenses.
2nd Quarter1st Quarter2nd QuarterSix MonthsSix Months
($ millions)20252025202420252024
Electricity sales
$58 $22 $36 $80 $51 
Electricity generation expenses
(5)(10)(14)(15)(22)
Electricity margin
$53 $12 $22 $65 $29 
OTHER OPERATING EXPENSES NET OF OTHER REVENUE
Management uses a measure called other operating expenses net of other revenue, which is calculated as the difference between other operating expenses, net and other revenue.
2nd Quarter1st Quarter2nd QuarterSix MonthsSix Months
($ millions)20252025202420252024
Other operating expenses, net
$65 $33 $65 $98 $110 
Other revenue
(5)(6)(10)(11)(17)
Other operating expenses net of other revenue
$60 $27 $55 $87 $93 
Page 16

LIQUIDITY
Management uses a measure called liquidity, which is defined as available cash and available borrowing capacity under our Revolving Credit Facility. CRC believes this measure provides a more comprehensive assessment of the Company’s immediate access to capital than cash alone and reflects management’s emphasis on maintaining financial flexibility and prudent liquidity risk management.
($ millions)June 30, 2025December 31, 2024
Available cash and cash equivalents(1)
$56 $354 
Revolving credit facility:
Borrowing capacity
1,150 1,150 
Outstanding letters of credit
(167)(167)
Availability
$983 $983 
Liquidity
$1,039 $1,337 
(1) Excludes restricted cash of $16 million and $18 million at June 30, 2025 and December 31, 2024, respectively.

Page 17

Attachment 4
PRODUCTION STATISTICS
2nd Quarter1st Quarter2nd QuarterSix MonthsSix Months
Net Production Per Day20252025202420252024
Oil (MBbl/d)
 San Joaquin Basin83 84 30 84 30 
 Los Angeles Basin17 18 17 17 17 
 Other Basins9 9 — 9 — 
 Total109 111 47 110 47 
NGLs (MBbl/d)
 San Joaquin Basin10 10 10 10 11 
 Total10 10 10 10 11 
Natural Gas (MMcf/d)
 San Joaquin Basin96 101 99 99 94 
 Los Angeles Basin1 1 1 1 1 
 Sacramento Basin12 12 14 12 14 
 Other Basins2 3 — 2 — 
 Total111 117 114 114 109 
Total Net Production (MBoe/d)137 141 76 139 76 
Gross Operated and Net Non-Operated2nd Quarter1st Quarter2nd QuarterSix MonthsSix Months
Production Per Day20252025202420252024
Oil (MBbl/d)
 San Joaquin Basin89 90 33 90 33 
 Los Angeles Basin21 22 24 21 24 
 Other Basins11 11 — 11 — 
 Total121 123 57 122 57 
NGLs (MBbl/d)
 San Joaquin Basin11 10 11 11 11 
 Other Basins— — — — — 
 Total11 10 11 11 11 
Natural Gas (MMcf/d)
 San Joaquin Basin134 134 125 134 127 
 Los Angeles Basin6 7 7 6 7 
 Sacramento Basin14 15 17 15 17 
 Other Basins4 3 — 3 — 
 Total158 159 149 158 151 
Total Gross Production (MBoe/d)158 160 93 159 93 
Page 18

Attachment 5
PRICE STATISTICS
2nd Quarter1st Quarter2nd QuarterSix MonthsSix Months
 20252025202420252024
Oil ($ per Bbl)
Realized price with derivative settlements$66.73 $72.01 $81.29 $69.39 $79.20 
Realized price without derivative settlements$65.07 $73.57 $83.14 $69.34 $81.63 
NGLs ($/Bbl)$42.41 $54.64 $46.96 $48.60 $48.76 
Natural gas ($/Mcf)
Realized price with derivative settlements$2.79 $4.12 $1.78 $3.46 $2.81 
Realized price without derivative settlements$2.79 $4.12 $1.78 $3.46 $2.81 
Index Prices
 Brent oil ($/Bbl)$66.76 $74.92 $85.00 $70.84 $83.42 
 WTI oil ($/Bbl)$63.74 $71.42 $80.57 $67.58 $78.77 
 NYMEX average monthly settled price ($/MMBtu)
$3.44 $3.65 $1.89 $3.55 $2.07 
Realized Prices as Percentage of Index Prices
Oil with derivative settlements as a percentage of Brent100 %96 %96 %98 %95 %
Oil without derivative settlements as a percentage of Brent97 %98 %98 %98 %98 %
Oil with derivative settlements as a percentage of WTI105 %101 %101 %103 %101 %
Oil without derivative settlements as a percentage of WTI102 %103 %103 %103 %104 %
NGLs as a percentage of Brent64 %73 %55 %69 %58 %
NGLs as a percentage of WTI67 %77 %58 %72 %62 %
Natural gas with derivative settlements as a percentage of NYMEX contract month average81 %113 %94 %97 %136 %
Natural gas without derivative settlements as a percentage of NYMEX contract month average81 %113 %94 %97 %136 %



Page 19

Attachment 6
SECOND QUARTER 2025 DRILLING ACTIVITY     
 San JoaquinLos AngelesVenturaSacramento 
Wells DrilledBasinBasinBasinBasinTotal
Development Wells     
Primary1———1
Waterflood23———23
Steamflood—————
Total (1)
24———24
SIX MONTHS 2025 DRILLING ACTIVITY
 San JoaquinLos AngelesVenturaSacramento 
Wells DrilledBasinBasinBasinBasinTotal
Development Wells
Primary4———4
Waterflood23———23
Steamflood—————
Total (1)
27———27
(1) Includes steam injectors and drilled but uncompleted wells, which are not included in the SEC definition of wells drilled.
Page 20