California Resources Corp
For the period ended Jun 30, 2025. Filed Aug 6, 2025.
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A company's report for each of its first three quarters. The financial statements are not audited. It shows how the business has moved since the last annual report, and what management says changed.
Jun 30, 2025 · Filed Aug 6, 2025
CRC$46.96+3.0%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-Q
Period ended 2025-03-31; filed 2025-05-07.
0001609253-25-000055
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-Q
Period ended 2025-06-30; filed 2025-08-06.
0001609253-25-000069
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 160 previous paragraphs and 166 current paragraphs.
86 unchanged; 36 reworded; 35 added; 36 removed; 2 previous and 9 current paragraphs rearranged.
Tables are not compared: 17 previous and 20 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (35)
Current report
During 2025, Brent prices were negatively affected by a succession of announcements by OPEC+ of its intention to return offline production to market at a much quicker pace than previously anticipated and concern over the state of global trade following a series of tariff announcements. Prices slightly increased in June 2025 as tensions between Iran and Israel became overtly military in nature and a concern developed that petroleum flowing through the Persian Gulf — and through the Strait of Hormuz, in particular — could ultimately be impacted.
Current report
Collectively, these factors introduced significant oil price volatility with Brent crude oil prices fluctuating between a low of approximately $60 per barrel in early May and a high of approximately $80 per barrel in mid-June.
Current report
Supply Chain and Inflation
Current report
We continued to experience relatively flat pricing from our suppliers in the first half of 2025 as compared to the prior year. Tariff policy changes by the U.S. government for both country of origin and material type remains uncertain. The United States recently expanded tariff rates on imported goods including a 50% tariff on the steel and aluminum value of imported products. These expanded tariff rates, if sustained, could increase our cost of oilfield goods and expand delivery lead times over the longer term. We have taken measures to limit the effects of price increases caused by the recent expansion of U.S. tariffs by entering into fixed price contracts with terms of one to three years for a significant majority of our materials and services based on our current expected development plans. We also pre-purchased inventory prior to the execution of the tariffs and continue to purchase from vendors who source domestic content to limit the impact of foreign tariffs on our business. Overall, we continue to expect minimal impact of tariffs in our supply chain in 2025. Assuming the current tariff regime remains in place or is expanded, our inventory, capital and operating costs could increase over the long-term.
Current report
During the first half of 2025, we have received total well permits for 139 workovers, 105 sidetracks and 4 deepenings. We have not received any permits for new wells in 2025.
Current report
Kern County EIR Litigation
Current report
On June 26, 2025, the Kern County Board of Supervisors certified a revised Environmental Impact Report (EIR) and approved an ordinance that authorizes the development of oil and natural gas wells in the county consistent with the revised EIR. Kern County is seeking the Trial Court’s determination that the revised EIR complies with the judgment and order of the Trial Court and decision of the Court of Appeal. After that, the Trial Court could lift the stay, subject to further potential appeals. The timing of when or if the Trial Court will take such action is uncertain. If the stay is lifted and no further stay is issued by the Court of Appeal, new well permitting could resume. However, there is no certainty we will obtain permits on that timeline or at all, or that the Trial Court and Court of Appeal will collectively lift the stay before a final, non-appealable ruling upholding the adequacy of the revised EIR is issued. These developments could further adversely affect our business, results of operations and financial condition.
Current report
Waste Emissions Charge
Current report
In May 2025, following a joint resolution of disapproval under the Congressional Review Act, the EPA issued a final rule to remove the Waste Emission Charge (WEC) regulations, originally adopted under the Inflation Reduction Act, from the Code of Federal Regulations. As a result, the fees associated with methane emissions from certain oil and gas facilities that would have been due to the EPA in September 2025 will not be collected. Although the underlying statute still requires a methane charge, An Act to Provide for Reconciliation Pursuant to Title II of H. Con. Res. 14th and commonly referred to as the One Big Beautiful Bill Act, postponed implementation from 2024 to 2034.
Current report
Water Injection
Current report
Our operations in the Wilmington Oil Field utilize injection wells to reinject produced water pursuant to waterflooding plans. CalGEM has issued a directive to reduce the injection well pressure in a gradual manner in accordance with a five-year injection reduction work plan. The first phase of reduction commenced July 1, 2024 and a second reduction began in January 2025. The next phase of reduction is currently on hold while we evaluate the impact of the previously implemented reductions together with CalGEM. The work plan may be adjusted and it is difficult to predict with accuracy the impact to production and reserves. However, we continue to estimate a negative impact on production of approximately 1 MBoe/d at the end of the current 5-year work plan. We also estimate that the net present value of our proved developed reserves would be negatively impacted by less than 1%. These estimates could change materially pending the results of future technical audits.
Current report
Our consolidated results of operations include the results of Aera beginning July 1, 2024, the closing date of the Aera Merger. For more information on the Aera Merger, see Part I, Item 1 – Financial Statements, Note 2 Aera Merger. The Aera Merger and related transactions have significantly impacted the comparability of our financial results for the six months ended 2024.
Current report
Electricity revenue — Electricity revenue increased by $36 million to $58 million for the three months ended June 30, 2025 compared to $22 million for the three months ended March 31, 2025. This increase was primarily a result of higher resource adequacy sales driven by increased seasonal pricing for the three months ended June 30, 2025 compared to the three months ended March 31, 2025, as well as downtime for maintenance that primarily impacted the three months ended March 31, 2025.
Current report
Costs related to marketing of purchased commodities — Costs related to marketing of purchased commodities for the three months ended June 30, 2025 were $41 million, which is a decrease of $9 million from $50 million for the three months ended March 31, 2025. This decrease was primarily due to lower natural gas prices, partially offset by increased volumes of purchased natural gas.
Current report
(a)See Part I, Item 1 – Financial Statements, Note 5 Lawsuits, Claims, Commitments and Contingenciesfor more information on a $25 million payment we made to CalGEM during the three months ended June 30, 2025.
Current report
(a)The increase in production primarily relates to the addition of the Aera fields on July 1, 2024. See Part I, Item 1 – Financial Statements, Note 2 Aera Mergerfor additional information.
Current report
Electricity revenue — Electricity revenue increased by $29 million to $80 million for the six months ended June 30, 2025 compared to $51 million for the six months ended June 30, 2024. This increase was primarily a result of higher pricing from resource adequacy contracts.
Current report
Energy operating costs — Energy operating costs for the six months ended June 30, 2025 were$181 million, which was an increase of $87 million from$94 million for the six months ended June 30, 2024. This increase was predominantly due to additional energy costs and natural gas used in our steamflood operations related to the addition of the Aera fields on July 1, 2024. Excluding $94 million related to the operation of the Aera fields, our energy operating costs would have been $87 million for the six months ended June 30, 2025. The decrease was primarily a result of lower energy and natural gas costs in the six months ended June 30, 2025 compared to the same prior year period.
Current report
Non-energy operating costs— Non-energy operating costs for the six months ended June 30, 2025 were$421 million, which was an increase of$190 million from$231 million for the six months ended June 30, 2024. The increase includes $191 million predominantly related to the addition of the Aera fields on July 1, 2024. Excluding the costs related to the Aera fields, our non-energy operating costs would have been $230 million for the six months ended June 30, 2025, which would be in line with the same prior year period.
Current report
General and administrative expenses — General and administrative (G&A) expenses were $151 million for the six months ended June 30, 2025 compared to $120 million for the six months ended June 30, 2024, which was an increase of $31 million. The increase was primarily due to additional compensation-related expense and other corporate expense resulting from the Aera Merger.
Current report
Asset impairments— During the six months ended June 30, 2024, we recognized a $13 million impairment for excess and obsolete materials and supplies related to our oilfield operations. We did not recognize an asset impairment during the six months ended June 30, 2025.
Current report
Taxes other than on income — Taxes other than on income for the six months ended June 30, 2025 were $117 million, which is an increase of $40 million from $77 million for the six months ended June 30, 2024. This increase was a result of higher greenhouse gas expense, production taxes and ad valorem taxes related to the Aera assets following the completion of the Aera Merger.
Current report
Accretion expense— Accretion expense for the six months ended June 30, 2025 was $57 million compared to $25 million for the six months ended June 30, 2024. The increase was primarily due to the addition of the Aera asset retirement liability assumed as of July 1, 2024 in connection with the Aera Merger.
Current report
Other operating expenses, net — Other operating expenses, net decreased $12 million to $98 million for the six months ended June 30, 2025 compared to $110 million for the six months ended June 30, 2024. For the six months ended June 30, 2025 and June 30, 2024, other operating expenses, net includes the following:
Current report
(a)See Part I, Item 1 – Financial Statements, Note 5 Lawsuits, Claims, Commitments and Contingenciesfor more information on a $25 million payment we made to CalGEM during the six months ended June 30, 2025.
Current report
Interest and debt expense, net— Interest and debt expense, net was $52 million for the six months ended June 30, 2025 compared to $30 million for the six months ended June 30, 2024. The increase was predominantly due to higher interest expense resulting from the issuance of our 2029 Senior Notes. In June 2024, we issued $600 million in aggregate principal amount of 2029 Senior Notes and in August 2024, we completed a follow-on offering of $300 million in aggregate principal amount of 2029 Senior Notes.
Current report
Production-Sharing Contracts
Current report
Oil — Brent prices were lower for the three months ended June 30, 2025 compared to the three months ended March 31, 2025 as well as for the six months ended June 30, 2025 compared to the six months ended June 30, 2024. See Business Environment and Industry Outlook above for more information on factors influencing Brent commodity prices for the periods presented.
Current report
Natural Gas — Natural gas prices decreased for the three months ended June 30, 2025 compared to the three months ended March 31, 2025 driven by seasonal demand changes and the effects of significant storage volumes. Natural gas prices increased for the six months ended June 30, 2025 compared to the six months ended June 30, 2024 driven by colder, late winter temperatures in early 2025.
Current report
Carbon management expenses increased for thesix months ended June 30, 2025 compared to the six months ended June 30, 2024 as a result of increased expenditure related to the evaluation of CCS projects and increased lease cost for the six months ended June 30, 2025.
Current report
On July 4, 2025, An Act to Provide for Reconciliation Pursuant to Title II of H. Con. Res. 14th and commonly referred to as the One Big Beautiful Bill Act was signed into law. This law contains several legislative changes including the reinstatement of full expensing for qualified assets placed in service after January 19, 2025. This law also reinstated the expensing all domestic research and development costs, including favorable transition rules, and increases the limitation on the amount of annual business interest expense which can be deducted each year. We expect these legislative changes will reduce our U.S. federal cash tax obligation by approximately $35 million in 2025 and the amount of U.S. federal taxes we would have otherwise owed in future years.
Current report
2026 Senior Notes Redemption
Current report
See Part I, Item 1 – Financial Statements, Note 4 Debtfor information on a partial redemption of our 2026 Senior Notes.
Current report
See Part I, Item 1 – Financial Statements, Note 10 Stockholders' Equity and Part II, Item 2 – Other Information, Unregistered Sales of Equity Securities and Use of Proceedsfor more information on our Share Repurchase Program including a repurchase of shares during the second quarter of 2025 from IKAV.
Current report
See Part I, Item 1 – Financial Statements, Note 10 Stockholders' Equityfor more information on our dividends. See Part I, Item 1 – Financial Statements, Note 16 Subsequent Eventsfor information on a dividend declared in August 2025.
Removed paragraphs (36)
Previous report
In early 2025, OPEC+ began unwinding prior voluntary production cuts, which added approximately 400,000 barrels per day to the global oil market. This substantial supply boost contributed to a decline in global oil prices during the three months ended March 31, 2025. Concurrently, in March and April 2025, the United States expanded tariff rates on imported goods based on both country of origin and material type. These expanded tariff rates, if sustained, could increase both the cost of oilfield goods and delivery lead times. Collectively, these policy changes—OPEC+'s production increase and the U.S. tariffs—are introducing significant volatility to the oil and gas sector. For more information on the impact of tariffs on our business, see Regulatory Updates.
Previous report
During the three months ended March 31, 2025, we continued to experience delays from CalGEM with respect to obtaining new well and deepening permits for our operations and did not receive any permits for these activities. However, during this period, CalGEM issued one new well permit for an oil and gas exploration well in Santa Barbara County to another operator in the state. This permit was issued outside of Kern County and in reliance on an environmental impact analysis other than the Kern County Environmental Impact Report (EIR) to comply with CEQA.
Previous report
Evolving Federal Energy and Climate Policies
Previous report
Since January 2025, the current administration has issued numerous Executive Orders that aim to increase oil production and decrease commodity prices. For example, a “national energy emergency” was declared in early January 2025, which gave the executive branch more power to expedite approvals for energy resource infrastructure (including oil and gas). Additionally, the administration issued the “Unleashing American Energy” Executive Order which incorporated numerous provisions aimed at unburdening and removing impediments to the development of various domestic energy resources, such as oil and gas. More recently, in March 2025, an Executive Order was signed that, among other matters, directed the U.S. Attorney General to investigate certain state laws that may adversely impact the development of energy resources, including state laws relating to climate change, environmental, social and governance initiatives, and funds collecting carbon penalties and/or taxes. We cannot predict what impact these Executive Orders or others may ultimately have on commodity prices, our operations or California laws and regulations relating to oil and gas, CCUS and climate change. We may respond to economic conditions by adjusting the amount and allocation of our capital program while continuing to identify efficiencies and cost savings. Volatility in oil prices may materially affect the quantities of oil and natural gas reserves we can economically produce over the longer term. Refer to Results of Our Oil and Natural Gas Operations, Prices and Realizations below for information on our realized price.
Previous report
In addition, in March and April 2025, the current administration implemented a substantial number of trade tariffs on all U.S. imports, including a new universal baseline reciprocal tariff of 10%, an additional country-specific reciprocal tariff for select trading partners and a tariff of 25% on imported steel and aluminum products. On April 10, 2025, the administration paused the additional country-specific tariffs for 90 days, until July 8, 2025, with the exception of the reciprocal tariff on China. While imports of oil, gas and refined products received exemptions from the tariffs, concerns that the measures could cause inflation, slow economic growth and intensify trade disputes have also placed downward pressure on oil prices. With negotiations and countermeasures still ongoing, the supply chain environment is fluid, and we expect price volatility to continue over the next few months. While we do not expect a significant and immediate impact on cost and availability of oilfield materials and supplies, these trade tariffs have the potential to significantly increase our operating and capital costs over the longer term.
Previous report
Responsible Net Zero Goal
Previous report
In May 2025, our Board of Directors adopted the following net zero emissions goal (Responsible Net Zero):
Previous report
Our goal is to achieve at least an 80% reduction of absolute Scope 1 and 2 greenhouse gas emissions and neutralize the remaining Scope 1 and 2 emissions to achieve Net Zero by 2045. Our near-term ambition is to achieve a 20% reduction in the average carbon intensity of all CRC oil and gas production by 2035, thereby reducing our customers’ Scope 3 emissions. We are committed to responsibly producing energy in a manner consistent with the UN’s Sustainable Development Goals.
Previous report
Our Responsible Net Zero goal is based on the following considerations:
Previous report
•We use 2020 total Scope 1 and 2 GHG emissions (including those of Aera) as our baseline to measure progress towards our Responsible Net Zero goal. Our emissions are based on calculations reported to the California Air Resources Board (CARB).
Previous report
•The term “neutralize” as it relates to Scope 1 GHG emissions refers to the planned use of either carbon offsets generated and claimed internally or carbon offsets purchased and claimed through the third party carbon market (including California’s Cap-and-Trade Program). For Scope 2 GHG emissions, the term “neutralize” refers to the use of contractual instruments such as renewable energy certificates or carbon offsets.
Previous report
•The term “carbon offsets” refers to greenhouse gas emission reductions arising from third-party certified projects that remove, reduce, or avoid GHG emissions from the atmosphere.
Previous report
•References to UN Sustainable Development Goals (UN SDGs) refer primarily to goals regarding income inequality, biodiversity, corruption, Scope 1 and 2 GHG emissions carbon intensity, fair labor and gender treatment. Operating a business consistent with UN SDGs is inherently a subjective determination regarding which UN SDGs to prioritize, how to weigh such matters against commercial considerations and to what extent a business activity promotes or is consistent with a given UN SDG.
Previous report
•Future acquisitions and divestitures, as well as changes to methodology in accounting for carbon emissions or adjustments to historical carbon calculations as well as the use of third-party data or validation processes, could cause us to change our Responsible Net Zero goal.
Previous report
•Assumptions, estimates, goals and similar statements and concepts regarding our Responsible Net Zero goal contain or assume forward looking statements within the meaning of federal securities laws and are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements. For a discussion of these risks and uncertainties, please refer to the Risk Factors and Forward-Looking Statements described in our Annual Report on our most recent Form 10-K and any subsequently filed Quarterly Reports on Form 10-Q and Current Reports on Form 8-K filed with the United States Securities and Exchange Commission.
Previous report
Our Responsible Net Zero goal replaces our previously adopted Full Scope Net Zero goal. This change was primarily driven by the impact of the Aera Merger, which nearly doubled the size of our asset base and impacted the overall carbon intensity of our operations. The continuing lack of regulatory clarity around the measurement of Scope 3 GHG emissions (including the impact of carbon capture and sequestration in such calculations) also contributed to this change.
Previous report
Electricity revenue — Electricity revenue decreased by $17 million to $22 million for the three months ended March 31, 2025 compared to $39 million for the three months ended December 31, 2024. This decrease was primarily a result of lower seasonal pricing.
Previous report
Non-energy operating costs— Non-energy operating costs for the three months ended March 31, 2025 were $209 million, which was a decrease of $16 million from $225 million for the three months ended December 31, 2024. The decrease was predominately a result of $7 million related to lower downhole maintenance, surface maintenance, and workover activity in addition to more favorable vendor pricing for the three months ended March 31, 2025 compared to the three months ended December 31, 2024.
Previous report
Compensation expense related to our bonus program decreased by $8 million for the three months ended March 31, 2025 compared to the three months ended December 31, 2024. This decrease was due to $4 million related to one-time retention awards granted in connection with the Aera Merger and $4 million related to the timing of the annual bonus accruals.
Previous report
Cash-settled stock-based compensation expense decreased by $7 million primarily resulting from a lower expected payout on our incentive awards primarily due to a decline in our stock price at March 31, 2025 compared to December 31, 2024. Changes in our stock price introduce volatility in our results of operations because we pay cash-settled incentive awards based on our stock price on the vesting date and accounting rules require that we adjust our obligation for unvested awards to the amount that would be paid using our stock price at the end of each reporting period. Consequently, any future increases in our stock price will result in additional cash-settled stock-based compensation expense. Equity-settled stock-based compensation awards are not similarly adjusted for changes in our stock price.
Previous report
The non-cash portion of general and administrative expenses, comprised of equity-settled stock-based compensation, was approximately $6 million for both the three months ended March 31, 2025 and December 31, 2024.
Previous report
Measurement period adjustments — Measurement period adjustments relate to the initial accounting for assets acquired and liabilities assumed in the Aera Merger. The adjustments during the three months ended March 31, 2025 included adjustments to depreciation, depletion and amortization expense resulting from changes to the initial purchase price allocation. The adjustments during the three months ended December 31, 2024 related to accretion expense related to asset retirement obligations and depreciation, depletion and amortization expense resulting from changes to the initial purchase price allocation.
Previous report
Production-Sharing Contracts (PSCs)
Previous report
Oil — Brent prices were slightly higher for the three months ended March 31, 2025 compared to the three months ended December 31, 2024. The increase in Brent prices is due to a combination of early-quarter OPEC+ inaction in terms of returning barrels to the market and various geopolitical factors.
Previous report
Natural Gas — Natural gas prices increased for the three months ended March 31, 2025 compared to the three months ended December 31, 2024 driven by colder-than-anticipated winter temperatures across most of the United States, resulting in strong demand and large storage withdrawals bringing storage inventories in line with historical norms.
Previous report
(a)Asset impairment for the three months ended December 31, 2024 related to land acquired for our carbon management activities. The table above excludes asset impairments that were not related to the carbon management segment.
Previous report
2026 Senior Note Redemptions
Previous report
In February 2025, we redeemed $123 million of our 2026 Senior Notes at 100% of the principal amount of such notes, resulting in a loss on early extinguishment of debt in the amount of $1 million for the write-off of unamortized debt issuance costs.
Previous report
Share Repurchase Program
Previous report
Our Board of Directors has authorized a Share Repurchase Program to acquire up to $1.35 billion of our common stock through December 31, 2025. As of March 31, 2025, the aggregate value of shares that may yet be purchased under the Share Repurchase Program totaled $457 million, excluding commissions and excise taxes on repurchases. The repurchases may be effected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, derivative contracts or contracts otherwise in compliance with Rule 10b-18, subject to market conditions and contractual limitations in our debt agreements. The Share Repurchase Program does not obligate us to repurchase any dollar amount or number of shares and our Board of Directors may modify, suspend or discontinue authorization of the program at any time. The following is a summary of our share repurchases, which are held as treasury stock, for the periods presented:
Previous report
Note: The total value of shares purchased includes approximately $1 million in both the three months ended March 31, 2025 and 2024 related to excise taxes on share repurchases, which was effective beginning on January 1, 2023. Commissions paid on share repurchases were not significant in all periods presented. Total commissions and excise taxes paid since the inception of the program total $4 million.
Previous report
We paid the following fixed cash dividends in each of the periods presented.
Previous report
In addition to dividends declared, we paid$1 million and $4 million of dividend equivalents related to stock-based compensation awards which were settled in thethree months ended March 31, 2025 and 2024, respectively. The declaration of future cash dividends, and the establishment of record and payment dates, is subject to final determination by our Board of Directors each quarter after reviewing our financial performance and position. Since the adoption of our dividend policy in 2021, we have returned $302 million to shareholders through dividends (excluding dividend equivalents).
Previous report
On May 5, 2025, our Board of Directors declared a quarterly cash dividend of$0.3875 per share of common stock. The dividend is payable to shareholders of record at the close of business on May 30, 2025 and is expected to be paid on June 13, 2025.
Previous report
Aera Integration
Previous report
We anticipate that the integration of our workforce and amendment of our benefit plans will result in approximately $80 million of annual savings, of which approximately $50 million relates to general and administrative expenses and approximately $30 million relates to non-energy operating costs. In August 2024, we also reduced the number of our contractors resulting in approximately $5 million of annual savings.
Reworded paragraphs (36)
Previous wording
Our operating results, and those of the oil and natural gas industry as a whole, are heavily influenced by commodity prices. Oil and natural gas prices and differentials may fluctuate significantly as a result of numerous market-related variables. These and other factors make it impossible to predict realized prices reliably. We may respond to economic conditions by adjusting the amount and allocation of our capital program while continuing to identify efficiencies and cost savings. Volatility in oil prices may materially affect the quantities of oil and natural gas reserves we can economically produce over the longer term. Refer to Results of Our Oil and Natural Gas Operations, Production, Prices and Realizations below for information on our realized prices.
Current wording
Our operating results, and those of the oil and natural gas industry, are heavily influenced by commodity prices. Oil and natural gas prices and differentials may fluctuate significantly as a result of numerous market-related variables. These and other factors make it challenging to predict realized prices reliably. We may respond to economic conditions by adjusting the amount and allocation of our capital program while continuing to identify efficiencies and cost savings. Volatility in oil and natural gas prices may affect the quantities of oil and natural gas reserves we can economically produce over the longer term. Refer to Results of Our Oil and Natural Gas Operations, Production, Prices and Realizations below for information on our realized prices.
Previous wording
In October 2024, Phillips 66 announced that it plans to close its Wilmington refinery in Los Angeles in late 2025. Additionally, in April 2025, Valero notified the California Energy Commission of its intent to idle, restructure, or cease refining operations at its Benicia refinery in the San Francisco Bay Area by the end of April 2026. Historically, we have sold a portion of our crude oil to these refineries. Assuming the Phillips 66 and Valero refineries both close, there will be six remaining major petroleum refineries in California, each of which have a refining capacity greater than 75,000 barrels per day. We expect California to collectively have 1.34 million barrels per day of remaining refining capacity, which is over four times the amount of crude oil produced in California in 2024. As a result of this and the considerable flexibility we have in marketing our production, we do not expect the closure of these refineries, should they occur, to affect our ability to market our crude oil production or to negatively impact our price realizations.
Current wording
In October 2024, Phillips 66 announced that it plans to close its Wilmington refinery in Los Angeles in late 2025. Additionally, in April 2025, Valero notified the California Energy Commission of its intent to idle, restructure, or cease refining operations at its Benicia refinery in the San Francisco Bay Area by the end of April 2026. Historically, we have sold a portion of our crude oil to these refineries. Assuming both refineries were to cease operations, there will be six remaining major petroleum refineries in California, each of which have a refining capacity greater than 75,000 barrels per day. We expect this would leave California with approximately 1.3 million barrels per day of remaining major refining capacity, which is more than four times the amount of crude oil produced in California in 2024. As a result of this and given the considerable flexibility we have in marketing our production, we do not expect the cessation of operations at these refineries, should they occur, will affect our ability to market our crude oil production. While these announcements have had no impact on our price realizations thus far, fewer refineries in California have the potential to impact our future price realizations.
Previous wording
During the three months ended March 31, 2025, we received well permits for 53 workovers and 21 sidetracks. This reflects a continuing improvement in the rate of issuance by CalGEM of permits for workovers and sidetracks.
Current wording
During the three months ended June 30, 2025, we received well permits for 86 workovers and 84 sidetracks. The rate at which CalGEM issued permits for workovers and sidetracks during this period continued to increase relative to the three months ended March 31, 2025.
Previous wording
We currently hold sufficient permits to maintain our existing capital program through 2025. We also have the requisite number of permits in hand to run one active drilling rig throughout 2026.
Current wording
We currently hold sufficient permits to maintain our existing two drilling rig capital program throughout 2025. We also have the requisite number of permits in hand to run one active drilling rig throughout 2026.
Previous wording
Oil, natural gas and natural gas liquids sales — Oil, natural gas and natural gas liquids sales, excluding the effects of cash settlements on our commodity derivative contracts, were $814 million for the three months ended March 31, 2025, which is a decrease of $12 million compared to $826 million for the three months ended December 31, 2024.
Current wording
Oil, natural gas and natural gas liquids sales — Oil, natural gas and natural gas liquids sales, excluding the effects of cash settlements on our commodity derivative contracts, were $702 million for the three months ended June 30, 2025, which is a decrease of $112 million compared to $814 million for the three months ended March 31, 2025.
Previous wording
Net (gain) loss on natural gas purchased derivatives — Net gain from derivatives related to our purchase of natural gas was $6 million for the three months ended March 31, 2025 compared to a net loss of $19 million for the three months ended December 31, 2024. The change primarily resulted from changes in the fair value of our outstanding commodity derivatives from the positions held, as well as the relationship between contract prices and the associated forward curves at the end of each measurement period. Gains and losses from our commodity derivative contracts are shown in the table below:
Current wording
Net gain from commodity derivatives — We report gains and losses on our derivative contracts related to sales of our oil and marketing activities in operating revenues. Net gain from commodity derivatives was $157 million for the three months ended June 30, 2025 compared to a net gain of $6 million for the three months ended March 31, 2025. The change primarily resulted from the non-cash changes in the fair value of our outstanding commodity derivatives from the positions held at the end of each measurement period. Gains and losses from our commodity derivative contracts are shown in the table below:
Previous wording
Energy operating costs — Energy operating costs for the three months ended March 31, 2025 were $103 million, which was an increase of $9 million from $94 million for the three months ended December 31, 2024. This increase was primarily due to higher natural gas prices. We reduced the volume of natural gas used in our steamflood operations, resulting in a savings of $3 million in each of the three months ended March 31, 2025 and December 31, 2024. For more information on natural gas market prices, see Prices and Realizations below.
Current wording
Energy operating costs — Energy operating costs for the three months ended June 30, 2025 were $78 million, which was a decrease of $25 million from $103 million for the three months ended March 31, 2025. This decrease was primarily due to lower prices and lower volumes ofnatural gas used in our steamflood operations. For more information on natural gas market prices, see Prices and Realizations below.
Previous wording
General and administrative expenses — General and administrative (G&A) expenses were $72 million for the three months ended March 31, 2025 compared to $95 million for the three months ended December 31, 2024, which was a decrease of $23 million. The decrease was primarily a result of lower compensation-related expenses including stock-based compensation, bonus and retention awards and workforce reductions following the Aera Merger. See Liquidity and Capital Resources, Aera Integration below for additional information.
Current wording
General and administrative expenses — General and administrative (G&A) expenses were $79 million for the three months ended June 30, 2025 compared to $72 million for the three months ended March 31, 2025, which was an increase of $7 million. The increase was primarily a result of higher legal expenses and compensation-related expenses during the three months ended June 30, 2025.
Previous wording
Taxes other than on income — Taxes other than on income for the three months ended March 31, 2025 were $70 million, which is a decrease of $10 million from $80 million for the three months ended December 31, 2024. This decrease was due to lower greenhouse gas expense.
Current wording
Taxes other than on income — Taxes other than on income for the three months ended June 30, 2025 were $47 million, which was a decrease of $23 million from $70 million for the three months ended March 31, 2025. The decrease was primarily due to an adjustment to the production tax rate. We also had lower greenhouse gas expense based on market prices.
Previous wording
Other operating expenses, net — Other operating expenses, net decreased $18 million to $33 million for the three months ended March 31, 2025 compared to $51 million for the three months ended December 31, 2024. For the three months ended March 31, 2025 and December 31, 2024, other operating expenses, net includes the following:
Current wording
Other operating expenses, net — Other operating expenses, net increased $32 million to $65 millionfor the three months ended June 30, 2025 compared to $33 million for the three months ended March 31, 2025. For the three months ended June 30, 2025 and March 31, 2025, other operating expenses, net includes the following:
Previous wording
Income taxes – The income tax provision for the three months ended March 31, 2025 was $47 million (representing an effective tax rate of 29%), compared to a provision of $8 million (representing an effective tax rate of 20%) for the three months ended December 31, 2024. See Part I, Item 1 – Financial Statements, Note 7 Income Taxes for additional information on our effective tax rate.
Current wording
Income taxes – The income tax provision for the three months ended June 30, 2025 was $70 million (representing an effective tax rate of 29%), compared to a provision of $47 million (representing an effective tax rate of 29%) for the three months ended March 31, 2025. See Part I, Item 1 – Financial Statements, Note 7 Income Taxes.
Previous wording
Net gain (loss) from commodity derivatives –We report gains and losses on our derivative contracts related to our oil production and marketing activities in operating revenue. Net gain from commodity derivatives was $6 million for the three months ended March 31, 2025 compared to a net loss of $49 million for the three months ended December 31, 2024. The change primarily resulted from payments to settle commodity derivative contracts and the non-cash changes in the fair value of our outstanding commodity derivatives from the positions held at the end of each measurement period. Gains and losses from our commodity derivative contracts are shown in the table below:
Current wording
Net gain (loss) from commodity derivatives –We report gains and losses on our derivative contracts related to sales of our produced oil and marketing activities in operating revenue. Net gain from commodity derivatives was $163 million for the six months ended June 30, 2025 compared to a net loss of $66 million for the six months ended June 30, 2024. The change primarily resulted from payments to settle commodity derivative contracts and the non-cash changes in the fair value of our outstanding commodity derivatives from the positions held at the end of each measurement period. Gains and losses from our commodity derivative contracts are shown in the table below:
Previous wording
Depreciation, depletion and amortization — Depreciation, depletion and amortization (DD&A) for the three months ended March 31, 2025 was $131 million compared to $142 million during the three months ended December 31, 2024. The decrease of $11 million was primarily the result of adjustments to the DD&A rate based on reserve estimates and fair value adjustments to the Aera assets in the three months ended March 31, 2025. See Part I, Item 1 – Financial Statements, Note 2 Aera Mergerfor information on the Aera assets and the purchase price allocation.
Current wording
Depreciation, depletion and amortization — Depreciation, depletion and amortization (DD&A) for the six months ended June 30, 2025 was $259 million compared to$106 million during the six months ended June 30, 2024. The increase of $153 million was primarily the result of the addition of the Aera assets included in the six months ended June 30, 2025. See Part I, Item 1 – Financial Statements, Note 2 Aera Mergerfor information on the Aera assets.
Previous wording
The following table includes financial results and key operating data for our oil and natural gas segment for the three months ended March 31, 2025 or December 31, 2024.
Current wording
The following table includes financial results and key operating data for our oil and natural gas segment for the three months ended June 30, 2025 and March 31, 2025 and the six months ended June 30, 2025 and 2024.
Previous wording
(a)Gain on asset divestitures for the three months ended December 31, 2024 related to the sale of our Ventura assets.
Current wording
(a)Gain on asset divestitures for the six months ended June 30, 2024 related to the sale of oil and gas assets located in Ventura.
Previous wording
Total average net production sold remained unchanged at 141 MBoe/d for the three months ended March 31, 2025 and December 31, 2024. Our PSCs, which are described below, positively impacted our net oil production by 1 MBoe/d in the three months ended March 31, 2025 compared to the three months ended December 31, 2024.
Current wording
Total average net production sold increased to 139 MBoe/d for the six months ended June 30, 2025 compared to 76 MBoe/d for the six months ended June 30, 2024. The increase was primarily a result of the Aera Merger. Our PSCs, which are described below, positively impacted our net oil production by 1 MBoe/d in the six months ended June 30, 2025 compared to the six months ended June 30, 2024.
Previous wording
The following table sets forth the average realized prices and price realizations on the commodities we sell as a percentage of average Brent, WTI and NYMEX indexes for our oil and natural gas operations for the periods presented:
Current wording
The following tables set forth the average realized prices and price realizations on the commodities we sell as a percentage of average Brent, WTI and NYMEX Henry Hub indexes for our oil and natural gas operations for the periods presented:
Previous wording
NGLs — Prices for natural gas liquids during the three months ended March 31, 2025 increased compared to the three months ended December 31, 2024, reflecting traditional seasonality and moving in tandem with crude oil prices.
Current wording
NGLs — Prices for natural gas liquids during the three months ended June 30, 2025 decreased compared to the three months ended March 31, 2025, reflecting traditional seasonality. Prices for natural gas liquids during the six months ended June 30, 2025 were consistent with the same prior year period.
Previous wording
Our carbon management segment, which we refer to as Carbon TerraVault, primarily pursues the development of carbon capture and sequestration projects. We expect that our Carbon TerraVault CCS projects will inject CO 2 captured from industrial, power, agriculture and other emissions sources into subsurface reservoirs and permanently store CO 2 deep underground. We also expect to invest in projects that rely on CCS technology in connection with reducing our own emissions. In addition, we may participate in the development of projects that are the source of these CO 2 emissions. Our carbon management segment is in its early stages of development, and did not have any revenue for the three months ended March 31, 2025 or December 31, 2024. We define carbon management expense to be our direct operating costs to run our carbon management segment.
Current wording
Our carbon management segment, which we refer to as Carbon TerraVault, primarily pursues the development of CCS projects. We expect that our Carbon TerraVault CCS projects will inject CO 2 captured from industrial, power, agriculture and other emissions sources into subsurface reservoirs and permanently store CO 2 deep underground. We also expect to invest in projects that rely on CCS technology in connection with reducing our own emissions. In addition, we may participate in the development of projects that are the source of these CO 2 emissions. Our carbon management segment is in its early stages of development. We expect construction of our first carbon capture project at our cryogenic gas processing facility to be completed at or around year end at which time we will be ready to inject subject to receipt of final regulatory approvals early in 2026.
Previous wording
The following tables include results for our carbon management segment for the three months ended March 31, 2025 and December 31, 2024.
Current wording
The following tables include results for our carbon management segment for the three months ended June 30, 2025 and March 31, 2025 and the six months ended June 30, 2025 and June 30 2024.
Previous wording
Carbon management expenses decreased for the three months ended March 31, 2025 compared to the three months ended December 31, 2024 as a result of lower advocacy and operating lease cost related to easements, partially offset by costs related to increases in front-end engineering design and other feasibility work during the three months ended March 31, 2025.
Current wording
Carbon management expenses decreased for thethree months ended June 30, 2025 compared to the three months ended March 31, 2025 as a result of lower lease costs related to easements.
Previous wording
Our primary sources of liquidity and capital resources are cash flows from operations, available cash and cash equivalents and available borrowing capacity under our Revolving Credit Facility. We consider our low leverage and ability to control costs to be a core strength and strategic advantage, which we are focused on maintaining. Our primary uses of operating cash flow for the three months ended March 31, 2025 were for debt reduction, repurchases of our common stock, payment of fixed dividends and capital investments.
Current wording
Our primary sources of liquidity and capital resources are cash flows from operations, available cash and cash equivalents and available borrowing capacity under our Revolving Credit Facility. We consider our low leverage and ability to control costs to be a core strength and strategic advantage, which we are focused on maintaining. Our primary uses of operating cash flow for the three and six months ended June 30, 2025 were for repurchases of our common stock, payment of dividends, and capital investments.
Previous wording
(a)Excludes restricted cash of $15 million.
Current wording
(a)Excludes restricted cash of $16 million.
Previous wording
At current commodity prices and based upon our planned 2025 capital program described below, we expect to generate operating cash flow to support and invest in our core assets and preserve financial flexibility. We regularly review our financial position and evaluate whether to (i) adjust our drilling program, (ii) return available cash to shareholders through dividends or stock buybacks to the extent permitted under our Revolving Credit Facility and the indentures for our 7.125% senior notes due 2026 (2026 Senior Notes) and our 8.25% senior notes due 2029 (2029 Senior Notes), (iii) reduce outstanding indebtedness, (iv) advance carbon management activities, or (v) maintain cash and cash equivalents on our balance sheet. We continue to monitor the current macroeconomic environment and will adjust our planned uses of cash as necessary. We believe we have sufficient sources of liquidity to meet our obligations for the next twelve months.
Current wording
At current commodity prices and based upon our planned 2025 capital program described below, we expect to generate operating cash flow to return cash to shareholders through dividends and repurchases of our common stock. In line with this strategy, our Board of Directors has extended the term of our Share Repurchase Program from December 31, 2025 to June 30, 2026. We regularly review our financial position and evaluate whether to (i) adjust our drilling program, (ii) return available cash to shareholders through dividends or share repurchases to the extent permitted under our Revolving Credit Facility and the indentures for our 7.125% senior notes due 2026 (2026 Senior Notes) and our 8.25% senior notes due 2029 (2029 Senior Notes), (iii) reduce outstanding indebtedness, (iv) advance carbon management activities, or (v) maintain cash and cash equivalents on our balance sheet. We continue to monitor the current macroeconomic environment and will adjust our planned uses of cash as necessary. We believe we have sufficient sources of liquidity to meet our obligations for the next twelve months.
Previous wording
In August 2024 and March 2025, management undertook a reduction in force as part of the integration process following the Aera Merger. After employee transition periods, the reduction in the combined employee headcount will be approximately 12%. We initiated this workforce reduction to align the size and composition of our workforce with expected future operating and capital plans. Employee severance and related costs are included in other operating expenses, net on our condensed consolidated statement of operations. We also amended Aera's pension and postretirement benefit plans in August 2024 resulting in a reduction of service cost, which is reported as a component of general and administrative expenses.
Current wording
We have taken steps to reduce headcount as part of the integration process following the Aera Merger. We initiated these workforce reductions to align the size and composition of our workforce with expected future operating and capital plans. Employee severance and related costs are included in other operating expenses, net on our condensed consolidated statement of operations.
Previous wording
The borrowing base under our Revolving Credit Facility is redetermined semi-annually and was reaffirmed at $1.5 billion on April 4, 2025. The borrowing base takes into account the estimated value of our proved reserves, total indebtedness and other relevant factors consistent with customary reserves-based lending criteria. The amount we are able to borrow under our Revolving Credit Facility is limited to the amount of the commitments from our lenders, which is currently $1.15 billion. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 5 Debtin our 2024 Annual Report for additional information on the Revolving Credit Facility and related amendments.
Current wording
See Part II, Item 8 – Financial Statements and Supplementary Data, Note 5 Debtin our 2024 Annual Report for information on the Revolving Credit Facility and related amendments.
Previous wording
Our capital program is dynamic in response to commodity price volatility and permit availability while focusing on oil production and maximizing our free cash flow. Our capital investment for the three months ended March 31, 2025 was $55 million. We expect our 2025 capital program to remain at a range between $285 million and $335 million. Of this amount, $250 million to $280 million is related to our oil and natural gas segment, $20 million to $30 million is for our carbon management segment and $15 million to $25 million is for corporate and other activities. The above amounts related to carbon management projects do not include amounts funded by Brookfield through the Carbon TerraVault JV, such as drilling injection and monitoring wells at our 26R reservoir. With respect to oil and natural gas development, we expect to run a two rig program in the second half of 2025 using existing permits in hand. Refer to Regulatory Updates above for more information on permitting. Refer to Part I, Item 1 – Financial Statements, Note 9 Segment Informationfor information on capital spend by segment.
Current wording
Our capital program is dynamic in response to commodity price volatility and permit availability while focusing on oil production and maximizing our free cash flow. Our capital investment for the six months ended June 30, 2025 was $111 million. We expect our full year 2025 capital program to range between $280 million and $330 million. Of this amount, $245 million to $275 million is related to our oil and natural gas segment, $20 million to $30 million is for our carbon management segment and $15 million to $25 million is for corporate and other activities. The above amounts related to carbon management projects do not include amounts funded by Brookfield through the Carbon TerraVault JV, such as drilling injection and monitoring wells at our 26R reservoir.
Previous wording
Significant changes in oil and natural gas prices may have a material impact on our liquidity. Declining commodity prices negatively affect our operating cash flow, and the inverse applies during periods of rising commodity prices. Our hedging strategy seeks to mitigate our exposure to commodity price volatility and ensure our financial strength and liquidity by protecting our cash flows. We will continue to evaluate our hedging strategy based on prevailing market prices and conditions.
Current wording
Significant changes in oil and natural gas prices may have a material impact on our liquidity. Declining oil prices negatively affect our operating cash flow, and the inverse applies during periods of rising oil prices. Our hedging strategy seeks to mitigate our exposure to commodity price volatility and ensure our financial strength and liquidity by protecting our cash flows. We will continue to evaluate our hedging strategy based on prevailing market prices and conditions.
Previous wording
Unless otherwise indicated, we use the term “hedge” to describe derivative instruments that are designed to achieve our hedging requirements and program goals, even though they are not accounted for as cash-flow or fair-value hedges. We did not have any commodity derivatives designated as accounting hedges as of and during the three months ended March 31, 2025. See Part I, Item 1 – Financial Statements, Note 6 Derivatives for further information on our derivatives and a summary of our open derivative contracts as of March 31, 2025 and Part II, Item 8 – Financial Statements and Supplementary Data, Note 4 Debtin our 2024 Annual Report for information on the hedging requirements included in our Revolving Credit Facility.
Current wording
Unless otherwise indicated, we use the term “hedge” to describe derivative instruments that are designed to achieve our hedging requirements and program goals, even though they are not accounted for as cash-flow or fair-value hedges. We did not have any commodity derivatives designated as accounting hedges as of and during the six months ended June 30, 2025. See Part I, Item 1 – Financial Statements, Note 6 Derivatives for further information on our derivatives and a summary of our open derivative contracts as of June 30, 2025 and Part II, Item 8 – Financial Statements and Supplementary Data, Note 5 Debtin our 2024 Annual Report for information on the hedging requirements included in our Revolving Credit Facility.
Previous wording
Cash flows from operating activities — For the three months ended March 31, 2025, our operating cash flow increased by $99 million to $186 million from $87 million in the same period in 2024. This increase in operating cash flow was primarily driven by the Aera Merger on July 1, 2024.
Current wording
Cash flows from operating activities — For the six months ended June 30, 2025, our operating cash flow increased by $167 million to $351 million from $184 million in the same period in 2024. This increase in operating cash flow was primarily driven by the Aera Merger on July 1, 2024.
Previous wording
With the acquisition of Aera's assets, oil production during the three months ended March 31, 2025 as compared to the same periods in 2024 increased 63 MBbl/d from 48 MBbl/d to 111 MBbl/d. Higher revenue from this increase in production was partially offset by lower average realized oil prices (after derivative settlements). Average realized prices for oil decreased by $5.16 per barrel to $72.01 in the three months ended March 31, 2025 from $77.17 in the same prior year period. Further, as a result of the Aera Merger, we experienced higher operating costs, production taxes and greenhouse gas taxes during the three months ended March 31, 2025 as compared to the same prior year period in addition to one-time transaction and integration costs were incurred in 2025.
Current wording
With the addition of Aera's assets, oil production during the six months ended June 30, 2025 as compared to the same period in 2024 increased 63 MBbl/d from 47 MBbl/d to 110 MBbl/d. Higher revenue from this increase in production was partially offset by lower average realized oil prices (after derivative settlements). Average realized prices for oil decreased by $9.81 per barrel to$69.39 in the six months ended June 30, 2025 from$79.20 in the same prior year period. Further, as a result of the Aera Merger, we experienced higher operating costs, production taxes and greenhouse gas taxes during the six months ended June 30, 2025 as compared to the same prior year period in addition to one-time transaction and integration costs were incurred in 2025.
Previous wording
During the three months ended March 31, 2024, scheduled plant downtime at the Elk Hills power plant negatively impacted our production and we purchased electricity at higher prices.
Current wording
During the six months ended June 30, 2024, scheduled plant downtime at the Elk Hills power plant negatively impacted our production and we purchased electricity at higher prices.
Previous wording
(a)The total value of shares purchased reported on our statement of cash flows includes approximately $1 million in both the three months ended March 31, 2025 and 2024 related to excise taxes on share repurchases, which was effective beginning on January 1, 2023. Commissions paid on share repurchases were not significant in all periods presented.
Current wording
(a)Note: The total value of shares purchased includes excise taxes, which are generally paid in the year following the share repurchase. Commissions paid on share repurchases were not significant in all periods presented.
Previous wording
For the three months ended March 31, 2025, our cash flow used in financing activities increased by $134 million to $265 million from $131 million in the same period in 2024. This increase in cash flow used in financing activities was primarily driven by $123 million used to redeem a portion of the 2026 Senior Notes in February 2025. Additionally,$101 million was used for the repurchases of common stock in the three months ended March 31, 2025 as compared to$58 millionin the three months ended March 31, 2024.
Current wording
For the six months ended June 30, 2025, our cash flow used in financing activities was $521 million compared to cash flow provided by financing activities of $433 million in the same period in 2024. This decrease in cash flow from financing activities was primarily driven by the $590 million of proceeds from 2029 Senior Notes issued in the six months ended June 30, 2024. Additionally, the decrease is caused by the $123 million cash outflow used to redeem a portion of the 2026 Senior Notes in February 2025 and the $318 million cash outflow used to repurchase stock in the six months ended June 30, 2025.
Previous wording
•our ability to successfully identify, develop and finance carbon capture and storage projects and other renewable energy efforts, including those in connection with the Carbon TerraVault JV, and our ability to convert our CDMAs to definitive agreements and enter into other offtake agreements;
Current wording
•our ability to successfully identify, develop and finance carbon capture and storage projects, power projects and other renewable energy efforts, including those in connection with the Carbon TerraVault JV, and our ability to convert our CDMAs to definitive agreements and enter into other offtake agreements;
Previous wording
•our access to and the terms of credit in commercial banking and capital markets, including our ability to refinance our debt or
Current wording
•our access to and the terms of credit in commercial banking and capital markets, including our ability to refinance our debt or obtain separate financing for our carbon management segment;
Rearranged current paragraphs (9)
Current report — wording carried from elsewhere
Six months ended June 30, 2025 compared to June 30, 2024
Current report — wording carried from elsewhere
The following table presents our consolidated operating revenues for the periods indicated:
Current report — wording carried from elsewhere
Oil, natural gas and natural gas liquids sales — Oil, natural gas and natural gas liquids sales, excluding the effects of cash settlements on our commodity derivative contracts, were $1,516 million for the six months ended June 30, 2025, which is an increase of $675 million compared to $841 million for the six months ended June 30, 2024.
Current report — wording carried from elsewhere
The following table shows changes in oil, natural gas and natural gas liquids sales for the six months ended June 30, 2025 compared to the six months ended June 30, 2024.
Current report — wording carried from elsewhere
Note: See Productionfor volumes by commodity type and Prices and Realizations for index and realized prices for comparative periods.
Current report — wording carried from elsewhere
The following table presents our consolidated operating and non-operating expenses and income for the six months ended June 30, 2025 and June 30, 2024.
Current report — wording carried from elsewhere
Income taxes – The income tax provision for the six months ended June 30, 2025 was $117 million (representing an effective tax rate of 29%), compared to a benefit of $6 million (representing an effective tax rate of 75%) for the six months ended June 30, 2024. See Part I, Item 1 – Financial Statements, Note 7 Income Taxes for additional information on our income taxes.
Current report — wording carried from elsewhere
Total average net production sold decreased to 137 MBoe/d for the three months ended June 30, 2025 compared to 141 MBoe/d for the three months ended March 31, 2025. The decrease was primarily a result of natural production decline partially offset by development results. In addition, our production-sharing contracts (PSCs), which are described below, negatively impacted our net oil production by 1 MBoe/d in the three months ended June 30, 2025 compared to the three months ended March 31, 2025.
Current report — wording carried from elsewhere
With respect to oil and natural gas development, we added a second drilling rig in June 2025 and currently expect to run our two rig program through the remainder of the year using existing permits in hand. Refer to Regulatory Updates above for more information on permitting. Refer to Part I, Item 1 – Financial Statements, Note 9 Segment Informationfor information on capital investment by segment.
Rearranged previous paragraphs (2)
Previous report — wording carried elsewhere
Regulation of Exploration and Production Activities
Previous report — wording carried elsewhere
obtain separate financing for our carbon management segment;