California Resources Corp: Form 10-Q for the period ended Jun 30, 2026

General

We are an independent energy and carbon management company advancing the energy transition. We are committed to environmental stewardship while safely providing local, responsibly sourced energy. We are also focused on maximizing the value of our land, mineral ownership, and energy expertise for decarbonization by developing carbon capture and storage (CCS) and other emissions-reducing projects.

Except when the context otherwise requires or where otherwise indicated, all references to ‘‘CRC,’’ the ‘‘Company,’’ ‘‘we,’’ ‘‘us’’ and ‘‘our’’ refer to California Resources Corporation and its consolidated subsidiaries as of the date presented.

Business Environment and Industry Outlook

Commodity Prices

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 can fluctuate significantly due to various market-related factors, making it challenging to predict realized prices reliably. We may respond to changing economic conditions by adjusting the amount and allocation of our capital program or by pursuing additional cost reductions. Significant changes in oil and natural gas prices may also affect the quantities of reserves that we can economically produce over the longer term.

Global oil prices were volatile during the first half of 2026 and continuing into the third quarter of 2026. During the second quarter of 2026, oil prices generally remained elevated due to the ongoing conflict in Iran and neighboring countries, disruptions to shipping through the Strait of Hormuz and concerns regarding the impact of supply disruptions on global energy markets. Oil prices declined sharply during the second half of June 2026 as tensions in the Middle East eased following an agreement to reopen the Strait of Hormuz. Prices were further impacted by continued tepid demand from Chinese refiners and the release of strategic petroleum reserves. In July 2026, oil prices increased as tensions in the Middle East re-escalated. We expect oil prices to remain volatile as these geopolitical circumstances continue to evolve. Refer to Results of Our Oil and Natural Gas Operations, Production, Prices and Realizations below for information on our realized prices.

The following table presents the average daily benchmark prices for oil and natural gas during the periods presented:

Supply Chain and Inflation

We continued to experience relatively flat pricing from our suppliers during the first six months of 2026 compared to the prior year. However, high fuel costs are adversely impacting transportation and equipment prices, and high oil prices are impacting oil-based products such as chemicals and lubricants. We expect these prices to impact our full year 2026 costs by approximately $9 million.

Marketing Arrangements

In the three months ended June 30, 2026, we were informed by a pipeline operator that it had received nominations in excess of available capacity on a segment of its pipeline and the volume of crude oil we were allowed to transport was pro-rated along with other shippers. This led to both lower realizations, higher transportation costs and the incurrence of capital expenditures related to additional storage capacity as we sought alternative routes to market. We also experienced a temporary crude oil inventory build of approximately 137,000 barrels that negatively impacted our net production sold for the period. A substantial majority of this inventory was sold in July 2026.

Furthermore, our realized prices were negatively impacted during the period due to force majeure claims made by certain counterparties that affected pricing and offtake commitments.

The negative impact of these disputes to our pre-tax income for the three months ended June 30, 2026 was approximately $25 million.

We are disputing the pipeline operator's ability to pro-rate our nominations under the applicable tariff as well as the validity of the force majeure claims. We expect to prevail in these disputes, however, the timing and outcome of such disputes are inherently uncertain. If we are not able to resolve these disputes on favorable terms or in a timely manner, we could experience an adverse effect on our realizations, our ability to market our crude oil and our financial results.

Regulatory Updates

Well Permitting

We currently hold sufficient permits to support our 2026 capital program and we continue to build our permit inventory in anticipation of our expected operations in 2027. Refer to Liquidity and Capital Resources, Capital Program for additional information on our 2026 capital program.

California Cap-and-Invest (AB 1207 and SB 840)

In May 2026, CARB adopted amendments updating the existing cap-and-invest program. The amendments include the inclusion of carbon capture and sequestration projects as activities that could qualify for reducing a reporting entity’s cap-and-invest reporting requirements. Before this credit mechanism can take effect, however, CARB must adopt additional rules under SB 905 defining a "quantification methodology" for how such reductions resulting from the projects will be measured and verified. The amendments also create a new “Manufacturing Decarbonization Incentive” under which an entity may be eligible for incentive allowances for carbon capture and sequestration projects. The amendments also revise the cap-and-invest program’s allowance budgets between 2027 and 2030. However, these changes to the allowance budgets are not expected to materially affect CRC’s compliance with the program or its operations thereunder. In July 2026, Communities for a Better Environment filed a lawsuit challenging the regulatory amendments alleging violations of the California Environmental Quality Act. We cannot predict whether or not this challenge will ultimately be successful or how CARB may revise the amendments if the challenge is successful.

Statements of Operations Analysis

Our consolidated results of operations include the results of Berry beginning on December 18, 2025, the closing date of the Berry Merger. For more information on the Berry Merger, see Part I, Item 1 – Financial Statements, Note 2 Business Combination. The Berry Merger affected the comparability of our financial results for the three and six months ended June 30, 2026 as compared to the prior-year comparative periods.

Consolidated Results of Operations

Three months ended June 30, 2026 compared to March 31, 2026

The following table presents our consolidated operating revenues for the periods indicated:

(in millions)

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 $1,056 million for the three months ended June 30, 2026, which was an increase of $151 million compared to $905 million for the three months ended March 31, 2026.

The following table shows changes in oil, natural gas and natural gas liquids sales for the three months ended June 30, 2026 compared to the three months ended March 31, 2026:

(in millions)

Note: See Production for volumes by commodity type and Prices and Realizations for index and realized prices for comparative periods.

Net gain (loss) from commodity sales 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 sales derivatives was $205 million for the three months ended June 30, 2026 compared to a net loss of $848 million for the three months ended March 31, 2026. 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.

(in millions)

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Revenue from marketing of purchased commodities — Revenue from marketing of purchased commodities was $26 million for the three months ended June 30, 2026 compared to $41 million for the three months ended March 31, 2026. The decrease was mainly related to lower crude oil volumes purchased and used in blending in the three months ended June 30, 2026 compared to the three months ended March 31, 2026.

The following table presents our consolidated operating and non-operating expenses and income for the three months ended June 30, 2026 and March 31, 2026.

(in millions)

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Operating costs — The following table presents our operating costs for the three months ended June 30, 2026 and March 31, 2026:

(in millions)

Energy operating costs consist of purchased natural gas used to generate electricity for our operations and steam for our steamfloods, purchased electricity and internal costs to generate electricity used in our operations. Gas processing costs include costs associated with compression, maintenance and other activities needed to run our gas processing facilities at Elk Hills. Non-energy operating costs equal total operating costs less energy operating costs and gas processing costs.

Energy operating costs — Energy operating costs for the three months ended June 30, 2026 were $87 million, which was a decrease of $23 million from $110 million for the three months ended March 31, 2026. This decrease was primarily due to lower prices for natural gas purchased and used in our steamflood operations.

Non-energy operating costs — Non-energy operating costs for the three months ended June 30, 2026 were $254 million, which was an increase of $4 million from $250 million for the three months ended March 31, 2026 primarily due to additional downhole maintenance activity.

General and administrative expenses — General and administrative (G&A) expenses were $97 million for the three months ended June 30, 2026 compared to $106 million for the three months ended March 31, 2026. The decrease primarily resulted from lower compensation-related costs due to workforce reductions associated with the Berry Merger and lower cash-settled stock-based compensation expense resulting from a decline in the fair value of our incentive awards.

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. Similarly, any future decrease in our stock price will result in lower compensation expense. Equity-settled stock-based compensation awards are not similarly adjusted for changes in our stock price. General and administrative expenses for equity-settled stock-based compensation, were approximately $8 million for the three months ended June 30, 2026 and $7 million for the three months ended March 31, 2026.

Net loss (gain) on natural gas purchase derivatives — Net loss from derivatives related to our purchase of natural gas was $5 million for the three months ended June 30, 2026 compared to a net loss of $24 million for the three months ended March 31, 2026. 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:

(in millions)

Other operating expenses, net — Other operating expenses, net increased $6 million to $60 million for the three months ended June 30, 2026 compared to $54 million for the three months ended March 31, 2026. For the three months ended June 30, 2026 and March 31, 2026, other operating expenses, net includes the following:

(in millions)

Income taxes – We recorded an income tax benefit of $56 million on $458 million of income before taxes for the three months ended June 30, 2026, representing an effective tax rate of 12% for the period and an annual effective tax rate of 35% for the six months ended June 30, 2026. The tax rate for the three months ended June 30, 2026 reflects a true up to the annual effective tax rate of 6% from the prior quarter as a result of an increase in the full year projected pre-tax loss and the benefit of income tax credits such as the marginal well credit made available in June 2026. The projected full year pre-tax loss is largely due to the effect of the derivative losses. The effective tax rate for the three months ended March 31, 2026 reflects nondeductible compensation and tax credits. See Part I, Item 1 – Financial Statements, Note 7 Income Taxes.

Six months ended June 30, 2026 compared to June 30, 2025

The following table presents our consolidated operating revenues for the periods indicated:

(in millions)

41

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 $1,961 million for the six months ended June 30, 2026, which was an increase of $445 million compared to $1,516 million for the six months ended June 30, 2025.

The following table shows changes in oil, natural gas and natural gas liquids sales for the six months ended June 30, 2026 compared to the six months ended June 30, 2025.

(in millions)

Note: See Production for volumes by commodity type and Prices and Realizations for index and realized prices for comparative periods.

(a) The increase in production primarily relates to the addition of the Berry fields on December 18, 2025. See Part I, Item 1 – Financial Statements, Note 2 Business Combination for additional information.

Net (loss) gain 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 loss from commodity derivatives was $643 million for the six months ended June 30, 2026 compared to a net gain of $163 million for the six months ended June 30, 2025. 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:

(in millions)

Revenue from marketing of purchased commodities — Revenue from marketing of purchased commodities was $67 million for the six months ended June 30, 2026, which was a decrease of $53 million from $120 million during the six months ended June 30, 2025. The decrease was primarily the result of lower natural gas prices and volumes in 2026 compared to 2025. Additionally, we had lower crude oil volumes purchased and used for blending in the six months ended June 30, 2026 compared to 2025.

Electricity revenue — Electricity revenue decreased by $63 million to $17 million for the six months ended June 30, 2026 compared to $80 million for the six months ended June 30, 2025. This decrease was primarily a result of lower pricing from resource adequacy contracts in 2026 compared to the prior year period.

The following table presents our consolidated operating and non-operating expenses and income for the six months ended June 30, 2026 and June 30, 2025.

(in millions)

Operating costs — The following table presents our operating costs for the six months ended June 30, 2026 and June 30, 2025.

(in millions)

Energy operating costs — Energy operating costs for the six months ended June 30, 2026 were $197 million, which was an increase of $16 million from $181 million for the six months ended June 30, 2025. The increase is primarily related to the addition of the Berry fields for the full six months of 2026 compared to the same prior year period. Excluding Berry, energy operating costs decreased due to lower prices and volumes of natural gas purchased and used in our steamflood operations for the six months ended June 30, 2026.

Non-energy operating costs — Non-energy operating costs for the six months ended June 30, 2026 were $504 million, which was an increase of $83 million from $421 million for the six months ended June 30, 2025. The increase is primarily related to the operation of the Berry fields for the full six months of 2026 compared to a six-month period in the same prior year period. Excluding Berry, we had higher downhole maintenance activity and compensation-related expenses during the six months ended June 30, 2026 compared to the same prior year period. These increases were partially offset by a decrease in workover activity and lower surface operations maintenance activity.

General and administrative expenses — General and administrative (G&A) expenses were $203 million for the six months ended June 30, 2026 compared to $151 million for the six months ended June 30, 2025, which was an increase of $52 million. The increase was primarily due to additional compensation-related expense and other corporate expenses resulting from the Berry Merger. We also had higher legal costs in the six months ended June 30, 2026 compared to the same prior year period.

Taxes other than on income — Taxes other than on income for the six months ended June 30, 2026 were $133 million, which is an increase of $16 million from $117 million for the six months ended June 30, 2025. This increase was a result of higher greenhouse gas expense, production taxes and ad valorem taxes related to the Berry assets following the completion of the Berry Merger.

Costs related to marketing of purchased commodities — Costs related to marketing of purchased commodities were $38 million for the six months ended June 30, 2026, which was a decrease of $53 million from $91 million for the six months ended June 30, 2025. The decrease primarily related to lower natural gas prices and lower crude oil volumes purchased for blending in the six months ended June 30, 2026 compared to 2025.

Transportation costs — Transportation costs for the six months ended June 30, 2026 were $56 million which is an increase of $16 million from $40 million for the six months ended June 30, 2025. The increase in transportation costs was primarily a result of additional transportation contracts assumed in the Berry Merger.

Net loss (gain) from natural gas purchase derivatives — Net loss from derivatives related to our purchase of natural gas was $29 million for the six months ended June 30, 2026 compared to a net gain of $3 million for the six months ended June 30, 2025. 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 natural gas purchase derivative contracts are shown in the table below:

(in millions)

Other operating expenses, net — Other operating expenses, net increased $16 million to $114 million for the six months ended June 30, 2026 compared to $98 million for the six months ended June 30, 2025.

For the six months ended June 30, 2026 and June 30, 2025, other operating expenses, net includes the following:

(in millions)

(a) See Part I, Item 1 – Financial Statements, Note 5 Lawsuits, Claims, Commitments and Contingencies for more information on a $25 million payment we made to CalGEM during the six months ended June 30, 2025.

Loss on early extinguishment of debt – Loss on early extinguishment of debt was $49 million for the six months ended June 30, 2026, which included $40 million of premiums paid and $9 million of write-offs of unamortized debt issuance costs net of unamortized premium. Loss on early extinguishment of debt was $1 million for the six months ended June 30, 2025 for the write-off of unamortized debt issuance costs.

Income taxes – The income tax benefit for the six months ended June 30, 2026 was $105 million (representing an effective tax rate of 35%), compared to a provision of $117 million (representing an effective tax rate of 29%) for the six months ended June 30, 2025. See Part I, Item 1 – Financial Statements, Note 7 Income Taxes for additional information on our income taxes.

For financial information related to our subsidiaries designated as Unrestricted Subsidiaries under the 2034 Senior Notes Indenture and 2035 Senior Notes Indenture, see Part I, Item 1 – Financial Statements, Note 14 Condensed Consolidating Financial Information.

Results of Our Oil and Natural Gas Operations

The following table includes financial results and key operating data for our oil and natural gas segment for the periods presented.

(in millions, except as otherwise stated)

(a) Includes general and administrative expenses allocated to our oil and natural gas segment.

(b) Excludes depreciation, depletion and amortization related to our corporate assets and our Elk Hills power plant.

Production, Prices, and Realizations

Net Production Sold

The following table presents our net production sold per day in each of the basins in which we operate for the periods presented. The amounts in the production table below include volumes produced from operated and non-operated fields for each of the periods presented.

Total average net production sold decreased by 5 MBoe/d to 149 MBoe/d for the three months ended June 30, 2026 compared to 154 MBoe/d for the three months ended March 31, 2026. The decrease was primarily a result of an increase in our crude oil inventory and natural production decline, partially offset by increased production from drilling and workover activity. Additionally our production-sharing contracts (PSCs), which are described below, negatively impacted our net oil production by 2 MBoe/d in the three months ended June 30, 2026 compared to the three months ended March 31, 2026.

Total average net production sold increased to 152 MBoe/d for the six months ended June 30, 2026 compared to 139 MBoe/d for the six months ended June 30, 2025. The increase included 22 MBoe/d related to the addition of the Berry properties. Excluding the impact of Berry production, our production decreased as a result of an increase in our crude oil inventory and natural production decline, partially offset by increased production from drilling and workover activity. Our PSCs, which are described below, negatively impacted our net oil production by 1 MBoe/d in the six months ended June 30, 2026 compared to the six months ended June 30, 2025. For more information on the increase in our crude oil inventory, see Marketing Arrangements above.

Production-Sharing Contracts

Our share of production and reserves from operations in the Wilmington field in the Los Angeles basin is subject to contractual arrangements similar to production-sharing contracts that are in effect through the economic life of the assets. Under such contracts we are obligated to fund all capital and operating costs. We record a share of production and reserves to recover a portion of such capital and operating costs and an additional share for profit. Our portion of the production represents volumes: (i) to recover certain capital and operating costs that we incur, (ii) for our share of contractually defined base production where applicable, and (iii) for our share of remaining production thereafter. We generate returns through our defined share of production from (ii) and (iii) above. These contracts do not transfer any right of ownership to us and reserves reported from these arrangements are based on our economic interest as defined in the contracts. Our share of production and reserves from these contracts decreases when product prices rise and increases when prices decline, assuming comparable capital investment and operating costs. However, our net economic benefit is greater when product prices are higher.

The reporting of our PSCs creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs. For further information on our production-sharing contracts, see Part I, Item 1 & 2 Business and Properties, Oil and Natural Gas Segment, Production, Price and Cost History in our 2025 Annual Report.

Prices and Realizations

The following table sets forth the average realized prices and price realizations (as a percentage of average Brent, WTI and NYMEX Henry Hub, as applicable) for the commodities we sell in the periods presented:

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Oil — Brent crude oil prices for the three and six months ended June 30, 2026 were volatile as a result of the conflict in the Middle East, as well as various market responses to cessations in hostilities.

NGLs — Realizations on natural gas liquids during the three months ended June 30, 2026 decreased compared to the three months ended March 31, 2026 as liquids attempted to keep pace with crude oil prices. Prices for natural gas liquids during the six months ended June 30, 2026 were slightly lower than the prior year due to year-over-year increases in U.S. natural gas production and ample product inventories. California NGLs maintained a premium to the broader North American NGL market.

Natural Gas — North American natural gas prices for the three months ended June 30, 2026 were generally lower compared to the three months ended March 31, 2026 due to reduced seasonal demand. Natural gas prices increased for the six months ended June 30, 2026 compared to the six months ended June 30, 2025 driven by stronger winter demand. California natural gas prices for the three months ended June 30, 2026 were lower than the three months ended March 31, 2026 as storage inventories remained elevated and production from outside the state made its way to California. California natural gas prices for the six months ended June 30, 2026 were lower compared to the prior year as warmer-than-normal winter temperatures, out-of-state imports and elevated storage inventory levels impacted prices.

Results of Our Carbon Management Segment

Our carbon management segment, which we refer to as Carbon TerraVault, is engaged in the operation and development of CCS projects. We recently completed construction of our first carbon capture project at our cryogenic gas processing facility and achieved our first injection during the second quarter of 2026. We expect that our Carbon TerraVault business will develop other CCS projects using CO2 captured from industrial, power, agriculture and other emissions sources into subsurface reservoirs and permanently store CO2 deep underground. We may also participate in the ownership and development of projects that are the source of these CO2 emissions. We define carbon management expenses to be our direct operating costs to run our carbon management segment.

The following table includes results for our carbon management segment for the periods presented.

(in millions)

(in millions)

Carbon management expenses were slightly higher for the three months ended June 30, 2026 compared to the three months ended March 31, 2026 as a result of additional compensation-related expense.

Carbon management expenses decreased for the six months ended June 30, 2026 compared to the six months ended June 30, 2025 as a result of lower easement costs and preliminary development expenses.

Liquidity and Capital Resources

Liquidity

Our primary sources of liquidity and capital resources are cash flows from operations, available cash and cash equivalents, proceeds from the 2034 Senior Notes and 2035 Senior Notes 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, 2026 were for capital investments, payment of dividends and costs related to the redemption of our 8.250% senior unsecured notes due 2029 (2029 Senior Notes).

The following table summarizes our liquidity:

(in millions)

(a) Excludes restricted cash of $13 million.

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, our 7.000% senior notes due 2034 (2034 Senior Notes), and our 7.250% senior notes due 2035 (2035 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.

Revolving Credit Facility

On April 14, 2026, the borrowing base under our Revolving Credit Facility was reaffirmed at $1.5 billion and we entered into an amendment to the Revolving Credit Facility. See Part I, Item 1 – Financial Statements, Note 4 Debt for more information.

Senior Notes

In June 2026, we completed an offering of $550 million of 2035 Senior Notes, the proceeds of which were used together with cash on hand to redeem all of the remaining outstanding 2029 Senior Notes. Following this redemption, we had outstanding $750 million of 2034 Senior Notes and $550 million of 2035 Senior Notes. See Part I, Item 1 – Financial Statements, Note 4 Debt for more information on our 2029 Senior Notes, 2034 Senior Notes and 2035 Senior Notes.

Share Repurchase Program

See Part I, Item 1 – Financial Statements, Note 9 Stockholders' Equity for more information on our Share Repurchase Program.

Dividends

See Part I, Item 1 – Financial Statements, Note 9 Stockholders' Equity for more information on our dividends. See Part I, Item 1 – Financial Statements, Note 15 Subsequent Events for information on a dividend declared in August 2026.

Capital Program

Our 2026 capital program is expected to range from $520 million to $560 million. Of this amount, $500 million to $525 million is related to our oil and natural gas segment, $12 million to $20 million is for our carbon management segment and $8 million to $15 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 an average of 5 rigs in the second half of 2026 which is an increase from an average of 4 drilling rigs in the first half of 2026.

The amounts in the table below reflect components of our capital investment for the periods indicated, excluding changes in capital investment accruals:

(in millions)

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Derivatives

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.

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, 2026. 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, 2026 and Part II, Item 8 – Financial Statements and Supplementary Data, Note 5 Debt in our 2025 Annual Report for information on the hedging requirements included in our Revolving Credit Facility.

Cash Flow Analysis

Cash flows from operating activities — For the six months ended June 30, 2026, our operating cash flow increased by $11 million to $362 million from $351 million in the same period in 2025. This increase in operating cash flow was primarily driven by changes in working capital.

Oil production during the six months ended June 30, 2026 as compared to the same period in 2025 increased 12 MBbl/d from 110 MBbl/d to 122 MBbl/d as a result of the Berry Merger. Revenue increased as a result of the increases in production from the Berry Merger and higher average realized prices after derivative settlements. Average realized prices after derivative settlements for oil increased by $3.49 per barrel to $72.88 in the six months ended June 30, 2026 from $69.39 in the same prior year period. Our derivative settlements and premiums paid for the six months ended June 30, 2026 were $258 million, which was an increase of $240 million from $18 million in the same prior year period. Further, as a result of the Berry Merger, we experienced higher operating costs, employee costs, well abandonment costs, production taxes and greenhouse gas taxes during the six months ended June 30, 2026 as compared to the same prior year period.

Cash flows used in investing activities — The following table provides a comparative summary of net cash used in investing activities:

(in millions)

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Cash flows used in financing activities — The following table provides a comparative summary of net cash used in financing activities:

(in millions)

(a) 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.

For the six months ended June 30, 2026, our cash flow used in financing activities was $149 million compared to $521 million in the same period in 2025. In the six months ended June 30, 2026, we completed the issuance of our 2035 Senior Notes, an add-on to our 2034 Senior Notes and redeemed all of our outstanding 2029 Senior Notes. In the six months ended June 30, 2025, we repurchased $318 million of our common stock and redeemed $123 million of our 2026 Senior Notes.

Acquisitions and Divestitures

Crimson Acquisition

In June 2026, we entered into an agreement to acquire Crimson Midstream Holdings, LLC (Crimson) from CorEnergy Infrastructure Trust Inc. Crimson owns various onshore midstream assets in California, including the San Pablo Bay Pipeline and SoCal Pipeline System. The aggregate cash purchase price for the transaction is approximately $63 million, subject to certain adjustments. We believe this transaction strengthens our long-term market access, while also providing opportunities to enhance flow and optimize utilization of the pipeline system. We also expect to generate tariff revenue from certain of these lines that are in service as common carriers. Closing of the transaction is contingent on satisfaction of customary closing conditions, including receipt of required government approvals, and is expected later this year.

Lawsuits, Claims, Commitments and Contingencies

See Part I, Item 1 – Financial Statements, Note 5 Lawsuits, Claims, Commitments and Contingencies for further information.

Critical Accounting Estimates and Significant Accounting and Disclosure Changes

There have been no changes to our critical accounting estimates, which are summarized in Part II, Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Estimates of our 2025 Annual Report.

Forward-Looking Statements

This document contains statements that we believe 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 our 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. Such 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 we believe the expectations and forecasts reflected in our 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 our 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 our actual results to be materially different than those expressed in our forward-looking statements include:

• fluctuations in commodity prices, including supply and demand considerations for our products and services, and the impact of such fluctuations on revenues and operating expenses;
• decisions as to production levels and/or pricing by OPEC+ or U.S. producers in future periods;
• government policy, war and political conditions and events, including the military conflicts in Israel and Ukraine and geopolitical uncertainty in the Middle East, including the current conflict in Iran;
• the ability to successfully execute integration efforts in connection with the Berry Merger, and achieve projected synergies and ensure that such synergies are sustainable;
• regulatory actions and changes that affect the oil and gas industry generally and us in particular, including (1) the availability or timing of, or conditions imposed on, EPA and other governmental permits and approvals necessary for drilling or development activities or our carbon management segment; (2) the management of energy, water, land, greenhouse gases (GHGs) or other emissions, (3) the protection of health, safety and the environment, or (4) the transportation, marketing and sale of our products;
• refinery closures and reductions in pipeline transportation capacity;
• the efforts of activists to delay or prevent oil and gas activities or the development of our carbon management segment through a variety of tactics, including litigation;
• the impact of inflation, tariffs and changes in domestic or global trade policies on future expenses and changes generally in the prices of goods and services;
• changes in business strategy and the ability and financial resources to execute our capital plan in a timely manner;
• lower-than-expected production or higher-than-expected production decline rates;
• changes to our estimates of reserves and related future cash flows, including changes arising from our inability to develop such reserves in a timely manner, and any inability to replace such reserves;
• the recoverability of resources and unexpected geologic conditions;
• general economic conditions and trends, including conditions in the worldwide financial, trade and credit markets;
• production-sharing contracts' effects on production and operating costs;
• the lack of available equipment, service or labor price inflation;
• limitations on transportation or storage capacity and the need to shut-in wells;
• any failure of risk management;
• results from operations and competition in the industries in which we operate;
• our ability to realize the anticipated benefits from prior or future efforts to reduce costs;
• environmental risks and liability under federal, regional, state, provincial, tribal, local and international environmental laws and regulations (including remedial actions);
• the creditworthiness and performance of our counterparties, including financial institutions, operating partners, CCS project participants and other parties;
• reorganization or restructuring of our operations;
• our ability to claim and utilize tax credits or other incentives in connection with our CCS projects;
• our ability to realize the benefits contemplated by our energy transition

strategies and initiatives, including CCS projects and other renewable energy efforts;

• 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 MOUs and CDMAs to definitive agreements and enter into other offtake agreements;
• our ability to grow and develop our carbon management segment and achieve projected injection and storage rates;
• our ability to successfully develop infrastructure projects and enter into third party contracts on contemplated terms;
• uncertainty around the accounting of emissions and our ability to successfully gather and verify emissions data and other environmental impacts;
• changes to our dividend policy and share repurchase program, and our ability to declare future dividends or repurchase shares under our debt agreements;
• limitations on our financial flexibility due to existing and future debt;
• insufficient cash flow to fund our capital plan and other planned investments and return capital to shareholders;
• changes in interest rates;
• 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;
• changes in state, federal or international tax rates, including our ability to utilize our net operating loss carryforwards to reduce our income tax obligations;
• effects of hedging transactions;
• the effect of our stock price on costs associated with incentive compensation;
• inability to enter into desirable transactions, including joint ventures, divestitures of oil and natural gas properties and real estate, and acquisitions, and our ability to achieve any expected synergies;
• disruptions due to earthquakes, forest fires, floods, extreme weather events or other natural occurrences, accidents, mechanical failures, power outages, transportation or storage constraints, labor difficulties, cybersecurity breaches or attacks or other catastrophic events;
• pandemics, epidemics, outbreaks, or other public health events, such as the COVID-19 pandemic;
• transaction costs;
• unknown liabilities; and
• other factors discussed in Part I, Item 1A – Risk Factors.

We caution you not to place undue reliance on forward-looking statements contained in this document, which speak only as of the filing date, and we undertake 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 we have not independently verified them and do not warrant the accuracy or completeness of such third-party information.

For the three and six months ended June 30, 2026, there were no material changes to market risks from the information provided under Item 305 of Regulation S-K included under the caption Part II, Item 7A – Quantitative and Qualitative Disclosures About Market Risk in the 2025 Annual Report.

Commodity Price Risk

Our financial results are sensitive to fluctuations in oil, NGL and natural gas prices. Increases in commodity prices generally result in higher revenues from commodity sales, while increases in natural gas prices also result in higher operating costs. These commodity price changes also impact the volume changes under our PSCs. We maintain a commodity hedging program focused on hedging crude oil sales and natural gas purchases to help protect our cash flows, margins and capital program from the volatility of commodity prices. As of June 30, 2026, we had a net liability of $198 million for our commodity derivative positions which are carried at fair value. We estimate that a $10/bbl increase in Brent oil forward prices could increase our settlement payments by $84 million in 2026, limiting our upside. We estimate that a $10/bbl decrease in Brent oil forward prices could decrease our settlement payments by $81 million in 2026, negating the downside price movements for hedged volumes.

As of June 30, 2026, we have hedges on approximately 64% of our expected oil production for the remainder of 2026 at a weighted average floor price of $64.88. As of June 30, 2026, our hedges for purchased natural gas approximate 59% of our expected fuel use in oil and natural gas operations for the remainder of 2026 at a fixed price of $4.05.

For more information on our derivative positions as of June 30, 2026, refer to Part I, Item 1 – Financial Statements, Note 6 Derivatives.

Counterparty Credit Risk

Our credit risk relates primarily to trade receivables and derivative financial instruments. Credit exposure for each customer is monitored for outstanding balances and current activity. Counterparty credit limits have been established based upon the financial health of our counterparties, and these limits are actively monitored. In the event counterparty credit risk is heightened, we may request collateral and accelerate payment dates. Concentration of credit risk is regularly reviewed to ensure that counterparty credit risk is adequately diversified.

As of June 30, 2026, the majority of our credit exposure was with investment-grade counterparties. We believe exposure to counterparty credit-related losses related to our business at June 30, 2026 was not material and losses associated with counterparty credit risk have been insignificant for all periods presented.

Interest-Rate Risk

Changes in interest rates may affect the amount of interest we pay on our long-term debt. We had no variable-rate debt outstanding as of June 30, 2026. Our 2034 Senior Notes bear interest at a fixed rate of 7.000% per annum. Our 2035 Senior Notes bear interest at a fixed rate of 7.250% per annum.

We are subject to various risks and uncertainties in the course of our business. A discussion of such risks and uncertainties may be found under the heading Risk Factors in our 2025 Annual Report. There were no material changes to those risk factors during the three months ended June 30, 2026.