California Resources Corp: Form 10-Q for the period ended Mar 31, 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 increased significantly towards the end of the three months ended March 31, 2026 and continuing to date through the second quarter due to military conflicts and geopolitical tensions. In March 2026, oil prices escalated sharply as Middle East crude and product flows from the region were interrupted due to damage to regional energy infrastructure and the effective closure of the Strait of Hormuz. Additionally, oil prices were affected to a lesser extent by Ukrainian military strikes that significantly impacted Russian export capabilities. 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 three months of 2026 compared to the prior year. U.S. tariff policy regarding both country of origin and material type remains highly uncertain and subject to future changes. During 2025, the United States significantly expanded tariff rates on imported goods, including increasing Section 232 tariffs on steel and aluminum to 50% and adding copper at the same rate. In February 2026, the Supreme Court ruled that the President's use of emergency powers under the International Emergency Economic Powers Act to impose country-specific "reciprocal" tariffs was unconstitutional; however, Section 232 metals tariffs were not affected by this ruling. In April 2026, the Federal government further restructured the Section 232 metals tariffs establishing a tiered rate structure based on metal content and applying tariffs to the full customs value of imported articles rather than only the embedded metal content.

These expanded and restructured tariff rates are expected to increase our cost of oilfield goods and extend delivery lead times over the longer term. The shift to full-value assessment for derivative articles, in particular, may increase duty burdens on certain imported components and assemblies beyond prior levels. Overall, we expect a slight impact from tariffs on our supply chain in 2026. We believe we can mitigate a portion of these cost increases through bulk purchases, domestic sourcing, and ongoing review of product classifications and supplier origin. However, the evolving nature of tariff policy — including the potential for future modifications, legal challenges, and new product inclusions — creates continued uncertainty that may limit our ability to fully offset these impacts.

High fuel costs are adversely impacting transportation and equipment prices, and high oil prices are impacting oil-based products such as chemicals and lubricants. At current oil prices, we expect these costs to increase by $6 million to $8 million for the remainder of 2026.

Marketing Arrangements

In early 2026 Valero ceased purchasing crude oil for its Benicia refinery and it is reported that the refinery ceased operations in April 2026. While we have historically sold a portion of our crude oil to this refinery, we have not experienced difficulty in selling our production to the remaining refineries in California or any negative impact on pricing or realizations as a result of this closure.

In March 2026, the United States Secretary of Energy issued an order under the authority of the Defense Production Act of 1950 directing Sable Offshore Corp. (Sable) to restart oil and gas production at the San Ynez Unit, located in Federal offshore waters, and to facilitate the movement of offshore crude oil into California via the Las Flores pipeline. The State of California and other non-governmental organizations have filed suit against the United States Secretary of Energy and Sable, the owner of the San Ynez Unit, to block transportation of this crude oil into California. However, Sable has indicated that it is currently producing crude oil and has the potential to increase production to approximately 60,000 barrels per day. We expect that this additional production could strain existing pipeline transportation capacity required to reach refiners, which could require us to find alternative routes to market that may be limited or more costly. In addition, we expect that this production will have the potential to compete with our crude oil production in the California refining market.

Regulatory Updates

Well Permitting

During the three months ended March 31, 2026, we received permits for 66 new oil and gas wells, 21 workovers and 2 sidetracks. We currently hold sufficient permits to support a seven rig program, which includes 6 rigs in California and 1 rig in Utah, in the second half of 2026.

Water Injection

Our operations in the Wilmington Oil Field use injection wells to reinject produced water under approved 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. We expect that the next phase of reduction will remain on hold until the fall of 2026 while we evaluate the impact of the previously implemented reductions together with CalGEM. We currently estimate a negligible impact on production and reserves under the existing work plan. However, material changes to the existing plan could require revisions to these estimates.

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

In January 2026, the California Air Resources Board released proposed amendments to update its existing Cap-and-Invest program. The rulemaking process is ongoing, and the final terms and requirements of any proposed amendments have not yet been determined. We are actively monitoring these developments and potential impacts to our business.

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 months ended March 31, 2026 to the prior comparative period.

Consolidated Results of Operations

Three months ended March 31, 2026 compared to December 31, 2025

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 $905 million for the three months ended March 31, 2026, which was an increase of $226 million compared to $679 million for the three months ended December 31, 2025. Oil, natural gas and natural gas liquids sales included $131 million and $18 million for the three months ended March 31, 2026 and December 31, 2025, respectively, related to sales of additional production from the Berry properties following the completion of the Berry Merger on December 18, 2025.

The following table shows changes in oil, natural gas and natural gas liquids sales for the three months ended March 31, 2026 compared to the three months ended December 31, 2025:

(in millions)

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

Net (loss) gain 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 loss from commodity sales derivatives was $848 million for the three months ended March 31, 2026 compared to a net gain of $126 million for the three months ended December 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. Oil prices significantly increased as of March 31, 2026 compared to December 31, 2025. For instance, the Brent forward curve for the twelve months following March 31, 2026 increased by approximately 40% to $83.66 compared to $60.30 at December 31, 2025. As of March 31, 2026, we have hedges on approximately 65% of our expected oil production for the remainder of 2026 at a weighted average floor price of $64.99. 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 $41 million for the three months ended March 31, 2026 compared to $60 million for the three months ended December 31, 2025. The decrease was related to lower natural gas prices in California resulting from high storage levels.

Electricity revenue — Electricity revenue decreased by $41 million to $11 million for the three months ended March 31, 2026 compared to $52 million for the three months ended December 31, 2025. This decrease was primarily a result of reduced resource adequacy revenues as well as less electricity generated in response to market conditions during the three months ended March 31, 2026 compared to the three months ended December 31, 2025.

The following table presents our consolidated operating and non-operating expenses and income for the three months ended March 31, 2026 and December 31, 2025.

(in millions)

Operating costs — The following table presents our operating costs for the three months ended March 31, 2026 and December 31, 2025:

(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 March 31, 2026 were $110 million, which was an increase of $9 million from $101 million for the three months ended December 31, 2025 primarily due to the addition of the effect of the Berry properties as part of the Berry Merger. Excluding the Berry properties, energy operating costs decreased as a result of lower natural gas prices in the three months ended March 31, 2026 compared to the three months ended December 31, 2025.

Non-energy operating costs — Non-energy operating costs for the three months ended March 31, 2026 were $250 million, which was an increase of $30 million from $220 million for the three months ended December 31, 2025 primarily due to the addition of the Berry properties following the Berry Merger. Excluding the Berry properties, non-energy operating costs decreased for the three months ended March 31, 2026 compared to the three months ended December 31, 2025 primarily due to lower compensation-related costs and less workover and surface maintenance activity.

General and administrative expenses — General and administrative (G&A) expenses were $106 million for the three months ended March 31, 2026 compared to $95 million for the three months ended December 31, 2025. The increase primarily resulted from the Berry Merger including $12 million from higher compensation-related costs related to the addition of the Berry workforce and $3 million of incremental insurance cost. Additionally, cash-settled stock-based compensation expense increased by $7 million due to higher value on our incentive awards resulting from an increase in our stock price at March 31, 2026 compared to December 31, 2025. We also had higher legal costs in the three months ended March 31, 2026 compared to the three months ended December 31, 2025. Offsetting these increases, compensation-related expenses decreased $10 million in the three months ended March 31, 2026 compared to the three months ended December 31, 2025 due to the reduction of annual incentive compensation accruals.

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, was approximately $7 million for the three months ended March 31, 2026 and $6 million for the three months ended December 31, 2025.

Asset impairment — We did not record an asset impairment in the three months ended March 31, 2026. We recognized an asset impairment during the three months ended December 31, 2025 of $57 million related to the write-down of our proved natural gas properties in the Sacramento basin. For more information, refer to Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Property, Plant and Equipment in our 2025 Annual Report for more information.

Taxes other than on income — Taxes other than on income for the three months ended March 31, 2026 were $67 million, which was an increase of $12 million from $55 million for the three months ended December 31, 2025. The increase was primarily due to an increase in ad valorem and production taxes resulting from the Berry Merger.

Costs related to marketing of purchased commodities — Costs related to marketing of purchased commodities were $23 million for the three months ended March 31, 2026 compared to $47 million for the three months ended December 31, 2025. The decrease was primarily a result of lower natural gas prices and volumes purchased in the three months ended March 31, 2026.

Other operating expenses, net — Other operating expenses, net decreased $28 million to $54 million for the three months ended March 31, 2026 compared to $82 million for the three months ended December 31, 2025. For the three months ended March 31, 2026 and December 31, 2025, other operating expenses, net includes the following:

(in millions)

Income taxes – The income tax provision for the three months ended March 31, 2026 was a benefit of $49 million (representing an effective tax benefit of 6%), compared to a provision of $11 million (representing an effective tax rate of 48%) for the three months ended December 31, 2025. The effective tax rate for the three months ended March 31, 2026, reflects nondeductible compensation and tax credit. See Part I, Item 1 – Financial Statements, Note 7 Income Taxes.

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 three months ended March 31, 2026 and December 31, 2025.

(in millions, except as otherwise stated)

(a) Asset impairment for the three months ended December 31, 2025 includes the write-down of our proved properties in the Sacramento basin.

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

(c) 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 California 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 increased by 17 MBoe/d to 154 MBoe/d for the three months ended March 31, 2026 compared to 137 MBoe/d for the three months ended December 31, 2025. The increase included 19 MBoe/d related to the addition of the Berry properties. Excluding the impact of the Berry production, our net production decreased by 1 MBoe/d primarily as a result of natural decline, offset by development results. Additionally our production-sharing contracts (PSCs), which are described below, negatively impacted our net oil production by 1 MBoe/d in the three months ended March 31, 2026 compared to the three months ended December 31, 2025.

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 Operations, 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:

Oil — Brent crude oil prices for the three months ended March 31, 2026 were volatile as market focus during the period shifted from a developing oversupply situation to shortages driven by the military conflict in the Middle East and escalating crude infrastructure damage in Russia. For the three months ended March 31, 2026, Brent crude oil prices averaged $77.90 per barrel which was higher than $63.08 for the three months ended December 31, 2025.

NGLs — Realizations on natural gas liquids during the three months ended March 31, 2026 decreased compared to the three months ended December 31, 2025 as propane inventories built despite seasonal demand. California NGLs maintained a material premium to the broader North American NGL market.

Natural Gas — North American natural gas prices for the three months ended March 31, 2026 were generally higher compared to the three months ended December 31, 2025 as the Eastern part of the country experienced unseasonably cold weather. California natural gas prices for the three months ended March 31, 2026 were lower than the three months ended December 31, 2025 as warmer-than-normal temperatures and an abundance of storage impacted prices.

Results of Our Carbon Management Segment

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 CO2 captured from industrial, power, agriculture and other emissions sources into subsurface reservoirs and permanently store CO2 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 CO2 emissions. We recently completed construction of our first carbon capture project at our cryogenic gas processing facility and are preparing for first injection, subject to commissioning and final regulatory approval. We define carbon management expense to be our direct operating costs to run our carbon management segment.

The following table includes results for our carbon management segment for the three months ended March 31, 2026 and December 31, 2025.

(in millions)

Carbon management expenses decreased for the three months ended March 31, 2026 compared to the three months ended December 31, 2025 as a result of lower easement costs.

Liquidity and Capital Resources

Liquidity

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, 2026 were for capital investments and payment of dividends.

The following table summarizes our liquidity:

(in millions)

(a) Excludes restricted cash of $15 million.

At current commodity prices and based upon our planned 2026 capital program described below, we expect to generate operating cash flow to return cash to shareholders through dividends. 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 8.25% senior notes due 2029 (2029 Senior Notes), and our 7.00% senior notes due 2034 (2034 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. For more information, see Part I, Item 1 – Financial Statements, Note 15 Subsequent Events for more information.

2029 Senior Notes

In March 2026, we redeemed $350 million in face value of 2029 Senior Notes from the proceeds of an offering of additional 2034 Senior Notes. See Part I, Item 1 – Financial Statements, Note 4 Debt for more information.

2034 Senior Notes

In March 2026, we completed an offering of $350 million of additional 2034 Senior Notes. See Part I, Item 1 – Financial Statements, Note 4 Debt for more information.

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 15 Subsequent Events for information on a dividend declared in May 2026.

Capital Program

We entered 2026 with a capital program of $430 million to $470 million and have revised our 2026 capital program to a range of $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 increase to a seven rig program in the second half of 2026, which includes 6 rigs in California and 1 rig in Utah. We currently hold sufficient permits to support a seven rig program in the second 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)

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 three months ended March 31, 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 March 31, 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 three months ended March 31, 2026, our operating cash flow decreased by $87 million to $99 million from $186 million in the same period in 2025. This decrease in operating cash flow was primarily driven by changes in working capital.

Oil production during the three months ended March 31, 2026 as compared to the same period in 2025 increased 13 MBbl/d from 111 MBbl/d to 124 MBbl/d as a result of the Berry Merger. Revenue increased as a result of the increases in production from the Berry Merger offset by lower average realized prices after derivative settlements. Average realized prices after derivative settlements for oil decreased by $2.64 per barrel to $69.37 in the three months ended March 31, 2026 from $72.01 in the same prior year period. Our derivative settlements and premiums paid for the three months ended March 31, 2026 were $68 million, which was an increase of $40 million from $28 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 three months ended March 31, 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)

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

(in millions)

(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.

For the three months ended March 31, 2026, our cash flow used in financing activities was $55 million compared to $265 million in the same period in 2025. In the three months ended March 31, 2026, we completed an add-on to our 2034 Senior Notes and redeemed $350 million in face value of our 2029 Senior Notes. In the three months ended March 31, 2025, we repurchased $101 million of our common stock and redeemed $123 million of our 2026 Senior Notes.

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, and Venezuela;
• 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 expected timing and resumption of the issuance of well permits following the enactment of SB 237;
• 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 months ended March 31, 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 March 31, 2026, we had a net liability of $582 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 $195 million in 2026, limiting our upside. We estimate that a $10/bbl decrease in Brent oil forward prices could decrease our settlement payments by $152 million in 2026, negating the downside price movement for hedged volumes.

As of March 31, 2026, we have hedges on approximately 65% of our expected oil production for the remainder of 2026 at a weighted average floor price of $64.99. As of March 31, 2026, our hedges for purchased natural gas approximate 61% of our expected fuel use in oil and natural gas operations for the remainder of 2026 at a fixed price of $4.00.

For more information on our derivative positions as of March 31, 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 March 31, 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 March 31, 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 $25 million of variable-rate debt outstanding as of March 31, 2026. Our 2029 Senior Notes bear interest at a fixed rate of 8.250% per annum. Our 2034 Senior Notes bear interest at a fixed rate of 7.000% 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 March 31, 2026.