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Year-over-year tone shift - average net-tone change across Risk Factors and MD&A vs the prior 10-K. This filing is -0.40pp more bearish than last year's.
Why YoY instead of absolute: the LM lexicon has ~6.6× more negative words than positive (legal/risk-disclosure language is heavy on hedging), so every 10-K reads bearish on raw tone. Year-over-year change strips that bias and surfaces the actual shift in management's framing.
Tone shift by section
The two components the gauge averages: how Risk Factors and MD&A each shifted in net tone versus last year's 10-K. The headline above is their average, so a green needle over a soft section just means the other section carried it.
Risk Factors
-0.60pp
Lean -
Net-tone change vs last year's 10-K.
MD&A
-0.20pp
Flat
Net-tone change vs last year's 10-K.
Per-snippet highlights
Sentence-level sentiment highlighting with category and subcategory filters is coming once the snippet-scoring pipeline lands. For now, dig into the actual section text on the Sections tab.
Language change vs prior 10-K
Risk Factors (Item 1A) - words with the biggest YoY frequency increase
Negative rising
adversely+7
delay+6
litigation+3
volatility+3
harm+3
Positive rising
efficiently+3
progress+3
improvements+2
beautiful+2
success+1
Risk Factors (Item 1A)
12,745 words
ITEM 1A RISK FACTORS
Described below are certain risks and uncertainties that could adversely affect our business, financial condition, results of operations or cash flow. These risks are not the only risks we face. Our business could also be affected materially and adversely by other risks and uncertainties that are not currently known to us or that we currently deem to be insignificant.
Summary:
Risks Related to Our Oil and Gas Business
• Prices for our products are volatile and a substantial decline in prices over an extended period could have a material adverse effect on our financial condition, results of operations, cash flow and ability to invest in our assets.
• Our producing properties are located primarily in California, making us vulnerable to risks associated with having operations concentrated in this geographic area, including drought, earthquake and wildfire risks.
• Drilling for and producing oil and natural gas carries significant operational risks and uncertainty. We may not drill wells at the times we schedule, or at all. Wells we do drill may not yield production in economic quantities or generate the expected payback.
Language change vs prior 10-K
MD&A (Item 7) - words with the biggest YoY frequency increase
Negative rising
impairment+6
abandonment+3
closing+1
claims+1
cancelled+1
Positive rising
gains+1
achieve+1
MD&A (Item 7)
9,872 words
ITEM 7 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion should be read in conjunction with other sections of this report, including but not limited to, Part I, Item 1 and 2 – Business and Properties and Part II, Item 8 – Financial Statements and Supplementary Data.
See Part II, Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2024 (2024 Annual Report) for our analysis of the changes in our consolidated statements of operations and statements of cash flows for the year ended December 31, 2024 compared to December 31, 2023.
Basis of Presentation
All financial information presented consists of our consolidated results of operations, financial position and cash flows unless otherwise indicated. We have eliminated all intercompany transactions and accounts. We account for our share of oil and natural gas production activities, in which we have a direct working interest by reporting our proportionate share of assets, liabilities, revenues, costs and cash flows within the relevant lines on our balance sheets and statements of operations and cash flows. In applying the equity method of accounting, our investments in our unconsolidated subsidiaries are recognized either at cost, as is the case with Carbon TerraVault JV HoldCo, LLC, or at fair value if acquired in a business combination, as is the case for Midway Sunset Cogeneration Company. These investments are then adjusted for our proportionate share of income or loss in addition to contributions and distributions.
• Our business involves substantial capital investments, and we may be unable to fund these investments which could lead to a decline in our oil and natural gas reserves or production.
• Reductions in California refining and pipeline capacity could adversely affect our ability to market our production and our realized prices.
• We may be negatively impacted by inflation, including through increased operating, capital and financing costs.
• We are subject to economic downturns and the effects of public health events which may materially and adversely affect the demand and the market price for our products.
• The other risk factors described under Risks Related to Our Oil and Gas Business below.
Risks Related to Carbon TerraVault and Our Carbon Management Segment
• We may not be able to grow our Carbon TerraVault business and develop large scale CCS projects.
• Our ability to achieve our emissions goals, including our Responsible Net Zero objective, and other carbon management objectives is subject to significant risks and uncertainties.
• Our Carbon TerraVault business and other CCS projects depend on financial and tax incentives to be economical, and these incentives may be insufficient, unavailable, delayed, reduced or terminated.
• Our Carbon TerraVault JV with Brookfield is subject to inherent uncertainties that could adversely affect our ability to implement our carbon management strategy.
Risk Factors Related to Our Business Generally
• Increasing activism against the industries in which we operate, including the oil and gas industry and our involvement in carbon capture, storage, utilization and sequestration, presents risks to our business.
• Changes in expectations as to ESG matters may adversely impact our business, regulation and access to capital.
• Mergers, acquisitions and dispositions, including continued integration of the Berry Merger completed in December 2025, involve substantial risks.
• The other risks described under Risks Related to Our Business Generally described below.
Risks Related to Regulation and Government Action
• We may face material delays related to our ability to timely obtain permits necessary for our operations, or be unable to secure such permits on favorable terms or at all as a result of numerous California political, regulatory, and legal developments.
• Our operations in Utah are subject to additional regulatory, permitting and legal risks, including risks associated with federal and tribal lands.
• We may face increased local restrictions on oil and gas exploration and production operations or even be prohibited from operating in certain areas as a result of recently enacted California legislation.
• Recent and future actions by the State of California could reduce both the demand for and supply of oil and natural gas within the state and consequently have a material and adverse effect on our business, results of operations and financial condition.
• Our business is highly regulated and government authorities can delay or deny permits and approvals or change requirements governing our operations, including hydraulic fracturing and other well stimulation methods, enhanced production techniques and fluid injection or disposal, that could increase costs, restrict operations and change or delay the implementation of our business plans.
• Our Carbon TerraVault business and our CCS projects are subject to extensive government regulation much of which is still being developed. Failure to comply with these regulations and obtain the necessary permits, or the development of government regulations that are unfavorable to our CCS projects, could have an adverse effect on our business, results of operations and financial condition.
• The other risks described under Risks Related to Regulation and Government Action below.
Risks Related to Our Indebtedness
• We may not be able to amend or refinance our existing debt to create more operating and financial flexibility and to enhance shareholder returns.
• Our existing and future indebtedness may adversely affect our business, financial condition and financial flexibility.
• The other risks described under Risks Related to Our Indebtedness below.
Risks Related to Our Common Stock
• Our ability to pay dividends and repurchase shares of our common stock is subject to certain risks.
• The trading price of our common stock may decline, and you may not be able to resell shares of our common stock at prices equal to or greater than the price you paid or at all.
• The other risks described under Risks Related to Our Common Stock below.
Risks Related to Our Oil and Gas Business
Prices for our products are volatile and a substantial decline in prices over an extended period could have a material adverse effect on our financial condition, results of operations, cash flow and ability to invest in our assets.
Our financial condition, results of operations, cash flow and ability to invest in our assets are highly dependent on oil, natural gas and NGL prices. Prices for these products are volatile and are subject to fluctuations in response to factors beyond our control, including changes in global and regional supply and demand, inventory levels, geopolitical events (including conflicts in Ukraine and Israel and the geopolitical uncertainty in the Middle East and Venezuela), actions by OPEC and other significant producers, economic conditions, public health events, government regulation and policies relating to energy and climate change, weather conditions, natural disasters, transportation and storage constraints, and market speculation. Sustained periods of lower commodity prices could materially and adversely affect our business by reducing our cash flows, limiting our ability to fund capital expenditures, decreasing the value of our proved reserves, reducing our borrowing capacity under our Revolving Credit Facility, limiting our access to capital markets, and impairing our ability to service our indebtedness or comply with financial covenants. While we use commodity price hedging arrangements to manage a portion of our exposure to price volatility, our hedging program does not provide protection for all of our production, may limit our ability to benefit from price increases, and exposes us to counterparty risk. We may be unable to enter into additional hedging arrangements on acceptable terms or at all.
Our producing properties are located primarily in California, making us vulnerable to risks associated with having operations concentrated in this geographic area, including drought, earthquake and wildfire risks.
Our operations are highly concentrated in California. As a result, the success and profitability of our operations may be disproportionatelyexposed to the effect of regional conditions. Changes in state or regional laws and regulations affecting our operations, local price fluctuations and other regional supply and demand factors, including gathering, pipeline, transportation and storage capacity constraints, limited potential customers, infrastructure capacity and availability of rigs, equipment, oil field services, supplies and labor. Our operations are also exposed to natural disasters and related events common to California, such as wildfires, mudslides, high winds, earthquakes and extreme weather events, and the potential increase to the frequency of drought and flooding. Further, our operations may be exposed to power outages, mechanical failures, industrial accidents or labor difficulties. Certain of our operations depend on a limited number of specialized vendors and service providers in California, and the exit or reduced availability of key suppliers could increase costs, disrupt operations or delay planned activities. Any one of these events has the potential to cause producing wells to be shut in, delay operations and growth plans, decrease cash flows, increase operating and capital costs, prevent development of lease inventory before expiration and limit access to markets for our products.
Drilling for and producing oil and natural gas carries significant operational risks and uncertainty. We may not drill wells at the times we schedule, or at all. Wells we do drill may not yield production in economic quantities or generate the expected payback.
The development of oil and natural gas properties is subject to numerous operational risks, including the risks of permitting or construction delays, equipment failures, accidents, environmental hazards, unusual or unexpected geologic conditions, adverse weather conditions, title or surface access disputes, cost over-runs, and disappointing drilling results or reservoir performance. Development activities also depend in part on our analysis of geophysical, geologic, engineering, production and other technical data and processes, including the interpretation of 3D seismic data. This analysis is often inconclusive or subject to varying interpretations. Any of the foregoing operational risks could cause actual results to differ materially from the expected payback or cause a well or project to become uneconomic or less profitable than forecast.
If future drilling activities do not generate sufficient production and reserves, we may be forced to curtail drilling or development of our assets. We make assumptions about the consistency and accuracy of data when we identify locations for new wells or opportunities for workovers, sidetracks and deepenings, and these assumptions may prove inaccurate. We cannot guarantee that well locations will ever be drilled or if we will be able to produce crude oil or natural gas from these drilling locations or from our other drilling activities. In addition, some of our leases could expire if we do not establish production in the leased acreage. The combined net acreage covered by leases expiring in the next three years represented 2% of our total net undeveloped acreage at December 31, 2025.
Our business involves substantial capital investments, and we may be unable to fund these investments which could lead to a decline in our oil and natural gas reserves or production.
We intend to fund our 2026 capital program using cash flow from operations. Accordingly, a reduction in operating cash flow could require us to reduce, defer or reprioritize capital investments. In general, the ability to execute our capital plan depends on a number of factors, including production levels and commodity prices, regulatory and third-party approvals, our ability to timely drill, complete and stimulate wells, our ability to secure equipment, services and personnel, and our ability to fund capital expenditures.
Access to future capital may be limited by our lenders, capital markets constraints, activist funds or investors, or poor stock price performance. As a result, we may be unable to deploy capital in the manner planned, which could negatively impact our production, development activities and ability to pursue acquisitions or partnerships.
Unless we make sufficient capital investments and conduct successful development and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Over time, a sustained decline in our production and reserves could reduce our cash flows, liquidity and ability to satisfy our debt obligations and the value of our reserves.
Reductions in California refining and pipeline capacity could adversely affect our ability to market our production and our realized prices.
We sell nearly all of our crude oil production into California markets. In recent periods, certain California refineries and interconnected pipelines have announced closures or reductions in operations, and additional reductions in refining capacity may occur in the future. Decreases in in-state refining capacity or in the availability of related pipeline throughput may disrupt our ability to efficiently transport and market our crude oil, increase competition among producers for access to remaining refining outlets and reduce the number of available purchasers for our products. For example, the recent shutdown of the San Pablo Bay Pipeline eliminated pipeline access to Bay Area refineries and has prompted us to modify our marketing, transportation and shipping arrangements to reach alternative markets. See Part I, Item 1 and 2 – Business and Properties, Oil and Natural Gas Segment, Marketing Arrangements, Our Principal Customers. While we seek to manage these risks through marketing arrangements and operational flexibility, reduced refining capacity or related pipeline takeaway could adversely affect our ability to efficiently deliver our production to market, negatively impact pricing dynamics for our crude oil and result in lower realized prices or wider differentials in future periods. Any such impacts could have a material adverse effect on our results of operations and cash flows.
We may be negatively impacted by inflation, including through increased operating, capital and financing costs.
Increases in inflation may have an adverse effect on us. Operating and capital costs in the oil and natural gas industry are heavily influenced by commodity prices, including the prices we pay for electricity, natural gas and steel-based materials used in our operations. For example, we use natural gas and electricity extensively in our operations, including gas to generate steam for steam floods and electricity to power field operations. If we are unable to generate sufficient electricity for use in our operations, we may need to purchase electricity from third parties. Increases in the volumes or prices of commodities used in our operations could cause increases in our operating expenses. We attempt to manage our exposure to commodity price increases through hedging and longer-term fixed price contracts. However, these measures do not fully protect us from inflationary pressures and may not be available on acceptable terms or at all. Inflation could also result in higher interest rates, which could increase our future financing costs.
We are subject to economic downturns and the effects of public health events which may materially and adversely affect the demand and the market price for our products.
The marketing of our oil, natural gas and NGLs depends on the existence of adequate markets for our products. Imbalances between supply and demand, including as a result of economic downturns or public health events, could cause significant market volatility and adversely affect commodity prices. The extent and duration of public health events, governmental responses and resulting economic impacts are hard to predict. This uncertainty could force us to reduce operating expenses or capital expenditures, which could negatively affect future production and our reserves. We may experience labor shortages if our employees are unwilling or unable to come to work because of illness, quarantines, government actions or other restrictions in connection with a pandemic. If our suppliers cannot deliver the materials, supplies and services we need, we may need to suspend operations. In addition, we are exposed to changes in commodity prices which have been and will likely remain volatile. We cannot predict the duration and extent of a pandemic's adverse impact on our operating results.
A public health event that adversely affects global economic conditions could also heighten or exacerbate many of the other risks described in the Risk Factors herein.
The conflicts in Ukraine and Israel and the geopolitical uncertainty in the Middle East and Venezuela have caused price volatility and geopolitical instability which impact our business.
Conflicts and geopolitical tensions have contributed to volatility in the prices of oil, natural gas and NGLs in recent periods. The extent and duration of military actions, sanctions, retaliatory measures and resulting market disruptions are uncertain and could continue to have a substantial impact on the global economy and our business. In addition, any easing, suspension or removal of sanctions on Venezuelan oil production or exports could increase global supply and exert downward pressure on oil prices, which could adversely affect our results of operations and cash flows. In addition, disruptions to global shipping routes, energy infrastructure or transportation corridors, including in or near the Middle East, could further constrain supply, increase costs or contribute to additional price volatility.
Actions by OPEC+ and other producing countries, including decisions to implement, extend, unwind or reinstate production limits, may significantly affect global oil supply and prices. Actual production levels and spare capacity are difficult to assess, and increased production by OPEC+ members or other producing countries could contribute to price declines. These geopolitical developments may also heighten or exacerbate other risks described in this “ Risk Factors ” section.
Some of our competitors have greater resources than us and we may not be able to successfully compete in acquiring and developing new properties.
We face competition in every aspect of our business, including, but not limited to, acquiring reserves and leases, obtaining goods and services and hiring and retaining employees needed to operate and manage our business and marketing oil, natural gas or NGLs. Competitors include a multinational oil company, independent production companies and individual producers and operators. In California, our competitors are few, which may limit available acquisition opportunities. Some of our competitors have greater financial and other resources than we do. As a result, these competitors may be able to address such competitive factors more effectively than we can or withstand industry downturns more easily than we can.
Our hedging activities limit our ability to realize the full benefits of increases in commodity prices.
We enter into hedges to mitigate our economic exposure to commodity price volatility and ensure our financial strength and liquidity by protecting our cash flows. Our Revolving Credit Facility also includes a covenant that would require us to enter into hedges if the ratio of our indebtedness to Consolidated EBITDAX (as defined in the Revolving Credit Facility) exceeds certain levels. These hedges expose us to the risk of financial losses depending on commodity price movements and may prevent us from realizing the full benefits of price increases. Our ability to realize the benefits of our hedges also depends in part upon the counterparties to these contracts honoring their financial obligations. If any of our counterparties are unable to perform their obligations in the future, we could be exposed to increased cash flow volatility that could affect our liquidity. In addition, our level of hedging activity may be impacted by financial regulations that could increase our costs of hedging and/or limit the number of hedging counterparties available to us.
Estimates of proved reserves and related future net cash flows are not precise. The actual quantities of our proved reserves and future net cash flows may differ materially from our estimates.
Estimating proved reserves and related future net cash flows involves significant judgment and uncertainty, and our assumptions may ultimately prove to be inaccurate. In addition, reserve estimates may change over time as additional data becomes available through development and appraisal activities.
Our ability to maintain or increase our reserves, other than through acquisitions, depends on our ability to drill new wells, which may be limited by permitting constraints. See Risks Related to Regulation and Government Action – We may face material delays related to our ability to timely obtain permits necessary for our operations or be unable to secure such permits on favorable terms or at all as a result of numerous California political, regulatory and legal developments.
To the extent we are able to drill new wells, our ability to maintain or increase reserves depends on the success of improved recovery, extension and discovery projects, which are influenced by reservoir characteristics, technology improvements, commodity prices and operating costs. Many of these factors are outside management’s control and will affect whether the historical sources of proved reserves additions continue to provide reserves at similar levels.
Lower commodity prices may reduce the quantity of our proved reserves, particularly those expected to be produced in later years, and may cause certain proved undeveloped reserves to become uneconomic or fail to meet SEC development timing requirements, including the five-year rule. In addition, our reserves information represents estimates prepared by internal engineers. Although a substantial portion of our proved reserve estimates are audited by independent petroleum engineers, we cannot guarantee that the estimates are accurate.
Reserves estimation is a partially subjective process that depends on numerous variables and assumptions, including geology, regulatory approvals, capital availability, development effectiveness and commodity prices, many of which are outside of our control. Actual developments that differ from our expectations could cause us to make significant negative revisions to our reserves which could materially adversely affect our business.
From time to time we may engage in step-out drilling, or drilling in new or emerging plays, which involves heightened uncertainty and may reduce the value of undeveloped acreage if unsuccessful.
The risk profile for step-out drilling or drilling in new or emerging plays is higher than for other locations because we have less geologic and production data and drilling history. The economic success of such drilling depends on numerous variables, including commodity prices, capital availability, drilling results, regulatory approvals, costs and transportation capacity. We may not find commercial amounts of oil or natural gas or actual costs may be higher than initially expected. If future drilling results in these projects do not establish sufficient reserves to achieve an economic return, we may curtail drilling or development of these projects. In either case, the value of our undeveloped acreage may decline and could be impaired.
Risks Related to Carbon TerraVault and Our Carbon Management Segment
We may not be able to grow our Carbon TerraVault business and develop large scale CCS projects.
We are developing a carbon management business in California that relies on CCS projects, an emerging sector with limited large-scale precedent in the state. These projects are in the early-stages of development and therefore face significant operational, technological and regulatory risks, and our ability to successfully develop these projects depends on a number of factors beyond our control, including the following:
• Obtaining Class VI permits for carbon dioxide injection and storage from the EPA is a multi-year process, and the time to obtain permits may vary with the complexity and type of storage reservoir. The analysis of the suitability of a reservoir for carbon sequestration is complex and our permit applications are subject to extensive review by the EPA. There can be no assurances that the EPA will release Class VI permits to us when we expect, if at all, and our efforts to obtain Class VI permits could be subject to legal challenges.
• Because large-scale CCS projects represent an emerging sector, there are limited precedents to assess the economic feasibility or commercial terms of such projects. In addition, any of the operational, regulatory or financial risks described herein could cause actual results to differ materially from expected payback or cause a project to become uneconomic or less profitable than forecast.
• CCS projects may require significant capital investments by us, our joint venture partners and third parties, and sufficient capital or financing may not be available on reasonable terms or at all. In some cases, these projects involve the production of hydrogen, ammonia or other products and markets for some of these products are still emerging.
• CCS projects may require long-term agreements with emitters and other third parties, and we may be unable to secure such agreements on acceptable terms or at all.
• The development and operation of production facilities for hydrogen, ammonia and other products and associated sequestration facilities are highly complex. There can be no assurances that we or our partners will be able to successfully develop, maintain and operate these production and sequestration facilities.
• The performance of certain of our carbon and power-related projects depends in part on the reliable operation of associated power generation facilities, and reduced availability or unplannedoutages could adversely affect project economics and expected returns.
• Certain of our CCS projects rely on pore space we do not own, and we may be unable to obtain necessary rights from landowners on acceptable terms or at all.
• Complex recordkeeping and GHG emissions/sequestration accounting may be required in connection with one or more of our projects, which may increase the costs of such operations. Different methodologies may be required for various regulatory and non-regulatory accounts regarding GHG emissions/sequestration at one or more of our projects, including but not limited to compliance with the EPA’s Mandatory Greenhouse Gas Reporting Program.
• Carbon capture may be viewed as a pathway to the continued use of fossil fuels and there may be organized opposition (including lawsuits) to CCS projects from environmental groups, local residents and legislators.
• Other regulatory uncertainties described herein.
There can be no assurances that we will successfully develop our CCS projects, including our cryogenic gas plant CCS project or CalCapture, and a failure to do so could have an adverse effect on our carbon management business and its prospects. We do not expect the failure of a single CCS project to create an impact on our overall financial condition or operations. However, as the scale of our CCS projects grows, so will their impact on our overall financial condition and operations. Moreover, our failure to successfully develop our CCS projects would adversely affect our ability to claim emissions reductions related to our sequestration activities and our ability to meet our carbon management goals, which in turn could have an adverse effect on our business and reputation.
Our ability to achieve our emissions goals, including our Responsible Net Zero objective, and other carbon management objectives is subject to significant risks and uncertainties.
We have adopted various sustainability-related targets and objectives, including our Responsible Net Zero objective, and our efforts to establish, pursue and report on these targets expose us to operational, reputational, financial, legal and other risks. Our Responsible Net Zero objective considers Scope 1 and Scope 2 emissions, reflecting an approach that prioritizes operational emissions reductions and carbon management solutions while recognizing the ongoing role of responsibly produced energy and the practical, regulatory and technological constraints associated with achieving absolute net zero emissions.
Our ability to advance our Responsible Net Zero objective depends in significant part on the successful development of our Carbon TerraVault business and related carbon capture and sequestration projects, as well as continued operational improvements. These efforts are subject to substantial regulatory, technical and commercial uncertainty, including risks related to permitting, financing, third-party participation and evolving regulatory frameworks. If we are unable to successfully develop these projects or achieve anticipated operational improvements, our ability to advance our Responsible Net Zero objective could be materially and adversely affected.
In addition, emissions accounting standards, regulatory requirements and climate science continue to evolve. Changes in applicable laws, regulations, guidance or methodologies could affect our ability to claim emissions reductions, accurately report progress or achieve our stated objectives on the timelines contemplated, if at all.
Our adoption of a Responsible Net Zero objective may increase scrutiny from investors, regulators and other stakeholders, some of whom may have differing views regarding the appropriate scope, pace or methods for achieving emissions reductions. A failure or perceived failure to pursue or accurately describe progress toward our Responsible Net Zero objective, or to align related disclosures with evolving regulatory or market expectations, could expose us to regulatory enforcement actions, litigation, reputational harm, increased costs or reduced access to capital.
Our Carbon TerraVault business and other CCS projects depend on financial and tax incentives to be economical, and these incentives may be insufficient, unavailable, delayed, reduced or terminated .
Our Carbon TerraVault business and other CCS projects depend on financial and tax incentives established under federal and state laws, regulations and governmental programs to be economically viable. Governmental incentives are important to the expected economics of our carbon management business and related projects, including the Section 45Q carbon sequestration credit expanded under the Inflation Reduction Act, the One Big Beautiful Bill Act and LCFS credits under California law. The availability and value of these incentives depend on satisfaction of detailed statutory and regulatory requirements, some of which remain subject to evolving guidance, interpretation, audit and enforcement by the U.S. Department of the Treasury, the Internal Revenue Service, the California Air Resources Board and other federal and California state governmental authorities.
In addition to tax incentives, certain CCS projects may rely on federal grants, loans or other funding programs authorized under the Inflation Reduction Act or the Infrastructure Investment and Jobs Act. Such programs are subject to agency discretion, eligibility criteria, administrative review, funding availability and the risk of delay, modification, reprioritization or cancellation. Changes in federal administration priorities, executive orders, agency rulemaking, enforcement practices or congressional action have and could further modify, delay, limit, condition or repeal grants, funding programs or tax incentives applicable to our carbon management business. For example, the current administration has taken steps to reduce the availability of federal grants for CCS projects, including canceling grants that had been previously awarded.
If incentives such as the Section 45Q credit, LCFS credit or other applicable federal or state programs are eliminated, reduced, delayed, materially restricted or made subject to more burdensome compliance requirements, our Carbon TerraVault projects may become uneconomic or no longer feasible. In addition, the ability to monetize tax credits, including through direct pay, tax equity financing or credit transfers, is uncertain and depends on evolving federal rules, market liquidity, counterparties, pricing dynamics and compliance risk. We cannot assure that we or our partners will be able to efficiently monetize such incentives on acceptable terms or at all.
Many incentives applicable to CCS projects require long-term secure geological storage of captured CO₂ and ongoing compliance with monitoring, reporting and verification requirements. Failure to satisfy these requirements could result in the recapture of tax credits or other incentives, indemnification obligations to partners or counterparties, penalties, increased regulatory scrutiny or other liabilities. Any of the foregoing risks could materially and adversely affect our carbon management business, financial condition, results of operations and prospects.
Our Carbon TerraVault JV with Brookfield is subject to inherent uncertainties that could adversely affect our ability to implement our carbon management strategy.
In August 2022, we entered into the Carbon TerraVault JV with Brookfield to pursue the development of a carbon management segment in California. The management and financing of the joint venture are subject to inherent uncertainties, which could delay or prevent CCS projects, require us to seek alternative sources of capital or otherwise affect our carbon management strategy.
Brookfield has committed an initial $500 million to invest in CCS projects that are jointly approved through Carbon TerraVault JV. The remaining amount of Brookfield's initial investment will depend on the amount of storage capacity that is permitted subject to certain contractual adjustments . Future storage projects for Brookfield’s initial commitment are subject to approval of the joint venture, including Brookfield. There can be no assurances that any of these funding milestones will be achieved so that Brookfield will fund the rest of its commitment. In addition, the parties have certain put and call rights with respect to the 26R reservoir if certain milestones are not met . The exercise of Brookfield’s put right could materially and adversely affect our carbon management business, financial condition, results of operations and prospects.
Although we own a 51% interest in the Carbon TerraVault JV, we share decision making authority with Brookfield on matters that most significantly impact the economic performance of the joint venture. Any failure to reach a decision with Brookfield could potentially prevent or delay our pursuit of CCS projects or cause such projects to be cancelled. Moreover, if Brookfield does not approve a proposed CCS project that we want to pursue, we will have to seek alternative sources of capital to fund the project and there can be no assurances that such sources of capital will be available.
Risk Factors Related to Our Business Generally
Increasing activism against the industries in which we operate, including the oil and gas industry and our involvement in carbon capture, storage, utilization and sequestration, presents risks to our business.
Opposition toward oil and gas drilling and development activity has increased over time, and companies in the oil and gas industry are often the target of efforts by non-governmental organizations and individuals to delay or prevent oil and gas development, including through allegations regarding safety, environmental impacts or compliance and business practices. These efforts include seeking changes to laws, pressuring governmental agencies to engage in rulemaking or pursuing litigation.
This opposition also extends to our carbon management segment as certain activists oppose carbon capture and sequestration efforts by the oil and gas companies. For example, on November 22, 2024, a group of non-governmental organizations filed a Petition for Writ of Mandate and Complaint for Injunctive Relief against Kern County and its Board of Supervisors (CTV I Complaint) in Kern County for our CTV I project. This litigation is ongoing. See Regulation of Carbon Capture, Sequestration and Storage - CCS Project Permitting . Such lawsuits could delay construction or commencement of operations and have a material and adverse effect on our carbon management business and its prospects.
Heightened concerns by certain parties around climate change and GHG emissions have increased pressure on lawmakers, regulators and others to take action, particularly in California, regardless of the merit of these allegations. We may need to incur significant costs associated with responding to these initiatives and such actions may have a material adverse effect on our financial results. Complying with any resulting additional legal or regulatory requirements that are substantial or prevent or interfere with our activities could have a material adverse effect on our business, financial condition and results of operations.
Changes in expectations as to ESG matters may adversely impact our business, reputation and access to capital.
We face increased attention and evolving expectations from investors, regulators and other stakeholders regarding ESG matters, including climate change, environmental and social impacts and voluntary or mandatory ESG disclosures. Increased demand for alternative forms of energy may increase costs, reduce demand for our products and contribute to increased investigations and litigation, any of which could adversely affect our business. Increased attention to climate change and environmental conservation, for example, may result in demand shifts for oil and natural gas products and additional governmental investigations and private litigationagainst us. In some cases, liability or regulatory action may be pursued without regard to our causation of, or contribution to, the asserted harm. While we may participate in various ESG frameworks and certification programs, we cannot guarantee that such participation or certification will achieve intended outcomes or improve perceptions of our products or business.
Our ESG disclosures may be based on expectations, assumptions or hypothetical scenarios that are uncertain, subject to change and difficult to verify over long time horizons. Such expectations, assumptions or hypothetical scenarios are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established approach to identifying, measuring and reporting on many ESG matters. Additionally, while we may also announce various ESG targets, such targets are often aspirational and may be subject to change depending on changed circumstances, methodologies, business forecasts or other factors. We may not be able to meet or make progressagainst such targets in the manner or on such a timeline as initially contemplated, including, but not limited to as a result of unforeseen costs, inaccurate forecasts or technical difficulties. To the extent we do meet such targets, they may ultimately be achieved through various contractual arrangements, including the purchase of various credits or offsets that may be deemed to mitigate our ESG impact instead of actual changes in our ESG performance. However, we cannot guarantee that there will be sufficient offsets available for purchase given the increased demand from numerous businesses implementing net zero goals, or heightened scrutiny of their methodologies. Some of these arrangements may receive scrutiny from certain constituencies who criticize the methodology of offsets or do not believe offsets should be utilized to neutralize GHG emissions. Also, despite these aspirational goals, we may receive pressure from investors, lenders or other groups to adopt more aggressive climate or other ESG-related goals, but we cannot guarantee that we will be able to pursue or implement such goals, in whole or in part, because of potential costs or technical, inaccurate assumptions or operational obstacles.
Certain public statements regarding ESG matters are subject to increasing regulatory, litigation and political scrutiny, including allegations of “greenwashing” or challenges from so-called “anti-ESG” constituencies, which could result in investigations, enforcement actions, litigation or reputational harm. Additionally, certain employment or business practices and social initiatives are the subject of scrutiny by both those calling for the continued advancement of such policies, as well as those who believe they should be curbed, including government actors, and the complex regulatory and legal frameworks applicable to such initiatives continue to evolve. As a result, we may face increased litigation risks from private parties and governmental authorities related to our ESG efforts. Such ESG-related matters may also impact our customers or suppliers, which may adversely impact our business, financial condition or results of operations.
Mergers, acquisitions and dispositions, including the integration of the Berry Merger completed in December 2025, involve substantial risks.
We engage in acquisition activities from time to time, including the Berry Merger which closed in December 2025. The Berry Merger and other acquisition activities carry risks that we may:
• not fully realize anticipated benefits due to less-than-expected reserves or production or changed circumstances;
• bear unexpected integration costs, experience delays or challenges in integrating assets, systems, personnel or operations (including, in the case of the Berry Merger, drilling services operations), or fail to achieve anticipated synergies;
• assume liabilities that are greater than anticipated; and
• be exposed to currency, political, marketing, labor and other risks.
Although the Berry Merger was completed in December 2025, the integration of Berry’s assets, operations and personnel is ongoing and subject to execution risk, and we may not realize anticipated benefits within expected timeframes or at all.
In connection with mergers and acquisitions, we are often only able to perform limited due diligence, and assessments of reserves, production, costs and liabilities may be inaccurate or incomplete.
Future mergers and acquisitions may require approvals from shareholders, government agencies or other regulatory bodies, and there can be no assurance that such approvals will be obtained on acceptable terms or at all. If we are not able to successfully complete mergers and acquisitions, we may not be able to grow our reserves or production or develop our properties in a timely manner or at all.
We regularly review our property base for the purpose of identifying nonstrategic assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. Our disposition activities carry risks that we may:
• not be able to realize reasonable prices or rates of return for assets;
• be required to retain liabilities that are greater than desired or anticipated;
• experience increased operating costs; and
• reduce our cash flows if we cannot replace associated revenue.
There can be no assurance that we will be able to divest assets on financially attractive terms or at all. Our ability to sell assets is also limited by the agreements governing our indebtedness. If we are not able to sell assets as needed, we may not be able to generate proceeds to support our liquidity and capital investments.
In addition, we have expended and will continue to expend significant time and resources in connection with any future acquisition and disposition activities.
We may incur substantial losses and be subject to substantial liability claims as a result of pollution, environmental conditions or catastrophic events such as wildfires. We may not be insured for, or our insurance may be inadequate to protect us against, these risks.
We are not fully insured against all risks. Our business and assets are subject to risks from natural disasters and operating risks associated with oil and natural gas exploration and production activities. Pollution or environmental conditions with respect to our operations or on or from our properties, whether arising from our operations or those of our predecessors or third parties, could expose us to substantial costs and liabilities. Such events may cause operations to cease or be curtailed and could adversely affect our business, workforce and the communities in which we operate. The cost of insurance for natural disasters has increased in recent years. In California, insurance coverage for certain operational and catastrophic risks such as wildfires may be limited, subject to exclusions or available only at significantly increased cost, which could result in greater self-insurance exposure. We may be unable to obtain, or may elect not to obtain, insurance for certain risks if we believe that the cost of available insurance is excessive relative to the risks presented.
Cybersecurity attacks, systems failures, and other disruptions could adversely affect our operations, financial condition and reputation.
We rely on electronic systems and networks to manage our operations, financial reporting, data storage and communications with employees, service providers and customers. Systems failures, data inaccuracies or outages could impair our ability to operate efficiently and make timely business decisions.
Cybersecurity attacks have become more frequent and sophisticated, and we or third parties with whom we interact may be targeted by malicious actors. We utilize various technologies, controls and procedures, as well as internal staff and external specialists to protect our systems and data, to identify and remediate vulnerabilities and to monitor and respond to threats. However, these measures may not prevent security breaches from occurring. If a breach occurs, it may remain undetected for an extended period of time. A cybersecurity incident could result in data loss, business interruption, reputational harm, regulatory scrutiny, litigation, financial loss and significant remediation costs.
Energy-related assets may be at a heightened risk of cybersecurity or other malicious attacks. Such attacks could disrupt energy markets, delay or prevent product delivery, impair accounting or settlement processes or result in environmental or safety incidents.
As cybersecurity threats continue to evolve in sophistication and magnitude, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any cybersecurity vulnerabilities. Further, state and federal cybersecurity and data privacy legislation could result in complex new requirements that increase our cost of doing business.
Risks Related to Regulation and Government Action
We may face material delays related to our ability to timely obtain permits necessary for our operations or be unable to secure such permits on favorable terms or at all as a result of numerous California political, regulatory, and legal developments.
We must obtain various governmental permits to conduct exploration and production activities, as well as other aspects of our operations. Obtaining the necessary governmental permits is often a complex and time-consuming process involving numerous federal, state and local agencies, and the duration and success of each permitting effort is contingent upon many variables not within our control.
In recent years, we experienced significant delays in obtaining new well, sidetrack, deepening and workover permits from CalGEM, including delays attributable to enhanced environmental review requirements, litigationchallenging the Kern County environmental impact review process, agency resource constraints and policy developments. In early 2026, following the enactment of Senate Bill 237, CalGEM resumed issuing permits for new oil and gas wells in Kern County, and permitting activity has increased significantly with 31 permits for new wells issued in Kern County as of January 31, 2026. However, we cannot provide assurances that permit issuances will continue at anticipated levels or that future legislative, regulatory, administrative or judicial actions will not again delay or restrict permitting activity.
Although we have historically mitigated permitting risk by maintaining an inventory of approved permits, prolonged permitting delays or renewed uncertainty could limit our ability to execute drilling plans, adversely affect our capital program, reduce our ability to replace reserves and negatively impact our business, financial condition and results of operations.
We may face increased local restrictions on oil and gas exploration and production operations or even be prohibited from operating in certain areas as a result of recently enacted California legislation .
California law authorizes local governments to impose regulations, restrictions or prohibitions on oil and gas operations within their jurisdictions, including with respect to existing operations. While certain local measures have previously been challengedsuccessfully in court, recently enacted legislation has expanded local authority in this area. Although we do not currently operate in certain jurisdictions that have proposed or adopted phase-outs or bans, similar actions by local governments in areas where we do operate could increase operating costs, reduce production or reserves, or otherwise adversely affect our business.
Local restrictions may be adopted notwithstanding state-level permitting frameworks, and the resulting regulatory landscape may vary significantly by jurisdiction, increasing compliance complexity and uncertainty.
Recent and future actions by the State of California could reduce both the demand for and supply of oil and natural gas within the state and consequently have a material adverse effect on our business, results of operations and financial condition.
California continues to pursue policies aimed at reducing greenhouse gas emissions and transitioning the state’s energy system over time. Legislative, regulatory and executive actions may increase compliance costs, restrict development activities, limit infrastructure availability or otherwise adversely affect the production, transportation or consumption of oil and natural gas in the state.
While recent legislation, including Senate Bill 237, has provided greater regulatory clarity for certain permitting activities in Kern County, we cannot predict the scope, timing or cumulative impact of future state actions or whether such actions may offset or limit the benefits of recent legislative developments.
Our business is highly regulated and government authorities can delay or deny permits and approvals or change requirements governing our operations, including hydraulic fracturing and other well stimulation methods, enhanced production techniques and fluid injection or disposal, that could increase costs, restrict operations and change or delay the implementation of our business plans.
Our operations are subject to complex and stringent federal, state, local and other laws and regulations relating to the exploration and development of our properties, as well as the production, transportation, marketing and sale of our products.
To operate in compliance with these laws and regulations, we must obtain and maintain permits, approvals and certificates from federal, state and local government authorities for a variety of activities including siting, drilling, completion, stimulation, operation, inspection, maintenance, transportation, storage, marketing, site remediation, decommissioning, abandonment, protection of habitat and threatened or endangered species, air emissions, disposal of solid and hazardous waste, fluid injection and water disposal and consumption, recycling and reuse.
Failure to obtain the necessary permits, approvals and certificates or comply with these laws and regulations may result in the assessment of administrative, civil and/or criminalfines and penalties, liability for noncompliance, costs of corrective action, cleanup or restoration, compensation for personal injury, property damage or other losses, and the imposition of injunctive or declaratory relief restricting or prohibiting certain operations or our access to property, water, minerals or other necessary resources, and may otherwise delay or restrict our operations and cause us to incur substantial costs. Under certain environmental laws and regulations, we could be subject to strict or joint and several liability for the removal or remediation of contamination, including on properties over which we and our predecessors had no control, without regard to fault, legality of the original activities, or ownership or control by third parties.
Our Carbon TerraVault business and our CCS projects are subject to extensive government regulation much of which is still being developed. Failure to comply with these regulations and obtain the necessary permits, or the development of government regulations that are unfavorable to our CCS projects, could have an adverse effect on our business, financial condition and results of operations.
Successful development of CCS projects in the United States require that we comply with what we anticipate will be a stringent regulatory scheme requiring that we obtain certain permits applicable to subsurface injection of CO 2 for geologic sequestration. Moreover, as the operator of our CCS projects, we must demonstrate and maintain levels of financial assurance sufficient to cover the cost of corrective action, injection well plugging, post injection site care and site closure, and emergency and remedial response. There are no assurances that we will be successful in obtaining or maintaining permits or adequate levels of financial assurance for one or more of our CCS projects or that permits can be obtained on a timely basis, whether due to difficulty with the technical demonstrations required to obtain such permits, public opposition, or otherwise.
Separately, permitting CCS projects requires obtaining a number of other permits and approvals unrelated to subsurface injection from various U.S. federal and state agencies, such as for air emissions or impacts to environmental, natural, historic or cultural resources resulting from the construction and operation of a CCS facility. We cannot guarantee that we will be able to obtain or maintain all applicable permits for CCS activities on a timely basis or on favorable terms, if at all. Moreover, to the extent any of our CCS projects will require any supporting pipeline infrastructure, we could face additional costs and delays obtaining the necessary permits and rights of ways for such infrastructure, and increased risk of opposition to our projects, which may ultimately mean we are unable to successfully pursue certain CCS projects because of these risks.
As CCS and carbon management represent an emerging sector, laws and regulations may evolve rapidly, which could impact the feasibility of one or more of our anticipated projects. To the extent additional legal or regulatory requirements are imposed, are amended, or more stringently enforced, we may incur additional costs in the pursuit of one or more of our carbon capture projects, which costs may be material or may render any one or more of our projects uneconomical.
New and developing regulations related to the CO 2 unitization, permitting and pipeline safety could negatively impact our business, financial condition and results of operations.
Senate Bill No. 905 contemplates the development of unitization, permitting and pipeline safety regulations over a multi-year period to facilitate the development of CCS projects in California, though the legislation does not provide for compulsory unitization. Senate Bill No. 905 also provides for a unified permitting process to simplify the permitting process for CCS projects, although this will be optional for project applicants. Additionally, the law contemplates the implementation of a new regulatory program incorporating standards that are not yet defined and that could affect the timing of future CCS projects in California. The California Air Resources Board has been tasked with developing this proposed framework. We believe our Carbon TerraVault projects will continue to be developed on a timeline consistent with our initial expectations. These initial projects are not reliant on the unitization or permitting regulations being developed. In addition, our Carbon TerraVault projects are expected to either use emitters that are directly sited above these storage facilities or rely on pipelines for transporting CO 2 Senate Bill No. 905 provides that pipelines may be used to transport carbon dioxide to or from a carbon dioxide capture, removal or sequestration project only upon conclusion of PHMSA’s rulemaking strengthening safety requirements for carbon dioxide pipelines. Although PHMSA released a notice of proposed rulemaking to this effect in early January 2025, was subsequently withdrawn by the current administration prior to publication in the Federal Register. The lack of these final pipeline safety regulations may impair or prohibit projects that rely on the transportation of CO 2 .
Senate Bill No. 905 also prohibits CCS projects that utilize and permanently sequester CO 2 in connection with EOR projects. Although we do not have any existing oil and natural gas production or proved reserves associated with EOR projects, this legislation required us to transition our CalCapture project to target CCS and may require us to make other adjustments to projects in the future.
Senate Bill 614 (SB 614), enacted in October 2025, revises the definition of “pipeline” for purposes of the Elder California Pipeline Safety Act of 1981 to include intrastate pipelines used for the transportation of carbon dioxide (CO₂). The law requires the Office of the State Fire Marshal to adopt implementing regulations regarding the safe transportation of CO₂ in pipelines by July 1, 2026, establishing a pathway to lifting the current moratorium on the construction and operation of new CO₂ pipeline operations in the state. The legislation mandates stringent design, routing, and disclosure standards consistent with or exceeding a proposed revision to federal requirements under the Pipeline and Hazardous Materials Safety Administration that was subsequently withdrawn prior to federal enactment (Draft PHMSA Regulations). Under SB 614, CO₂ pipelines within a single facility and for which construction was permitted before July 1, 2025, shall not be required to subsequently comply with those regulations that pertain to design and construction if the pipeline is constructed to meet the standards of the Draft PHMSA Regulations. The CO₂ pipelines comprising our Carbon Terra Vault I (CTV I) project at our Elk Hills field were permitted prior to July 1, 2025, and have been constructed to meet the standards of the Draft PHMSA Regulations. Upon implementation, SB 614 is expected to help enable the development of carbon-capture and storage projects that rely upon capture of carbon dioxide from an emission source that is remote from the facility into which the emissions will be sequestered.
Our operations and financial performance may be negatively affected directly or indirectly by changes in trade policies and tariffs.
The United States government has indicated its intent to adopt a new approach to trade policy and in some cases to renegotiate, or potentially terminate, certain existing trade agreements. It has also initiated or is considering the imposition of tariffs on certain foreign goods and products. This has led to the United States increasing tariffs for certain goods, which triggered other nations to also increase tariffs on certain of their goods. While the extent and duration of the such tariffs remain uncertain, these measures, including 50% tariffs on imported steel, are likely to lead to increased material costs.
Concerns about climate change and other environmental issues may prompt governmental action that could have a material adverse effect on our operations or results.
Governmental, scientific and public concern over the threat of climate change arising from GHG emissions, and regulation of GHGs and other air quality issues, may have a material adverse effect on our business in many ways, including increasing the costs to provide our products and services and reducing demand for, and consumption of, our products and services, and we may be unable to recover or pass through a significant portion of our costs. In addition, legislative and regulatory responses to such issues at the federal, state and local level may increase our capital and operating costs and render certain wells or projects uneconomic, and potentially lower the value of our reserves and other assets. Both the EPA and California have implemented laws, regulations and policies that seek to reduce GHG emissions. California’s cap-and-trade program operates under a market system and the costs of such allowances per metric ton of GHG emissions are expected to increase in the future as the CARB tightens program requirements and annually increases the minimum state auction price of allowances and reduces the state’s GHG emissions cap. As the foregoing requirements become more stringent, we may be unable to implement them in a cost-effective manner, or at all.
In August 2022, President Biden signed the Inflation Reduction Act into law. The Inflation Reduction Act includes a charge on methane emissions that exceed certain thresholds from sources required to report their GHG emissions to the EPA, including certain oil and natural gas operations. In November 2024, the EPA issued a final rule implementing the methane emissions charge, although in February 2025, Congress repealed the rule. Additionally, the One Big Beautiful Bill Act, enacted in July 2025, delays implementation of the methane emissions charge until 2034. We cannot predict if Congress or the current administration may take actions to further repeal or revise the Inflation Reduction Act, including with respect to the methane emissions charge. In fact, the full impact of future climate regulations is uncertain at this time and it is unclear what additional actions may be taken that may have an adverse effect upon our carbon management business and its prospects.
To the extent financial markets view climate change and GHG or other emissions as an increasing financial risk, this could adversely impact our cost of, and access to, capital and the value of our stock and our assets. Current investors in oil and natural gas companies may elect in the future to shift some or all of their investments into other sectors, and institutional lenders may elect not to provide funding for oil and natural gas companies. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector, although this trend has waned recently and several high-profile banks and institutional investors have withdrawn from various associations that aim to limit financing of industries that emit significant GHG emissions. Additionally, California has enacted new laws requiring additional disclosure with respect to certain climate-related risks and GHG emissions reduction claims. The laws have been challenged and, in November 2025, the United States Court of Appeals for the Ninth Circuit ordered a preliminary injunction on one of the laws (which requires disclosure for certain climate-related risks), which stays enforcement of that law. Oral argument on the laws occurred in January 2026, although the Ninth Circuit has not yet released its decision. (See Part I, Item 1 and 2 – Business and Properties, Regulation of the Industries in Which We Operate, Regulation of Climate Change and Greenhouse Gas (GHG) Emissions for more information). Non-compliance with these new laws may result in the imposition of fines or penalties. Other states are considering similar laws. Any new laws or regulations imposing more stringent requirements on our business related to the disclosure of climate-related risks may result in reputation harms among certain stakeholders if they disagree with our approach to mitigating climate-related risks, additional costs to comply with any such disclosure requirements and increased costs of and restrictions on access to capital.
We believe, but cannot guarantee, that our local production of oil, NGLs and natural gas will remain essential to meeting California’s energy and feedstock needs for the foreseeable future. We have also established 2030 Sustainability Goals for water recycling, renewables integration, methane emission reduction and carbon capture and sequestration in our life-of-field planning in an attempt to align with the state’s long-term goals and support our ability to continue to efficiently implement federal, state and local laws, regulations and policies, including those relating to air quality and climate, in the future. However, there can be no assurances that we will be able to design, permit, fund and implement such projects in a timely and cost-effective manner or at all, or that we, our customers or end users of our products will be able to satisfy long-term environmental, air quality or climate goals if those are applied as enforceable mandates.
The adoption and implementation of new or more stringent international, federal, state or local legislation, regulations or policies that impose more stringent standards for GHG or other emissions from our operations or otherwise restrict the areas in which we may produce oil, natural gas, NGLs or electricity or generate GHG or other emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for or the value of our products and services. Additionally, political, litigation and financial risks may result in restricting or canceling oil and natural gas production activities, incurring liability for infrastructure damages or other losses as a result of climate change, or impairing our ability to continue to operate in an economic manner. Moreover, climate change may pose increasing risks of physical impacts to our operations and those of our suppliers, transporters and customers through damage to infrastructure and resources resulting from drought, wildfires, sea level changes, flooding and other natural disasters and other physical disruptions. One or more of these developments could have a material adverse effect on our business, financial condition and results of operations.
Tax law changes could have an adverse effect on our business, financial condition and results of operations.
We are subject to taxation by various tax authorities at the federal, state and local levels where we do business. New legislation could be enacted by any of these government authorities that could adversely affect our business.
In addition, from time to time, legislation has been proposed that would, if enacted into law, make significant changes to U.S. federal income tax laws, including the elimination of certain U.S. federal income tax benefits currently available to oil and natural gas exploration and production companies. Such changes have included, but have not been limited to: (i) the repeal of percentage depletion allowance for oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) an extension of the amortization period for certain geological and geophysical expenditures; (iv) the elimination of certain other tax deductions and relief previously available to oil and natural gas companies; and (v) an increase in the U.S. federal income tax rate applicable to corporations such as us. However, it is unclear whether any such changes will be enacted and, if enacted, how soon any such changes would be effective. Additionally, legislation could be enacted that imposes new fees or increases the taxes on oil and natural gas extraction, which could result in increased operating costs and/or reduced demand for our products. The passage of any such legislation or any other similar change in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available with respect to natural gas and oil exploration and development or could increase costs and any such changes could have an adverse effect on our business, financial condition and results of operations. Similarly, legislation could be enacted that changes or terminates the current tax incentives that our CCS projects depend on to be economical. The enactment of any legislation that reduces, eliminates, delays, materially restricts or makes Section 45Q credits subject to more burdensome compliance requirements, could have an adverse effect on our business, financial condition and results of operations.
In California, there have been numerous state and local proposals for additional income, sales, excise and property taxes, including additional taxes on oil and natural gas production and a windfall profits tax on refineries. Although such proposals targeting the oil and natural gas industry have not become law, campaigns by various interest groups could lead to additional future taxes.
Financial assurance requirements related to plugging and abandonment costs, decommissioning, and site restoration on those who acquire the right to operate wells and production facilities could impact our ability to sell or acquire assets in California or increase our costs in connection with the same.
California law imposes stringent financial assurance requirements on persons who acquire the right to operate a well or production facility in California, requiring them to file either an individual indemnity bond for single-well or production facility acquisitions, or a blanket indemnity bond for multiple wells or production facilities. The bond imposed on the acquirer is an amount determined by the state to sufficiently cover plugging and abandonment costs, decommissioning, and site restoration, and California law prohibits the closing of any acquisition of the right to operate a well or production facility until a determination on the appropriate bond amount has been completed by the state and the bond has been filed. This bonding requirement significantly impacts the economic feasibility of transferring the right to operate wells and production facilities, including transfers from smaller, less-capitalized operators to more financially stable operators such as ourselves. As of the year ended December 31, 2025, our asset retirement obligations were $1,033 million. This law will continue to impact our ability to grow or divest our assets within California.
Our operations in Utah are subject to additional regulatory, permitting and legal risks, including risks associated with federal and tribal lands.
As a result of the Berry Merger, we have oil and gas operations and interests in Utah. Certain of these operations are located on federal lands administered by the U.S. Department of the Interior and the Bureau of Land Management, and certain acreage may be subject to tribal jurisdiction. Oil and gas development on federal and tribal lands is subject to regulatory regimes, approval processes and oversight that differ from those applicable to state or private lands and may be more complex, time-consuming or uncertain.
Development activities on federal lands may require compliance with the National Environmental Policy Act (NEPA) and other federal statutes and regulations, which can result in extended permitting timelines, additional environmental review requirements, increased costs, or litigation risk. Changes in federal laws, regulations, policies, enforcement practices or fiscal terms applicable to federal lands, including royalty rates, bonding requirements, leasing terms or permitting standards, could delay or restrict development activities or adversely affect the economics of our operations.
Operations on tribal lands may be subject to additional approvals, contractual requirements and regulatory authority of tribal governments. Disputes relating to tribal lands may be subject to different legal standards, forums or remedies, including limitations arising from tribal sovereign immunity, which could restrict our ability to enforce contractual rights or obtain judicial relief. Any of these factors could delay operations, increase costs, limit development opportunities or otherwise have a material adverse effect on our business, financial condition, results of operations or cash flows.
Risks Related to Our Indebtedness
We may not be able to amend or refinance our existing debt to create more operating and financial flexibility and to enhance shareholder returns .
Our ability to refinance our debt depends on a variety of factors, including our ability to access the commercial banking and debt capital markets. Changes in interest rates could also impact our ability to refinance our debt. If interest rates increase, the interest expense burden of any refinanced debt or other variable rate debt would increase even though the amount borrowed remained the same. There can be no assurances that we will be successful in amending, replacing or refinancing our existing debt on acceptable terms or at all.
Our existing and future indebtedness may adversely affect our business, financial condition and financial flexibility.
As of December 31, 2025, we had $1,283 million of total long-term debt, net and additional borrowing capacity of $1,284 million under the Revolving Credit Facility (after giving effect to $176 million of outstanding letters of credit). The terms of our Revolving Credit Facility and Senior Notes permit us to incur significant additional debt, some of which may be secured. Our level of future indebtedness could affect our business in several ways, including the following:
• limit management’s discretion in operating our business and reacting to changes in market conditions;
• require us to dedicate a significant portion of our cash flow to debt service, thereby reducing funds available for operations, capital expenditures, acquisitions or shareholder returns;
• increase our vulnerability to commodity price volatility, economic downturns and adverse regulatory developments;
• limit our access to capital markets or increase the cost of future financing; and
• expose us to borrowing base reductions or interest rate increases that could adversely affect liquidity.
Our ability to execute our business strategy and satisfy our debt obligations depends on our future operating performance and on economic, financial, competitive and other factors, many of which are beyond our control.
We may not be able to generate sufficient cash to service all of our indebtedness, and may be forced to take other actions to satisfy the obligations under our indebtedness, which may not be successful.
Our earnings and cash flows may vary significantly due to commodity price volatility and other industry factors, and the level of indebtedness that is manageable in some periods may be unsustainable in others. Additionally, our future cash flow may be insufficient to meet our debt obligations and other commitments at that time. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt obligations. Many of these factors, such as oil and natural gas prices, economic and financial conditions in our industry and the global economy and initiatives of our competitors, are beyond our control as discussed in this “ Risk Factors ” section. We may be unable to maintain cash flows sufficient to pay the principal, premium, if any, and interest on our indebtedness.
The lenders under our Revolving Credit Facility could limit our ability to borrow and restrict our use or access to capital.
Our Revolving Credit Facility is an important source of our liquidity. Our ability to borrow under our Revolving Credit Facility is limited by our borrowing base, the size of our lenders’ commitments and our ability to comply with covenants. The borrowing base under our Revolving Credit Facility is redetermined semi-annually by our lenders who review the value of our reserves and other factors that may be deemed appropriate. A reduction in our borrowing base below the aggregate commitment amount of our lenders would have a material adverse effect on our liquidity and may hinder our ability to execute on our business strategy.
Restrictive covenants in our Revolving Credit Facility and the indentures governing our Senior Notes may limit our financial and operating flexibility and adversely affect our ability to execute our business strategy.
Our Revolving Credit Facility and the indentures governing our Senior Notes contain covenants that may adversely effect our business, financial condition or results of operations. These covenants limit our ability to, among other things, incur additional indebtedness, pay dividends or repurchase shares, dispose of assets, or make capital investments. The Revolving Credit Facility also requires us to comply with certain financial maintenance covenants, including a leverage ratio and current ratio. A breach of these covenants could result in a default under the Revolving Credit Facility and/or the Senior Notes. If a default occurs under the Revolving Credit Facility, the lenders may elect to declare all borrowings thereunder outstanding, together with accrued interest and other fees, to be immediately due and payable. If we are unable to repay our indebtedness when due or declared due, the lenders under the Revolving Credit Facility will also have the right to proceed against the collateral pledged to them to secure the indebtedness. An event of default under the Senior Notes may cause all outstanding Senior Notes to become due and payable immediately or give the trustee and the holders the right to declare all outstanding Senior Notes to become due and payable immediately.
Variable rate indebtedness under our Revolving Credit Facility subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.
Borrowings under our Revolving Credit Facility are at variable rates of interest and expose us to interest rate risk. As of December 31, 2025, we had no amounts borrowed under our Revolving Credit Facility. If in the future we borrow under the Revolving Credit Facility, then our results of operations would be sensitive to movements in interest rates. There are many economic factors outside our control that have in the past and may, in the future, impact rates of interest including publicly announced indices that underlie the interest obligations related to our Revolving Credit Facility. Factors that impact interest rates include governmental monetary policies, inflation, economic conditions, changes in unemployment rates, international disorder and instability in domestic and foreign financial markets. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and our results of operations would be adversely impacted. Such increases in interest rates could have a material adverse effect on our business, financial condition and results of operations if we borrow under the Revolving Credit Facility in the future.
Risks Related to Our Common Stock
Our ability to pay dividends and repurchase shares of our common stock is subject to certain risks.
We have adopted a cash dividend policy which anticipates a total annual dividend of $1.62 per share, payable to shareholders in quarterly increments of $0.405 per share of common stock, subject to board authorization and declaration each quarter. Our Board of Directors has authorized a share repurchase program to acquire up to $1.78 billion of our common stock through December 31, 2027. After the increase and shares repurchased in January 2026, approximately $600 million remained unused as of February 28, 2026. Any payment of future dividends or repurchasing shares of our common stock will be at the discretion of our Board of Directors and will depend upon, among other things, our earnings, liquidity, capital requirements, financial condition and other factors deemed relevant. Our Revolving Credit Facility and Senior Notes both limit our ability to pay dividends and repurchase shares of our common stock. In addition, cash dividend payments in the future may only be made out of legally available funds and, if we experience substantial losses, such funds may not be available. We can provide no assurances that we will continue to pay dividends at the anticipated rate or repurchase shares of our common stock within the authorized amount or at all.
The trading price of our common stock may decline, and you may not be able to resell shares of our common stock at prices equal to or greater than the price you paid or at all.
The trading price of our common stock may be volatile and may decline for reasons beyond our control. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. Numerous factors, including changes in our operating results, commodity prices, economic conditions, regulatory developments, capital allocation decisions, analyst estimates and market valuations of comparable companies, could adversely affect our stock price.
Future issuances of our common stock could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.
We may issue shares of common stock or securities convertible into common stock in public or private transactions. We may also issue additional shares of common stock or convertible securities in connection with mergers or acquisitions, such as in December 2025 when we issued 5.6 million shares of common stock in connection with the Berry Merger. We cannot predict the size of other future issuances of our common stock or securities convertible into common stock or the effect, if any, that such other future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock, or the perception that such sales could occur, may adversely affect the market price of our common stock.
The ownership position of certain of our stockholders limits other stockholders’ ability to influence corporate matters and could affect the price of our common stock.
As of December 31, 2025, four of our shareholders owned at least 5% each and collectively owned approximately 41% of our common stock. As a result, each of these stockholders, or any entity to which such stockholders sell their stock, may be able to exercise significant control over matters requiring stockholder approval. Further, because of this large ownership position, if these stockholders sell their stock, the sales could depress our share price.
Sales of shares of our common stock by our executive officers could negatively impact the market price for our common stock.
Sales of our common stock by our executive officers may adversely impact the trading price of our common stock, even when done in compliance with our policies with respect to insider sales. Although we do not expect that the relatively small volume of such sales will itself significantly impact the trading price of our common stock, the market could react negatively to the announcement of such sales, which could in turn affect the trading price of our common stock.
Supply Chain and Inflation
We continued to experience relatively flat pricing from our suppliers during the year ended December 31, 2025 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 expanded tariff rates on imported goods including a 50% tariff on the steel and aluminum value of imported products. If sustained, these expanded tariff rates could increase our cost of oilfield goods and extend delivery lead times over the longer term. We have taken measures to limit the effects of potential 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 implementation 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 expect minimal impact from tariffs on our supply chain in 2026. However, if the current tariff regime persists or expands, our inventory, capital and operating costs could increase over the long term.
Statement of Operations Analysis
Consolidated Results of Operations
Our consolidated results of operations include the results of Berry beginning December 18, 2025, the closing date of the Berry Merger. 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 Berry Merger and the Aera Merger, see Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Business Combinations. The Aera Merger and related integration activities significantly impacted the comparability of our financial results for the year ended December 31, 2025 compared to the prior year.
For financial information related to our subsidiaries designated as Unrestricted Subsidiaries under the 2026 Senior Notes Indenture, 2029 Senior Notes Indenture and 2034 Senior Notes Indenture, see Part II, Item 8 – Financial Statements and Supplementary Data, Note 18 Condensed Consolidating Financial Information.
Year Ended December 31, 2025 vs. 2024
The following table presents our consolidated operating revenues:
Year ended
December 31,
Year ended
December 31,
(in millions)
Oil, natural gas and natural gas liquids sales
Net gain from commodity derivatives
Revenue from marketing of purchased commodities
Electricity revenue
Other revenue
Total operating revenues
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 $2,910 million for the year ended December 31, 2025, which is an increase of $373 million from $2,537 million for the year ended December 31, 2024. The following table shows changes in oil, natural gas and natural gas liquids sales for the year ended December 31, 2025 compared to the year ended December 31, 2024:
Oil
NGLs
Natural Gas
Total
(in millions)
Year ended December 31, 2024
Changes in realized prices
Changes in production and other
Changes in intersegment revenues
Year ended December 31, 2025
Note: See Results of Our Oil and Natural Gas Operations Production for volumes by commodity type and Prices and Realizations for index and average realized prices for each period.
Net gain 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 $266 million for the year ended December 31, 2025 compared to a net gain of $241 million for the year 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:
Year ended
December 31,
Year ended
December 31,
(in millions)
Non-cash commodity derivative gain
Net proceeds (settlements) and premium amortization
Net gain from commodity derivatives
Electricity revenue – Electricity revenue increased by $74 million to $233 million during the year ended December 31, 2025 compared to $159 million for the year ended December 31, 2024. This increase was primarily a result of higher pricing from resource adequacy contracts and additional electricity sales in 2025 as a result of scheduled maintenance and unplanneddowntime at our Elk Hills power plant in 2024.
The following table presents our consolidated operating and non-operating expenses and income for the years ended December 31, 2025 and 2024:
Year ended
December 31,
Year ended
December 31,
(in millions)
Operating expenses
Operating costs
General and administrative expenses
Depreciation, depletion and amortization
Asset impairment
Taxes other than on income
Costs related to marketing of purchased commodities
Electricity generation expenses
Transportation costs
Accretion expense
Net loss on natural gas purchase derivatives
Measurement period adjustments, net
Other operating expenses, net
Total operating expenses
(Loss) gain on asset divestitures
Operating income
Non-operating (expenses) income
Interest and debt expense, net
Loss on early extinguishment of debt
Equity loss from unconsolidated subsidiaries
Other non-operating income (expense), net
Income before income taxes
Income tax provision
Net income
Operating costs - The following table presents our operating costs for the years ended December 31, 2025 and December 31, 2024:
Year ended
December 31,
Year ended
December 31,
(in millions)
Energy operating costs
Gas processing costs
Non-energy operating costs
Operating costs
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 year ended December 31, 2025 were $374 million, which was an increase of $95 million from $279 million for the year ended December 31, 2024. Approximately $94 million of this increase is related to the addition of the Aera fields for the full year of 2025 compared to only six months in 2024. The remaining increase primarily related to higher energy prices partially offset by savings related to the additional supply of electricity generated at our Elk Hills power plant which is used at our Elk Hills field in 2025. During the year ended December 31, 2024, our Elk Hills power plant experienced unplanneddowntime and scheduled maintenance resulting in lower electricity generation available the Elk Hills field. For more information on our natural gas market prices, see Segment Results of Oil and Natural Gas Operations, Production, Prices and Realizations below.
Non-energy operating costs – Non-energy operating costs for the year ended December 31, 2025 were $859 million, which was an increase of $188 million from $671 million for the year ended December 31, 2024. Of this increase, $191 million related to the operation of the Aera fields for the full year ended December 31, 2025 compared to only six months in 2024. This increase was partially offset by lower maintenance activity during the year ended December 31, 2025 as compared to 2024.
General and administrative expenses – General and administrative expenses were $333 million for the year ended December 31, 2025, which was an increase of $12 million from $321 million for the year ended December 31, 2024. The increase was primarily a result of additional compensation-related expense and other corporate expenses resulting from the Aera Merger.
Depreciation, depletion and amortization – Depreciation, depletion and amortization increased $123 million to $511 million for the year ended December 31, 2025 from $388 million for the same prior year period. The increase was primarily the result of the addition of the Aera assets included in the full year ended December 31, 2025.
Asset impairment – We recognized a $59 million asset impairment during the year ended December 31, 2025 of which $57 million related to the write-down of our proved natural gas properties in the Sacramento basin. For more information on the impairment of natural gas properties in the Sacramento basin, see Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Property, Plant and Equipment. During the year ended December 31, 2024, we recognized a $14 million impairment primarily related to excess and obsolete materials and supplies related to our oilfield operations. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 1 Nature of Business, Summary of Significant Accounting Policies and Other for more information.
Accretion expense – Accretion expense was $114 million for the year ended December 31, 2025, which was an increase of $27 million from $87 million for the year ended December 31, 2024. The increase was primarily due to the addition of the Aera asset retirement liability related to the Aera fields in connection with the Aera Merger.
Net loss on natural gas purchase derivatives – Net loss on natural gas purchase derivatives was $50 million for the year ended December 31, 2025. For the same prior year period, we recognized a net loss of $30 million. 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. We added derivative positions held by Berry at December 18, 2025 and recognized a change in fair value between legal close and December 31, 2025. Gains and losses from our commodity derivative contracts are shown in the table below. For more information on our derivatives, see Part II, Item 8 – Financial Statements and Supplementary Data, Note 7 Derivatives.
Year ended
December 31,
Year ended
December 31,
(in millions)
Non-cash loss (gain) on natural gas purchase derivatives
Settlements
Net loss on natural gas purchase derivatives
Measurement period adjustments, net – Measurement period adjustments relate to changes made to the initial accounting for assets acquired and liabilities assumed in the Aera Merger. The adjustments for the year ended December 31, 2025 included adjustments to depreciation, depletion and amortization expense resulting from changes to the initial purchase price allocation. The adjustments for the year 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.
Other operating expenses, net – Other operating expenses, net decreased $30 million to $209 million for the year ended December 31, 2025 compared to $239 million for the year ended December 31, 2024.
For the years ended December 31, 2025 and 2024, other operating expenses, net includes the following:
Year ended
December 31,
(in millions)
Carbon management expenses (a)
Transaction and integration costs
Incremental energy costs due to downtime at our Elk Hills power plant
Severance and termination costs
Litigation and settlement related expenses (b)
Offshore platforms maintenance and abandonment costs
Information technology infrastructure
Environmental remediation
All other
Total operating expenses, net
(a) Carbon management expenses relates to the development of our carbon management business and includes operating lease costs, payroll costs related to our technical teams and is included in other segment expenses. For more information on our carbon management segment, refer to Part II, Item 8 – Financial Statements and Supplementary Data, Note 16 Segment Information.
(b) See Part II, Item 8 – Financial Statements and Supplementary Data, Note 6 Lawsuits, Claims, Commitments and Contingencies for more information on a $25 million payment we made to CalGEM.
(Loss) gain on asset divestitures – Our loss on asset divestitures for the year ended December 31, 2025 was $1 million primarily related to the final purchase price adjustment related to the sale of oil and gas assets located in Ventura. Gain on asset divestitures for the year ended December 31, 2024 was $11 million primarily related to the divestiture of non-core assets and our Ventura divestiture. For more information on our asset divestitures, see Part II, Item 8 – Financial Statements and Supplementary Data, Note 9 Divestitures and Acquisitions.
Interest and debt expense, net – Interest and debt expense, net was $106 million for the year ended December 31, 2025, which was an increase of $19 million from $87 million for the year ended December 31, 2024. The increase was predominately due to higher outstanding debt for the full year ended 2025 compared to 2024. Our 2029 Senior Notes were outstanding for only part of 2024 compared to the full year in 2025, as $600 million was issued in June 2024 and $300 million was issued in August 2024 in a follow-on issuance. Outstanding debt was also higher in 2025 due to the issuance of $400 million of our 2034 Senior Notes completed in October 2025 resulting in increased interest expense. This increase in interest expense was partially offset by lower interest expense resulting from debt repayments, including the redemption of $123 million of our 2026 Senior Notes in February 2025 and the redemption of the remaining $122 million of the 2026 Senior Notes in October 2025, which reduced outstanding principal and related interest expense. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 5 Debt for information on our recent financings.
Other non-operating income (expenses), net – We recognized $15 million other non-operating income during the year ended December 31, 2025 primarily related to actuarial gains on plan assets held in our pension and postretirement benefit plan. During the year ended December 31, 2024, we recognized $2 million other non-operating expense primarily relating to the write-off of financing fees related to a bridge loan we entered into in connection with the Aera Merger which was partially offset by a prior service cost gain on our postretirement benefit plan.
Segment Results of Oil and Natural Gas Operations
The following tables includes financial results and key operating data for our oil and natural gas segment for the years ended December 31, 2025, 2024 and 2023. Our results of operations for the oil and natural gas segment include the financial and operating results of Aera beginning on July 1, 2024, the closing date of the Aera Merger. For more information on the Aera Merger, see Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Business Combinations.
Year ended December 31,
Production and oil and gas segment financial data
(in millions, except as otherwise stated)
Net production sold (MBoe/d)
Total operating revenues
Segment profit
Items affecting comparability:
Asset impairments (a)
Net (loss) gain on asset divestitures (b)
Key operating expenses per Boe
Operating costs
Operating costs, after hedges on purchased natural gas
General and administrative expenses (c)
Depreciation, depletion and amortization (d)
Taxes other than on income
Field transportation expenses
(a) Asset impairment for the year ended December 31, 2025 includes the write-down of our proved properties in the Sacramento basin. Asset impairment for the year ended December 31, 2024 related to the write-off of excess and obsolete materials and supplies, generally requisitioned for wells and capitalized as part of drilling and completion activities. The table above excludes asset impairments that were not related to the oil and natural gas segment.
(b) Loss on asset divestitures for the year ended December 31, 2025 related to the sale of our West Montalvo property in Ventura County, California. Gain on asset divestitures for the year ended December 31, 2024 related to the sale of our 0.9-acre Fort Apache real estate property in Huntington Beach, California as well as the remaining portion of our Ventura assets which were classified as held for sale. Gain on asset divestitures for the year ended December 31, 2023 related to the sale of our non-operated interest in the Round Mountain Unit and a non-producing asset in exchange for the assumption of liabilities.
(c) Only includes general and administrative expenses allocated to our oil and natural gas segment.
(d) Excludes depreciation, depletion and amortization related to our corporate assets and Elk Hills power plant.
Production, Prices and Realizations
The amounts in the production tables below show volumes from CRC's operated and non-operated fields for each of the periods presented. These amounts include volumes produced from Berry's operated and non-operated fields during the period from December 18, 2025 through December 31, 2025, and volumes produced from Aera's operated and non-operated fields beginning July 1, 2024.
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.
Year ended December 31,
Oil (MBbl/d)
NGLs (MBbl/d)
Natural gas (MMcf/d)
Total Daily Net Production (MBoe/d)
The following table summarizes the changes to our total daily net production per day for the periods presented:
Year ended December 31,
(MBoe/d)
Beginning of the year
Divestitures (a)
Plant downtime (b)
Acquisitions (c)
PSC effect
Natural decline and other
Total change
End of the year
(a) See Part II, Item 8 – Financial Statements and Supplementary Data, Note 9 Divestitures and Acquisitions for more information. Note that for the year ended December 31, 2023, our divestitures did not have a significant impact on our production volumes because the sale of our non-operated working interest in the Round Mountain Unit closed on December 29, 2023 and we sold a non-producing asset during the year.
(b) Included scheduled maintenance and unplanneddowntime at our Elk Hills power plant for the year ended December 31, 2024.
(c) We completed the Aera Merger on July 1, 2024 and the amount of production shown in the table above is averaged over a 12-month period. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Business Combinations for more information.
Prices and Realizations
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. The following tables set forth average benchmark prices, average realized prices and price realizations as a percentage of average benchmark prices for our products for the periods indicated below:
Price
Realization
Price
Realization
Price
Realization
Oil ($ per Bbl)
Brent
Realized price without derivative settlements
Derivative settlements
Realized price with derivative settlements
WTI
Realized price without derivative settlements
Realized price with derivative settlements
Natural Gas Liquids ($ per Bbl)
Realized price (% of Brent)
Realized price (% of WTI)
Natural gas
NYMEX Henry Hub ($/MMBtu)
Realized price ($/Mcf)
Oil — Brent and our average realized price without derivative settlements were lower for the year ended December 31, 2025 compared to the same prior year period largely due to an increase in global oil production beginning in later 2025 as both OPEC+ and non-OPEC countries increased production.
NGLs — Prices for natural gas liquids were lower for the year ended December 31, 2025 compared to the prior year which is consistent with broader declines in oil commodity prices. The California market continued to carry a premium as compared to other markets in 2025.
Natural Gas — Average realized prices for our natural gas during the year ended December 31, 2025 were higher than the year ended December 31, 2024 as demand for U.S. natural gas reached record levels.
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 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 years ended December 31, 2025, 2024 or 2023. We recently completed construction of our first carbon capture project at our cryogenic gas processing facility and expect first injection in spring 2026, 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 tables include results for our carbon management segment, excluding unallocated corporate expenses for the years ended December 31, 2025, 2024 and 2023.
Year ended December 31,
(in millions, except as otherwise stated)
Segment loss
Items affecting comparability:
Asset impairments (a)
(a) Asset impairment for the years ended December 31, 2025, 2024 and 2023 related to land acquired for our carbon management activities. The table above excludes asset impairments that were not related to the carbon management segment.
We recognized our share of losses for the years ended December 31, 2025, 2024 and 2023 related to our Carbon TerraVault joint venture, as shown in the table below. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 4 Investments and Related Party Transactions for more information on our Carbon TerraVault joint venture. Carbon management expense and general and administrative expense for the years ended December 31, 2025, 2024 and 2023 are included in the table below.
Year ended December 31,
(in millions)
Carbon management expenses
Segment general and administrative expense
Loss from investment in the Carbon TerraVault JV
Carbon management expenses decreased in 2025 compared to 2024 as a result of lower community development activities which were partially offset by higher costs related to feasibility studies that were undertaken.
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 issuance of our 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 year ended December 31, 2025 were for capital investments, redemption of our 2026 Senior Notes, repurchase of our common stock, and payment of dividends.
The following table summarizes our liquidity:
December 31, 2025
(in millions)
Available cash and cash equivalents (a)
Revolving Credit Facility:
Borrowing capacity
Outstanding letters of credit
Availability
Liquidity
(a) Excludes restricted cash of $15 million.
Derivatives
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 upon 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 for the year ended December 31, 2025.
Refer to Part II, Item 8 – Financial Statements and Supplementary Data, Note 7 Derivatives for more information on our open derivative contracts as of December 31, 2025 and Note 5 Debt for more information on the hedging requirements included in our Revolving Credit Facility.
Long-Term Debt
Our long-term debt consists of borrowings and indebtedness under our Revolving Credit Facility, 2029 Senior Notes and 2034 Senior Notes. Our previously issued 2026 Senior Notes were redeemed in full in 2025. For more information regarding our Revolving Credit Facility, 2026 Senior Notes, 2029 Senior Notes and 2034 Senior Notes, refer to Part II, Item 8 – Financial Statements and Supplementary Data, Note 5 Debt.
Revolving Credit Facility
On April 26, 2023, we entered into an Amended and Restated Credit Agreement (Revolving Credit Facility) with Citibank, N.A., as administrative agent, and certain other lenders, which amended and restated in its entirety the prior credit agreement dated October 27, 2020. As of December 31, 2025, we were in compliance with all of the covenants of our Revolving Credit Facility. Refer to Part II, Item 8 – Financial Statements and Supplementary Data, Note 5 Debt for more information on recent amendments to our Revolving Credit Facility.
2034 Senior Notes
On October 8, 2025, we completed an offering of $400 million in an aggregate principal amount of 7.000% senior notes due 2034 (2034 Senior Notes). The terms of the 2034 Senior Notes are governed by the Indenture, dated as of October 8, 2025, by and among us, our subsidiary guarantors and Wilmington Trust, National Association, as trustee (2034 Senior Notes Indenture). The net proceeds of $393 million, after $7 million of debt issuance costs, were used to repay Berry's long-term debt at closing of the Berry Merger.
2029 Senior Notes
On June 5, 2024, we completed an offering of $600 million in aggregate principal amount of 8.25% senior notes due 2029 (2029 Senior Notes). The terms of the 2029 Senior Notes are governed by the Indenture, dated as of June 5, 2024, by and among us, our subsidiary guarantors and Wilmington Trust, National Association, as trustee (2029 Senior Notes Indenture). The net proceeds of $590 million, after $10 million of debt discount and issuance costs, were used along with available cash to repay all of Aera's outstanding debt at closing of the Aera Merger.
On August 22, 2024, we completed a follow-on offering of $300 million in aggregate principal amount of 2029 Senior Notes. The net proceeds from this offering of $298 million, after $3 million of debt premium and $5 million of debt issuance costs, were used to repurchase a portion of our outstanding 2026 Senior Notes as described below. The follow-on 2029 Senior Notes issued on August 22, 2024 are governed by the same indenture as the $600 million of 2029 Senior Notes that were previously issued on June 5, 2024.
2026 Senior Notes
In the year ended December 31, 2025, we redeemed $245 million of our 7.125% Senior Notes due 2026 (2026 Senior Notes) at 100% of the principal amount, resulting in an extinguishment loss in the amount of $1 million for the write-off of unamortized debt issuance costs. Following this redemption, none of our 2026 Senior Notes were outstanding.
In the year ended December 31, 2024, we repurchased $300 million in face value of our 2026 Senior Notes for $303 million resulting in a loss on early extinguishment of debt in the amount of $5 million which includes a $2 million write-off of unamortized debt issuance costs.
Transactions Related to Our Common Stock
The following table is a summary of changes in our outstanding shares of our common stock during the year ended December 31, 2025:
Common Stock
Balance at December 31, 2024
Issued as part of the Berry Merger (a)
Shares issued related to the Aera Merger (a)
Shares issued under ESPP
Shares issued under stock-based compensation arrangements
Repurchased shares held as treasury stock
Repurchased shares cancelled
Shares cancelled for taxes (b)
Balance at December 31, 2025
(a) Refer to Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Business Combinations for additional information.
(b) In connection with the vesting of equity awards, we withheld and cancelled shares to satisfy applicable tax-withholding requirements.
Common Stock Issued as Part of the Berry Merger
We issued 5,572,115 shares of CRC common stock in connection with the Berry Merger. The shares issued were registered under the Securities Act of 1933, as amended, pursuant to a registration statement on Form S-4 (File No. 333-290871) filed by CRC with the Securities and Exchange Commission on October 14, 2025, which became effective on November 3, 2025.
Dividends
Once declared, dividends are payable to shareholders in cash on a quarterly basis. The actual 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.
On March 1, 2026, our Board of Directors declared a cash dividend of $0.405 per share of common stock. The dividend is payable to shareholders of record at the close of business on March 13, 2026 and is expected to be paid on March 20, 2026.
We paid the following cash dividends for each of the periods presented.
Total Dividend
Annual Rate Per Share
(in millions)
($ per share)
Year ended December 31, 2023
Year ended December 31, 2024
Year ended December 31, 2025
Share Repurchase Program
Our Board of Directors authorized a Share Repurchase Program to acquire up to $1.78 billion of our common stock through December 31, 2027. This includes a recent increase of $430 million and extension approved by our Board of Directors on February 24, 2026. After the increase and shares repurchased in January 2026, we had approximately $600 million of remaining unused capacity under this program as of February 28, 2026. For additional information, see Part II, Item 8 – Financial Statements and Supplementary Data, Note 19 Subsequent Events.
The repurchases may be effected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, derivative contracts or otherwise in compliance with Rule 10b-18, subject to market conditions. The Share Repurchase Program does not obligate us to repurchase any dollar amount or number of shares and our Board of Directors may modify, suspend, or discontinue authorization of the program at any time. The following is a summary of our share repurchases, held as treasury stock, for the periods presented:
Total Number of Shares Purchased
Dollar Value of Shares Purchased
Average Price Paid per Share
(number of shares)
(in millions)
($ per share)
Year ended December 31, 2023
Year ended December 31, 2024
Year ended December 31, 2025
Inception of Program (May 2021) through December 31, 2025
Note: The total value of shares purchased includes approximately $2 million and $1 million in the years ended December 31, 2024 and 2023 related to excise taxes on share repurchases. Excise taxes in 2025 were insignificant and include a reversal for 2024 excise taxes that were no longer due. Commissions paid were not significant in all periods presented.
Uses of Cash
At current commodity prices, we expect to generate operating cash flow to support and invest in our assets as part of our planned 2026 capital program described below. We regularly review our financial position, commodity prices, market conditions and other considerations to evaluate and optimize the deployment of our cash. We believe we have sufficient sources of liquidity to meet our obligations for the next twelve months.
2026 Capital Program
We expect our total 2026 capital program to range between $430 million and $470 million. Of this amount, $410 million to $435 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. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 4 Investments and Related Party Transactions for more information on our joint venture with Brookfield.
Oil and natural gas segment – With respect to oil and natural gas development, we expect to run a four rig program in 2026. We currently hold the majority of permits necessary to undertake our 2026 capital program. We expect to obtain additional new well permits for the remainder of our 2026 capital program on a timely basis. For more information on permitting, refer to Part I, Item 1 and 2 – Business and Properties, Regulation of the Industries in Which We Operate, Regulation of Exploration and Production Activities .
Carbon management segment – Our 2026 capital for carbon management projects includes approximately $15 million for the completion of the carbon capture project at our cryogenic gas processing facility at Elk Hills. This gas processing facility is adjacent to the 26R storage reservoir held by Carbon TerraVault JV. For more information this project, refer to Part I, Item 1 and 2 – Business and Properties, Carbon Management Segment .
Other Uses of Cash
Other than our 2026 capital program, our expected material uses of cash during 2026 may include, subject to available liquidity, commodity prices, market conditions and other considerations, one or more of the following: (1) operating expenses; (2) dividends, share and debt repurchases; (3) settlements on commodity derivative contracts; (4) income taxes and other taxes not on income; (5) settlement of asset retirement obligations; and (6) costs related to advancing our carbon management activities not included in our capital program, such as employee costs and front-end engineering and design studies.
Our long-term material uses of cash include the following:
• repayment of principal and interest on our 2029 Senior Notes and 2034 Senior Notes (see Part II, Item 8 – Financial Statements and Supplementary Data, Note 5 Debt )
• operating lease liabilities including our commercial office space, fleet vehicles, easements and certain facilities (see Part II, Item 8 – Financial Statements and Supplementary Data, Note 13 Leases)
• obligations associated with our defined benefit and post-employment benefit plans (see Part II, Item 8 – Financial Statements and Supplementary Data, Note 14 Pension and Postretirement Benefit Plans )
• asset retirement obligations over the longer term (see Part II, Item 8 – Financial Statements and Supplementary Data, Note 1 Nature of Business, Summary of Significant Accounting Policies and Other, Asset Retirement Obligations )
We have certain off-balance sheet commitments under contracts, including purchase commitments for goods and services used in the normal course of business such as pipeline transportation capacity, oil and natural gas leases, obligations under long-term service agreements and field equipment. The table below summarizes our undiscounted current and long-term purchase obligations as of December 31, 2025.
One Year or Less
More Than One Year
Total
(in millions)
Oil and gas leases, surface easements and pipeline right-of-way (a)
Oil and gas transportation, throughput and storage arrangements (b)
Software licenses and other contracts
Contracts related to our carbon management segment (c)
Total
(a) Oil and natural gas leases reflect obligations for fixed payments under our contracts.
(b) Purchase obligations for pipeline capacity include ship or pay arrangements that are based on contractual volumes and current market rates for firm transportation capacity during the contract period.
Cash Flow Analysis
Cash flows from operating activities – Our net cash provided by operating activities is sensitive to many variables, particularly changes in commodity prices. Commodity price movements may also lead to changes in other variables in our business, including adjustments to our capital program. We experienced peak pricing for resource adequacy contracts in 2025 as compared to 2024. However, market prices for 2026 resource adequacy contracts declined due to growth in available resource adequacy-eligible capacity in the California market. As a result, we expect that our 2026 revenues from resource adequacy contracts will decrease between $125 million to $135 million in 2026 as compared to 2025.
Our operating cash flow for the year ended December 31, 2025 was $865 million, which was an increase of $255 million, from $610 million for the year ended December 31, 2024. The increase was primarily driven by increased production after the Aera Merger which occurred on July 1, 2024. For the year ended December 31, 2025 we produced 138 MBoe/d, which was an increase of 37 MBoe/d from 110 MBoe/d for the year ended December 31, 2024. Our oil production increased to 109 MBbl/d for the year ended December 31, 2025 compared to 80 MBbl/d for the year ended December 31, 2024. Increases in production were partially offset by lower realized oil prices in 2025. Our average realized price for oil without the effects of derivative settlements decreased by $10.40 to $66.52 for the year ended December 31, 2025 compared to $76.92 for the same prior year period. For more information on our production and price changes, see Segment Results of Oil and Natural Gas Operations above.
Settlement proceeds from our derivative contracts increased $79 million from $64 million settlement payments for the year ended December 31, 2024 to $15 million settlement proceeds for the year ended December 31, 2025. For more information on our derivative contracts see, Part II, Item 8 – Financial Statements and Supplementary Data, Note 7 Derivatives.
Operating costs and general and administrative expenses increased in 2025 as compared to 2024 primarily due to the addition of Aera's operations for the full year. As a result, we had higher compensation-related costs and additional costs related to surface maintenance, energy and purchase injectant.
Cash flows used in investing activities - The following table provides a comparative summary of net cash used in investing activities:
Year ended December 31,
(in millions)
Capital investments
Changes in accrued capital investments
Proceeds from asset divestitures
Purchase of a business, net of cash acquired
Asset acquisitions
Other, net
Net cash used in investing activities
For the years ended December 31, 2025 and 2024, purchase of a business, net of cash acquired includes our investing activities related to the Berry Merger and the Aera Merger, respectively. In connection with the Berry Merger, we repaid $449 million of Berry’s outstanding long-term debt and acquired cash of $12 million (after a $3 million payment for settlement of certain stock-based compensation awards). Additionally, we increased our 2025 capital program following the Aera Merger. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Business Combinations for more information on these transactions.
Proceeds from asset divestitures for the year ended December 31, 2025 primarily included the sale of properties for carbon management activities. Proceeds from asset divestitures for the year ended December 31, 2024 included the sale of our 0.9-acre Fort Apache real estate property in Huntington Beach, California as well as the remaining portion of our Ventura assets which were classified as held for sale. In the year ended December 31, 2024, the acquisitions shown in the table above related to purchasing storage reservoirs for our carbon management segment. Part II, Item 8 – Financial Statements and Supplementary Data, Note 9 Divestitures and Acquisitions for more information on our divestitures and acquisitions.
Cash flows used in financing activities – The following table provides a comparative summary of net cash used in financing activities:
Year ended December 31,
(in millions)
Proceeds from Revolving Credit Facility
Repayments of Revolving Credit Facility
Proceeds from 2029 Senior Notes, net
Proceeds from 2034 Senior Notes, net
Repurchases of common stock (a)
Common stock dividends
Dividend equivalents on equity-settled awards
Issuance of common stock
Bridge loan commitment costs
Debt redemption
Debt amendment costs
Stock warrants exercised
Shares cancelled for taxes
Net cash (used in) provided by financing activities
(a) The total value of shares purchased reported on our statement of cash flows includes approximately $2 million in the year ended December 31, 2024, related to excise taxes on share repurchases. Excise taxes in 2025 were insignificant and include a reversal for 2024 excise taxes that were no longer due. Commissions paid on share repurchases were not significant in all periods presented.
As noted above in Long-Term Debt , in October 2025, we completed an offering of $400 million in aggregate principal amount of our 7.000% 2034 Senior Notes. We also redeemed $245 million of our 2026 Senior Notes at 100% of the principal amount. In the year ended December 31, 2024, we completed an initial offering and a follow-on offering for our 2029 Senior Notes and we repurchased $300 million in face value of our 2026 Senior Notes at a premium. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 5 Debt for more information on our financing arrangements.
Cash used for repurchases of our common stock under our Share Repurchase Program increased in 2025 as compared to 2024. Additionally, our Board of Directors increased the quarterly dividend rate on our common stock during 2025. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 11 Stockholders' Equity for more information on our Share Repurchase Program and cash dividends.
Divestitures and Acquisitions
From time to time, we review our extensive portfolio of assets for potential divestitures. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 9 Divestitures and Acquisitions for more information.
Lawsuits, Claims, Commitments and Contingencies
We are involved, in the normal course of business, in lawsuits, environmental and other claims and other contingencies that seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitivedamages, civil penalties, or injunctive or declaratory relief.
We accrue reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. Reserve balances at December 31, 2025 and 2024 were not material to our consolidated balance sheets as of such dates.
In October 2020, Signal Hill Services, Inc. defaulted on its decommissioning obligations associated with two offshore platforms. The Bureau of Safety and Environmental Enforcement (BSEE) determined that former lessees, including our former parent, Occidental Petroleum Corporation (Oxy) with a 37.5% share, are responsible for accrued decommissioning obligations associated with these offshore platforms. Oxy sold its interest in the platforms approximately 30 years ago and it is our understanding that Oxy has not had any connection to the operations since that time and challenged BSEE's order. Oxy notified us of the claim under the indemnification provisions of the Separation and Distribution Agreement between us and Oxy. In September 2021, we accepted the indemnification claim from Oxy and we are challenging the order from BSEE. In March 2024, we entered into a cost sharing agreement with former lessees to share in ongoing maintenance costs during the pendency of the challenge to the BSEE order. In September 2025, the parties amended the cost sharing agreement to include well abandonment work. As of December 31, 2025, we recognized a liability of $12 million, included in accrued liabilities in our consolidated balance sheet related to this abandonment work.
We also evaluate the amount of reasonably possible losses that we could incur as a result of these matters. We believe that reasonably possible losses that we could incur in excess of reserves cannot be accurately determined.
See Part II, Item 8 – Financial Statements and Supplementary Data, Note 6 Lawsuits, Claims, Commitments and Contingencies .
Critical Accounting Estimates
Our critical accounting estimates that could result in a material impact to the consolidated financial statements due to the levels of subjectivity and management judgment include the following:
Title
Description
Estimation and Uncertainties
Sensitivities
Oil and Natural Gas Properties
The carrying value of our property, plant and equipment represents the costs incurred to acquire or develop the asset, including any asset retirement obligations, net of accumulated depreciation, depletion and amortization. For assets acquired in a business combination, PP&E cost is based on fair values at the acquisition date. We use the successful efforts method of accounting for our oil and natural gas producing activities. Under this method, we capitalize the cost of acquiring properties, development costs and the costs of drilling successful exploration wells.
The estimated amount of proved reserve volumes is used as the basis for recording depletion expense. We determine depletion on our oil and natural gas producing properties using the unit-of-production method. Under this method, acquisition costs are amortized based on total proved oil and gas reserves and capitalized development and successful exploration costs are depleted based on proved developed oil and natural gas reserves.
Accounting for business combinations requires the allocation of the purchase price to the various assets and liabilities of the acquired business and recording deferred taxes for any differences between the allocated values and tax basis of assets and liabilities. Any excess of the purchase price over the amounts assigned to assets and liabilities is recorded as goodwill. The preliminary fair value of Berry's proved reserves acquired in the acquisition approximated $637 million. We do not have significant capitalized costs related to unproved properties and have not identified significant unproved properties as a result of the acquisition of Berry.
The determination of quantities of proved reserves is a highly technical process performed by our engineers and geoscientists. The analysis is based on drilling results, reservoir performance, subsurface interpretation and future development plans. Production rate forecasts are primarily derived from estimates from decline-curve analysis and type-curve analysis. Secondary inputs may include material balance calculations, which consider the volumes of substances replacing the volumes produced and associated reservoir pressure changes. Additional inputs may also include seismic analysis and computer simulations of reservoir performance. These field-tested technologies have demonstrated reasonably certain results with consistency and repeatability in the formations being evaluated or in analogous formations. The data for a given reservoir may also change over time as a result of numerous factors including, but not limited to, additional development activity and future development costs, production history and continuous reassessment of the viability of future production volumes under varying economic conditions.
Several other factors could change our proved oil and gas reserves including changes in energy costs, inflation, deflation and the political and regulatory environment, all of which are beyond our control.
We estimated the fair value of Berry’s proved reserves at the acquisition date using the expected present value of discounted future cash flows, on an after-tax basis, and applying a reasonable discount rate. We have used all available information to make a fair value determination, including assistance from third-party valuation experts. The assumptions used are believed to be reasonable but could change. This would have the effect of increasing or decreasing the amount of DD&A we recognized on acquired assets.
Our total proved reserves were 654 MMBoe and our total proved developed reserves were 541 MMBoe at December 31, 2025. We estimate our 2026 depletion rate for oil and natural gas producing properties using the unit-of-production method will be approximately $9/Boe. A 5% change in our reserves would increase or decrease this DD&A rate by approximately $0.47/Boe.
Title
Description
Estimation and Uncertainties
Sensitivities
Asset Retirement Obligations
Our asset retirement obligations relate to the plugging and abandonment of oil and natural gas wells and facilities used in the oil and natural gas segment.
We determine our asset retirement obligation, including the obligations related to Berry's assets we acquired, by calculating the present value of estimated future cash outflows related to the abandonment obligation.
The asset retirement cost is capitalized as part of the carrying amount of the related long-lived asset or included in the fair value estimate in a business combination. In periods subsequent to initial measurement, the asset retirement cost is depreciated using the unit-of-production method, while increases in the ARO liability resulting from the passage of time (accretion expense) is included in operating expenses on our consolidated statements of operations.
The recognition of an asset retirement obligation requires us to make assumptions including an estimate of future abandonment costs and inflation rates, timing of activity and our credit-adjusted discount rate among others. Changes in the legal, regulatory and political environment could also affect our estimated future cash outflows.
As of December 31, 2025 and 2024, we had asset retirement obligations of $1,033 million and $1,129 million, respectively.
A 1% increase in the inflation rate would increase our liability by $94 million and a 1% decrease in the inflation rate would decrease our liability by $89 million as of December 31, 2025.
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. Additionally, the information in this report contains forward-looking statements related to the recently announced Aera merger.
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 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 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.
